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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
/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)
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Commission File Number 1-4393
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PUGET SOUND POWER & LIGHT COMPANY
(Exact name of registrant as specified in its charter)
Washington 91-0374630
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
411 - 108th Avenue N.E., Bellevue, Washington 98004-5515
(Address of principal executive offices)
(206) 454-6363
(Registrant's telephone number, including area code)
Exhibit Index on Page 60
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which listed
Common Stock, without par value,
$10 stated value N. Y. S. E.
Preference Share Purchase Rights N. Y. S. E.
7-7/8% Series Preferred Stock
(Cumulative $25 Par Value) N. Y. S. E.
Adjustable Rate Cumulative Preferred
Stock, Series B ($25 Par Value) N. Y. S. E.
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Preferred Stock (Cumulative; $100 Par Value)
Preferred Stock (Cumulative; $25 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 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 voting stock held by non-affiliates of the
registrant at December 31, 1995 was approximately $1,476,435,000.
The number of shares of the registrant's common stock outstanding at January
31, 1996 was 63,640,861.
Documents Incorporated by Reference
The Company's definitive proxy statement for its annual meeting of
shareholders on May 14, 1996, is incorporated by reference in Part III
hereof.
INDEX
Item Page
No. No.
Part I
1. Business.................................................1
The Company..............................................1
Industry Evolution and Merger with Washington Energy
Company..................................................2
Regulation and Rates.....................................3
Power Resources..........................................3
Construction Financing...................................8
Environment..............................................9
Operating Statistics....................................12
Executive Officers......................................14
2. Properties..............................................15
3. Legal Proceedings.......................................15
4. Submission of Matters to a Vote of Security.............15
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
8. Financial Statements and Supplementary Data.............24
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure..................24
Part III
(Incorporated by reference from the Company's
definitive proxy statement issued in connection
with the 1996 Annual Meeting of Shareholders)
10. Directors and Executive Officers of the Registrant
11. Executive Compensation
12. Security Ownership of Certain Beneficial
Owners and Management
13. Certain Relationships and Related Transactions
Part IV
14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.....................................25
Signatures..............................................26
Exhibit Index...........................................60
DEFINITIONS
AFUCE Allowance for Funds Used to Conserve Energy
AFUDC Allowance for Funds Used During Construction
BPA Bonneville Power Administration
CAAA Clean Air Act Amendments
Chelan Public Utility District No. 1 of
Chelan County, Washington
EPA Environmental Protection Agency
FERC Federal Energy Regulatory Commission
KW Kilowatts
KWH Kilowatt Hours
MW Megawatts (one MW equals one thousand KW)
MWH Megawatt Hours
Montana Power The Montana Power Company
NMFS National Marine Fisheries Service
NWPPC Northwest Power Planning Council
PRAM Periodic Rate Adjustment Mechanism
PRP Potentially Responsible Party
PUDs Washington Public Utility Districts
Washington Commission Washington Utilities and Transportation
Commission
WECO Washington Energy Company
WNG Washington Natural Gas Company
WPPSS Washington Public Power Supply System
PART I
ITEM 1. BUSINESS
THE COMPANY
The Company is an investor-owned public utility incorporated in the
State of Washington furnishing electric service in a territory covering
approximately 4,500 square miles, principally in the Puget Sound region of
Washington State. The population of the Company's service area is over 1.8
million. In December 1995, the Company had approximately 840,700 total
customers, consisting of 747,100 residential, 88,300 commercial, 3,900
industrial and 1,400 other customers. For the year 1995, the Company added
approximately 17,600 customers, an annual growth rate of 2.1%. Growth in
total kilowatt-hour sales increased 5.4% in 1995 over 1994, due to increased
sales to other utilities and continuing growth in the number of customers in
1995.
During 1995, the Company's billed revenues were derived 44% from
residential customers, 34% from commercial customers, 14% from industrial
customers and 8% from sales to other utilities and others. During this
period, the largest single customer accounted for 3.2% of the Company's
operating revenues. The average number of kilowatt-hours billed per
residential customer served by the Company in 1995 was 12,139 kilowatt-
hours. At December 31, 1995, the peak power resources of the Company were
approximately 5,310,000 KW. The Company's historical peak load of
approximately 4,615,000 KW occurred on December 21, 1990.
The Company is affected by various seasonal weather patterns throughout
the year and, therefore, operating revenues and associated expenses are not
generated evenly during the year. Variations in energy usage by consumers
do occur from season to season and from month to month within a season,
primarily as a result of weather conditions. The Company normally
experiences its highest energy sales in the first and fourth quarters of the
year. Sales to other utilities also vary by quarters and years depending
principally upon water conditions for the generation of surplus hydro-
electric power, customer usage and the energy requirements of other
utilities. With the implementation of the Periodic Rate Adjustment
Mechanism ("PRAM") in October 1991, earnings have not been significantly
influenced, up or down, by sales of surplus electricity to other utilities
or by variations in normal seasonal weather or hydro conditions. The PRAM
however, will end effective September 30, 1996 under a stipulated negotiated
settlement approved by the Washington Utilities and Transportation
Commission (the "Washington Commission"). Under terms of the settlement,
PRAM accrued revenues at that time would be recovered in rates over a period
not to exceed two years. With the discontinuance of the PRAM, the annual
regulatory adjustments for variations in weather and hydro conditions
provided for in the PRAM will also be discontinued. (See "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Rate Matters")
During the period from January 1, 1991 through December 31, 1995, the
Company made gross utility plant additions of $821 million and retirements
of $113 million. Gross electric utility plant at December 31, 1995 was
approximately $3.4 billion which consisted of 46% distribution, 27%
generation, 15% transmission and 12% general plant and other.
The Company had 2,150 full-time equivalent employees on December 31,
1995, down from 2,775 at the end of 1992. This represents a workforce
reduction of 23% over the last three years.
1
INDUSTRY EVOLUTION AND MERGER WITH WASHINGTON ENERGY COMPANY
The electric utility industry in general is facing a more competitive
environment, particularly in wholesale generation and industrial customer
markets.
The National Energy Policy Act of 1992 ("EPACT") has intensified competition
in the wholesale electric market by easing restrictions on wholesale power
producers and by allowing the Federal Energy Regulatory Commission ("FERC")
to order access for wholesale sellers to deliver power to wholesale buyers
over transmission systems owned by others. FERC has also initiated a rule
making process regarding transmission access for wholesale purposes, and has
requested jurisdictional utilities, including the Company, to file pro forma
wholesale transmission tariffs providing pricing and terms for such access.
The EPACT does not permit the FERC to order transmission access for retail
purposes, but some states, including California, Michigan and Massachusetts,
are considering proposals which would allow such access for retail purposes.
In December 1994, the Washington Commission issued a notice of inquiry
seeking comments from interested parties on the costs and benefits of
increased retail competition. In 1995, the Commission said it would take no
action on various proposals and instead issued an interim statement of
principles. Any substantial changes in utility regulation in Washington
state, such as mandating retail wheeling, would require legislative action.
The major credit rating agencies have expressed the general view that
increased competition is likely to increase business risks in the electric
utility industry, with resulting pressures on utility credit quality and
investor returns.
In this environment, the Company seeks to build on the strengths of its
efficient electric distribution and transmission system to become a leading
provider of energy and related services to homes and businesses in the
Pacific Northwest. To prepare for a more competitive business environment,
the Company has committed itself to being a low cost supplier of
electricity. The Company has taken steps to reduce costs, including work
force reductions, facility consolidations and reductions in capital budgets.
The Company intends to pursue opportunities for improved operating
efficiencies and productivity, including possible restructuring of its power
supply resources and contracts. The Company is also actively pursuing
opportunities to become a provider of new high value services such as
wireless automated meter-based services and geographic information systems,
to utility customers and other utilities.
A major step in becoming a leading provider of energy and related
services in the Northwest was taken on October 18, 1995, when the Company
entered into an Agreement and Plan of Merger with Washington Energy Company
("WECO") and Washington Natural Gas Company ("WNG"), a wholly-owned
subsidiary of WECO. WNG is engaged primarily in the retail distribution of
natural gas. Pursuant to the Agreement, WECO and WNG would be merged with
and into Puget Power, after which the merged company would be renamed. The
merger would create the largest combined electric and gas utility in the
state of Washington. The Agreement calls for each share of WECO common
stock to be exchanged for 0.86 shares of the Company's common stock. Based
on the capitalization of the Company and WECO on December 31, 1995, holders
of the Company's and WECO's common stock would have held approximately 75%
and 25%, respectively, of the aggregate number of outstanding shares of the
merged company's common stock had the merger been consummated on that date.
In addition, the Agreement calls for the preferred stock of WNG to be
converted into preferred shares of the merged company. The merger would be
structured as a tax-free exchange of shares, and is expected to be accounted
for as a pooling of interests. The board of directors of the new company
would consist of up to 15 individuals, drawn in a two-to-one ratio from the
current Puget Power and WECO boards.
The merger agreement is subject to the approval of the shareholders of the
respective companies and by the Washington Commission which regulates the
utility
2
operations of each entity. Shareholder approval will be sought at
shareholder
meetings scheduled for March 20, 1996. The Company has requested that the
regulatory approval process be completed no later than the second half of
1996.
REGULATION AND RATES
The Company is subject to the regulatory authority of (1) the
Washington Commission as to rates, accounting, the issuance of securities
and certain other matters, and (2) the FERC in the transmission of electric
energy in interstate commerce, the sale of electric energy at wholesale for
resale, accounting and certain other matters. The Washington Commission
consists of three Commissioners, each appointed for a six-year term by the
Governor of the State of Washington. (See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Rate Matters.")
POWER RESOURCES
During 1995, the Company's total energy production was supplied 26% by
its own resources, 28% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydroelectric projects
on the Columbia River, 40% from other firm purchases and 6% from non-firm
purchases.
The following table shows the Company's resources at December 31, 1995,
and energy production during the year:
Peak Power Resources at
December 31, 1995 1995 Energy Production
----------------------- ----------------------
Kilowatts % Kilowatt-Hours %
--------- ----- -------------- -----
(Thousands)
Purchased Resources:
Columbia River
PUD Contracts (Hydro) 1,453,980 27.4 6,798,677 27.9
Other Hydro(a) 672,962 12.7 3,271,654 13.5
Thermal(a) 1,398,900 26.3 7,876,076 32.4
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Total Purchased 3,525,842 66.4 17,946,407 73.8
- ----------------------------------------------------------------------------
Company-owned Resources:
Hydro 309,950 5.9 1,494,067 6.2
Coal 771,900 14.5 4,696,536 19.3
Natural gas/oil 702,350 13.2 180,813 0.7
- ---------------------------------------------------------------------------
Total Company-owned 1,784,200 33.6 6,371,416 26.2
- ----------------------------------------------------------------------------
Total Capability 5,310,042 100.0 24,317,823 100.0
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(a) Power received from other utilities is classified between hydro and
thermal based on the character of the utility system used to supply the
power or, if the power is supplied from a particular resource, the character
of that resource.
3
Company Owned Resources
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The Company and other utilities are joint owners of four mine-mouth,
coal-
fired, steam-electric generating units at Colstrip, Montana, approximately
100 miles east of Billings. The Company owns a 50% interest (330,000 KW) in
Units 1 and 2 and a 25% interest (350,000 KW) in Units 3 and 4. The owners
of the Colstrip Units purchase coal for the units from Western Energy
Company ("Western Energy"), an affiliate of Montana Power - one of the joint
owners, under the terms of long-term coal supply agreements.
A contract price reopener for both the base price and adjustment
provisions of the Colstrip 1 and 2 Coal Supply Agreement became effective
July 30, 1991. The coal price was eventually arbitrated in January of 1995
and a decision on the arbitration was rendered on March 17, 1995, reducing
the base cost of coal from $9.80 per ton to $7.68 per ton effective July 30,
1991. The next contract price reopener will be on July 30, 1996.
There are several issues pending between the buyers, including the
Company, and Western Energy, the seller, under the Colstrip 3 and 4 Coal
Supply Agreement. On February 23, 1995, the buyers, other than Montana
Power, gave Western Energy and Montana Power written notice of their intent
to submit a number of these issues to arbitration. The issues have been
arbitrated and a decision is expected in March 1996. The outcome is not
expected to have an adverse impact on the cost the Company pays for coal.
The Company owns a 7% interest (91,900 KW) in a coal-fired, steam-
electric generating plant near Centralia, Washington, with a net capability
of 1,313,000 KW. In 1991, the Company and other owners of the Centralia
Project renegotiated a long-term coal supply agreement with Pacific Power &
Light Company.
The Company also has the following plants with an aggregate net
generating capability of 1,012,300 KW: Upper Baker River hydro project
(103,000 KW) constructed in 1959; Lower Baker River hydro project (71,400
KW) reconstructed in 1968; White River hydro plant (63,400 KW) constructed
in 1911 with installation of the last unit in 1924; Snoqualmie Falls hydro
plant (44,000 KW), half the capability of which was installed during the
period 1898 to 1910 and half in 1957; two smaller hydro plants, Electron
(26,400 KW) and Nooksack Falls (1,750 KW), constructed during the period
1904 to 1929; a standby internal combustion unit (2,750 KW) installed in
1969; two oil-fired combustion turbine units (28,500 KW and 67,500 KW)
installed in 1972 and 1974, respectively; four dual-fuel combustion turbine
units (89,100 KW each) installed during 1981; and two dual-fuel combustion
turbine units (123,600 KW each) installed during 1984.
The Company's combustion turbines installed in 1981 and 1984 may be
fueled with natural gas or distillate oil. Short-term supplies of fuel are
stored on-site. The Company has not entered into contracts which assure a
future long-term supply or price of fuel for the Company's combustion
turbines.
The Company has applied to the FERC for an initial license for its
existing and operating White River project which includes authorization to
install an additional 14,000 KW generating unit. The initial license for
the Snoqualmie Falls project expired in December 1993, and the Company is
continuing the FERC application process to relicense the project. The
Company has also applied for a license to expand its 1,750 KW Nooksack Falls
project which is currently an unlicensed facility.
4
Columbia River Projects
- -----------------------
The purchase of power from the Columbia River projects is generally on
a "cost of service" basis under which the Company pays a proportionate share
of the annual debt service and operating and maintenance costs of each
project in direct ratio to the amount of power annually allocated to it.
Such payments are not
contingent upon the projects being operable. These projects are financed
through substantially level debt service payments, and their annual costs
may vary over the term of the contracts as additional financing is required
to meet the costs of major maintenance, repairs or replacements or license
requirements. The average cost of power purchased from these projects was
approximately 10.3 mills per KWH in 1995.
The Company has contracted to purchase a share of the output of the
original units of the Rock Island Project that equals 59.2% through June 30,
1996. This share decreases gradually to 50% of the output until July 1,
1999, and remains unchanged thereafter for the duration of the contract.
The Company has contracted to purchase the entire output of the additional
Rock Island units for the duration of the contract, except that the
Company's share of output of the additional units may be reduced not in
excess of 10% per year beginning July 1, 2000, to a minimum of 50% upon the
exercise of rights of withdrawal by Chelan for use in its local service
area. Chelan has given notice of withdrawal of 5% on July 1, 2000. The
Company has contracted to purchase a share of the output of the Rocky Reach
Project that remains unchanged for the duration of the contract. Under
terms of a withdrawal of power settlement, the Company's share of the output
of the Wells Project is currently 33.6% and is expected to decrease to 32.3%
by September 1, 1996. However, the Company's share of the output can be
ultimately reduced to 31.3% upon the exercise of withdrawal rights by
Douglas County PUD. The Company has contracted to purchase a share of the
output of the Priest Rapids and Wanapum projects that remains unchanged for
the duration of the contracts.
As of December 31, 1995, the Company was entitled to purchase portions
of the power output of the PUDs' projects as set forth in Note 15 to the
Consolidated Financial Statements.
In 1964, the Company and fifteen other utilities and agencies in the
Pacific Northwest entered into a long-term coordination agreement extending
until June 30, 2003 (the "Coordination Agreement"). This agreement provides
for the coordinated operation of substantially all of the hydroelectric
power plants and reservoirs in the Pacific Northwest. Various fishery
enhancement measures, including most recently the 1995 "biological opinion"
from the National Marine Fisheries Service ("NMFS"), have reduced the
flexibility provided by the Coordination Agreement.
Certain utilities in the northwest United States and Canada are
obtaining the benefits of over 1,000,000 KW of additional firm power as a
result of the ratification of a treaty between the United States and Canada
under which Canada is providing approximately 15,500,000 acre-feet of
reservoir storage on the upper Columbia River. As a result of this storage,
streamflow which would otherwise not be usable to serve firm load is shifted
into periods when it is usable. The Company obtains firm power based upon
its percentage entitlement under its Columbia River contracts, currently
approximately 106,300 KW. In addition, the Company has contracted to
purchase 17.5% of Canada's share of the power resulting from such storage
(92,476 KW capacity and 48,836 KW average energy in the 1995-96 contract
year, April 1 to March 31, which amounts decrease gradually until expiration
of the contract in 2003). The Company has also contracted to purchase from
the Bonneville Power Administration ("BPA") supplemental capacity in amounts
that decrease gradually until expiration of the contract in 2003. The
amount of supplemental capacity currently purchased is approximately 32,066
KW.
5
A 1995 Memorandum of Understanding pursuant to which the United States would
have purchased a portion of Canada's share of the Entitlement capacity has
been terminated. BPA and Canadian negotiators are now working on
alternative arrangements. Concurrently, BPA negotiators and representatives
of participants in the five Mid-Columbia projects from which the Company
purchases power are finalizing associated agreements which define the
amounts of power which each project, and in turn each purchaser including
the Company, will contribute to
the delivery of the Entitlement to Canada.
See "ENVIRONMENT - Federal Endangered Species Act" for discussion of
the fishery enhancement plan related to these projects.
Contracts and Agreements with Other Utilities
- ---------------------------------------------
On September 17, 1985, the Company and BPA entered into a settlement
agreement settling the Company's claims against BPA resulting from BPA's
action in halting construction on Washington Public Power Supply System
("WPPSS") Nuclear Project No. 3 in which the Company has a five percent
interest. Under the settlement agreement, the Company is receiving from BPA
for approximately 30.5 years, beginning January 1, 1987, a certain amount of
electric power during the months of November through April. Under the
contract, the Company is guaranteed to receive not less than 191,667 MWH in
each contract year until the Company has received total deliveries of
5,833,333 MWH.
On April 4, 1988, the Company executed a 15-year contract, with
provisions for early termination by the company, for the purchase of firm
energy supply from Washington Water Power Company. This agreement calls for
the delivery of 100 MW of capacity and 657,000 MWH of energy from the
Washington Water Power system annually (75 annual average MW). Minimum and
maximum delivery rates are prescribed. Under this agreement, the energy is
to be priced at Washington Water Power's average generation and transmission
cost, subject to certain price ceilings.
On October 27, 1988, the Company executed a 15-year contract for the
purchase of firm power and energy from Pacific Power & Light Company. Under
the terms of the agreement, the Company receives 120 average MW of energy
and 200 MW of peak capacity.
On November 23, 1988, the Company executed an agreement to purchase
surplus firm power from BPA. Under the agreement, the Company receives 150
average MW of energy and 300 MW of peak capacity from BPA between October 1
and March 31 of each contract year. The contract extends for 20 years,
ending in 2008. The sale will convert to a power-for-power exchange on June
30, 2001.
On October 1, 1989, the Company signed a contract with Montana Power
under which Montana Power provides, from its share of Colstrip Unit 4, to
the Company 71 average MW of energy (94 MW of peak capacity) over a 21-year
period. On February 27, 1995, the Company delivered to Montana Power notice
of termination of the contract based on Montana Power's failure to arrange
for firm contractual
transmission rights for such energy as required by the contract. On
February 28, 1995, Montana Power filed a lawsuit in a Montana State Court
and obtained a temporary restraining order regarding the termination. The
Company then filed a
notice of removal of the Montana State Court action to the Federal District
Court in Montana requesting termination and reimbursement. On March 7,
1995, the Company filed a lawsuit in the United States District Court for
the Western District of Washington in response to Montana Power's failure to
terminate the contract as required and for failure to reimburse the Company
for approximately
6
$39 million in power costs, which are due upon termination under contract
provisions. In January 1996, the FERC declined to take discretionary
jurisdiction over the issue of what constitutes firm transmission rights,
leaving it to the court to determine the intent of the parties.
On December 11, 1989, the Company executed a conservation transfer
agreement with Snohomish County PUD. Snohomish County PUD, together with
Mason and Lewis County PUDs, will install conservation measures in their
service areas. The
agreement calls for the Company to receive the power saved over the expected
20-year life of the measures. The agreement calls for BPA to deliver the
conservation power to the Company from March 1, 1990 through June 30, 2001,
and for Snohomish County PUD to deliver the conservation power for the
remaining term of the agreement. Power deliveries gradually increase over
the first five years of the agreement, roughly matching the installation of
the conservation measures, and will reach six average MW of energy in the
fifth year. Under the agreement,
deliveries of conservation power will then remain at six average MW of
energy throughout the term of the agreement.
The Company executed an exchange agreement with Pacific Gas & Electric
Company which became effective on January 1, 1992. Under the agreement, 300
MW of capacity together with 413,000 MWH of energy are exchanged every year
on a unit for unit basis. No payments are made under this agreement.
Pacific Gas & Electric Company is a summer peaking utility and will provide
power during the months of November through February. The Company is a
winter peaking utility and will provide power during the months of June
through September. By giving proper notice, either party may terminate the
contract for various reasons.
Contracts and Agreements with Non-Utilities
- -------------------------------------------
As required by federal law, Public Utility Regulatory Policies Act of
1978, P.L. 95-617 ("PURPA"), the Company has contracted to purchase the net
electrical output from a number of non-utility generators, of which the most
significant are described below. Payments by the Company to owners of these
non-utility generating resources are subject to the delivery of power. (See
Note 15 to the Consolidated Financial Statements)
On February 21, 1985, the Company executed a 50-year contract to
purchase 6 average MW of energy and 14 MW of capacity, beginning in December
1990, from Koma Kulshan Associates, which owns and operates a small
hydroelectric project located near the Company's Upper Baker Dam.
On January 4, 1988, the Company executed a 21-year contract to purchase
15 average MW of energy and 23 MW of capacity, beginning November 1991, from
the City of Spokane, which owns and operates a regional solid waste
incineration project located near Spokane, Washington.
On June 29, 1989, the Company executed a 20-year contract to purchase
70 average MW of energy and 23 MW of capacity, beginning October 11, 1991,
from the March Point Cogeneration Company ("March Point"), which owns and
operates a natural gas-fired cogeneration facility known as March Point
Phase I, located at a Texaco refinery in Anacortes, Washington. On December
27, 1990, the Company executed a second contract (having a term coextensive
with the first contract) to purchase an additional 53 average MW of energy
and 60 MW of capacity, beginning January 1993, from March Point which owns
and operates another natural gas-fired cogeneration facility known as March
Point Phase II, also located at the Texaco refinery in Anacortes,
Washington. On November 29, 1995, March Point commenced litigation against
the Company in federal court for the Western District of Washington
regarding the contracts. March Point filed an amended complaint on
7
December 6, 1995; it seeks a declaration of certain obligations of March
Point and the Company under the contracts, injunctive relief preventing the
Company from terminating its contracts with March Point and damages based on
breach of contract. March Point's claim for damages seeks compensation for
the Company's alleged failure to make full payments for amounts due upon the
displacement of certain power from June 1995 to the present. The Company
denies this claim. The Company has answered and counterclaimed in the
action, contending that March Point has breached the contracts. The Company
seeks declaratory relief regarding the parties' obligations and rights under
the contracts, damages based on the breach
and rescission.
On February 24, 1989, the Company executed a 20-year contract to
purchase 108 average MW of energy and 123 MW of capacity, beginning in April
1993, from Sumas Cogeneration Company, L.P., which owns and operates a
natural gas-fired cogeneration project located in Sumas, Washington.
On September 26, 1990, the Company executed a 15-year contract to
purchase 141 average MW of energy and 160 MW of capacity, beginning July
1993, from Encogen Northwest L.P. ("Encogen") (a limited partnership having
a general partner that is a subsidiary of Enserch Development Corp.), which
owns and operates a natural-gas fired cogeneration facility located near
Bellingham, Washington. On September 20, 1995, Encogen commenced litigation
against the Company in Whatcom County Superior Court requesting a
declaration of certain obligations of Encogen under the contract, and
seeking further relief. The Company has answered and counterclaimed in the
action, contending that Encogen has breached the agreement and seeking
declaratory relief regarding Encogen's duty to provide certain information.
On March 20, 1991, the Company executed a 20-year contract to purchase
216 average MW of energy and 245 MW of capacity, beginning April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas
fired cogeneration project located near Ferndale, Washington.
Energy Conservation
- -------------------
The Company offers programs designed to help new and existing customers
use electric energy efficiently. In addition to providing information and
analyses, the Company may provide limited grants to encourage the
installation of energy conservation measures in customer facilities. Energy
conservation measures installed in 1995 are expected to result in annualized
savings of approximately 96,429 MWH.
The Company's energy conservation expenditures have historically been
accumulated, included in rate base and amortized to expense over a ten year
period at the direction of the Washington Commission. In June 1995 the
Company sold approximately $202.5 million of its investment in customer-
owned energy conservation measures to a grantor trust, which, in turn,
issued securities backed by a Washington state statute enacted in 1994.
(See Note 1 to the Consolidated Financial Statements)
CONSTRUCTION FINANCING
The Company estimates its construction expenditures, which include
energy conservation expenditures and exclude Allowance for Funds Used During
Construction ("AFUDC") and Allowance for Funds Used to Conserve Energy
("AFUCE"), for 1996 and 1997 will be $133.5 million and $143.8 million,
respectively. The Company expects cash from operations (net of dividends,
AFUDC and AFUCE) in 1996 and 1997 will, on average, be approximately 114% of
average estimated construction expenditures (excluding AFUDC and AFUCE)
during the same period.
8
(See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" for a discussion of the Company's construction
program.) The Company's ability to finance its future construction program
is dependent upon market conditions and maintaining a level of earnings
sufficient to permit the sale of additional securities. In determining the
type and amount of future financings, the Company may be limited by
restrictions contained in its Mortgage Indenture, Articles of Incorporation
and certain loan agreements.
Under the most restrictive tests, at December 31, 1995, the Company
could issue (i) approximately $939 million of additional first mortgage
bonds or (ii)
approximately $535 million of additional preferred stock at an assumed
dividend rate of 7.22% or (iii) a combination thereof.
ENVIRONMENT
The Company's operations are subject to environmental regulation by
federal, state and local authorities. Capital expenditures for
environmental controls on all Company facilities are estimated at $17.1
million for the period 1996 through 1998. Due to the inherent uncertainties
surrounding the development of federal and state environmental and energy
laws and regulations, the Company cannot determine the impact such laws may
have on its existing and future facilities.
Federal Comprehensive Environmental Response, Compensation and
Liability Act, and the Washington State Model Toxics Control Act
- ----------------------------------------------------------------
The federal Comprehensive Environmental Response, Compensation and
Liability Act (commonly referred to as the "Superfund Act") subjects certain
parties to liability for remedial action at contaminated disposal sites.
The Company has been named by the Environmental Protection Agency
("EPA") as a Potentially Responsible Party ("PRP") at four sites in
Washington State. The Company has reached settlements with the EPA on all
four sites under which the Company has paid approximately $7.6 million.
Estimated future remediation costs at these four sites are expected to be
$0.5 million. To date, the Company has recovered $3.9 million from its
insurance companies in connection with remediation and legal costs and
expects to recover an additional $1.5 million. These sites represent all
significant superfund sites at which the Company believes it has liability.
There is, however, no assurance that all contaminated sites and contaminants
for which the Company may have a responsibility have been identified or that
remedial actions planned to date at current sites, including actions
pursuant to consent decrees, will be adequate.
The Company has also commenced a program to test, replace and remediate
certain underground storage tanks as required by federal and state laws.
Remediation and testing of Company vehicle service facilities and storage
yards have also been commenced. To date, the Company has spent $3.2 million
to remediate underground tank sites and has recovered $0.4 million in
insurance proceeds. Future expenditures are anticipated to be $1.2 million
and future insurance proceeds are anticipated to be $1.5 million. Estimated
future remediation costs at other Company-owned sites were $0.9 million at
December 31, 1995. (See Note 15 to the Consolidated Financial Statements
for further discussion of environmental obligations and the related
regulatory treatment.)
9
Federal Clean Air Act Amendments of 1990
- ----------------------------------------
The Company has an ownership interest in coal-fired, steam-electric
generating plants at Centralia, Washington and Colstrip, Montana which are
subject to the federal Clean Air Act Amendments of 1990 ("CAAA") and other
regulatory requirements.
The Centralia Project and the Colstrip Projects meet the sulfur dioxide
limits of the CAAA in Phase I (1995). Pacific Power & Light Company, which
operates the Centralia Project, is working on compliance plans to meet the
Phase II limits in the year 2000.
Montana Power, which operates the Colstrip 3 and 4 Project, is working
to meet the Phase II limits in the year 2000. Under the CAAA, allowances
may be used
to achieve compliance. It is believed that Units 1 and 2 may have an excess
of allowances above what is currently set for Phase II requirements and that
Units 3 and 4 have sufficient allowances for Phase II requirements.
The Company owns combustion turbine units which are capable of being
fueled by natural gas or oil. The nature of these units provides
operational flexibility in meeting air emission standards.
There is no assurance that in the future environmental regulations
affecting sulfur dioxide or nitrogen oxide emissions may not be further
restricted, and there is no assurance that restrictions on emissions of
carbon dioxide or other combustion by-products may not be imposed.
Federal Endangered Species Act
- ------------------------------
In November 1991, the NMFS listed the Snake River Sockeye as an
endangered species pursuant to the federal Endangered Species Act. Since
the Sockeye listing, the Snake River fall and spring/summer Chinook have
also been listed as threatened. In response to the listings, a team of
experts was formed to develop a plan for the recovery needs of these
species. In anticipation of the listings, the Northwest Power Planning
Council ("NWPPC") previously developed a fishery enhancement plan which
combines increased springtime flows with habitat enhancements, harvest
reductions, and other measures. The spring flow augmentation portion of the
plan began in 1991. Federal agencies that operate the Federal Columbia
River Power System must consult with the NMFS to determine whether any
action they undertake will unduly jeopardize the listed species. In 1995,
the NMFS issued a biological opinion that could, depending on flow
conditions and implementation procedures, significantly change the operation
of the Federal Columbia River Power System.
The NWPPC plan and plans developed by NMFS affect the Mid-Columbia
projects from which the Company purchases power on a long-term basis, and
will further reduce the flexibility of the regional hydroelectric system.
Although the full impacts are unknown at this time, the plan ultimately
developed by NMFS could shift an amount of the Company's generation from the
Mid-Columbia projects from winter periods into the spring when it is not
needed for system loads, and will increase the potential for spill and loss
of generation at the Mid-Columbia projects. Under the NWPPC's plan
presently in effect, in years of critical water flows, the maximum amount of
generation that the Company would have to transfer into the spring is
limited to approximately 275,000 MWH or 4% of the Company's share of energy
production from the Mid-Columbia during 1995.
10
Other species are also proposed for listing as endangered species and
could further restrict hydro system flexibility and energy production.
11
Puget Sound Power & Light Company
OPERATING STATISTICS
Year Ended on December 31 1995 1994 1993 1992 1991
- --------------------------------------------------------------------------------------------
Operating revenues by classes
(thousands):
- --------------------------------------------------------------------------------------------
Residential $ 524,749 $ 532,124 $ 502,037 $ 443,490 $ 480,356
Commercial 397,212 375,751 356,586 323,764 310,824
Industrial 168,501 163,574 150,063 138,416 127,164
Other consumers 38,730 38,759 28,189 35,779 26,897
- --------------------------------------------------------------------------------------------
Operating revenues billed
to consumers (a) 1,129,192 1,110,208 1,036,875 941,449 945,241
Unbilled revenues -
net increase (decrease) (6,382) (2,522) 14,409 15,080 (16,216)
PRAM accrual 3,953 25,835 42,100 42,119 670
- --------------------------------------------------------------------------------------------
Total operating revenues
from consumers 1,126,763 1,133,521 1,093,384 998,648 929,695
Other utilities 52,567 60,537 19,494 26,322 27,074
- --------------------------------------------------------------------------------------------
Total operating revenues $1,179,330 $1,194,058 $1,112,878 $1,024,970 $956,769
- --------------------------------------------------------------------------------------------
Number of customers (average):
Residential 739,173 723,566 708,123 692,100 673,883
Commercial 87,404 85,203 82,875 80,963 78,691
Industrial 3,908 3,851 3,715 3,659 3,574
Other 1,346 1,325 1,289 1,254 1,226
- --------------------------------------------------------------------------------------------
Total customers (average) 831,831 813,945 796,002 777,976 757,374
KWH generated, purchased
and interchanged (thousands):
Total Company generated 6,371,416 7,011,932 6,414,311 7,420,058 6,819,348
Purchased power 17,897,922 16,268,042 14,608,899 13,408,522 14,770,597
Interchanged power (net) 48,485 (87,771) 174,478 (118,346) (139,110)
- --------------------------------------------------------------------------------------------
Total energy output 24,317,823 23,192,203 21,197,688 20,710,234 21,450,835
Losses and Company use (1,235,457) (1,291,322) (1,096,599) (1,202,194) (1,267,919)
- --------------------------------------------------------------------------------------------
Total energy sales 23,082,366 21,900,881 20,101,089 19,508,040 20,182,916
- --------------------------------------------------------------------------------------------
(a) Operating revenues in 1995 were reduced by $25.1 million as a result of the
Company's
sale of customer-owned energy conservation measures. (See "Operating revenues" in
Management's Discussion and Analysis and Note 1 to the Consolidated Financial
Statements.)
12
(Continued from prior page 1995 1994 1993 1992 1991
- --------------------------------------------------------------------------------------------
Electric energy sales, KWH
(thousands):
Residential 8,972,498 8,913,903 8,974,787 8,297,293 8,906,470
Commercial 6,538,533 6,301,568 6,175,911 5,945,284 5,930,385
Industrial 3,720,641 3,724,931 3,690,473 3,704,450 3,598,683
Other consumers 205,232 200,622 196,246 193,563 185,879
- --------------------------------------------------------------------------------------------
Total energy billed
to consumers 19,436,904 19,141,024 19,037,417 18,140,590 18,621,417
Unbilled energy sales -
net increase (decrease) (158,920) (72,352) 139,329 209,565 (309,279)
- --------------------------------------------------------------------------------------------
Total energy sales
to consumers 19,277,984 19,068,672 19,176,746 18,350,155 18,312,138
Sales to other
electric utilities 3,804,382 2,832,209 924,343 1,157,885 1,870,778
- --------------------------------------------------------------------------------------------
Total energy sales 23,082,366 21,900,881 20,101,089 19,508,040 20,182,916
- --------------------------------------------------------------------------------------------
Per residential customer:
Annual use (KWH) 12,139 12,319 12,674 11,989 13,217
Annual billed revenue 726.95 $735.42 $708.97 $640.79 $712.82
Billed revenue per KWH $.0599 $.0597 $.0559 $.0534 $.0539
Company-owned generation
capability - kilowatts:
Hydro 309,950 309,950 309,950 309,950 309,950
Steam 771,900 771,900 857,700 857,700 857,700
Natural gas/oil 702,350 702,350 702,350 702,350 702,350
- --------------------------------------------------------------------------------------------
Total 1,784,200 1,784,200 1,870,000 1,870,000 1,870,000
- --------------------------------------------------------------------------------------------
Heating degree days 3,994 4,341 4,691 4,090 4,556
% of normal of 30 year
average (4,908) 81.4% 88.4% 95.6% 83.3% 92.8%
Load factor 56.7% 54.7% 52.5% 57.0% 54.8%
13
EXECUTIVE OFFICERS AT DECEMBER 31, 1995:
Name Age Offices
- ---------------- --- ---------------------------------------------------
R. R. Sonstelie 50 President and Chief Executive Officer since 1992;
President and Chief Operating Officer 1991-1992;
President and Chief Financial Officer 1987-1991;
Executive Vice President 1985-1987;
Senior Vice President Finance 1983-1985;
Vice President Engineering and Operations 1980-1983;
Director since 1987.
W. S. Weaver 51 Executive Vice President and Chief Financial Officer
and Director since 1991. For more than five years
prior to that time, a Partner in the law firm Perkins
Coie.
G. B. Swofford 54 Senior Vice President Customer Operations since
1994; Vice President Divisions and Customer
Services 1991-1994; Vice President Rates and Customer
Programs 1986-1991; Director Conservation and
Division Services 1980-1986.
S. M. Vortman 50 Senior Vice President Corporate & Regulatory
Relations since 1994; Vice President
Strategic Planning and Regulatory Affairs
February 10, 1994 - May 9, 1994; Vice President
Corporate Services 1992-1994; Director Real Estate
1990-1992; Manager Community and Economic
Development 1986-1990.
R. G. Bailey 56 Vice President Power Systems since 1980.
J. W. Eldredge 45 Chief Accounting Officer since 1994;
Corporate Secretary and Controller since 1993;
Controller since 1988; Manager Budgets and
Performance 1987-1988; Manager General Accounting
1984-1987.
G. N. Ferencz 49 Vice President Divisions since 1994; Director
Division Services 1992-1994; General Manager Thurston
Division 1990-1992; Division Administrator Southern
Division 1982-1990.
D. E. Gaines 38 Treasurer since 1994; Director Strategic
Planning 1992-1994; Manager Financial Planning 1986 -
1992.
J. L. Henry 50 Vice President Engineering and Operating Services
since 1994; Vice President Operations
Services 1991-1994; Director South Central Division
1990-1991; Director Division Operations 1984-1990.
J. R. Lauckhart 47 Vice President Power Planning since 1991;
Director Power Planning 1986-1991.
Officers are elected for one-year terms.
14
ITEM 2. PROPERTIES
The principal generating plants owned by the Company are described under
Item 1 - "Business - Power Resources." The Company owns its transmission and
distribution facilities, and various other properties. Substantially all
properties of the Company are subject to the lien of the Company's Mortgage
Indenture.
ITEM 3. LEGAL PROCEEDINGS
See Note 15 to the Consolidated Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - NONE
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Company's common stock is traded on the New York Stock Exchange
(symbol PSD). The number of stockholders of record of the Company's common
stock at December 31, 1995, was 58,940.
The Company has paid dividends on its common stock each year since 1943
when such stock first became publicly held. Future dividends will be
dependent upon earnings, the financial condition of the Company and other
factors.
Certain provisions relating to the Company's senior securities limit
funds available for payment of dividends to net income available for
dividends on common stock (as defined in the Company's Mortgage Indenture)
accumulated after December 31, 1957, plus the sum of $7.5 million. As of
December 31, 1995, the balance of earnings reinvested in the business that
was not restricted as to dividends on common stock was approximately $252
million. (See Note 6 to the Consolidated Financial Statements.)
Dividends paid and high and low stock prices for each quarter over the
last two years were:
1995 1994
--------------------------- ---------------------------
Price Range Price Range
--------------- Dividends --------------- Dividends
Quarter Ended High Low Paid High Low Paid
- ------------- ------ ------ --------- ------ ------ ---------
March 31 21-1/2 20-1/8 $.46 24-7/8 22 $.46
June 30 23-3/8 20-3/4 $.46 22-3/4 16-1/2 $.46
September 30 23-3/8 21-1/4 $.46 20 18-3/8 $.46
December 31 24 22-1/4 $.46 21 19-3/8 $.46
15
ITEM 6. SELECTED FINANCIAL DATA
Year Ended December 31 1995 1994 1993 1992 1991
- ---------------------------- --------- ---------- ---------- ---------- ----------
(Thousands of Dollars except per share data)
Operating Revenue $1,179,330 $1,194,058 $1,112,878 $1,024,970 $ 956,769
Operating Income $ 214,588 $ 193,498 $ 210,980 $ 214,670 $ 213,731
Net Income $ 135,720 $ 120,059 $ 138,327 $ 135,720 $ 132,777
Income for Common Stock $ 120,192 $ 104,328 $ 121,885 $ 121,836 $ 122,738
Common Shares Outstanding -
Weighted Average 63,640,861 63,632,057 60,930,859 56,283,949 55,561,647
Earnings Per Common Share
(Note 1 to the
Financial Statements) $1.89 $1.64 $2.00 $2.16 $2.21
Dividends Per Common Share $1.84 $1.84 $1.83 $1.79 $1.76
Book Value Per Common Share $18.48 $18.43 $18.65 $17.76 $16.96
Total Assets at Year End* $3,268,995 $3,463,770 $3,341,130 $2,997,721 $2,676,438
Long-term Obligations $ 920,439 $ 963,298 $1,036,079 $1,044,992 $1,052,309
Redeemable Preferred Stock $ 89,039 $ 91,242 $ 93,176 $ 93,822 $ 20,189
* The Company adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes," effective January 1, 1993, providing deferred
taxes for items which previously had tax benefits flowed through to
ratepayers. A corresponding regulatory asset was recorded under long-term
assets. For years prior to 1993, the Company has reclassified as
liabilities deferred taxes previously netted with plant and other property
and investments.
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net income in 1995 was $135.7 million on operating revenues of $1.179
billion, compared to $120.1 million on operating revenues of $1.194 billion
in 1994 and $138.3 million on operating revenues of $1.113 billion in 1993.
Income for common stock was $120.2 million, $104.3 million and $121.9
million for 1995, 1994 and 1993, respectively.
Earnings per share in 1995 were $1.89 on 63.6 million weighted average
common shares outstanding during the period compared to $1.64 on 63.6
million weighted average common shares outstanding in 1994 and $2.00 on 60.9
million weighted average common shares outstanding in 1993.
Return on the average book value of the Company's common equity in 1995 was
10.3%, compared to 8.9% in 1994 and 11.0% in 1993. The dividend payout
ratio was 97.4% in 1995, compared to 112.2% in 1994 and 91.5% in 1993.
The decline in net income during 1994 reflects after-tax charges totaling
$13.6 million associated with the Company's two voluntary early retirement
and separation programs and related business office and service facility
consolidations. These charges, recorded in other operation expenses,
represent a decrease in earnings per common share of $0.21 for the period.
Total kilowatt-hour sales to ultimate consumers in 1995 were 19.3 billion,
compared with 19.1 billion in 1994 and 19.2 billion in 1993. Kilowatt-hour
sales to other utilities were 3.8 billion in 1995, 2.8 billion in 1994 and
0.9 billion in 1993.
The preferred stock dividend accrual decreased $0.2 million in 1995 compared
to 1994 due to the the redemption of the $40 million Adjustable Rate
Cumulative Preferred Stock ("ARPS"), Series A ($100 par value) in February
1994. The preferred stock dividend accrual decreased $0.7 million in 1994
compared to 1993. This decrease was due to the redemptions of the $50
million Flexible Dutch Auction Rate Transferable Securities $100 Par Value
Preferred Stock ("FLEX DARTS"), Series B in July 1993 and the $40 million
ARPS, Series A in February 1994. These decreases were partially offset by
the issuance in February 1994 of the $50 million ARPS, Series B ($25 par
value).
The preferred stock dividend accrual increased $2.6 million in 1993 compared
to 1992 primarily due to the issuance of the 7.75% Series Preferred Stock in
March 1992 and the 7.875% Series Preferred Stock in July 1992. This was
partially offset by the reacquisition of the Series A FLEX DARTS in April
1992. The 1993 increase was also partially offset by the reacquisition of
the Series B FLEX DARTS in July 1993.
17
Years Ending December 31
Increase (Decrease) Over Preceding Year
(Dollars in Millions)
1995 1994 1993
- ------------------------------------------------------------------------
Operating revenues
General rate increase $ -- $27.0 $ 14.2
PRAM surcharge billed 53.5 29.6 48.8
Accrual of revenue under
the PRAM - Net (21.9) (16.3) --
BPA Residential Purchase and
Sale Agreement (25.3) 2.3 (15.0)
Sales to other utilities (8.0) 41.0 (6.8)
Revenue sold to conservation trust (25.1) -- --
Load and other changes 12.1 (2.4) 46.7
- ------------------------------------------------------------------------
Total operating revenue changes (14.7) 81.2 87.9
- ------------------------------------------------------------------------
Operating expenses
Purchased and interchanged power 14.8 77.1 81.5
Fuel (11.5) (5.5) (4.4)
Other operation expenses (38.7) 26.0 5.9
Maintenance 1.8 (2.5) (1.8)
Depreciation and amortization (8.2) 0.1 (7.2)
Taxes other than federal income taxes 1.7 7.2 6.1
Federal income taxes 4.3 (3.7) 11.5
- ------------------------------------------------------------------------
Total operating expense changes (35.8) 98.7 91.6
- ------------------------------------------------------------------------
Allowance for funds used during
construction ("AFUDC") 0.8 (0.8) 1.5
Other income (5.3) 1.0 (5.5)
Interest charges 0.9 1.0 (10.3)
- ------------------------------------------------------------------------
Net income changes $15.7 $(18.3) $ 2.6
========================================================================
The following information pertains to the changes outlined in the table
above:
Operating revenues
Revenues since October 1, 1995, increased as a result of rates authorized by
the Washington Utilities and Transportation Commission (the "Washington
Commission") under the fifth Periodic Rate Adjustment Mechanism ("PRAM")
filing. Revenues since October 1, 1994, increased as a result of rates
authorized by the Washington Commission under the fourth PRAM filing.
Revenues since October 1, 1993, increased as a result of rates authorized by
the Washington Commission in its general rate order issued on September 21,
1993. (See "Rate Matters.")
Revenues have been reduced by virtue of the credit that the Company received
through the Residential Purchase and Sale Agreement with the Bonneville
Power Administration ("BPA"). This agreement enables the Company's
residential and small farm customers to receive the benefits of lower-cost
federal power. A corresponding reduction is included in purchased and
interchanged power expenses.
Revenues since June 1995 have been reduced by $25.1 million as a result of
the
18
Company's sale of revenues associated with $202.5 million of its investment
in conservation assets to a grantor trust. The revenue decrease represents
the portion of rate revenues that were sold and forwarded to the trust. The
impact of this revenue decrease, however, was offset by related reductions
in other operation and interest expenses.(See "Other" for a discussion of
the sale of conservation assets.)
Although the Company is dependent on purchased power to meet customer
demand, it may, from time to time, have energy available for sale to other
utilities, depending principally upon water conditions for the generation of
hydroelectric power, customer usage and the energy requirements of other
utilities.
Operating expenses
Purchased and interchanged power expenses increased $14.8 million in 1995
when compared to 1994. Higher payments for firm power purchases from non-
utility generators and secondary power purchases from other utilities
contributed an increase of $35.4 million. This increase was partially
offset by increased credits associated with the Residential Purchase and
Sale Agreement with BPA of $24.1 million. (See discussion of the
Residential Purchase and Sale Agreement under "Operating revenues.") Also
contributing to the increase were higher payments of $2.7 million relating
to storage and interchange of electric power.
Purchased and interchanged power expenses increased $77.1 million in 1994
when compared to 1993. Higher payments related to new firm power purchase
contracts from non-utility generators contributed an increase of $89.3
million. Also contributing to the increase was a reduction in credits
associated with the Residential Purchase and Sale Agreement with BPA of $2.2
million. Partially offsetting these increases were lower secondary power
purchases from other utilities of $15.6 million.
Purchased and interchanged power expenses increased $81.5 million in 1993.
Purchased power expenses increased $95.8 million due primarily to new firm
power purchase contracts and higher secondary power purchases from other
utilities. This increase was partially offset by increased credits
associated with the Residential Purchase and Sale Agreement with BPA, which
resulted in a reduction of $14.4 million.
Fuel expense decreased $11.5 million in 1995 as the Company generated less
electricity at company-owned coal plants while purchasing more power on the
secondary market. Additionally, an Arbitration Panel's decision of a
dispute involving the coal supply agreement at the Company's fifty percent-
owned Colstrip 1 and 2 plants resulted in a $4.6 million decrease to fuel
expense in the first quarter of 1995 pertaining to coal deliveries from
August 1, 1991, through March 31, 1995.
Fuel expense decreased $5.5 million in 1994 as the Company purchased
additional power from cogeneration facilities rather than run Company-owned
gas turbines. Fuel expense decreased $4.4 million in 1993 due to decreased
use of the coal-fired plants.
Other operation expenses decreased $38.7 million in 1995 when compared to
1994. The decrease was due in part to charges in 1994 totaling $20.9
million associated with the Company's two voluntary early retirement and
separation programs and related business office and service facility
consolidations. (See Note 10 to the Consolidated Financial Statements.)
Also contributing to the decrease was lower amortization expense of $14.3
million associated with the Company's conservation program. In June 1995
the Company sold, to a grantor trust, approximately $202.5
19
million of its investment in customer-owned energy conservation measures.
(See discussion of the conservation asset transaction in "Other.")
Other operation expenses increased $26.0 million in 1994. Included in the
increase were charges totaling $20.9 million reflecting costs associated
with the Company's two voluntary early retirement and separation programs
and related business office and service facility consolidations. Also
included was an increase of $4.0 million in amortization expense associated
with the Company's energy conservation program and an increase of $1.8
million in transmission and distribution expenses.
Other operation expenses increased $5.9 million in 1993 due primarily to a
$5.1 million increase in the amortization of energy conservation
expenditures. Also influencing 1993 expenses was an increase of $1.8
million in steam generation expenses and a decrease of $2.3 million in
administration and general expenses.
Maintenance expense increased $1.8 million in 1995 over 1994 due primarily
to higher distribution maintenance expenses in the first and fourth quarters
of 1995 resulting from storm damage to Company transmission and distribution
facilities.
Maintenance expense in 1994 was lower by $2.5 million compared to 1993 due
primarily to a $4.4 million decrease in distribution maintenance expense.
This decrease was partially offset by a $1.3 million increase in
administration and general maintenance expense. Maintenance expense in 1993
declined $1.8 million compared to 1992 due primarily to a $2.2 million
decrease in distribution maintenance expense.
Depreciation and amortization expense decreased $8.2 million in 1995 from
1994 levels. A decrease of $12.9 million was attributable to the completion
in September 1994, of the 10 year amortization period related to two
terminated generating projects. This decrease was partially offset by the
effects of new plant placed into service.
Depreciation and amortization expense increased $0.1 million in 1994
compared to the prior year. Increased depreciation expense related to
additional plant placed into service was offset by the completion of the 10
year amortization period related to two terminated generating projects.
Depreciation and amortization expense declined $7.2 million in 1993. This
decrease was due to a change in depreciation rates approved by the
Washington Commission staff in the second quarter of 1993 that was made
retroactive to the beginning of 1993. This adjustment had the effect of
decreasing depreciation expense by $10.5 million during 1993. This
adjustment was partially offset by the effects of additional plant placed
into service.
Taxes other than federal income taxes increased $1.7 million in 1995
compared to 1994. Municipal and state excise tax payments increased $3.5
million and were partially offset by lower property tax payments of $0.8
million and other federal and state taxes of $1.0 million.
Taxes other than federal income taxes increased $7.2 million in 1994
compared to the prior year. Municipal and state excise taxes, which are
revenue-based, were higher by $4.5 million. Also contributing to the
increase were higher Washington and Montana state property tax payments of
$1.4 million. Taxes other than federal income taxes increased $6.1 million
in 1993 due primarily to higher excise and municipal tax payments.
Federal income taxes on operations increased $4.3 million in 1995 compared
to the prior year due primarily to higher pre-tax operating income during
1995.
20
Federal income taxes on operations decreased $3.7 million in 1994 compared
to 1993 due primarily to lower pre-tax operating income during 1994.
Federal income taxes on operations increased $11.5 million in 1993. The
increase was due in part to higher pre-tax operating income in 1993 and an
increase in the corporate tax rate from 34 to 35 percent, retroactive to
January 1, 1993. (See Note 12 to the Consolidated Financial Statements.)
AFUDC
(See Note 1 to the Consolidated Financial Statements.)
Other income
Total other income decreased $5.3 million in 1995. The decrease was due in
part to lower energy conservation expenditures resulting in a $2.2 million
decline in Allowance for Funds Used to Conserve Energy ("AFUCE") and a $1.4
million decrease in excess AFUDC over the Federal Energy Regulatory
Commission ("FERC") maximum allowed by the Washington Commission. Also
contributing to the decrease were higher non-utility expenses of $0.9
million when compared to 1994.
Other income increased $1.0 million in 1994 over 1993. Included was an
increase in subsidiary earnings of $2.2 million due primarily to an after-
tax gain of $1.9 million resulting from the sale of a small hydroelectric
generating project by the Company's Hydro Energy Development Corporation
subsidiary. Cash received from the sale, which totaled $30.1 million, is
recorded on the Statement of Cash Flows as "Cash received from subsidiary."
Other income decreased $5.5 million in 1993. The decrease was due in part
to a charge totaling $1.4 million as a result of the Washington Commission's
September 1993 general rate case ruling and a $1.4 million decrease in
excess AFUDC over the FERC maximum allowed by the Washington Commission.
Also contributing to the 1993 decrease was a non-recurring $2.3 million
decrease in non-operating federal income taxes in the second quarter of 1992
as a result of an IRS settlement.
Interest charges
Interest charges, which consist of interest and amortization on long-term
debt and other interest, increased $0.9 million in 1995 compared to 1994.
Interest and amortization on long-term debt alone decreased $3.0 million.
Contributing $4.3 million in reduced interest expense were five First
Mortgage Bond retirements or redemptions totaling $181 million over the
previous 23 months. Partially offsetting this was $1.3 million in new
interest expense associated with two issues of Secured Medium-Term Notes
totaling $85 million that were issued during the same period.
Other interest expense increased $3.9 million in 1995 over 1994. The
increase was the result of higher weighted average interest rates and higher
average daily short-term borrowings in 1995 as compared to 1994.
Interest charges increased $1.0 million in 1994 compared to 1993. Interest
and amortization on long-term debt alone decreased $1.9 million.
Contributing $8.1 million in reduced interest expense were eight First
Mortgage Bond and Secured Medium-Term Note retirements or redemptions
totaling $191 million over the previous 22 months. Partially offsetting
this was $6.4 million in new interest expense associated with nine issues of
Secured Medium-Term Notes totaling $169 million issued over the previous 23
months. Other interest expense increased $2.9 million in 1994 due to higher
average daily short-term borrowings and higher weighted average interest
rates in 1994 as compared to 1993.
21
Interest charges decreased $10.3 million in 1993 compared to 1992. Interest
and amortization on long-term debt alone decreased $3.5 million.
Contributing $29.1 million in reduced interest expense were 11 issues of
First Mortgage Bonds totaling $510 million redeemed or retired over the
previous 21 months. Partially offsetting this was $23.7 million in new
interest expense associated with 22 issues of Secured Medium-Term Notes
totaling $549 million issued over the previous 23 months. Other interest
expense decreased $6.8 million in 1993 compared to the prior year. Much of
the decrease was the result of a $5.3 million non-recurring interest charge
in 1992 relating to a federal income tax assessment. Also contributing were
lower average daily short-term borrowings and lower weighted average
interest rates in 1993.
CONSTRUCTION AND FINANCING PROGRAM
Current construction expenditures are primarily transmission and
distribution-related, designed to meet continuing customer growth.
Construction expenditures, which include energy conservation expenditures
and exclude AFUDC and AFUCE, were $128.1 million in 1995 and are expected to
be approximately $133.5 million in 1996 and $143.8 million in 1997. The
ratio of cash from operations (net of dividends, AFUDC and AFUCE) to
construction expenditures (excluding AFUDC and AFUCE) was 88.4% in 1995.
The Company expects cash from operations (net of dividends, AFUDC and AFUCE)
in 1996 and 1997 will, on average, be approximately 114% of average
estimated construction expenditures (excluding AFUDC and AFUCE) during the
same period.
In October 1992, the Company filed a shelf registration statement with the
Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to $450 million principal amount of First Mortgage
Bonds. The First Mortgage Bonds can be issued as Secured Medium-Term Notes,
through underwritten offerings, pursuant to delayed delivery contracts or
any combination thereof. These Secured Medium-Term Notes were designated
Series B. As of February 10, 1996, the Company has issued $364 million in
Series B Notes having an average coupon rate of 6.90%.
Short-term borrowings from banks and the sale of commercial paper are used
to provide working capital for the construction program. At December 31,
1995, the Company had in place $176.5 million in lines of credit with
several banks, which provided liquidity support for outstanding commercial
paper of $123.0 million, effectively reducing the available borrowing
capacity under these lines of credit to $53.5 million. (See Note 8 to the
Consolidated Financial Statements.)
RATE MATTERS
In the Washington Commission's September 21, 1993 general rate case order,
the Company was allowed a 10.5% return on common equity and 8.94% return on
rate base, based on a capital structure of 47% debt, 8% preferred stock and
45% common equity.
On September 22, 1995, the Washington Commission issued a rate order relating
to the Company's fifth annual rate adjustment under the PRAM. The Company
had requested a $62.8 million revenue increase and the Commission allowed
$58.8 million. The decrease included $3.3 million related to resource cost
projections that are subject to true-up during the PRAM period and a flow-
through to customers of $0.7 million related to tax benefits on the Company's
conservation expenditures. In addition to approval of the rate adjustment,
the Commission also agreed, pursuant to a negotiated settlement, to
discontinue the PRAM on September 30, 1996, the end of the current PRAM
period. Under the terms of the settlement agreement, PRAM accrued revenues
outstanding at that time will be recovered in
22
rates over a period not to exceed two years. With the discontinuance of the
PRAM, the annual regulatory adjustments for variations in weather and hydro
conditions provided for in the PRAM will also be discontinued.
The decrease in allowed return on common equity from 12.8% to 10.5% in the
last general rate case has put downward pressure on earnings since the order
became effective on October 1, 1993. In addition, it will be difficult for
the Company to earn its full allowed rate of return because of changes made
by the rate orders in the recovery methods of certain costs.
THE MERGER
On October 18, 1995, the Company entered into an Agreement and Plan of
Merger with Washington Energy Company ("WECO") and Washington Natural Gas
Company ("WNG"), a wholly owned subsidiary of WECO. The Merger has been
unanimously approved by the Company's Board of Directors as well as the
Board of Directors of WECO. Pursuant to the Agreement, WECO and WNG would
be merged with and into Puget Power, after which the merged company would be
renamed. (See Note 18 to the Consolidated Financial Statements.)
OTHER
The electric utility industry in general is facing a more competitive
environment, particularly in wholesale generation and industrial customer
markets. The National Energy Policy Act of 1992 ("EPACT") has intensified
competition in the wholesale electric market by easing restrictions on
wholesale power producers and by allowing the Federal Energy Regulatory
Commission ("FERC") to order access for wholesale sellers to deliver power
to wholesale buyers over transmission systems owned by others. FERC has
also initiated a rule making process regarding transmission access for
wholesale purposes, and has requested jurisdictional utilities, including
the Company, to file pro forma wholesale transmission tariffs providing
pricing and terms for such access. The EPACT does not permit the FERC to
order transmission access for retail purposes, but some states, including
California, Michigan and Massachusetts, are considering proposals which
would allow such access for retail purposes. In December 1994, the
Washington Commission issued a notice of inquiry seeking comments from
interested parties on the costs and benefits of increased retail
competition. In 1995, the Commission said it would take no action on
various proposals and instead issued an interim statement of principles.
Any substantial changes in utility regulation in Washington state, such as
mandating retail wheeling, would require legislative action. The major
credit rating agencies have expressed the general view that increased
competition is likely to increase business risks in the electric utility
industry, with resulting pressures on utility credit quality and investor
returns.
In this environment, the Company seeks to build on the strengths of its
efficient electric distribution and transmission system to become a leading
provider of energy and related services to homes and businesses in the
Pacific Northwest. To prepare for a more competitive business environment,
the Company has committed itself to being a low cost supplier of
electricity. The Company has taken steps to reduce costs, including work
force reductions, facility consolidations and reductions in capital budgets.
The Company intends to pursue opportunities for improved operating
efficiencies and productivity, including possible restructuring of its power
supply resources and contracts. The Company is also actively pursuing
opportunities to become a provider of new high value services such as
wireless automated meter-based services and geographic information systems,
to utility customers and other utilities.
The Company and BPA have entered into a letter of intent, subject to various
23
conditions, regarding pursuit of construction of a joint transmission
project in Whatcom and Skagit counties in northern Washington state, the
northernmost portion of the Company's service territory. The joint project
is intended to provide the Company and BPA with certain transfer capacity
with Canadian utilities and is intended to relieve certain transmission
constraints on the respective systems of BPA and the Company. The joint
project, which is expected to be completed in late 1997, will involve a
combination of existing facility upgrades and new construction.
The Company's energy conservation expenditures have historically been
accumulated, included in rate base and amortized to expense over a ten year
period at the direction of the Washington Commission. In June 1995 the
Company sold approximately $202.5 million of its investment in customer-
owned energy conservation measures to a grantor trust, which, in turn,
issued securities backed by a Washington state statute enacted in 1994. The
statute provides that if certain conditions are met, securities could be
issued, backed by a statutory requirement that a portion of rate revenues be
forwarded to the trust to repay those securities. The proceeds of the sale
were used to pay down short-term debt. The securities were issued in June
1995 and carry a coupon rate of 6.45 percent. The Company recognized no
gain or loss on the sale.
The Company is in the process of selectively replacing the High Molecular
Weight ("HMW") underground distribution cable installed during the 1960s and
1970s. The Company installed about 4,800 miles of industrial standard HMW
cable between 1964 and 1979, but the Company and other utilities have
experienced increasing cable failures in recent years. The Company is
continuing to analyze cable failure trends to find ways to mitigate the
effect of cable failures on customer service. To minimize the impact on
customers of increasing cable failures, the Company replaces a certain
amount of HMW cable each year and is beginning to use silicone injection
into potentially problem cables to lengthen the life of these cables. The
Company so far has replaced 600 miles of HMW cable and expects to spend $43
million on additional cable replacement during the period 1996-1999. In
1996 the Company is planning either to replace or use silicone injection on
150 miles of HMW cable.
For a discussion of Financial Accounting Standards Board ("FASB") Statement
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to be Disposed Of", issued in March 1995, see Note 1 to the
Consolidated Financial Statements.
For a discussion of FASB Statement No. 123, "Accounting for Stock-Based
Compensation", issued in October 1995, see Note 1 to the Consolidated
Financial Statements.
For a discussion of environmental obligations, see Note 15 to the
Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See index on page 30.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE - NONE.
24
PART III
Part III is incorporated by reference from the Company's definitive
proxy statement issued in connection with the 1995 Annual Meeting of
Shareholders.
Certain information regarding executive officers is set forth in Part I.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1) Financial statement schedule - see index on page 30.
2) Exhibits - see index on page 60.
(b) Reports on Form 8-K:
1) Form 8-K dated October 23, 1995, Item 5 - Other Events,
related to merger agreement between Puget Sound Power & Light
Company and Washington Energy Company.
25
SIGNATURES
Pursuant to the requirements of Section 13 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.
PUGET SOUND POWER & LIGHT COMPANY
By R. R. Sonstelie
--------------------------------------
R. R. Sonstelie
President and Chief Executive Officer
Date: February 27, 1996
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
- ------------------------ ------------------------- --------------
R. R Sonstelie President and
- ------------------------ Chief Executive Officer
(R. R. Sonstelie) and Director
William S. Weaver Executive Vice President and
- ------------------------ Chief Financial Officer
(William S. Weaver) and Director
February 27, 1996
James W. Eldredge Corporate Secretary
- ------------------------ and Controller and
(James W. Eldredge) Chief Accounting Officer
Douglas P. Beighle Director
- ------------------------
(Douglas P. Beighle)
Charles W. Bingham Director
- ------------------------
(Charles W. Bingham)
26
Signatures, continued
Director
- ------------------------
(Phyllis J. Campbell)
John D. Durbin Director
- ------------------------
(John D. Durbin)
John W. Ellis Director
- ------------------------
(John W. Ellis)
Daniel J. Evans Director
- ------------------------
(Daniel J. Evans)
Nancy L. Jacob Director
- ------------------------
(Nancy L. Jacob)
R. Kirk Wilson Director
- ------------------------
(R. Kirk Wilson)
27
Puget Sound Power & Light Company
Report of Management: February 27, 1996
The accompanying consolidated financial statements of Puget Sound Power &
Light Company have been prepared under the direction of management, which is
responsible for their integrity and objectivity. The statements have been
prepared in accordance with generally accepted accounting principles and
include amounts based on judgments and estimates by management where
necessary. Management also prepared the other information in the Annual
Report on Form 10-K and is responsible for its accuracy and consistency with
the financial statements.
The Company maintains a system of internal control which, in management's
opinion, provides reasonable assurance that assets are properly safeguarded
and transactions are executed in accordance with management's authorization
and properly recorded to produce reliable financial records and reports. The
system of internal control provides for appropriate division of
responsibility and is documented by written policy and updated as necessary.
The Company's internal audit staff assesses the effectiveness and adequacy of
the internal controls on a regular basis and recommends improvements when
appropriate. Management considers the internal auditor's and independent
auditor's recommendations concerning the Company's internal controls and
takes steps to implement those that they believe are appropriate in the
circumstances.
In addition, Coopers & Lybrand L.L.P., the independent auditors, have
performed audit procedures deemed appropriate to obtain reasonable assurance
about whether the financial statements are free of material misstatement.
The Board of Directors pursues its oversight role for the financial
statements through the audit committee, which is composed solely of outside
Directors. The audit committee meets regularly with management, the internal
auditors and the independent auditors, jointly and separately, to review
management's process of implementation and maintenance of internal accounting
controls and auditing and financial reporting matters. The internal and
independent auditors have unrestricted access to the audit committee.
R. R. Sonstelie William S. Weaver James W. Eldredge
____________________ _______________________ _______________________
R. R. Sonstelie William S. Weaver James W. Eldredge
President and Executive Vice President Corporate Secretary
Chief Executive Officer and Chief Financial Officer and Controller
(Chief Accounting Officer)
28
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of
Puget Sound Power & Light Company
We have audited the consolidated financial statements and the financial
statement schedule of Puget Sound Power & Light Company listed on page 30 of
this Annual Report on Form 10-K. These financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Puget Sound
Power & Light Company as of December 31, 1995 and 1994, and the consolidated
results of its operations and its cash flows for each of the three years in
the period ended December 31, 1995 in conformity with generally accepted
accounting principles. In addition, in our opinion, the financial statement
schedule referred to above, when considered in relation to the basic
financial statements taken as a whole, presents fairly, in all material
respects, the information required to be included therein.
/s/ Coopers & Lybrand L.L.P.
Seattle, Washington
February 12, 1996
29
PUGET SOUND POWER & LIGHT COMPANY
CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
COVERED BY THE FOREGOING REPORT OF INDEPENDENT ACCOUNTANTS
CONSOLIDATED FINANCIAL STATEMENTS: Page
Consolidated Statements of Income for the years ended
December 31, 1995, 1994 and 1993.......................................31
Consolidated Balance Sheets, December 31, 1995 and 1994..................32
Consolidated Statements of Capitalization, December 31, 1995 and 1994....34
Consolidated Statements of Earnings Reinvested in the Business
for the years ended December 31, 1995, 1994 and 1993...................35
Consolidated Statements of Cash Flows for the years
ended December 31, 1995, 1994 and 1993.................................36
Notes to Consolidated Financial Statements...............................37
SCHEDULE:
II. Valuation and Qualifying Accounts and Reserves for the
years ended December 31, 1995, 1994 and 1993.......................59
All other schedules have been omitted because of the absence of the
conditions under which they are required, or because the information
required is included in the financial statements or the notes thereto.
Financial statements of the Company's subsidiaries are not filed herewith
inasmuch as the assets, revenues, earnings and earnings reinvested in the
business of the subsidiaries are not material in relation to those of the
Company.
30
Consolidated Statements of Income
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
Year Ended December 31 1995 1994 1993
- --------------------------------------------------------------------------------------------
(Dollars in thousands except per share amounts.)
Operating Revenues $1,179,330 $1,194,058 $1,112,878
- --------------------------------------------------------------------------------------------
Operating Expenses:
Operation (Note 15):
Purchased and interchanged power 409,541 394,758 317,642
Fuel 35,658 47,166 52,654
Other (Notes 10 and 11) 164,735 203,476 177,444
Maintenance 53,148 51,342 53,900
Depreciation and amortization 107,582 115,738 115,690
Taxes other than federal income taxes (Note 10) 109,533 107,821 100,598
Federal income taxes (Note 12) 84,545 80,259 83,970
- --------------------------------------------------------------------------------------------
Total operating expenses 964,742 1,000,560 901,898
- --------------------------------------------------------------------------------------------
Operating Income 214,588 193,498 210,980
- --------------------------------------------------------------------------------------------
Other Income:
Allowance for funds used during
construction - equity portion 719 530 2,301
Miscellaneous (Notes 10 and 12) 6,957 12,290 11,277
- --------------------------------------------------------------------------------------------
Total other income - net 7,676 12,820 13,578
- --------------------------------------------------------------------------------------------
Income Before Interest Charges 222,264 206,318 224,558
- --------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 77,224 80,213 82,065
Allowance for funds used during
construction - debt portion (4,292) (3,667) (2,714)
Other interest 9,722 5,782 2,915
Amortization of debt expense,
net of premium (Note 7) 3,890 3,931 3,965
- --------------------------------------------------------------------------------------------
Total interest charges 86,544 86,259 86,231
- --------------------------------------------------------------------------------------------
Net Income 135,720 120,059 138,327
- --------------------------------------------------------------------------------------------
Less Preferred Stock Dividend Accruals 15,528 15,731 16,442
- --------------------------------------------------------------------------------------------
Income for Common Stock $ 120,192 $ 104,328 $ 121,885
- --------------------------------------------------------------------------------------------
Common shares outstanding weighted average 63,640,861 63,632,057 60,930,859
Earnings per common share (Note 1) $ 1.89 $ 1.64 $ 2.00
============================================================================================
The accompanying notes are an integral part of the financial statements.
31
Consolidated Balance Sheets
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
Assets
December 31 1995 1994
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
Utility Plant:
Electric plant, at original cost (Notes 1, 2, 7 and 15) $3,400,723 $3,306,854
Less: Accumulated depreciation 1,118,678 1,039,943
- --------------------------------------------------------------------------------------------
Net utility plant 2,282,045 2,266,911
- --------------------------------------------------------------------------------------------
Other Property and Investments:
Investment in Bonneville Exchange Power Contract 94,241 101,309
Investment in and advances to subsidiaries 95,459 76,517
Energy conservation loans to customers 783 1,409
Other investments, at cost 11,328 12,203
- --------------------------------------------------------------------------------------------
Total other property and investments 201,811 191,438
- --------------------------------------------------------------------------------------------
Current Assets:
Cash (Note 9) 12,498 5,284
- --------------------------------------------------------------------------------------------
Accounts receivable:
Customers 90,345 80,503
Other 34,627 27,695
Less allowance for doubtful accounts 886 610
- --------------------------------------------------------------------------------------------
Total accounts receivable 124,086 107,588
- --------------------------------------------------------------------------------------------
Estimated unbilled revenue 80,363 86,745
PRAM accrued revenues 59,123 47,178
Materials and supplies, at average cost 46,407 49,543
Prepayments and Other 4,352 5,260
- --------------------------------------------------------------------------------------------
Total current assets 326,829 301,598
- --------------------------------------------------------------------------------------------
Long-Term Assets:
Regulatory asset for deferred income taxes (Note 12) 249,731 275,296
PRAM accrued revenues (net of current portion) 55,673 63,663
Unamortized debt expense 10,264 8,076
Unamortized energy conservation charges 37,889 239,500
Other 104,753 117,288
- --------------------------------------------------------------------------------------------
Total long-term assets 458,310 703,823
- --------------------------------------------------------------------------------------------
Total Assets $3,268,995 $3,463,770
============================================================================================
The accompanying notes are an integral part of the financial statements.
32
- --------------------------------------------------------------------------------------------
Capitalization and Liabilities
December 31 1995 1994
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
Capitalization (See "Consolidated Statements of Capitalization"):
Common equity $1,175,904 $1,172,729
Preferred stock not subject to mandatory redemption 125,000 125,000
Preferred stock subject to mandatory redemption 89,039 91,242
Long-term debt 920,439 963,298
- --------------------------------------------------------------------------------------------
Total capitalization 2,310,382 2,352,269
- --------------------------------------------------------------------------------------------
Current Liabilities:
Accounts payable 50,269 58,025
Short-term debt (Notes 8 and 9) 167,049 234,454
Current maturities of long-term debt (Note 7) 43,000 108,000
Accrued expenses:
Taxes 36,321 40,337
Salaries and wages 22,011 20,809
Interest 22,921 26,181
Other 27,356 25,018
- --------------------------------------------------------------------------------------------
Total current liabilities 368,927 512,824
- --------------------------------------------------------------------------------------------
Deferred Income Taxes:
Deferred income taxes (Note 12) 528,400 541,501
Investment tax credits 311 726
- --------------------------------------------------------------------------------------------
Total deferred income taxes 528,711 542,227
- --------------------------------------------------------------------------------------------
Other Deferred Credits:
Customer advances for construction 19,972 21,939
Other 41,003 34,511
- --------------------------------------------------------------------------------------------
Total other deferred credits 60,975 56,450
- --------------------------------------------------------------------------------------------
Commitments and Contingencies
(Notes 1, 11, 12, 13, 14, 15 and 18) -- --
Total Capitalization and Liabilities $3,268,995 $3,463,770
============================================================================================
The accompanying notes are an integral part of the financial statements.
33
Consolidated Statements of Capitalization
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
December 31 1995 1994
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
Common Equity:
Common stock - ($10 stated value) - 80,000,000 shares
authorized, 63,640,861 shares
outstanding (Notes 3 and 14) $ 636,409 $636,409
Additional paid-in capital (Notes 5 and 14) 328,963 328,753
Earnings reinvested in the business (Note 6) 210,532 207,567
- --------------------------------------------------------------------------------------------
Total common equity 1,175,904 1,172,729
- --------------------------------------------------------------------------------------------
Preferred Stock Not Subject to Mandatory
Redemption - cumulative (Note 3):
$25 par value:*
7.875% series - 3,000,000 shares authorized and outstanding 75,000 75,000
Adjustable Rate, Series B - 2,000,000 shares authorized
and outstanding 50,000 50,000
- --------------------------------------------------------------------------------------------
Total preferred stock not subject to mandatory redemption 125,000 125,000
- --------------------------------------------------------------------------------------------
Preferred Stock Subject To Mandatory Redemption - cumulative
(Notes 4 and 9):
$100 par value:*
4.84% series - 150,000 shares authorized,
47,956 shares outstanding 4,796 4,796
4.70% series - 150,000 shares authorized,
56,215 and 66,215 shares outstanding 5,621 6,621
8% series - 150,000 shares authorized,
36,224 and 48,253 shares outstanding 3,622 4,825
7.75% series - 750,000 shares authorized and outstanding 75,000 75,000
- --------------------------------------------------------------------------------------------
Total preferred stock subject to mandatory redemption 89,039 91,242
- --------------------------------------------------------------------------------------------
Long-Term Debt (Notes 7 and 9):
First mortgage bonds 794,000 894,000
Guaranteed collateralized bonds 8,000 16,000
Pollution control revenue bonds:
Revenue refunding 1991 series, due 2021 50,900 50,900
Revenue refunding 1992 series, due 2022 87,500 87,500
Revenue refunding 1993 series, due 2020 23,460 23,460
Other notes 21 24
Unamortized discount - net of premium (442) (586)
Long-term debt due within one year (43,000) (108,000)
- --------------------------------------------------------------------------------------------
Total long-term debt excluding current maturities 920,439 963,298
- --------------------------------------------------------------------------------------------
Total Capitalization $2,310,382 $2,352,269
============================================================================================
* 13,000,000 shares authorized for $25 par value preferred stock
and 3,000,000 shares authorized for $100 par value preferred stock.
The accompanying notes are an integral part of the financial statements.
34
Consolidated Statements of Earnings Reinvested in the Business
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
Year Ended December 31 1995 1994 1993
- --------------------------------------------------------------------------------------------
(Dollars in thousands except per share amounts.)
Balance at Beginning of Year $207,567 $220,259 $210,544
Net Income 135,720 120,059 138,327
- --------------------------------------------------------------------------------------------
Total 343,287 340,318 348,871
- --------------------------------------------------------------------------------------------
Deductions:
Dividends Declared:
Preferred stock:
$4.84 per share on 4.84% series 232 242 252
$4.70 per share on 4.70% series 276 319 327
$8.00 per share on 8% series 314 410 495
$7.75 per share on 7.75% series 5,813 5,813 5,813
$1.97 per share on 7.875% series 5,906 5,906 5,906
Adjustable Rate, Series A -- 700 2,800
Adjustable Rate, Series B 3,115 2,277 --
Flexible Dutch Auction Rate Transferable
Securities Series B (Note 3): -- -- 912
Common stock 117,099 117,084 111,498
Loss on reacquisition of preferred stock -- -- 609
- --------------------------------------------------------------------------------------------
Total deductions 132,755 132,751 128,612
- --------------------------------------------------------------------------------------------
Balance at End of Year (Note 6) $210,532 $207,567 $220,259
Dividends declared per common share $ 1.84 $ 1.84 $ 1.83
============================================================================================
The accompanying notes are an integral part of the financial statements.
35
Consolidated Statements of Cash Flows
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
Year Ended December 31 1995 1994 1993
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
Operating Activities:
Net income $135,720 $120,059 $138,327
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 107,582 115,738 115,690
Deferred income taxes and tax credits - net 12,049 17,762 30,149
Equity portion of AFUDC (719) (530) (2,301)
PRAM accrued revenues (3,955) (25,835) (42,100)
Other 18,597 37,813 (15,079)
Change in certain current assets and
liabilities (Note 17) (17,564) (5,979) 9,645
- --------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 251,710 259,028 234,331
- --------------------------------------------------------------------------------------------
Investing Activities:
Construction expenditures - excluding equity AFUDC (119,294) (213,982) (156,123)
Additions to energy conservation program (15,156) (36,648) (64,027)
Decrease in energy conservation loans 626 875 1,688
Cash received from subsidiary -- 30,136 --
Cash received from sale of conservation assets - net 199,452 -- --
Other (including advances to subsidiaries) 76 (8,116) (438)
- ---------------------------------------------------------------------------------------------
Net Cash Provided (Used) by Investing Activities 65,704 (227,735) (218,900)
- ---------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in short-term debt (67,405) 85,148 58,856
Dividends paid (net of newly issued shares
totaling $239,000 in 1994
and $25,658,000 in 1993) (132,755) (132,513) (102,345)
Issuance of common and preferrred stock
(Notes 3, 4 and 5) -- 50,000 113,377
Issuance of bonds (Note 7) -- 85,000 107,460
Redemption of bonds and notes (108,004) (73,014) (255,472)
Redemption of preferred stock (1,993) (41,865) (50,643)
Issue costs of bonds and stock (43) (2,210) (4,325)
- ---------------------------------------------------------------------------------------------
Net Cash Used by Financing Activities (310,200) (29,454) (133,092)
Increase (decrease) in Cash 7,214 1,839 (117,661)
Cash at Beginning of Year 5,284 3,445 121,106
- ---------------------------------------------------------------------------------------------
Cash at End of Year $ 12,498 $ 5,284 $ 3,445
=============================================================================================
The accompanying notes are an integral part of the financial statements.
36
Puget Sound Power & Light Company
Notes To Consolidated Financial Statements
- -------------------------------------------------------------------------
1) Summary of Significant Accounting Policies
Significant accounting policies are described below.
Basis of Presentation:
Puget Sound Power & Light Company ("the Company") is an investor-owned
public utility incorporated in the State of Washington furnishing electric
service in a territory covering approximately 4,500 square miles,
principally in the Puget Sound region of Washington state.
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiary, Puget Energy, Inc. ("Puget Energy").
Guaranteed Collateralized Bonds were issued by Puget Energy and the net
proceeds from the sale of bonds were advanced to the Company (see Note 7).
Puget Energy has no independent operations. Investments in all other
subsidiaries are stated on an equity basis inasmuch as the assets, revenues,
earnings and earnings reinvested in the business of the subsidiaries are not
material in relation to those of the Company.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Utility Plant:
The costs of additions to utility plant, including renewals and betterments,
are capitalized at original cost. Costs include indirect costs such as
engineering, supervision, certain taxes and pension and other benefits, and
an allowance for funds used during construction. Replacements of minor
items of property are included in maintenance expense. The original cost of
operating property together with removal cost, less salvage, is charged to
accumulated depreciation when the property is retired and removed from
service.
Accounting for Regulatory Assets:
The Company prepares its financial statements in accordance with Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" ("Statement No. 71"). Statement No. 71
requires the Company to defer certain costs that would otherwise be charged
to expense, if it is probable that future rates will permit recovery of such
costs. Accounting under Statement No. 71 is appropriate as long as: rates
are established by or subject to approval by independent, third-party
regulators; rates are designed to recover the specific enterprise's cost-of-
service; and in view of demand for service, it is reasonable to assume that
rates set at levels that will recover costs can be charged to and collected
from customers. In applying Statement No. 71, the Company must give
consideration to changes in the level of demand or competition during the
cost recovery period. In accordance with Statement No. 71, the Company
capitalizes certain costs in accordance with regulatory authority whereby
those costs will be expensed and recovered in future periods.
37
Net regulatory assets at December 31, 1995 and 1994 included the following:
(Dollars in Millions)
1995 1994
Deferred income taxes $249.7 $275.3
PRAM accrued revenues 114.8 110.8
Investment in BEP Exchange Contract 94.2 101.3
Unamortized energy conservation charges 37.9 239.5
Various other costs 96.8 101.4
Total $593.4 $828.3
If the Company, at some point in the future, determines that all or a
portion of the utility operations no longer meets the criteria for continued
application of Statement No. 71, the Company would be required to adopt the
provisions of Statement of Financial Accounting Standards No. 101,
"Regulated Enterprises - Accounting for the Discontinuation of Application
of FASB Statement No. 71." Adoption of Statement No. 101 would require the
Company to write off the regulatory assets and liabilities related to those
operations not meeting Statement No. 71 requirements.
The Company, in prior years, incurred costs associated with it's 5% interest
in a now terminated nuclear generating project (identified herein as
"Investment in Bonneville Exchange Power ("BEP")"). Under terms of a
settlement agreement with the Bonneville Power Administration ("BPA"), which
settled claims of the Company relating to construction delays associated
with that project, the Company is receiving, over 30.5 years, power from the
federal power system resources marketed by BPA. Approximately two-thirds of
the Company's Investment in BEP is included in rate base and amortized on a
straight-line basis over the life of the contract (amortization is included
in "Purchased and interchanged power"). The remainder of the Company's
investment is being recovered in rates over ten years, without a return
during the recovery period (the related amortization is included in
"Depreciation and amortization", pursuant to a FERC accounting order).
Operating Revenues:
Operating revenues are recorded on the basis of service rendered, which
include estimated unbilled revenue and revenue accrued under the Periodic
Rate Adjustment Mechanism ("PRAM").
Energy Conservation:
The Company accumulates energy conservation expenditures which are included
in rate base and amortized to expense over a ten-year period when authorized
by the Washington Utilities and Transportation Commission ("Washington
Commission").
In June 1995, the Company sold approximately $202.5 million of its
investment in customer-owned energy conservation measures to a grantor trust
which, in turn, issued securities backed by a Washington state statute
enacted in 1994. The statute provides that if certain conditions are met,
securities could be issued, backed by a statutory requirement that a portion
of rate revenues be forwarded to the trust to repay those securities. The
proceeds of the sale were used to pay down short-term debt. The securities
were issued by the trust in June 1995, and carry a coupon rate of 6.45
percent. The Company recognized no gain or loss on the sale. After the
sale, the Company's total remaining unamortized conservation
balance at December 31, 1995 was $38 million.
38
Self-Insurance:
Prior to October 1, 1993, provision was made for uninsured storm damage,
comprehensive liability, industrial accidents and catastrophic property
losses, with the approval of the Washington Commission, on the basis of the
amount of outside insurance in effect and historical losses. To the extent
actual costs varied from the provision, the difference was deferred for
incorporation into future rates.
In its September 21, 1993 order, the Washington Commission terminated,
prospectively, the provision for deferral of uninsured storm damage except
for certain losses associated with major storms. The order also terminated
the provision for deferral of other uninsured losses retroactively,
resulting in an after-tax write-off in 1993 of $2.0 million. At December
31, 1995, the Company had no insurance coverage for storm damage and is self-
insured for a portion of the risk associated with comprehensive liability,
industrial accidents and catastrophic property losses. The amount of
uninsured storm damage costs deferred under the regulatory treatment
approved by the Washington Commission at December 31, 1995 was $27.3
million, which includes $6.0 million of costs deferred as a result of a
severe windstorm on December 12, 1995.
Depreciation and Amortization:
For financial statement purposes, the Company provides for depreciation on a
straight-line basis. The depreciation of automobiles, trucks, power
operated equipment and tools is allocated to asset and expense accounts
based on usage.
With the Washington Commission's approval, the Company reduced its
depreciation rates in 1993. This adjustment had the effect of reducing
depreciation expense by $10.5 million during 1993. The annual depreciation
provision stated as a percent of average original cost of depreciable
utility plant was 3.0% in 1995 and 1994, and 3.1% in 1993.
The Company's investments in terminated generating projects were amortized
on a straight-line basis over the ten year period ending in 1994 (included
in operating expenses under "Depreciation and amortization").
Amounts recoverable through rates related to investments in terminated
generating projects and the Bonneville Exchange Power Contract were adjusted
to their present value in prior years in accordance with Statement of
Financial Accounting Standards No. 90 ("Statement No. 90"). These
adjustments result in reduced net amortization expense over the recovery
periods, the effect of which is included in miscellaneous income in the
amount, net of federal income tax expense, of $1.3 million, $1.8 million and
$2.7 million for 1995, 1994 and 1993, respectively.
Federal Income Taxes:
The Company normalizes, with the approval of the Washington Commission,
certain items. Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 109. (See Note 12.)
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. The amount of AFUDC recorded in
each accounting period
varies depending principally upon the level of construction work in progress
and
39
the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility
plant and is credited as a non-cash item to other income and interest
charges currently. Cash inflow related to AFUDC does not occur until these
charges are reflected in rates.
The AFUDC rate allowed by the Washington Commission is the Company's
authorized rate of return, which was 10.16% effective October 1, 1991 and
8.94% effective October 1, 1993. To the extent amounts calculated using
this rate exceed the AFUDC calculated using the Federal Energy Regulatory
Commission ("FERC") formula, the Company capitalizes the excess as a
deferred asset, crediting miscellaneous income. The amounts included in
income were: $1,614,000 for 1995; $3,016,000 for 1994; and $2,309,000 for
1993. The deferred asset is being amortized over the average useful life of
the Company's non-project utility plant.
Allowance For Funds Used to Conserve Energy:
The Washington Commission has authorized the Company to capitalize, as part
of energy conservation costs, related carrying costs calculated at a rate
established by the Washington Commission. This Allowance for Funds Used to
Conserve Energy ("AFUCE") has been credited as a non-cash item to
miscellaneous income in the amount of $1,463,000 in 1995, $3,317,000 in
1994, and $4,276,000 in 1993. Cash inflow related to AFUCE occurs when
these charges are reflected in rates, or when the underlying asset is sold
to a third party.
Periodic Rate Adjustment Mechanism:
In April 1991, the Washington Commission issued an order establishing a PRAM
designed to operate as an interim rate adjustment mechanism between tri-
annual general rate cases. Under the PRAM, the Company is allowed to
request annual rate adjustments, on a prospective basis, to reflect changes
in certain costs as set forth in the PRAM order. Also, under terms of the
order, recovery of certain costs is decoupled from levels of electricity
sales.
Rates established for the PRAM period are subject to future adjustment based
on actual customer growth and variations in certain costs, principally those
affected by hydro and weather conditions. To the extent revenue billed to
customers varies from amounts allowed under the methodology established in
the PRAM order, the difference is accumulated, without interest, for rate
recovery which will be established in the next PRAM hearing. In its
September 22, 1995 order, the Washington Commission approved the Company's
latest PRAM filing and the recovery of $71.2 million over the period October
1, 1995 through September 30, 1996. In addition to approval of the rate
adjustment, the Commission also agreed, pursuant to a negotiated settlement,
to discontinue the PRAM on September 30, 1996, the end of the current PRAM
period. Under the terms of the settlement, PRAM accrued revenues at that
time would be recovered in rates over a period not to exceed two years.
PRAM accrued revenues of approximately $114.8 million were recorded at
December 31, 1995 under this methodology. Amounts expected to be collected
within one year have been included in current assets.
Other:
Debt premium, discount and expenses are amortized over the life of the
related debt.
In March 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
("Statement No. 121").
40
Statement No. 121 requires that long-lived assets and certain intangibles be
reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount of the asset may not be recoverable. If impairment
has occurred, an impairment loss must be recognized. Implementation of
Statement No. 121 is required in 1996. Based on estimates by management as
of December 31, 1995, the impact of the adoption of this standard is not
expected to be material to the financial position, results of operations, or
liquidity of the Company.
In October 1995, the FASB issued Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation" ("Statement No. 123").
Statement No. 123 establishes a fair value based method of accounting for
stock-based compensation plans and encourages entities to adopt that method
in place of the provisions of Accounting Principles Board Opinion No. 25
("APB 25"). The Company intends to continue to apply the provisions of APB
25 in recognizing compensation expense related to its stock-based
compensation plans.
Earnings Per Common Share:
Earnings per common share have been computed based on the weighted average
number of common shares outstanding.
2) Property Plant and Equipment
- ----------------------------------------------------------------------------
December 31 1995 1994
- ----------------------------------------------------------------------------
(Dollars in Thousands)
Electric utility plant classified by prescribed
accounts at original cost:
Intangible plant $ 38,786 $ 36,458
Production plant 905,047 897,139
Transmission plant 521,810 499,016
Distribution plant 1,571,037 1,513,264
General plant 241,533 246,351
Construction work in progress 105,617 94,067
Plant held for future use 15,644 19,310
Acquisition adjustments 1,249 1,249
- ----------------------------------------------------------------------------
Total electric utility plant 3,400,723 $3,306,854
============================================================================
41
3) Capital Stock
Preferred Stock Preferred Stock
Not Subject to Subject to Common
Mandatory Redemption Mandatory Redemption Stock
- --------------------------------------------------------------------------------------------
Without
Par Value
$25 Par $100 Par $100 Par ($10 Stated
Value Value Value Value)
- --------------------------------------------------------------------------------------------
Shares outstanding
January 1, 1993 3,000,000 900,000 938,222 58,574,633
Sold to Public:
1993 -- -- -- 3,450,000
1994 2,000,000 -- -- --
Issued to trustee of
employee investment plan:
1993 -- -- -- 130,009
Issued to shareholders under
the stock purchase and
dividend reinvestment plan:
1993 -- -- -- 1,474,774
1994 -- -- -- 11,445
Acquired for sinking fund:
1993 -- -- (6,459) --
1994 -- -- (19,339) --
1995 -- -- (22,029) --
Called for redemption
and cancelled:
1993 -- (500,000) -- --
1994 -- (400,000) -- --
- --------------------------------------------------------------------------------------------
Shares outstanding
December 31, 1995 5,000,000 -- 890,395 63,640,861
============================================================================================
See "Consolidated Statements of Capitalization" for details on specific
series.
On January 15, 1991, the Board of Directors declared a dividend of one
preference share purchase right (a "Right") on each outstanding common share
of the Company. The dividend was distributed on January 25, 1991, to
shareholders of record on that date. The Rights will be exercisable only if
a person or group acquires 10 percent or more of the Company's common stock
or announces a tender offer which, if consummated, would result in ownership
by a person or group of 10 percent or more of the common stock. Each Right
entitles the registered holder to purchase from the Company one one-
thousandth of a share of Preference Stock, $50 par value per share, at an
exercise price of $45, subject to adjustments. The description and terms of
the Rights are set forth in a Rights Agreement between the Company and The
Bank of New York, as Rights Agent. The Rights expire on January 25, 2001,
unless earlier redeemed by the Company. On October 18, 1995, the Company's
Board of Directors approved an amendment to the Rights Agreement which
precludes the
42
merger with Washington Energy Company from triggering any rights under the
Rights Agreement.
On February 3, 1994, the Company issued $50 million, Adjustable Rate
Cumulative Preferred Stock ("ARPS"), Series B ($25 par value). The proceeds
were used to retire the $40 million principal amount of its ARPS Series A
($100 par value). The weighted average dividend rate for the ARPS Series B
was 6.05% for 1995 and 5.93% for 1994. The weighted average dividend rate
for the ARPS Series A was 7.00% in the first two months of 1994 and 7.00%
for 1993.
For each quarterly period, dividends on the ARPS Series B, determined in
advance of such period, will be set at 83% of the highest of three interest
rates as defined in the Statement of Relative Rights and Preferences for
ARPS Series B. The dividend rate for any dividend period will in no event
be less than 4% per annum or greater than 10% per annum. The Company may
redeem the ARPS Series B at any time on not less than 30 days notice at
$27.50 per share on or prior to February 1, 1999, and at $25 per share
thereafter, plus in each case accrued dividends to the date of redemption;
provided however, that no shares shall be redeemed prior to February 1,
1999, if such redemption is for the purpose or in anticipation of refunding
such share at an effective interest or dividend cost to the Company of less
than 5.37% per annum.
4) Preferred Stock Subject to Mandatory Redemption
The Company is required to deposit funds annually in a sinking fund
sufficient to redeem the following number of shares of each series of
preferred stock at $100 per share plus accrued dividends: 4.84% Series and
4.70% Series, 3,000 shares each; 8% Series, 6,000 and 1,000 shares through
2003 and 2004, respectively; and 7.75% Series, 37,500 shares on each
February 15, commencing on February 15, 1998. Previous requirements have
been satisfied by delivery of reacquired shares. At December 31, 1995,
there were 12,044 shares of the 4.84% Series, 9,785 shares of the 4.70%
Series and 776 shares of the 8% Series acquired by the Company and available
for future sinking fund requirements. Upon involuntary liquidation, all
preferred shares are entitled to their par value plus accrued dividends.
The preferred stock subject to mandatory redemption (see Note 3) may also be
redeemed by the Company at the following redemption prices per share plus
accrued dividends: 4.84% Series, $102; 4.70% Series, $101; and 8% Series,
$101. The 7.75% Series may be redeemed by the Company, subject to certain
restrictions, at $105.68 per share plus accrued dividends through February
15, 1997 and at per share amounts which decline annually to a price of $100
after February 15, 2007.
43
5) Additional Paid-in Capital
1995 1994 1993
- ------------------------------------------------------------------------------
(Dollars in Thousands)
Balance at beginning of year $328,753 $329,922 $243,874
Excess of proceeds over stated values of:
Common stock issued to trustee of
employee investment plan -- -- 2,234
Common stock issued under the
stock purchase and
dividend reinvestment plan -- 124 24,584
Common stock sold to the public -- -- 61,669
Par value over cost of reacquired
preferred stock 210 68 612
Issue costs of common stock -- -- (3,035)
Issue costs of preferred stock -- (1,361) (16)
- ------------------------------------------------------------------------------
Balance at end of year $328,963 $328,753 $329,922
==============================================================================
6) Earnings Reinvested in the Business
Earnings reinvested in the business unrestricted as to payment of cash
dividends on common stock approximated $252 million at December 31, 1995,
under the provisions of the most restrictive covenants applicable to
preferred stock and long-term debt contained in the Company's Articles of
Incorporation and indentures. The adjustments made to the carrying value of
costs associated with the terminated generating projects and Bonneville
Exchange Power as a result of Statement No. 90 and the disallowance of
certain terminated generating project costs by the Washington Commission do
not impact the amount of earnings reinvested in the business for purposes of
payment of dividends on common stock under the terms of the aforementioned
Articles and indentures. (See Note 1.)
44
7) Long-Term Debt
First Mortgage Bonds at December 31:
Series Due 1995 1994 Series Due 1995 1994
- -------------------------------------------------------------------------------
(Dollars in Thousands) (Dollars in Thousands)
8.25% 1995 $ -- $100,000 7.15% 2002 $ 5,000 $ 5,000
5.25% 1996 20,000 20,000 7.625% 2002 25,000 25,000
4.85% 1996 15,000 15,000 7.02% 2003 30,000 30,000
7.875% 1997 100,000 100,000 6.20% 2003 3,000 3,000
6.17% 1998 10,000 10,000 6.40% 2003 11,000 11,000
5.70% 1998 5,000 5,000 7.70% 2004 50,000 50,000
8.83% 1998 25,000 25,000 7.80% 2004 30,000 30,000
6.50% 1999 16,500 16,500 8.06% 2006 46,000 46,000
6.65% 1999 10,000 10,000 8.14% 2006 25,000 25,000
6.41% 1999 20,500 20,500 7.75% 2007 100,000 100,000
7.25% 1999 50,000 50,000 8.40% 2007 10,000 10,000
6.61% 2000 10,000 10,000 8.59% 2012 5,000 5,000
9.14% 2001 30,000 30,000 8.20% 2012 30,000 30,000
7.85% 2002 30,000 30,000 7.35% 2024 55,000 55,000
7.07% 2002 27,000 27,000 --
- -------------------------------------------------------------------------------
Total First Mortgage Bonds $794,000 $894,000
===============================================================================
Guaranteed Collateralized Bonds at December 31:
Series Due 1995 1994
- ------------------------------------- -----------------------------------------
(Dollars in Thousands)
8.30% 1995 $ -- $ 8,000
8.45% 1996 $ 8,000 $ 8,000
- --------------------------------------------------------------------------------
Total Guaranteed Collateralized Bonds $ 8,000 $16,000
================================================================================
The Company has unconditionally guaranteed all payments of principal and
premium, if any, and interest on each series of the Guaranteed
Collateralized Bonds of Puget Energy issued in 1986. The guarantee of the
Company with respect to each series of the Guaranteed Collateralized Bonds
is backed by a related series of the Company's First Mortgage Bonds. Each
related series of First Mortgage Bonds has been issued to the trustee for
the Guaranteed Collateralized Bonds and so long as payment is made on the
Guaranteed Collateralized Bonds no payment is due with respect to the
related series of First Mortgage Bonds.
Substantially all properties owned by the Company are subject to the lien of
the First Mortgage Bonds.
Pollution Control Bonds
- -----------------------
The Company has outstanding three series of Pollution Control Bonds.
Amounts outstanding were borrowed from the City of Forsyth, Montana ("the
City"). The City obtained the funds from the sale of Customized Pollution
Control Refunding Bonds issued to finance pollution control facilities at
Colstrip Units 3 and 4.
45
Each series of bonds are collateralized by a pledge of the Company's First
Mortgage Bonds, the terms of which match those of the Pollution Control
Bonds. No payment is due with respect to the related series of First
Mortgage Bonds, so long as payment is made on the Pollution Control Bonds.
Interest rates for the 1992 and 1993 series are 6.80% and 5.875%,
respectively. The 1991 series consists of $27.5 million principal amount
bearing interest at 7.05% and $23.4 million principal amount bearing
interest at 7.25%.
Long-Term Debt Maturities
- -------------------------
The principal amounts of long-term debt maturities for the next five years
are as follows:
1996 1997 1998 1999 2000
- ----------------------------------------------------------------------------
(Dollars in Thousands)
Maturities of
long-term debt $ 43,000 $100,000 $ 40,000 $ 97,000 $10,000
8) Short-Term Debt
The Company has short-term borrowing arrangements which include a $100
million line of credit with five major banks, a $75 million line of credit
with five banks and a $1.5 million line with another two banks. The
agreements provide the Company with the ability to borrow at different
interest rate options. For the $100 million and $75 million lines of
credit, the options are: (1) the higher of the prime rate or the Federal
Funds rate plus 1/2 of 1 percent or (2) the bank Certificate of Deposit rate
plus .425 percent or (3) the Eurodollar rate plus .30 percent. These Credit
Agreements require an availability fee of .10 percent per annum on the
unused loan commitment. Borrowings on the $1.5 million credit line are at
the prime rate and compensating balances of 2-1/2% are required.
In addition, the Company has agreements with several banks to borrow on an
uncommitted, as available, basis at money-market rates quoted by the banks.
There are no costs, other than interest, for these arrangements. The
Company also uses commercial paper to fund its short-term borrowing
requirements.
At December 31: 1995 1994 1993
- ----------------------------------------------------------------------------
(Dollars in Thousands)
Short-term borrowings outstanding:
Bank notes $ 44,000 $ 94,900 $ 79,300
Commercial paper notes $123,049 $139,554 $ 70,006
Weighted average interest rate 6.00% 6.24% 3.49%
Unused lines of credit (a) $176,500 $176,500 $152,000
- ----------------------------------------------------------------------------
(a) Provides liquidity support for outstanding commercial paper in the
amount of $123.0 million, $139.6 million and $70.0 million for 1995,
1994 and 1993, respectively, effectively reducing the available
borrowing capacity under these credit lines to $53.5 million, $36.9
million and $82.0 million, respectively.
46
9) Estimated Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 1995 and 1994.
1995 1994
------------------ ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(Dollars in Millions)
Financial Assets:
Cash $ 12.5 $ 12.5 $ 5.3 $ 5.3
Financial Liabilities:
Short-term debt $ 167.0 $ 167.0 $ 234.5 $ 234.5
Preferred stock subject to
mandatory redemption $ 89.0 $ 91.2 $ 91.2 $ 84.4
Long-term debt $ 963.4 $1,012.8 $1,071.3 $1,010.4
The fair value of outstanding bonds including current maturities is
estimated based on quoted market prices.
The preferred stock subject to mandatory redemption is estimated based on
dealer quotes.
The carrying value of short-term debt is considered to be a reasonable
estimate of fair value. The carrying amount of cash, which includes
temporary investments with maturities of 3 months or less, is also
considered to be a reasonable estimate of fair value.
10) Supplementary Income Statement Information
1995 1994 1993
- ---------------------------------------------------------------------------------
(Dollars in Thousands)
Taxes:
Real estate and personal property $ 32,208 $ 33,050 $ 29,354
State business 43,541 42,241 40,102
Municipal, occupational and other 27,280 25,132 23,064
Payroll 8,638 9,514 9,664
Other 3,512 4,194 3,462
- ---------------------------------------------------------------------------------
Total taxes $115,179 $114,131 $105,646
- ---------------------------------------------------------------------------------
Charged to:
Operating expense $109,533 $107,821 $100,598
Other accounts, including
construction work in progress 5,646 6,310 5,048
- ---------------------------------------------------------------------------------
Total taxes $115,179 $114,131 $105,646
=================================================================================
See "Consolidated Statements of Income" for maintenance and depreciation
expense.
Other operation expenses in 1994 include charges totaling $20.9 million
related to
47
two early separation and retirement programs and associated facilities
consolidations. Severance packages accepted by employees totaled $18.3
million, including retirement benefits and pension expenses of $6.9 million.
Facility consolidation expenses were $2.6 million. (See Note 18)
Advertising, research and development expenses and amortization of
intangibles are not significant. The Company pays no royalties.
11) Leases
The Company treats all leases as operating leases for ratemaking purposes as
required by the Washington Commission. Certain leases contain purchase
options, renewal and escalation provisions. Capitalized leases are not
material.
Rental and operating lease expenses for the years ended December 31, 1995,
1994 and 1993 were approximately $15,119,000, $13,874,000 and $14,016,000,
respectively. At December 31, 1995, future minimum lease payments for
noncancelable leases are $9,114,000 for 1996, $9,173,000 for 1997,
$9,118,000 for 1998, $9,130,000 for 1999, $8,488,000 for 2000 and in the
aggregate $26,601,000 thereafter.
12) Federal Income Taxes
The details of federal income taxes ("FIT") are as follows:
1995 1994 1993
- ------------------------------------------------------------------------------
Charged to Operating Expense: (Dollars in Thousands)
Current $72,020 $63,935 $56,908
Deferred - net 12,940 16,739 29,180
Deferred investment tax credits (415) (415) (2,118)
- ------------------------------------------------------------------------------
Total FIT charged to operations $84,545 $80,259 $83,970
==============================================================================
Charged to Miscellaneous Income:
Current $(1,125) $(1,253) $(3,665)
Deferred - net (476) 1,438 3,087
- -------------------------------------------------------------------------------
Total FIT charged to miscellaneous income $(1,601) $ 185 $ (578)
===============================================================================
Total FIT $82,944 $80,444 $83,392
===============================================================================
48
The following is a reconciliation of the difference between the amount of
FIT computed by multiplying pre-tax book income by the statutory tax rate,
and the amount of FIT in the Consolidated Statements of Income:
1995 1994 1993
- -----------------------------------------------------------------------------
(Dollars in Thousands)
- -----------------------------------------------------------------------------
FIT at the statutory rate $76,532 $70,177 $77,602
- -----------------------------------------------------------------------------
Increase (Decrease):
Depreciation expense deducted in the
financial statements in excess of tax
depreciation, net of depreciation
treated as a temporary difference 5,370 4,717 4,698
AFUDC included in income in the financial
statements but excluded from taxable income (2,319) (2,525) (2,563)
Investment tax credit amortization (415) (415) (2,118)
Amortization of Pebble Springs and Skagit/
Hanford projects, deducted for financial
statements but not deducted for income tax
purposes, net of amount treated as a
temporary difference -- 748 1,465
Energy conservation expenditures - net 806 5,607 5,608
Other 2,970 2,135 (1,300)
- ------------------------------------------------------------------------------
Total FIT $82,944 $80,444 $83,392
==============================================================================
Effective tax rate 37.9% 40.1% 37.6%
==============================================================================
49
The following are the principal components of FIT as reported:
1995 1994 1993
- ------------------------------------------------------------------------------
(Dollars in Thousands)
- ------------------------------------------------------------------------------
Current FIT $70,895 $62,682 $53,243
===============================================================================
Deferred FIT - other:
Conservation tax settlement (7) 341 (257)
Periodic rate adjustment mechanism (PRAM) 1,384 9,287 14,959
Deferred taxes related to insurance
reserves (938) (938) 1,409
Terminated generating projects -- (3,345) (5,735)
Reversal of Statement No. 90 present
value adjustments 688 926 1,477
Residential Purchase and Sale
Agreement - net (4,010) (624) 4,136
Normalized tax benefits of the
accelerated cost recovery system 19,435 19,042 19,839
Energy conservation program (1,969) (2,253) (2,938)
Other (2,119) (4,259) (623)
- -------------------------------------------------------------------------------
Total deferred FIT - other $12,464 $18,177 $32,267
===============================================================================
Deferred investment tax credits -
net of amortization $ (415) $ (415) $(2,118)
- -------------------------------------------------------------------------------
Total FIT $82,944 $80,444 $83,392
===============================================================================
Deferred tax amounts shown above result from temporary differences for tax
and financial statement purposes. Deferred tax provisions are not recorded
in the income statement on certain temporary differences between tax and
financial statement purposes because they are not allowed for ratemaking
purposes.
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("Statement No.
109"). Statement No. 109 requires recording deferred tax balances, at the
currently enacted tax rate, for all temporary differences between the book
and tax bases of assets and liabilities, including temporary differences for
which no deferred taxes had been previously provided because of use of flow-
through tax accounting for rate-making purposes. Because of prior, and
expected future ratemaking treatment for temporary differences for which
flow-through tax accounting has been utilized, a regulatory asset for income
taxes recoverable through future rates related to those differences has also
been established. At December 31, 1995, the balance of this asset is $250
million. The effect on net income from adoption of Statement No. 109 was
not significant nor is it expected to be in the future.
50
The deferred tax liability at December 31, 1995 and 1994 is comprised of
amounts related to the following types of temporary differences:
1995 1994
------- -------
(Dollars in Thousands)
Utility plant $442,425 $446,177
PRAM 40,181 38,795
Energy conservation charges 32,441 35,836
Contributions in aid of construction (25,425) (24,075)
Bonneville Exchange Power 14,217 16,672
Other 24,561 28,096
------- -------
Total $528,400 $541,501
======= =======
The totals of $528 million and $542 million for 1995 and 1994 consist of
deferred tax liabilities of $564 million and $576 million net of deferred
tax assets of $36 million and $34 million, respectively.
13) Retirement Benefits
The Company has a noncontributory defined benefit pension plan covering
substantially all of its employees. Benefits are a function of both years
of service and the average of the five highest consecutive years of basic
earnings within the last ten years of employment. The Company funds pension
cost using the "frozen entry-age" actuarial cost method.
Through September 30, 1993, in accordance with the methodology confirmed in
the January 17, 1990 general rate order from the Washington Commission, the
Company recognized pension costs for ratemaking and financial statement
purposes using a formula based on a multi-year average of actual
contributions to the plan. Effective October 1, 1993, because of a change
in methodology made by the Washington Commission in its September 21, 1993
rate order, the Company's pension costs for financial statement purposes are
determined in accordance with the provisions of Statement of Financial
Accounting Standards No. 87, "Accounting for Pensions."
51
Net pension costs for 1995, 1994 and 1993, including $1,966,000 for 1995,
$2,752,000 for 1994 and $1,440,000 for 1993 which were charged to
construction and other asset accounts, were comprised of the following
components:
1995 1994 1993
- ----------------------------------------------------------------------------------
(Dollars in Thousands)
Service cost (benefits earned during
the period) $ 6,129 $ 7,244 $ 6,952
Interest cost on projected benefit
obligation 15,656 14,895 14,676
Actual return on plan assets (53,810) 4,392 (21,786)
Net amortization and deferral 35,335 (21,539) 5,121
- ----------------------------------------------------------------------------------
Net pension costs under FASB Statement No. 87 3,310 4,992 4,963
- ----------------------------------------------------------------------------------
Regulatory adjustment 1,263 1,263 (2,083)
- ----------------------------------------------------------------------------------
Net pension costs $ 4,573 $ 6,255 $ 2,880
==================================================================================
Funded Status of Plan
At December 31: 1995 1994
- ----------------------------------------------------------------------------
(Dollars in Thousands)
Actuarial present value of benefit obligations:
Vested $(181,367) $(154,950)
Non-vested (1,387) (1,029)
- ----------------------------------------------------------------------------
Accumulated benefit obligation (182,754) (155,979)
Effect of future compensation levels (41,566) (39,455)
- ----------------------------------------------------------------------------
Total projected benefit obligation (224,320) (195,434)
Plan assets at market value 254,844 205,655
- ----------------------------------------------------------------------------
Plan assets in excess of projected benefit
obligation 30,524 10,221
Unrecognized net gain due to variance
between assumptions and experience (34,584) (19,453)
Prior service cost 9,606 10,295
Transition asset as of January 1, 1986,
being amortized on a straight-line
basis over 18 years (3,354) (3,774)
Regulatory adjustment, cumulative 4,927 6,190
- ----------------------------------------------------------------------------
Prepaid pension cost recognized
in long-term assets on balance sheet $ 7,119 $ 3,479
============================================================================
Assumptions used for the above calculations are as follows: settlement
(discount) rate for 1995 - 7.5%, 1994 - 8.25% and for 1993 - 7.5%; rate of
annual compensation increase for 1995 - 5.0%, 1994 - 5.5% and for 1993 -
5.5%; and long-term rate of return on assets for 1995 - 9.0%, 1994 - 8.5%,
and for 1993 - 8.5%.
Plan assets consist primarily of U.S. Government securities, corporate debt
and equity securities.
Effective October 1, 1991, the Company's Board of Directors approved
supplemental
52
retirement plans for officer and director level employees. Expenses for
this plan for 1995, 1994 and 1993 were $916,000, $1,043,000 and $651,000,
respectively.
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees.
Substantially all of the Company's employees may become eligible for health
care benefits and salaried employees become eligible for life insurance
benefits upon reaching normal retirement age. These benefits are provided
principally through an insurance company whose premiums are based on the
benefits paid during the year.
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" ("Statement No. 106") which requires the costs
associated with postretirement benefits to be accrued over the period of
employment. The Company is recognizing the impact of Statement No. 106 by
amortizing its transition obligation of $24.9 million to expense over 20
years. The resulting 1995, 1994 and 1993 annual costs under Statement No.
106 were approximately $3.3 million, $3.6 million and $3.8 million,
respectively.
In the rate order issued by the Washington Commission on September 21, 1993,
the Washington Commission approved adoption of accrual accounting for
postretirement benefits. For rate purposes, the difference between accrual
and pay-as-you-go accounting will be phased in over five years. The
Washington Commission's calculation of Statement No. 106 costs for rate
purposes is lower than the Company's cost. In 1995, 1994 and 1993, the
expenses recognized for postretirement benefits were $2.5 million, $2.4
million and $2.8 million respectively, including $.2 million, $.1 million
and $.5 million, which were disallowed by the Washington Commission.
14) Employee Investment Plan
The Company has a qualified employee Investment Plan under which employee
salary deferrals and after-tax contributions are used to purchase several
different investment fund options. The Company makes a monthly contribution
equal to 55% of the basic contribution of each participating employee. The
basic contribution is limited to 6% of the employee's eligible earnings.
All Company contributions are used to purchase Company common stock on the
open market or directly from the Company.
The Company contributions to the plan were $3,103,000, $3,321,000 and
$3,520,000 for the years 1995, 1994 and 1993, respectively. The
shareholders have authorized the issuance of up to 2,000,000 shares of
common stock under the plan, of which 959,142 were issued through December
31, 1995. The employee Investment Plan eligibility requirements are set
forth in the plan documents.
15) Commitments and Contingencies
Commitments
For the twelve months ended December 31, 1995, approximately 28% of the
Company's energy output was obtained at an average cost of approximately
10.3 mills per KWH through long-term contracts with several of the
Washington public utility districts ("PUDs") owning hydroelectric projects
on the Columbia River.
The purchase of power from the Columbia River projects is generally on a
"cost-of-service" basis under which the Company pays a proportionate share
of the annual cost of each project in direct ratio to the amount of power
allocated to it. Such payments are not contingent upon the projects being
operable. These projects are
53
financed through substantially level debt service payments, and their annual
costs
should not vary significantly over the term of the contracts unless
additional financing is required to meet the costs of major maintenance,
repairs or replacements or license requirements. The Company's share of the
costs and the output of the projects is subject to reduction due to various
withdrawal rights of the PUDs and others over the lives of the contracts.
As of December 31, 1995, the Company was entitled to purchase portions of
the power output of the PUDs' projects as set forth in the following
tabulation:
Company's Annual Amount
Bonds Purchasable (Approximate)
Outstanding ---------------------------------
Contract License 12/31/95(a) % of Kilowatt Costs(b)
Project Exp.Date Exp.Date (Millions) Output Capacity (Millions)
- ----------------------------------------------------------------------------------
Rock Island
Original units 2012 2029 $ 88.6 59.2 )
) 496,000 $ 43.6
Additional units 2012 2029 323.2 100.0 )
Rocky Reach 2011 2006(c) 208.1 38.9 505,700 17.3
Wells 2018 2012(c) 189.5 33.6 282,240 10.4
Priest Rapids 2005 2005(c) 128.4 8.0 71,760 2.2
Wanapum 2009 2005(c) 183.0 10.8 98,280 2.7
- ----------------------------------------------------------------------------------
Total 1,453,980 $ 76.2
==================================================================================
(a) The contracts for purchases are generally coextensive with the term
of the PUD bonds associated with the project. Under the terms of some
financings, however, long-term bonds were sold to finance certain assets
whose estimated useful lives extend beyond the expiration date of the power
sales contracts. Of the total outstanding bonds sold for each project, the
percentage of principal amount of bonds which mature beyond the contract
expiration dates are: 69.4% at Rock Island; 31.6% at Rocky Reach; 65.7% at
Priest Rapids; and 40.8% at Wanapum.
(b) The components of 1996 costs associated with the interest portion
of debt service are: Rock Island, $24.5 million for all units; Rocky Reach,
$4.9 million; Wells, $3.2 million; Priest Rapids, $1.1 million; and Wanapum,
$1.5 million.
(c) The Company is unable to predict whether the licenses under the
Federal Power Act will be renewed to the current licensees or what effect
the term of the licenses may have on the Company's contracts.
- -----------------------------
The Company's estimated payments for power purchases from the Columbia River
projects are $76 million for 1996, $76 million for 1997, $79 million for
1998, $81 million for 1999, $83 million for 2000 and in the aggregate $1.134
billion thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with
other utilities and non-utility generators in the region. The Company is
not obligated to make payments under these contracts unless power is
delivered. The Company's estimated payments for firm power purchases from
other utilities and non-utility generators, excluding the Columbia River
projects, are $392 million for 1996, $394 million for 1997, $413 million for
1998, $437 million for 1999, $455 million for
54
2000 and in the aggregate $5.015 billion thereafter through 2024. These
contracts have varying terms and may include escalation and termination
provisions.
Total purchased power contracts provided the Company with approximately 16.4
million, 16.0 million, and 13.5 million MWH of firm energy at a cost of
approximately $478.7 million, $450.7 million and $353.5 million for the
years 1995, 1994 and 1993, respectively.
The following table indicates the Company's percentage ownership and the
extent of the Company's investment in jointly-owned generating plants in
service at December 31, 1995:
Company's Share
Energy Company's Plant in Accumulated
Source Ownership Service at cost Depreciation
Project (Fuel) Share (%) (Millions) (Millions)
Centralia Coal 7 $ 27.0 $ 16.6
Colstrip 1 & 2 Coal 50 182.9 91.2
Colstrip 3 & 4 Coal 25 448.1 142.6
Financing for a participant's ownership share in the projects is provided
for by such participant. The Company's share of related operating and
maintenance expenses is included in corresponding accounts in the
Consolidated Statements of Income.
Certain purchase commitments have been made in connection with the Company's
construction program.
Contingencies
In July 1995, the Company paid $500,000 as part of a negotiated agreement
between bondholders of Washington Public Power Supply System ("WPPSS") Unit
5 project and the Company and other owners of WPPSS Unit 3. The agreement
settled all outstanding claims by the bondholders against the owners of
WPPSS Unit 3, including the Company.
The Company is subject to environmental regulation by federal, state and
local authorities. The Company has been named a Potentially Responsible
Party by the Environmental Protection Agency ("EPA") at four sites. The
Company has also commenced a program to test, replace and remediate certain
underground storage tanks as required by federal and state laws.
Remediation and testing of Company vehicle service facilities and storage
yards have also been commenced.
On April 1, 1992, the Washington Commission issued an order regarding the
treatment of costs incurred by the Company for certain sites under its
environmental remediation program. The order authorizes the Company to
accumulate and defer prudently incurred cleanup costs paid to third parties
for recovery in rates established in future rate proceedings. The Company
believes a significant portion of its past and future environmental
remediation costs are recoverable from either insurance companies, third
parties or under the Washington Commission's order.
The Company has expended approximately $14.3 million related to the
remediation activities covered by the Washington Commission's order, of
which approximately $4.6 million has been recovered from insurance carriers.
At December 31, 1995, approximately $2.6 million has been accrued as a
liability for future remediation costs for these and other remediation
activities. At December 31, 1995, an asset of approximately $11.3 million
has been recorded related to expected future
55
recoveries.
Other contingencies, arising out of the normal course of the Company's
business, exist at December 31, 1995. The ultimate resolution of these
issues is not expected to have a material adverse impact on the financial
condition, results of operations or liquidity of the Company.
16) Supplemental Quarterly Financial Data (Unaudited)
The following unaudited amounts, in the opinion of the Company, include all
adjustments (consisting of normal recurring adjustments) necessary for a
fair presentation of the results of operations for the interim periods.
Quarterly amounts vary during the year due to the seasonal nature of the
utility business.
1995 Quarter Ended March 31 June 30 Sept. 30 Dec. 31
- --------------------------------------------------------------------------
(Dollars in thousands except per share amounts)
Operating revenues $338,345 $261,592 $248,584 $330,809
Operating income $ 70,359 $ 42,938 $ 37,001 $ 64,290
Other income $ 1,682 $ 2,587 $ 2,258 $ 1,149
Net income $ 48,746 $ 22,863 $ 19,019 $ 45,091
Earnings per common share $ 0.70 $ 0.30 $ 0.24 $ 0.65
- --------------------------------------------------------------------------
1994 Quarter Ended March 31 June 30 Sept. 30 Dec. 31
- --------------------------------------------------------------------------
(Dollars in thousands except per share amounts)
Operating revenues $329,222 $263,612 $264,289 $336,935
Operating income $ 63,892 $ 35,579 $ 33,104 $ 60,924
Other income $ 3,881 $ 3,341 $ 3,279 $ 2,318
Net income $ 46,527 $ 17,772 $ 14,927 $ 40,833
Earnings per common share $ 0.67 $ 0.22 $ 0.17 $ 0.58
- --------------------------------------------------------------------------
17) Consolidated Statement of Cash Flows
For purposes of the Statement of Cash Flows, the Company considers all
temporary investments to be cash equivalents. These temporary cash
investments are securities held for cash management purposes, having
maturities of three months or less. The net change in current assets and
current liabilities for purposes of the Statement of Cash Flows excludes
short-term debt, current maturities of long-term debt and the current
portion of PRAM accrued revenues.
56
The following provides additional information concerning cash flow
activities:
Year Ended December 31: 1995 1994 1993
- --------------------------------------------------------------------------
(Dollars in Thousands)
Changes in certain current
assets and current liabilities:
Accounts receivable $(16,498) $(16,725) $ (5,050)
Unbilled revenues 6,382 2,521 (14,410)
Materials and supplies 3,136 2,840 1,054
Prepayments and Other 908 (75) 5,809
Accounts payable (7,756) 4,576 10,731
Accrued expenses and Other (3,736) 884 11,511
- --------------------------------------------------------------------------
Net change in certain current assets
and current liabilities $(17,564) $ (5,979) $ 9,645
==========================================================================
Cash payments:
Interest (net of capitalized interest) $ 90,015 $ 83,959 $ 80,646
Income taxes $ 74,273 $ 63,477 $ 32,585
- --------------------------------------------------------------------------
18) Other
On October 18, 1995, the Company entered into an Agreement and Plan of Merger
with Washington Energy Company ("WECO") and Washington Natural Gas Company
("WNG"), a wholly-owned subsidiary of WECO. The Merger has been unanimously
approved by the Company's Board of Directors as well as the Board of
Directors of WECO. Pursuant to the Agreement, WECO and WNG would be merged
with and into Puget Power, after which the merged company would be renamed.
The Agreement calls for each share of WECO common stock to be exchanged for
0.86 share of the Company's common stock. Based on the capitalization of
the Company and WECO on December 31, 1995, holders of the Company's and
WECO's common stock would have held approximately 75% and 25% respectively,
of the aggregate number of outstanding shares of the merged company's common
stock had the merger been consummated at that date. In addition, the
Agreement calls for the preferred stock of WNG to be converted into
preferred shares of the merged company. The merger would be structured as a
tax-free exchange of shares, and is expected to be accounted for as a
pooling of interests.
The merger agreement is subject to the approval of the shareholders of the
respective companies and by the Washington Commission which regulates the
utility operations of each entity. Shareholder approval will be sought at
shareholder meetings scheduled for March 20, 1996. The regulatory approval
process is requested to be completed in the second half of 1996.
The Hart-Scott-Rodino Act ("HSR Act") and the rules and regulations
thereunder provide that the Merger may not be consummated until certain
information has been submitted to the Antitrust Division of the United
States Department of Justice and the Federal Trade Commission and specified
HSR Act waiting period requirements have been satisfied.
In connection with its application for approval of the merger with WECO, the
Company filed with the Washington Commission, in February 1996, a proposed
rate stability plan which, if adopted, would among other things, increase
general electric rates by 1% annually through 2000 with no rate increase in
2001.
57
Also in connection with the merger, the Company, on December 11, 1995,
offered a voluntary early separation plan to approximately 890 employees.
The plan, which offers a severance package based on years of service, was
accepted by 204 employees on January 31, 1996. Under the terms of the plan,
the Company has the right to retain the employees for up to 60 days after
the merger is completed. If, for any reason, the merger plans are
discontinued prior to the employee's separation date, the employee's
participation in the plan will thereupon be considered terminated and no
severance benefits will be paid. The costs of the plan will be recognized
when the Company releases specific employees. Total additional costs of
this voluntary separation plan are currently estimated to be $7 million.
58
Puget Sound Power & Light Company
Schedule II. Valuation and Qualifying Accounts and Reserves
- -----------------------------------------------------------------------------
(Dollars in Thousands)
- -----------------------------------------------------------------------------
Column A Column B Column C Column D Column E
- -----------------------------------------------------------------------------
Additions
Balance at Charged to Balance
Beginning Costs and at End
of Period Expenses Deductions of Period
Year Ended December 31, 1995
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 610 $ 4,527 $ 4,251 $ 886
=============================================================================
Year Ended December 31, 1994
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 523 $ 3,537 $ 3,450 $ 610
=============================================================================
Year Ended December 31, 1993
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 488 $ 2,799 $ 2,764 $ 523
- -----------------------------------------------------------------------------
Reserves:
Accumulated provision
for self-insurance $ 87 $13,634(A) $13,721(A) $ --
=============================================================================
Note (A): Includes charges of $10.3 million in 1993 that were transferred to
a deferred asset account.
59
EXHIBIT INDEX
Certain of the following exhibits are filed herewith. Certain other of the
following exhibits have heretofore been filed with the Commission and are
incorporated herein by reference.
2.1 Agreement and Plan of Merger dated as of October 18, 1995 among
the Registrant, Washington Energy Company and Washington Natural Gas Company.
(Exhibit 2.1 to Registration No. 333-617)
2.2 Puget Sound Power & Light Company Stock Option Agreement dated as
of October 18, 1995, between Puget Sound Power & Light Company and Washington
Energy Company. (Exhibit 2.2 to Registration No. 333-617)
2.3 Washington Energy Company Stock Option Agreement dated as of
October 18, 1995, between Washington Energy Company and Puget Sound Power &
Light Company. (Exhibit 2.3 to Registration No. 333-617)
3-a Restated Articles of Incorporation of the Company. (Exhibit 1.2
to Registration Statement on Form 8-A filed February 14, 1994, Commission
File No. 1-4393)
3-b Restated Bylaws of the Company. (Exhibit 4-b to Registration
No. 33-18506)
4.1 Fortieth through Seventy-fifth Supplemental Indentures defining
the rights of the holders of the Company's First Mortgage Bonds. (Exhibit 2-
d to Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347;
Exhibits 2-e through and including 2-k to Registration No. 2-60200; Exhibit 4-
h to Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No.
2-60200; Exhibits 2-m to Registration No. 2-37645; Exhibit 2-o through and
including 2-s to Registration No. 2-60200; Exhibit 5-b to Registration No. 2-
62883; Exhibit 2-h to Registration No. 2-65831; Exhibit (4)-j-1 to
Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit
(4)-b to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No. 1-4393; Exhibits (4)(a) and (4)(b) to Company's
Current Report on Form 8-K, dated April 22, 1986; Exhibit (4)a to Company's
Current Report on Form 8-K, dated September 5, 1986; Exhibit (4)-b to
Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
1986, Commission File No. 1-4393; Exhibit (4)-c to Registration No. 33-18506;
Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended
December 31, 1989, Commission File No. 1-4393; Exhibit (4)-b to Annual Report
on Form 10-K for the fiscal year ended December 31, 1990, Commission File No.
1-4393; Exhibits (4)-b and (4)-c to Registration No. 33-45916; Exhibit (4)-c
to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; and
Exhibit 4.3 to Registration No. 33-63278.)
4.2 Credit Agreement dated as of December 1, 1991, among the Company
and various banks named therein, Seattle-First National Bank as Agent.
(Exhibit (4)-d to Registration No. 33-45916)
4.3 Credit Agreement dated as of December 1, 1991, among the Company
and various banks named therein, Bank of New York as Agent. (Exhibit (4)-e
to Registration No. 33-45916)
60
4.4 Final form of Indenture dated as of November 1, 1986, among
Puget Energy, the Company, and The First National Bank of Boston, as Trustee.
(Exhibit 4-a to Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1986, Commission File No. 1-4393)
4.5 Final form of Pledge Agreement dated November 1, 1986, between
the Company and The First National Bank of Boston, as Trustee. (Exhibit 4-c
to Company's Quarterly Report on Form 10-Q for the quarter ended September
30, 1986, Commission File No. 1-4393)
4.6 Rights Agreement, dated as of January 15, 1991, between the
Company and The Chase Manhattan Bank, N.A., as Rights Agent. (Exhibit 2.1 to
Registration Statement on Form 8-A filed on January 17, 1991, Commission File
No. 1-4393)
4.7 Amendment No. 1 dated as of August 30, 1991, to the Rights
Agreement dated as of January 15, 1991, between the Registrant and the Bank
of New York (as successor to The Chase Manhatten Bank, N.A.), as Rights
Agent. (Exhibit 2.1 to Registration Statement on Form 8 filed on August 30,
1991)
4.8 Amendment No. 2 dated as of October 18, 1995, to the Rights
Agreement dated as of January 15, 1991, between the Registrant and The Bank
of New York (as successor to The Chase Manhatten Bank, N.A.), as Rights
Agent. (Exhibit 1 to Registration Statement on Form 8-A/A filed on October
27, 1995)
4.9 Pledge Agreement dated August 1, 1991, between the Company and
The First National Bank of Chicago, as Trustee. (Exhibit (4)-j to
Registration No. 33-45916)
4.10 Loan Agreement dated August 1, 1991, between the City of
Forsyth, Rosebud County, Montana and the Company. (Exhibit (4)-k to
Registration No. 33-45916)
4.11 Statement of Relative Rights and Preferences for the Adjustable
Rate Cumulative Preferred Stock, Series B ($25 Par Value). (Exhibit 1.1 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)
4.12 Statement of Relative Rights and Preferences for the Series A
Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred
Stock. (Exhibit 1.3 to Registration Statement on Form 8-A filed February 14,
1994, Commission File No. 1-4393)
4.13 Statement of Relative Rights and Preferences for the Series B
Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred
Stock. (Exhibit 1.4 to Registration Statement on Form 8-A filed February 14,
1994, Commission File No. 1-4393)
4.14 Statement of Relative rights and Preferences for the Preference
Stock, Series R, $50 Par Value. (Exhibit 1.5 to Registration Statement on
Form 8-A filed February 14, 1994, Commission File No. 1-4393)
61
4.15 Statement of Relative Rights and Preferences for the 7 3/4%
Series Preferred Stock Cumulative, $100 Par Value. (Exhibit 1.6 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)
4.16 Statement of Relative Rights and Preferences for the 7 7/8%
Series Preferred Stock Cumulative, $25 Par Value. (Exhibit 1.7 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)
4.17 Pledge Agreement, dated as of March 1, 1992, by and between the
Company and and Chemical Bank relating to a series of first mortgage bonds.
(Exhibit 4.15 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1993, Commission File No. 1-4393)
4.18 Pledge Agreement, dated as of April 1, 1993, by and between the
Company and The First National Bank of Chicago, relating to a series of first
mortgage bonds. (Exhibit 4.16 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1993, Commission File No. 1-4393)
10.1 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 1 of Chelan County, Washington and
the Company, relating to the Rock Island Project. (Exhibit 13-b to
Registration No. 2-24262)
10.2 First Amendment, dated as of October 4, 1961, to Power Sales
Contract between Public Utility District No. 1 of Chelan County,
Washington and the Company, relating to the Rocky Reach Project.
(Exhibit 13-d to Registration No. 2-24252)
10.3 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 1 of Chelan County, Washington and
the Company, relating to the Rocky Reach Project. (Exhibit 13-e to
Registration No. 2-24252)
10.4 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 2 of Grant County, Washington and the
Company, relating to the Priest Rapids Development. (Exhibit 13-j to
Registration No. 2-24252)
10.5 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 2 of Grant County, Washington and the
Company, relating to the Wanapum Development. (Exhibit 13-n to
Registration No. 2-24252)
10.6 First Amendment, dated February 9, 1965, to Power Sales
Contract between Public Utility District No. 1 of Douglas County,
Washington and the Company, relating to the Wells Development. (Exhibit
13-p to Registration No. 2-24252)
10.7 First Amendment, executed as of February 9, 1965, to
Reserved Share Power Sales Contract between Public Utility District No. 1
of Douglas County, Washington and the Company, relating to the Wells
Development. (Exhibit 13-r to Registration No. 2-24252)
62
10.8 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 1 of Douglas County, Washington and
the Company, relating to the Wells Development. (Exhibit 13-u to
Registration No. 2-24252)
10.9 Pacific Northwest Coordination Agreement, executed as of
September 15, 1964, among the United States of America, the Company and
most of the other major electrical utilities in the Pacific Northwest.
(Exhibit 13-gg to Registration No. 2-24252)
10.10 Contract dated November 14, 1957, between Public Utility
District No. 1 of Chelan County, Washington and the Company, relating to
the Rocky Reach Project. (Exhibit 4-1-a to Registration No. 2-13979)
10.11 Power Sales Contract, dated as of November 14, 1957, between
Public Utility District No. 1 of Chelan County, Washington and the
Company, relating to the Rocky Reach Project. (Exhibit 4-c-1 to
Registration No. 2-13979)
10.12 Power Sales Contract, dated May 21, 1956, between Public
Utility District No. 2 of Grant County, Washington and the Company,
relating to the Priest Rapids Project. (Exhibit 4-d to Registration No.
2-13347)
10.13 First Amendment to Power Sales Contract dated as of August
5, 1958, between the Company and Public Utility District No. 2 of Grant
County, Washington, relating to the Priest Rapids Development. (Exhibit
13-h to Registration No. 2-15618)
10.14 Power Sales Contract dated June 22, 1959, between Public
Utility District No. 2 of Grant County, Washington and the Company,
relating to the Wanapum Development. (Exhibit 13-j to Registration No. 2-
15618)
10.15 Reserve Share Power Sales Contract dated June 22, 1959, between
Public Utility District No. 2 of Grant County, Washington and the Company,
relating to the Priest Rapids Project. (Exhibit 13-k to Registration No. 2-
15618)
10.16 Agreement to Amend Power Sales Contracts dated July 30, 1963,
between Public Utility District No. 2 of Grant County, Washington and the
Company, relating to the Wanapum Development. (Exhibit 13-1 to Registration
No. 2-21824)
10.17 Power Sales Contract executed as of September 18, 1963, between
Public Utility District No. 1 of Douglas County, Washington and the Company,
relating to the Wells Development. (Exhibit 13-r to Registration No. 2-
21824)
10.18 Reserved Share Power Sales Contract executed as of September
18, 1963, between Public Utility District No. 1 of Douglas County,
Washington and the Company, relating to the Wells Development. (Exhibit 13-
s to Registration No. 2-21824)
63
10.19 Exchange Agreement dated April 12, 1963, between the United
States of America, Department of the Interior, acting through the Bonneville
Power Administrator and Washington Public Power Supply System and the
Company, relating to the Hanford Project. (Exhibit 13-u to Registration 2-
21824)
10.20 Replacement Power Sales Contract dated April 12, 1963, between
the United States of America, Department of the Interior, acting through the
Bonneville Power Administrator and the Company, relating to the Hanford
Project. (Exhibit 13-v to Registration No. 2-21824)
10.21 Contract covering undivided interest in ownership and operation
of Centralia Thermal Plant, dated May 15, 1969. (Exhibit 5-b to
Registration No. 2-3765)
10.22 Construction and Ownership Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-b to
Registration No. 2-45702)
10.23 Operation and Maintenance Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-c to
Registration No. 2-45702)
10.24 Coal Supply Agreement, dated as of July 30, 1971, among The
Montana Power Company, the Company and Western Energy Company. (Exhibit 5-d
to Registration No. 2-45702)
10.25 Power Purchase Agreement with Washington Public Power Supply
System and the Bonneville Power Administration dated February 6, 1973.
(Exhibit 5-e to Registration No. 2-49029)
10.26 Ownership Agreement among the Company, Washington Public Power
Supply System and others dated September 17, 1973. (Exhibit 5-a-29 to
Registration No. 2-60200)
10.27 Contract dated June 19, 1974, between the Company and P.U.D.
No. 1 of Chelan County. (Exhibit D to Form 8-K dated July 5, 1974
10.28 Restated Financing Agreement among the Company, lessee,
Chrysler Financial Corporation, owner, Nevada National Bank and Bank of
Montreal (California), trustee, dated December 12, 1974 pertaining to a
combustion turbine generating unit trust. (Exhibit 5-a-35 to Registration
No. 2-60200)
10.29 Restated Lease Agreement between the Company, lessee, and the
Bank of California, and National Association, lessor, dated December 12,
1974 for one combustion generating unit. (Exhibit 5-a-36 to Registration
No. 2-60200)
64
10.30 Financing Agreement Supplement and Amendment among the Company,
lessee, Chrysler Financial Corporation, owner, The Bank of California,
National Association, trustee, Pacific Mutual Life Insurance Company,
Bankers Life Company, and The Franklin Life Insurance Company, lenders,
dated as of March 26, 1975, pertaining to a combustion turbine generating
unit trust. (Exhibit 5-a-37 to Registration No. 2-60200)
10.31 Lease Agreement Supplement and Amendment between the Company,
lessee, and The Bank of California, National Association, lessor, dated as
of March 26, 1975 for one combustion turbine generating unit. (Exhibit 5-a-
38 to Registration No. 2-60200)
10.32 Exchange Agreement executed August 13, 1964, between the United
States of America, Columbia Storage Power Exchange and the Company, relating
to Canadian Entitlement. (Exhibit 13-ff to Registration No. 2-24252)
10.33 Loan Agreement dated as of December 1, 1980 and related
documents pertaining to Whitehorn turbine construction trust financing.
(Exhibit 10.52 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1980, Commission File No. 1-4393)
10.34 Letter Agreement dated March 31, 1980, between the Company and
Manufacturers Hanover Leasing Corporation. (Exhibit b-8 to Registration No.
2-68498)
10.35 Coal Supply Agreement for Colstrip 3 and 4, dated as of July 2,
1980; Amendment No. 1 to Coal Supply Agreement, dated as of July 10, 1981;
and Coal Transportation Agreement dated as of July 10, 1981. (Exhibit 20-a
to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981,
Commission File No. 1-4393)
10.36 Residential Purchase and Sale Agreement between the Company and
the Bonneville Power Administration, effective as of October 1, 1981.
(Exhibit 20-b to Quarterly Report on Form 10-Q for the quarter ended
September 30, 1981, Commission File No. 1-4393)
10.37 Letter of Agreement to Participate in Licensing of Creston
Generating Station, dated September 30, 1981. (Exhibit 20-c to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1981, Commission
File No. 1-4393)
10.38 Power sales contract dated August 27, 1982 between the Company
and Bonneville Power Administration. (Exhibit 10-a to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1982, Commission File No. 1-
4393)
10.39 Agreement executed as of April 17, 1984, between the United
States of America, Department of the Interior, acting through the Bonneville
Power Administration, and other utilities relating to extension energy from
the Hanford Atomic Power Plant No. 1. (Exhibit (10)-47 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1984, Commission File No. 1-
4393)
65
10.40 Agreement for the Assignment of Output from the Centralia
Thermal Project, dated as of April 14, 1983, between the Company and Public
Utility District No. 1 of Grays Harbor. (Exhibit (10)-48 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1984, Commission File
No. 1-4393)
10.41 Settlement Agreement and Covenant Not to Sue executed by the
United States Department of Energy acting by and through the Bonneville
Power Administration and the Company dated September 17, 1985. (Exhibit
(10)-49 to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No. 1-4393)
10.42 Agreement to Dismiss Claims and Covenant Not to Sue dated
September 17, 1985 between Washington Public Power Supply System and the
Company. (Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1985, Commission File No. 1-4393)
10.43 Irrevocable Offer of Washington Public Power Supply System
Nuclear Project No. 3 Capability for Acquisition executed by the Company,
dated September 17, 1985. (Exhibit A of Exhibit (10)-50 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-
4393)
10.44 Settlement Exchange Agreement ("Bonneville Exchange Power
Contract") executed by the United States of America Department of Energy
acting by and through the Bonneville Power Administration and the Company,
dated September 17, 1985. (Exhibit B of Exhibit (10)-50 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-
4393)
10.45 Settlement Agreement and Covenant Not to Sue between the
Company and Northern Wasco County People's Utility District, dated
October 16, 1985. (Exhibit (10)-53 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.46 Settlement Agreement and Covenant Not to Sue between the
Company and Tillamook People's Utility District, dated October 16, 1985.
(Exhibit (10)-54 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1985, Commission File No. 1-4393)
10.47 Settlement Agreement and Covenent Not to Sue between the
Company and Clatskanie People's Utility District, dated September 30,
1985. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1985, Commission File No. 1-4393)
10.48 Stipulation and Settlement Agreement between the Company and
Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October
31, 1986. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1986, Commission File No. 1-4393)
66
10.49 Transmission Agreement dated April 17, 1981, between the
Bonneville Power Administration and the Company (Colstrip Project). (Exhibit
(10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
10.50 Transmission Agreement dated April 17, 1981, between the
Bonneville Power Administration and Montana Intertie Users (Colstrip
Project). (Exhibit (10)-56 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.51 Ownership and Operation Agreement dated as of May 6, 1981,
between the Company and other Owners of the Colstrip Project (Colstrip 3 and
4). (Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
10.52 Colstrip Project Transmission Agreement dated as of May 6, 1981,
between the Company and Owners of the Colstrip Project. (Exhibit (10)-58 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.53 Common Facilities Agreement dated as of May 6, 1981, between the
Company and Owners of Colstrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.54 Agreement for the Purchase of Power dated as of October 29,
1984, between South Fork II, Inc. and the Company (Weeks Falls Hydroelectric
Project). (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.55 Agreement for the Purchase of Power dated as of October 29,
1984, between South Fork Resources, Inc. and the Company (Twin Falls
Hydroelectric Project). (Exhibit (10)-61 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.56 Agreement for Firm Purchase Power dated as of January 4, 1988,
between the City of Spokane, Washington, and the Company (Spokane Waste
Combustion Project). (Exhibit (10)-62 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.57 Agreement for Evaluating, Planning and Licensing dated as of
February 21, 1985 and Agreement for Purchase of Power dated as of February
21, 1985 between Pacific Hydropower Associates and the Company (Koma Kulshan
Hydroelectric Project). (Exhibit (10)-63 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.58 Power Sales Agreement dated as of August 1, 1986, between
Pacific Power & Light Company and the Company. (Exhibit (10)-64 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987, Commission
File No. 1-4393)
67
10.59 Agreement for Purchase and Sale of Firm Capacity and Energy
dated as of August 1, 1986 between The Washington Water Power Company and the
Company. (Exhibit (10)-65 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.60 Amendment dated as of June 1, 1968, to Power Sales Contract
between Public Utility District No. 1 of Chelan County, Washington and the
Company (Rocky Reach Project). (Exhibit (10)-66 to Annual Report on Form 10-
K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.61 Coal Supply Agreement dated as of October 30, 1970, between the
Washington Irrigation & Development Company and the Company and other Owners
of the Centralia Thermal Project (Centralia Generating Plant). (Exhibit (10)-
67 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.62 Interruptible Natural Gas Service Agreement dated as of May 14,
1980, between Cascade Natural Gas Corporation and the Company (Whitehorn
Combustion Turbine). (Exhibit (10)-68 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.63 Interruptible Natural Gas Service Agreement dated as of January
31, 1983, between Cascade Natural Gas Corporation and the Company (Fredonia
Generating Station). (Exhibit (10)-69 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.64 Interruptible Gas Service Agreement dated May 14, 1981, between
Washington Natural Gas Company and the Company (Fredrickson Generating
Station). (Exhibit (10)-70 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.65 Settlement Agreement dated April 24, 1987, between Public
Utility District No. 1 of Chelan County, the National Marine Fisheries
Service, the State of Washington, the State of Oregon, the Confederated
Tribes and Bands of the Yakima Indian Nation, Colville Indian Reservation,
Umatilla Indian Reservation, the National Wildlife Federation and the Company
(Rock Island Project). (Exhibit (10)-71 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.66 Amendment No. 2 dated as of September 1, 1981, and Amendment No.
3 dated September 14, 1987, to Coal Supply Agreement between Western Energy
Company and the Company and the other Owners of Colstrip 3 and 4. (Exhibit
(10)-72 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
10.67 Amendatory Agreement No. 1 dated August 27, 1982, and Amendatory
Agreement No. 2 dated August 27, 1982, to the Power Sales Contract between
the Company and the Bonneville Power Administration dated August 27, 1982.
(Exhibit (10)-73 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
68
10.68 Transmission Agreement dated as of December 30, 1987, between
the Bonneville Power Administration and the Company (Rock Island Project).
(Exhibit (10)-74 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1988, Commission File No. 1-4393)
10.69 Agreement for Purchase and Sale of Firm Capacity and Energy
between The Washington Water Power Company and the Company dated as of
January 1, 1988. (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the
quarter ended March 31, 1988, Commission File No. 1-4393)
10.70 Amendment dated as of August 10, 1988, to Agreement for Firm
Purchase Power dated as of January 4, 1988, between the City of Spokane,
Washington, and the Company (Spokane Waste Combustion Project).(Exhibit (10)-
76 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988,
Commission File No. 1-4393)
10.71 Agreement for Firm Power Purchase dated October 24, 1988,
between Northern Wasco People's Utility District and the Company (The Dalles
Dam North Fishway). (Exhibit (10)-77 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1988, Commission File No. 1-4393)
10.72 Agreement for the Purchase of Power dated as of October 27,
1988, between Pacific Power & Light Company (PacifiCorp) and the Company.
(Exhibit (10)-78 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1988, Commission File No. 1-4393)
10.73 Agreement for Sale and Exchange of Firm Power dated as of
November 23, 1988, between the Bonneville Power Administration and the
Company. (Exhibit (10)-79 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1988, Commission File No. 1-4393)
10.74 Agreement for Firm Power Purchase, dated as of February 24,
1989, between Sumas Energy, Inc. and the Company. (Exhibit (10)-1 to
Quarterly Report on Form 10-Q for the quarter ended March 31, 1989,
Commission File No. 1-4393)
10.75 Settlement Agreement, dated as of April 27, 1989, between Public
Utility District No. 1 of Douglas County, Washington, Portland General
Electric Company, PacifiCorp, The Washington Water Power Company and the
Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q the for quarter
ended September 30, 1989, Commission File No. 1-4393)
10.76 Agreement for Firm Power Purchase (Thermal Project), dated as of
June 29, 1989, between San Juan Energy Company and the Company. (Exhibit
(10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30,
1989, Commission File No. 1-4393)
10.77 Agreement for Verification of Transfer, Assignment and
Assumption, dated as of September 15, 1989, between San Juan Energy Company,
March Point Cogeneration Company and the Company. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1989,
Commission File No. 1-4393)
69
10.78 Power Sales Agreement between The Montana Power Company and the
Company, dated as of October 1, 1989. (Exhibit (10)-4 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-
4393)
10.79 Conservation Power Sales Agreement dated as of December 11,
1989, between Public Utility District No. 1 of Snohomish County and the
Company. (Exhibit (10)-87 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1989, Commission File No. 1-4393)
10.80 Memorandum of Understanding dated as of January 24, 1990,
between the Bonneville Power Administrator and The Washington Public Power
Supply System, Portland General Electric Company, Pacific Power & Light
Company, The Montana Power Company, and the Company. (Exhibit (10)-88 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1989,
Commission File No. 1-4393)
10.81 Amendment No. 1 to Agreement for the Assignment of Power from
the Centralia Thermal Project dated as of January 1, 1990, between Public
Utility District No. 1 of Grays Harbor County, Washington, and the Company.
(Exhibit (10)-89 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1990, Commission File No. 1-4393)
10.82 Preliminary Materials and Equipment Acquisition Agreement dated
as of February 9, 1990, between Northwest Pipeline Corporation and the
Company. (Exhibit (10)-90 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1990, Commission File No. 1-4393)
10.83 Amendment No. 1 to the Colstrip Project Transmission Agreement
dated as of February 14, 1990, among the Montana Power Company, The
Washington Water Power Company, Portland General Electric Company, PacifiCorp
and the Company. (Exhibit (10)-91 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.84 Settlement Agreement dated as of February 27, 1990, among United
States of America Department of Energy acting by and through the Bonneville
Power Administrator, the Washington Public Power Supply System, and the
Company. (Exhibit (10)-92 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1990, Commission File No. 1-4393)
10.85 Amendment No. 1 to the Fifteen-Year Power Sales Agreement dated
as of April 18, 1990, between Pacificorp and the Company. (Exhibit (10)-93
to Annual Report on Form 10-K for the fiscal year ended December 31, 1990,
Commission File No. 1-4393)
10.86 Settlement Agreement dated as of October 1, 1990, among Public
Utility District No. 1 of Douglas County, Washington, the Company, Pacific
Power and Light Company, The Washington Water Power Company, Portland General
Electric Company, the Washington Department of Fisheries, the Washington
Department of Wildlife, the Oregon Department of Fish and Wildlife, the
National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the
Confederated Tribes and Bands of the Yakima Indian Nation, the Confederated
70
Tribes of the Umatilla Reservation, and the Confederated Tribes of the
Colville Reservation. (Exhibit (10)-95 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.87 Agreement for Firm Power Purchase dated July 23, 1990, between
Trans-Pacific Geothermal Corporation, a Nevada corporation, and the Company.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March
31, 1991, Commission File No. 1-4393)
10.88 Agreement for Firm Power Purchase dated July 18, 1990, between
Wheelabrator Pierce, Inc., a Delaware corporation, and the Company. (Exhibit
(10)-2 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991,
Commission File No. 1-4393)
10.89 Agreement for Firm Power Purchase dated September 26, 1990,
between Encogen Northwest, L.P., A Delaware Corporation and the Company.
(Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended March
31, 1991, Commission File No. 1-4393)
10.90 Agreement for Firm Power Purchase (Thermal Project) dated
December 27, 1990, among March Point Cogeneration Company, a California
general partnership comprising San Juan Energy Company, a California
corporation; Texas-Anacortes Cogeneration Company, a Delaware corporation;
and the Company. (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the
quarter ended March 31, 1991, Commission File No. 1-4393)
10.91 Agreement for Firm Power Purchase dated March 20, 1991, between
Tenaska Washington, Inc. a Delaware corporation, and the Company. (Exhibit
(10)-1 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991,
Commission File No. 1-4393)
10.92 Letter Agreement dated April 25, 1991, between Sumas Energy,
Inc., and the Company, to amend the Agreement for Firm Power Purchase dated
as of February 24, 1989. (Exhibit (10)-2 to Quarterly Report on Form 10-Q
for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.93 Amendment dated June 7, 1991, to Letter Agreement dated April
25, 1991, between Sumas Energy, Inc., and the Company. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission
File No. 1-4393)
10.94 Amendatory Agreement No. 3, dated August 1, 1991, to the Pacific
Northwest Coordination Agreement, executed September 15, 1964, among the
United States of America, the Company and most of the other major electrical
utilities in the Pacific Northwest. (Exhibit (10)-4 to Quarterly Report on
Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.95 Amendment dated July 11, 1991, to the Agreement for Firm Power
Purchase dated September 26, 1990, between Encogen Northwest, L.P., a
Delaware limited partnership and the Company. (Exhibit (10)-1 to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1991, Commission File
No. 1-4393)
71
10.96 Agreement between the 40 parties to the Western Systems Power
Pool (the Company being one party) dated July 27, 1991. (Exhibit (10)-2 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1991,
Commission File No. 1-4393)
10.97 Memorandum of Understanding between the Company and the
Bonneville Po wer Administration dated September 18, 1991. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1991,
Commission File No. 1-4393)
10.98 Amendment of Seasonal Exchange Agreement, dated December 4,
1991, between Pacific Gas and Electric Company and the Company. (Exhibit
(10)-107 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.99 Capacity and Energy Exchange Agreement, dated as of October 4,
1991, between Pacific Gas and Electric Company and the Company. (Exhibit
(10)-108 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.100 Intertie and Network Transmission Agreement, dated as of October
4, 1991, between Bonneville Power Administration and the Company. (Exhibit
(10)-109 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.101 Amendatory Agreement No. 4, executed June 17, 1991, to the Power
Sales Agreement dated August 27, 1982, between the Bonneville Power
Administration and the Company. (Exhibit (10)-110 to Annual Report on Form
10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.102 Amendment to Agreement for Firm Power Purchase, dated as of
September 30, 1991, between Sumas Energy, Inc. and the Company. (Exhibit
(10)-112 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.103 Centralia Fuel Supply Agreement, dated as of January 1, 1991,
between Pacificorp Electric Operations and the Company and other Owners of
the Centralia Steam-Electric Power Plant. (Exhibit (10)-113 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1991, Commission File No.
1-4393)
10.104 Agreement for Firm Power Purchase dated August 10, 1992, between
Pyrowaste Corporation, Puget Sound Pyroenergy Corporation and the Company.
(Exhibit (10)-114 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, Commission File No. 1-4393)
10.105 Memorandum of Termination dated August 31, 1992, between Encogen
Northwest, L.P. and the Company. (Exhibit (10)-115 to Annual Report on Form
10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.106 Agreement Regarding Security dated August 31, 1992, between
Encogen Northwest, L.P. and the Company. (Exhibit (10)-116 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
72
10.107 Consent and Agreement dated December 15, 1992, between the
Company, Encogen Northwest, L.P. and The First National Bank of Chicago, as
collateral agent. (Exhibit (10)-117 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.108 Subordination Agreement dated December 17, 1992, between the
Company, Encogen Northwest, L.P., Rolls-Royce & Partners Finance Limited and
The First National Bank of Chicago. (Exhibit (10)-118 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-
4393)
10.109 Letter Agreement dated December 18, 1992, between Encogen
Northwest, L.P. and the Company regarding arrangements for the application of
insurance proceeds. (Exhibit (10)-119 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.110 Guaranty of Ensearch Corporation in favor of the Company dated
December 15, 1992. (Exhibit (10)-120 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.111 Letter Agreement dated October 12, 1992, between Tenaska
Washington Partners, L.P. and the Company regarding clarification of issues
under the Agreement for Firm Power Purchase. (Exhibit (10)-121 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1992, Commission
File No. 1-4393)
10.112 Consent and Agreement dated October 12, 1992, between the
Company, and The Chase Manhattan Bank, N.A., as agent. (Exhibit (10)-122 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1992,
Commission File No. 1-4393)
10.113 Settlement Agreement dated December 29, 1992, between the
Company and the Bonneville Power Administration (BPA) providing for power
purchase by BPA. (Exhibit (10)-123 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.114 Contract with W. S. Weaver, Executive Vice President & Chief
Financial Officer, dated April 24, 1991. (Exhibit 10.114 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1993, Commission File No. 1-
4393)
10.115 General Transmission Agreement dated as of December 1, 1994,
between the Bonneville Power Administration and the Company (BPA Contract No.
DE-MS79-94BP93947) (Exhibit 10.115 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1994, Commission File No. 1-4393)
10.116 PNW AC Intertie Capacity Ownership Agreement dated as of October
11, 1994 between the Bonneville Power Administration and the Company (BPA
Contract No. DE-MS79-94BP94521) (Exhibit 10.116 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, Commission File No. 1-4393)
*12-a Statement setting forth computation of ratios of earnings to
fixed charges (1991 through 1995).
73
*12-b Statement setting forth computation of ratios of earnings to
combined fixed charges and preferred stock dividends (1991 through 1995).
*21 List of subsidiaries.
*23 Consent of accountants.
*27 Financial Data Schedule
_________________________________
*Filed herewith.
74