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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, 1994
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 61
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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, 1994 was approximately $1,278,978,607.
The number of shares of the registrant's common stock outstanding at January
31, 1995 was 63,640,861.
Documents Incorporated by Reference
The Company's definitive proxy statement for its annual meeting of
shareholders on May 9, 1995, is incorporated by reference in Part III hereof.
INDEX
Item Page
No. No.
Part I
1. Business................................................. 1
The Company.............................................. 1
Regulation and Rates..................................... 2
Power Resources.......................................... 3
Construction Financing................................... 9
Environment.............................................. 9
Operating Statistics.....................................12
Executive Officers.......................................14
2. Properties...............................................16
3. Legal Proceedings........................................16
4. Submission of Matters to a Vote of Security Holders......16
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................16
6. Selected Financial Data..................................17
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations............18
8. Financial Statements and Supplementary Data..............27
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure...................27
Part III
(Incorporated by reference from the Company's
definitive proxy statement issued in connection
with the 1994 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......................................27
Signatures...............................................28
Exhibit Index............................................61
DEFINITIONS
A.C. Alternating Current
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
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 1994, the Company had approximately 823,100 total
customers, consisting of 731,700 residential, 86,200 commercial, 3,900
industrial and 1,300 other customers. For the year 1994, the Company added
approximately 18,500 customers, an annual growth rate of 2.3%. Growth in
total kilowatt-hour sales increased 9.0% in 1994 over 1993, due to increased
sales to other utilities and continuing growth in the number of customers in
1994.
During 1994, the Company's billed revenues were derived 47% from
residential customers, 33% from commercial customers, 14% from industrial
customers and 6% from sales to other utilities and others. During this
period, the largest single customer accounted for 3.3% of the Company's
operating revenues. The average number of kilowatt-hours billed per
residential customer served by the Company in 1994 was 12,319 kilowatt-
hours. At December 31, 1994, the peak power resources of the Company were
approximately 5,400,000 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 are no longer significantly
influenced, up or down, by sales of surplus electricity to other utilities
or by variations in normal seasonal weather or hydro conditions. (See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Rate Matters")
The electric utility industry in general is facing a more competitive
environment, particularly in wholesale generation and industrial customer
markets, with the prospect of changes in utility regulation which could
accelerate competitive pressures. The National Energy Policy Act of 1992
has intensified competition in the wholesale electric generation market by
easing restrictions on producers of wholesale power and by authorizing the
Federal Energy Regulatory Commission ("FERC") to mandate access by wholesale
power producers to electric transmission systems owned by others. The
potential for increased competition at the retail level through mandated
retail wheeling has also been the subject of legislative and administrative
agency interest in a number of states including the state of Washington.
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Retail wheeling is the term for regulatory changes that would allow
competing electric suppliers access to transmission and distribution lines
owned by others to distribute power to any industrial, commercial or
residential customer, regardless of service territory boundaries. In April
1994, utility regulators in California proposed a plan to open competition
in the sale of electricity at the retail level, suggesting that both
industrial and residential customers be allowed to shop freely for
electricity among competing suppliers. Recommendations by the utility
regulators to the California legislature are expected by the end of 1995.
In December 1994, the Washington Utilities and Transportation Commission
(the "Washington Commission")issued a notice of inquiry seeking comments
from utility companies, ratepayers and other interested parties on costs and
benefits of retail competition and on creating a new regulatory structure to
better accommodate the electric utility industry as it evolves towards
retail competition. 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
view that competitive developments are likely to increase business risks in
the electric utility industry, with resulting pressures on utility credit
quality and investor returns. The Company and other electric utilities now
face an increasing prospect of competition for customers and resources from
other investor-owned utilities, government agencies, independent power
producers, exempt wholesale power producers, industrial customers developing
cogeneration and other power resources, and suppliers of natural gas and
other fuels.
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 has also
conducted joint customer service operations with Washington Natural Gas
Company to lower costs of serving customers of both utilities. 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 reading and billing, to utility customers and other utilities.
During the period from January 1, 1990 through December 31, 1994, the
Company made gross utility plant additions of $834 million and retirements
of $105 million. Gross electric utility plant at December 31, 1994 was
approximately $3.3 billion which consisted of 46% distribution, 27%
generation, 15% transmission and 12% general plant and other.
The Company had 2,221 full-time equivalent employees on December 31,
1994, down from 2,775 at the end of 1992. This represents a workforce
reduction of 20% over the last two years.
REGULATION AND RATES
The Company is subject to the regulatory authority of (1) the
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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 1994, the Company's total energy production was supplied 30% by
its own resources, 25% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydroelectric projects
on the Columbia River, 44% from other firm purchases and 1% from non-firm
purchases.
The following table shows the Company's resources at December 31, 1994,
and energy production during the year:
Peak Power Resources at
December 31, 1994 1994 Energy Production
----------------------- ----------------------
Kilowatts % Kilowatt-Hours %
--------- ----- -------------- -----
(Thousands)
Purchased Resources:
Columbia River
PUD Contracts (Hydro) 1,469,591 27.2 5,841,169 25.2
Other Hydro(a) 699,325 13.0 3,711,797 16.0
Thermal(a) 1,446,914 26.8 6,627,304 28.6
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Total Purchased 3,615,830 67.0 16,180,270 69.8
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Company-owned Resources:
Hydro 309,950 5.7 1,284,384 5.5
Coal 771,900 14.3 5,527,600 23.8
Natural gas/oil 702,350 13.0 199,949 0.9
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Total Company-owned 1,784,200 33.0 7,011,933 30.2
- ----------------------------------------------------------------------------
Total Capability 5,400,030 100.0 23,192,203 100.0
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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.
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,
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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, an affiliate of Montana Power - one of the joint
owners, under the terms of long-term coal supply agreements, with escalation
provisions to cover actual mining cost increases and inflationary factors.
These contracts are expected to satisfy the majority of the requirements for
the units over their anticipated useful life.
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. A dispute exists between the buyers, including the Company,
and the seller on this reopener. This dispute was arbitrated in January of
1995 and a decision on the arbitration is expected in the first quarter of
1995. The outcome is not expected to have a material adverse impact on the
financial condition, results of operations or liquidity of the Company.
There are several issues pending between the buyers, including the
Company and the seller, under the Colstrip 3 and 4 Coal Supply Agreement.
On February 23, 1995, the buyers, other than Montana Power, gave
Western Energy Company and Montana Power written notice of their intent to
submit a number of these issues to arbitration.
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 1912 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 combustion turbine units
(89,100 KW each) installed during 1981; and two 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. The Company has not entered into
contracts which assure a future long-term supply or price of fuel for the
Company's combustion turbines, and the future availability and prices of
fuel for the Company's combustion turbines are not assured.
The Company has applied to the FERC for an initial license for its
existing and operating White River project and authorization to install an
additional 14,000 KW generating unit. The initial license for the
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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.
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 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 average
cost of power purchased from these projects is approximately 12.1 mills per
KWH.
As of December 31, 1994, the Company was entitled to purchase portions
of the power output of the PUDs' projects as set forth in Note 16 to the
Consolidated Financial Statements.
The Company has contracted to purchase a share of the output of the
original units of the Rock Island Project that equals 61.4% through June 30,
1995, 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. 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 34.8% and is expected to decrease to 33.6% by
September 1, 1995. However, the Company's share of the output can be
reduced to 31.3% at any time 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.
The eleven turbines at Rocky Reach are in the process of being
replaced. Turbine replacement is planned for all ten units at Wanapum.
Also, as a result of FERC settlements, it is anticipated that installation
of fish bypasses will be required at Rocky Reach, Rock Island, Priest
Rapids and Wanapum Dams. These and other multi-year capital projects are
expected to result in increases in annual power costs as they progress. The
Company expects the increases in power costs, due to debt service for
capital expenditures, to average 2.5% to 3.0% annually for the next five
years.
In 1964, the Company and fifteen other utilities and agencies in the
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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. A 1995 biological
opinion from the National Marine Fisheries Service ("NMFS"), if implemented
in its present form, could reduce the benefits 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 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 storage on
the upper Columbia River. As a result of this storage, 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 (111,524 KW capacity and 49,993 KW average energy in the 1994-
95 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 38,032 KW.
Late in 1994, the United States (through the BPA) and Canada signed a
Memorandum of Understanding regarding the disposition of the Canadian share
of benefits ("Entitlement") from 1998 to 2024. For a payment of $180
million the United States will purchase a portion of the Entitlement
capacity. BPA and Canadian negotiators are working on a definitive
agreement. Concurrently, BPA negotiators and representatives of
participants in the five Mid Columbia projects from which the Company
purchases power are developing associated agreements which will define the
amount of payment, if any, and 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. The settlement includes a Settlement Exchange Agreement
("Bonneville Exchange Power Contract") under which the Company is receiving
from BPA for a period of approximately 30.5 years, beginning January 1,
1987, a certain amount of electric power determined by a formula and
depending on the equivalent annual availability factors of several surrogate
nuclear plants. The power is received 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
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deliveries of 5,833,333 MWH. BPA may request energy at times not needed by
the Company during the months of September through June of each contract
year. The payment to the Company for such energy would be based on the
actual costs to produce such energy up to the operating and maintenance
costs of the Company's oil and natural gas fired combustion turbines.
On April 4, 1988, the Company executed a 15-year contract 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.
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, or earlier, if BPA provides the Company with a five-year notice
that it no longer has surplus energy available to support the power sale.
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 has filed a notice of removal of the Montana State
Court action to the Federal District Court in Montana. On March 7, 1995,
the Company filed a lawsuit in the United Stated 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 $39 million in power costs, which are due upon termination
under contract provisions.
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 conser-
vation 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
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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
- -------------------------------------------
The Company has contracted to purchase the output from a number of non-
utility generating resources. The Company currently has available 648 MW of
capacity from natural gas fired cogeneration, 40.9 MW from small hydro
generation and 28 MW from municipal solid waste and others. Payments by the
Company to owners of these non-utility generating resources are subject to
the delivery of power. (See Note 16 to the Consolidated Financial
Statements)
Energy Conservation
- -------------------
The Company offers programs designed to help new and existing customers
conserve electric energy. In addition to providing energy audits and
analyses, the Company may provide grants and rebates to encourage the
installation of energy conservation measures in customer facilities. Energy
conservation measures installed in 1994 are expected to result in annualized
savings of approximately 189,400 MWH.
The Company's energy conservation expenditures are accumulated,
included in rate base and amortized to expense over a ten year period at the
direction of the Washington Commission. The Company's total unamortized
conservation balance, at December 31, 1994, was $241 million. The amount
included in rate base by the Washington Commission in its September 1994
PRAM order, based on expenditures through April 30, 1994, was $229 million.
Conservation investments made from May 1, 1994 to December 31, 1994 are
expected to be included in rates beginning October 1, 1995. The Washington
Commission has authorized the Company to accrue, as non-cash income, the
carrying costs on energy conservation expenditures until such investments
are reflected in rates. (See "Management's Discussion and Analysis of
Financial Condition and Results of Operations.")
The energy conservation grants the Company makes to its customers to
invest in energy efficiency improvements to their homes and businesses do
not produce collateral which the Company can use to finance those grants.
In principle, therefore, energy conservation has been financed by the
Company entirely through the use of equity capital. To remedy this
situation, the State of Washington enacted a new law effective June 9, 1994.
This new law provides, if certain conditions are met, that a utility would
8
be able to issue securities backed by a statutory requirement that rate
revenues be provided to repay those securities. The law provides the
Company, with the Washington Commission's approval, with an avenue to
refinance its existing investment in energy conservation and to finance new
conservation investment in a more cost-effective manner.
On February 16, 1995, the Company filed an application with the
Washington Commission for approval to issue securities for the purpose of
selling to a trust energy conservation investments currently included in
customer rates.
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 1995 and 1996 to be $154.9 million and $198.1 million,
respectively. The Company expects to fund an average of 72% of its
estimated construction expenditures (excluding AFUDC and AFUCE) in 1995 and
1996 from cash from operations (net of dividends, AFUDC and AFUCE), and to
fund the balance through the sale of securities. (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, 1994, the Company
could issue (i) approximately $745 million of additional first mortgage
bonds or (ii) approximately $373 million of additional preferred stock at an
assumed dividend rate of 8.55% 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 $22.6
million for the period 1995 through 1997. 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
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four sites under which the Company has paid approximately $7.6 million. To
date, the Company has recovered $3.6 million from its insurance companies in
connection with remediation and legal costs and expects to recover an
additional $3.1 million in the next twelve months. Estimated future
remediation costs at these four sites are expected to be $0.8 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.
In addition, the Company has remediated two locations at the Company's
Electron Generating Station under provisions of the state's Model Toxics
Control Act beginning in 1991 and completed in 1992. A final remedial
report has been filed with and reviewed by the Washington Department of
Ecology. No further action by the Company is expected to be required.
The Company also participated in a joint research project with the
Electric Power Research Institute to clean up the Snoqualmie Railroad site
in the town of Snoqualmie, Washington. The site has been leased from the
Company since 1959 by the non-profit Puget Sound Railway Historical
Association. The contamination consists of heavy petroleum hydrocarbons
which were used as lubricants for railroad equipment. The purpose of the
project was to provide a field demonstration of new technologies to treat
heavy molecular weight petroleum hydrocarbons in soil. Remediation of the
research project site was completed in February 1994.
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. Estimated future remediation costs at
Company-owned sites was $2.7 million at December 1994. (See Note 16 to the
Consolidated Financial Statements for further discussion of environmental
obligations and the related regulatory treatment.)
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.
10
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. The Company's share of energy
production from the Mid-Columbia during 1994 was approximately 5,841,000 MWH
and the total production from all resources was more than 23,192,000 MWH.
Other species are also proposed for listing as endangered species and
could further restrict system flexibility and energy production.
11
Puget Sound Power & Light Company
OPERATING STATISTICS
Year Ended or on December 31 1994 1993 1992 1991 1990
- --------------------------------------------------------------------------------------------
Operating revenues by classes
(thousands):
- --------------------------------------------------------------------------------------------
Residential $ 532,124 $ 502,037 $ 443,490 $480,356 $452,385
Commercial 375,751 356,586 323,764 310,824 288,346
Industrial 163,574 150,063 138,416 127,164 122,983
Other consumers 38,759 28,189 35,779 26,897 25,731
- --------------------------------------------------------------------------------------------
Operating revenues billed
to consumers 1,110,208 1,036,875 941,449 945,241 889,445
Unbilled revenues -
net increase (decrease) (2,522) 14,409 15,080 (16,216) 19,171
PRAM accrual 25,835 42,100 42,119 670 --
- --------------------------------------------------------------------------------------------
Total operating revenues
from consumers 1,133,521 1,093,384 998,648 929,695 908,616
Other utilities 60,537 19,494 26,322 27,074 26,657
- --------------------------------------------------------------------------------------------
Total operating revenues 1,194,058 1,112,878 $1,024,970 $956,769 $935,273
- --------------------------------------------------------------------------------------------
Number of customers (average):
Residential 723,566 708,123 692,100 673,883 651,060
Commercial 85,203 82,875 80,963 78,691 76,536
Industrial 3,851 3,715 3,659 3,574 3,502
Other 1,325 1,289 1,254 1,226 1,193
- --------------------------------------------------------------------------------------------
Total customers (average) 813,945 796,002 777,976 757,374 732,291
KWH generated, purchased
and interchanged (thousands):
Total Company generated 7,011,932 6,414,311 7,420,058 6,819,348 6,630,767
Purchased power 16,268,042 14,608,899 13,408,522 14,770,597 14,212,117
Interchanged power (net) (87,771) 174,478 (118,346) (139,110) 62,964
- --------------------------------------------------------------------------------------------
Total energy output 23,192,203 21,197,688 20,710,234 21,450,835 20,905,848
Losses and Company use (1,291,322) (1,096,599) (1,202,194) (1,267,919) (1,334,337)
- --------------------------------------------------------------------------------------------
Total energy sales 21,900,881 20,101,089 19,508,040 20,182,916 19,571,511
- --------------------------------------------------------------------------------------------
Electric energy sales, KWH
(thousands):
Residential 8,913,903 8,974,787 8,297,293 8,906,470 8,364,737
Commercial 6,301,568 6,175,911 5,945,284 5,930,385 5,565,672
Industrial 3,724,931 3,690,473 3,704,450 3,598,683 3,559,574
Other consumers 200,622 196,246 193,563 185,879 182,568
- --------------------------------------------------------------------------------------------
Total energy billed
to consumers 19,141,024 19,037,417 18,140,590 18,621,417 17,672,551
Unbilled energy sales -
net increase (decrease) (72,352) 139,329 209,565 (309,279) 343,053
- --------------------------------------------------------------------------------------------
12
(Continued from prior page 1994 1993 1992 1991 1990
- --------------------------------------------------------------------------------------------
Total energy sales
to consumers 19,068,672 19,176,746 18,350,155 18,312,138 18,015,604
Sales to other
electric utilities 2,832,209 924,343 1,157,885 1,870,778 1,555,907
- --------------------------------------------------------------------------------------------
Total energy sales 21,900,881 20,101,089 19,508,040 20,182,916 19,571,511
- --------------------------------------------------------------------------------------------
Per residential customer:
Annual use (KWH) 12,319 12,674 11,989 13,217 12,848
Annual billed revenue $735.42 $708.97 $640.79 $712.82 $694.84
Billed revenue per KWH $.0597 $.0559 $.0534 $.0539 $.0541
Company-owned generation
capability - kilowatts:
Hydro 309,950 309,950 309,950 309,950 309,950
Steam 771,900 857,700 857,700 857,700 857,700
Other 702,350 702,350 702,350 702,350 702,350
- --------------------------------------------------------------------------------------------
Total 1,784,200 1,870,000 1,870,000 1,870,000 1,870,000
- --------------------------------------------------------------------------------------------
Heating degree days 4,341 4,691 4,090 4,556 4,773
% of normal of 30 year
average (5,121) 84.8% 91.6% 79.9% 89.0% 93.2%
Load factor 54.7% 52.5% 57.0% 54.8% 47.8%
13
EXECUTIVE OFFICERS AT DECEMBER 31, 1994:
Name Age Offices
- ---------------- --- ---------------------------------------------------
R. R. Sonstelie 49 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 50 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.
R. V. Myers 61 Senior Vice President since May 10, 1994;
Senior Vice President Operations 1985-1994;
Vice President Engineering and Operations 1983-1985;
Vice President Generation Resources 1980-1983.
G. B. Swofford 53 Senior Vice President Customer Operations since
May 10, 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 49 Senior Vice President Corporate & Regulatory
Relations since May 10, 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 55 Vice President Power Systems since 1980.
J. W. Eldredge 44 Chief Accounting Officer since October 10, 1994;
Corporate Secretary and Controller since 1993;
Controller since 1988; Manager Budgets and
Performance 1987-1988; Manager General Accounting
1984-1987.
G. N. Ferencz 48 Vice President Divisions since May 10, 1994; Director
Division Services 1992-1994; General Manager Thurston
Division 1990-1992; Division Administrator Southern
Division 1982-1990.
D. E. Gaines 37 Treasurer since October 10, 1994; Director Strategic
Planning 1992-1994; Manager Financial Planning 1986 -
1992.
14
J. L. Henry 49 Vice President Engineering and Operating Services
since January 11, 1994; Vice President Operations
Services 1991-1994; Director South Central Division
1990-1991; Director Division Operations 1984-1990.
C. A. Knutsen 48 Vice President Administration and Corporate Services
since February 10, 1994; Vice President Corporate
Planning 1989-1994; Director Strategic Planning
1987-1988; Manager Demand and Resource Evaluation
Project 1986-1987.
J. R. Lauckhart 46 Vice President Power Planning since 1991;
Director Power Planning 1986-1991.
Officers are elected for one-year terms.
15
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 Notes 10 and 16 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, 1994, was 62,364.
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, 1994, the balance of earnings reinvested in the business that
was not restricted as to dividends on common stock was approximately $251
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:
1994 1993
--------------------------- ---------------------------
Price Range Price Range
--------------- Dividends --------------- Dividends
Quarter Ended High Low Paid High Low Paid
- ------------- ------ ------ --------- ------ ------ ---------
March 31 24-7/8 22 $.46 28-3/4 26-1/8 $.45
June 30 22-3/4 16-1/2 $.46 29-3/8 26-1/4 $.46
September 30 20 18-3/8 $.46 29-3/4 25-5/8 $.46
December 31 21 19-3/8 $.46 26-7/8 23-1/2 $.46
16
ITEM 6. SELECTED FINANCIAL DATA
Year Ended December 31 1994 1993 1992 1991 1990
- ---------------------------- --------- ---------- ---------- ---------- ----------
(Thousands of Dollars except per share data)
Operating Revenue $1,194,058 $1,112,878 $1,024,970 $ 956,769 $ 935,273
Operating Income $ 193,498 $ 210,980 $ 214,670 $ 213,731 $ 215,376
Net Income $ 120,059 $ 138,327 $ 135,720 $ 132,777 $ 132,343
Income for Common Stock $ 104,328 $ 121,885 $ 121,836 $ 122,738 $ 119,948
Common Shares Outstanding -
Weighted Average 63,632,057 60,930,859 56,283,949 55,561,647 55,561,647
Earnings Per Common Share
(Note 1 to the
Financial Statements) $1.64 $2.00 $2.16 $2.21 $2.16
Dividends Per Common Share $1.84 $1.83 $1.79 $1.76 $1.76
Book Value Per Common Share $18.43 $18.65 $17.76 $16.96 $16.52
Total Assets at Year End* $3,463,770 $3,341,130 $2,997,721 $2,676,438 $2,602,536
Long-term Obligations $ 963,298 $1,036,079 $1,044,992 $1,052,309 $1,005,834
Redeemable Preferred Stock $ 91,242 $ 93,176 $ 93,822 $ 20,189 $ 28,766
* 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.
17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net income in 1994 was $120.1 million on operating revenues of $1.194
billion, compared to $138.3 million on operating revenues of $1.113 billion
in 1993 and $135.7 million on operating revenues of $1.025 billion in 1992.
Income for common stock was $104.3 million, $121.9 million and $121.8
million for 1994, 1993 and 1992, respectively.
Earnings per share in 1994 were $1.64 on 63.6 million weighted average
common shares outstanding during the period compared to $2.00 on 60.9
million weighted average common shares outstanding in 1993 and $2.16 on 56.3
million weighted average common shares outstanding in 1992.
Return on the average book value of the Company's common equity in 1994 was
8.9%, compared to 11.0% in 1993 and 12.6% in 1992. The dividend payout
ratio was 112.2% in 1994, compared to 91.5% in 1993 and 82.9% in 1992.
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.
Also contributing to this decline in net income was the reduction in the
Company's allowed rate of return on common equity from 12.8% to 10.5%
resulting from the Company's September 21, 1993 general rate order.
Total kilowatt-hour sales to ultimate consumers in 1994 were 19.1 billion,
compared with 19.2 billion in 1993 and 18.4 billion in 1992. Kilowatt-hour
sales to other utilities were 2.8 billion in 1994, 0.9 billion in 1993 and
1.2 billion in 1992.
The preferred stock dividend accrual decreased $0.7 million in 1994 compared
to 1993. The 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, Adjustable
Rate Cumulative Preferred Stock, Series A ($100 par value) in February 1994.
These decreases were partially offset by the issuance in February 1994 of
the $50 million, Adjustable Rate Cumulative Preferred Stock, Series B ($25
par value).
The preferred stock dividend accrual increased $2.6 million in 1993 and $3.8
million in 1992 compared to 1991 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. Lower dividend
rates associated with the FLEX DARTS were also an offsetting factor during
1992.
18
Years Ending December 31
Increase (Decrease) Over Preceding Year
(Dollars in Millions)
1994 1993 1992
- -----------------------------------------------------------------------
Operating revenues
General rate increase $27.0 $ 14.2 $ --
PRAM surcharge billed 29.6 48.8 44.8
Accrual of revenue under
the PRAM - Net (16.3) -- 41.5
BPA Residential Purchase and
Sale Agreement 2.3 (15.0) (25.1)
Sales to other utilities 41.0 (6.8) (0.8)
Load and other changes (2.4) 46.7 7.8
- -----------------------------------------------------------------------
Total operating revenue changes 81.2 87.9 68.2
- -----------------------------------------------------------------------
Operating expenses
Purchased and interchanged power 77.1 81.5 18.2
Fuel (5.5) (4.4) 11.9
Other operation expenses 26.0 5.9 9.9
Maintenance (2.5) (1.8) (0.4)
Depreciation and amortization 0.1 (7.2) 6.6
Taxes other than federal income taxes 7.2 6.1 4.8
Federal income taxes (3.7) 11.5 16.3
- -----------------------------------------------------------------------
Total operating expense changes 98.7 91.6 67.3
- -----------------------------------------------------------------------
Allowance for funds used during
construction ("AFUDC") (0.8) 1.5 (1.0)
Other income 1.0 (5.5) 12.3
Interest charges 1.0 (10.3) 9.3
- -----------------------------------------------------------------------
Net income changes ($18.3) $ 2.6 $ 2.9
=======================================================================
The following information pertains to the changes outlined in the table
above:
OPERATING REVENUES
Revenues since October 1, 1994, increased as a result of rates authorized
by the Washington Utilities and Transportation Commission (the "Washington
Commission") under the fourth Periodic Rate Adjustment Mechanism ("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. Revenues since October 1, 1992, increased as a result
of rates authorized by the Washington Commission under the second PRAM
filing. (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
19
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 in 1993 were higher due to PRAM rate adjustments and continuing
load growth. Revenues in 1992 were higher as a result of the recognition
of $6.7 million in September 1992 related to incentive payments authorized
by the Washington Commission for meeting energy conservation targets during
1991. These revenues were collected in rates beginning October 1, 1992.
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 $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. (See discussion of the Residential Purchase and Sale
Agreement under "Operating Revenues.") 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.
Purchased and interchanged power expenses increased $18.2 million in 1992.
Higher purchased power expenses of $42.3 million were influenced by new
firm power purchase contracts and higher costs on certain firm power
purchase contracts with other utilities. The Residential Purchase and Sale
Agreement with BPA resulted in a reduction of $23.9 million.
Fuel expense decreased $5.5 million in 1994 as the Company purchased
additional power from cogeneration facilities rather than run Company-owned
gas turbines to generate electricity. Fuel expense decreased $4.4 million
in 1993 due to decreased use of the coal-fired plants. Fuel expense
increased $11.9 million in 1992 over the previous year due to increased
usage of the coal-fired and gas turbine plants.
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. (See Note
11 to the Consolidated Financial Statements.) Also included was an
increase of $4.0 million in amortization expense associated with the
20
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.
Other operation expenses increased $9.9 million in 1992. Transmission
expense accounted for $5.3 million of the increase. Also contributing was
a $2.2 million rise in customer service expenses and a $1.5 million
increase in administration and general expenses.
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. Maintenance expense in 1992
was largely unchanged from levels of the previous year.
Depreciation and amortization expense increased $0.1 million in 1994
compared to the prior year. Increased depreciation expense related to
additional plant being 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 being
placed into service. Depreciation and amortization expense increased $6.6
million in 1992 as a result of additional plant being placed into service.
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. Taxes
other than federal income taxes increased $4.8 million in 1992. An
increase in Washington state property tax payments of $2.2 million
accounted for much of the increase.
Federal income taxes on operations decreased $3.7 million in 1994 compared
to the prior year 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. Federal income taxes on operations increased $16.3
million in 1992 due to an increase in pre-tax operating income and a change
in the method in which energy conservation expenditures are deducted for
federal tax purposes. (See Note 13 to the Consolidated Financial
Statements.)
21
AFUDC
(See Note 1 to the Consolidated Financial Statements.)
OTHER INCOME
Total 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, has been paid to the Company and 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 Federal Energy Regulatory Commission
("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.
Other income increased $12.3 million in 1992 over 1991 levels. This
increase was due in part to an increase of $4.2 million in Allowance for
Funds Used to Conserve Energy ("AFUCE"). The Washington Commission, in its
April 1, 1991 order authorizing the PRAM, ordered the Company to start
accruing carrying costs on energy conservation expenditures until such
investments are included in ratebase. These accruals commenced in May 1991
but did not become significant until the third quarter of 1991. The AFUDC
allowed by the Washington Commission in excess of the FERC maximum
contributed $2.0 million to the increase over 1991. In addition, other
income increased $3.8 million because of net income from subsidiaries of
$1.0 million in 1992 versus losses of $2.8 million in 1991 and $1.1 million
from lower non-operating federal income taxes.
INTEREST CHARGES
Interest charges, which consist of interest and amortization on long-term
debt and other interest, 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 compared to the prior
year. The increase was the result of higher average daily short-term
borrowings and higher weighted average interest rates in 1994 as compared
to 1993.
Interest charges decreased $10.3 million in 1993 compared to 1992.
22
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.
Interest charges increased $9.3 million in 1992 compared to the prior year.
Interest and amortization on long-term debt alone increased $4.7 million.
Contributing $24.0 million of new interest expense were 19 issues of
Secured Medium-Term Notes totaling $645 million issued over the previous 19
months. Partially offsetting this were $21.1 million in interest
reductions from First Mortgage Bond retirements or redemptions of $451
million over the same period. Also contributing an increase of $1.5
million were the effects of three issues of fixed rate pollution control
bonds that were used to refund floating rate pollution control bonds of
identical amounts. Other interest expense increased $4.6 million in 1992
compared to 1991. An interest charge of $5.3 million relating to a federal
income tax assessment was partially offset by lower short-term interest
rates in 1992.
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 $242.8 million in 1994 and are expected to
be approximately $154.9 million in 1995 and $198.1 million in 1996. The
ratio of cash from operations (net of dividends, AFUDC and AFUCE) to
construction expenditures (excluding AFUDC and AFUCE) was 49.2% in 1994.
The Company expects to fund an average of 72% of its total 1995 and 1996
estimated construction expenditures (excluding AFUDC and AFUCE) from cash
from operations (net of dividends, AFUDC and AFUCE) and the balance through
the sale of securities, the nature, amount and timing of which will be
subject to market and other relevant factors. The Company made a final
payment of $77.6 million in December 1994 for capacity rights to BPA's third
A.C. transmission line to the southwestern United States following an
initial payment of $8.0 million in May 1993. Construction expenditure
estimates are subject to periodic review and adjustment.
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 an additional $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, 1995, the Company has
issued $364 million in Series B Notes having an average coupon rate of
6.90%.
23
On February 1, 1994, the Company issued $55 million principal amount of
Secured Medium-Term Notes, Series B, due February 1, 2024, bearing interest
at 7.35% per annum. Proceeds of this issue were used to extinguish $50
million principal amount of the Company's First Mortgage Bonds, 9.625%
Series due 1997. The Company redeemed $24.5 million through a tender offer
completed February 7, 1994. A portfolio of U.S. Government Treasury
Securities was purchased to defease the remaining $25.5 million of the
bonds.
On February 14, 1994, the Company redeemed $15 million principal amount of
First Mortgage Bonds, 4.75% Series due May 1, 1994.
On May 27, 1994, the Company issued $30 million principal amount of Secured
Medium-Term Notes Series B, due May 27, 2004, bearing interest at 7.80% per
annum. Proceeds of this issue were used to pay down short-term debt.
In February 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 $200 million of preferred stock. In 1992, the
Company issued an aggregate of $150 million of preferred stock from this
shelf. On February 3, 1994, the Company issued $50 million Adjustable Rate
Cumulative Preferred Stock, Series B ($25 par value). The proceeds were
used to retire the $40 million principal amount of Adjustable Rate
Cumulative Preferred Stock, Series A ($100 par value) and to pay down short-
term debt.
Short-term borrowings from banks and the sale of commercial paper are used
to provide working capital for the construction program. At December 31,
1994, the Company had in place $176.5 million in lines of credit with
several banks, which provided liquidity support for outstanding commercial
paper of $139.6 million, effectively reducing the available borrowing
capacity under these lines of credit to $36.9 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 27, 1994 the Washington Commission issued two rate orders, one
regarding the case initiated by the Washington Commission to review the
prudence of nine of the Company's recent purchase power contracts, the other
related to an annual rate adjustment under the Washington Commission's PRAM.
In the order relating to the prudence review case, the Washington Commission
ruled that 1.2% of the contract payments on the Tenaska cogeneration
purchased power contract and 3% of the contract payments on the March Point
Phase II cogeneration purchased power contract should not be recovered in
rates. In light of the Washington Commission order, the Company, in
December 1994, reduced PRAM deferral revenue by $1.5 million, representing
the disallowance for the period from October 1, 1993 through December 31,
1994. On January 12, 1995, the Company filed a petition for review in King
24
County Superior Court appealing the Washington Commission's final order. No
disallowance was ordered in respect to the other seven purchased power
contracts under review.
On September 27, 1994 the Washington Commission also acted on the Company's
pending annual rate increase under the PRAM. The Company had requested a
$55.5 million revenue increase and the Washington Commission allowed $53.7
million. The items of revenue disallowed were the $1.6 million related to
the two purchased power contracts and $208,000 related to a $978,000
reduction that the Washington Commission ordered in the Company's rate base
for its conservation program. Previously deferred conservation program
costs of $690,000 were written off to expense in the third quarter of 1994
to conform deferred conservation program costs to the Washington
Commission's September 27, 1994 order.
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.
OTHER
The electric utility industry in general is facing a more competitive
environment, particularly in wholesale generation and industrial customer
markets, with the prospect of changes in utility regulation which could
accelerate competitive pressures. The National Energy Policy Act of 1992
has intensified competition in the wholesale electric generation market by
easing restrictions on producers of wholesale power and by authorizing the
FERC to mandate access by wholesale power producers to electric transmission
systems owned by others. The potential for increased competition at the
retail level through mandated retail wheeling has also been the subject of
legislative and administrative agency interest in a number of states
including the state of Washington. Retail wheeling is the term for
regulatory changes that would allow competing electric suppliers access to
transmission and distribution lines owned by others to distribute power to
any industrial, commercial or residential customer, regardless of service
territory boundaries. In April 1994 utility regulators in California
proposed a plan to open competition in the sale of electricity at the retail
level, suggesting that both industrial and residential customers be allowed
to shop freely for electricity among competing suppliers. Recommendations
by the utility regulators to the California legislature are expected by the
end of 1995. In December 1994 the Washington Commission issued a notice of
inquiry seeking comments from utility companies, ratepayers and other
interested parties on costs and benefits of retail competition and on
creating a new regulatory structure to better accommodate the electric
utility industry as it evolves towards retail competition. 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 view that competitive developments are likely to
increase business risks in the electric utility industry, with resulting
pressures on utility credit quality and investor returns. The Company and
other electric utilities now face an increasing prospect of competition for
customers and resources from other investor-owned utilities, government
25
agencies, independent power producers, exempt wholesale power producers,
industrial customers developing cogeneration and other power resources, and
suppliers of natural gas and other fuels.
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 has also
conducted joint customer service operations with Washington Natural Gas
Company to lower costs of serving customers of both utilities. 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 reading and billing, to utility customers and other utilities.
In the first quarter of 1994, the Company offered to 650 manager-level and
eligible professional staff the opportunity to voluntarily leave or, if
eligible, to retire from the Company. The offer was accepted by 98
employees in March 1994. A charge of $6.9 million ($4.5 million or 7 cents
a share after-tax) was taken in the first quarter to reflect costs
associated with this program and is included in other operation expenses.
During the second quarter, 155 Company employees, including 131 bargaining
unit employees, elected to accept a second voluntary retirement package
offered by the Company. A charge of $9.6 million ($6.2 million or 10 cents
a share after-tax) was taken in the second quarter to reflect costs
associated with this program and is included in other operation expenses.
In the third and fourth quarters of 1994, the Company recorded charges
totaling $4.4 million ($2.9 million or 5 cents a share after-tax) for costs
related to the work force reductions described above and related
consolidation of facilities. These costs are also included in other
operation expenses.
The Company and BPA have entered into a letter of intent, subject to various
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 would involve a combination of existing facility upgrades and new
construction and is currently under environmental review. The Company's
efforts in this project are preliminary in nature and, as such, the Company
cannot give assurance that any construction will result.
The Company is in the process of 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
26
increasing cable failures in recent years. The Company is continuing to
analyze cable failure trends to find ways to mitigate the long term effect
of cable failures on customer service, within budgetary constraints. To
minimize the impact of increasing cable failures, the Company replaces a
certain amount of HMW cable each year. The Company estimates that the total
cost of replacing all 4,800 miles of cable will be approximately $550
million. With 458 miles of cable replaced to date, the Company expects to
spend $53 million during the period 1995-1998 for replacement of this cable.
For a discussion of environmental obligations, see Note 16 to the
Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See index on page 32.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE - NONE.
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 32.
2) Exhibits - see index on page 61.
(b) Reports on Form 8-K:
1) Form 8-K dated December 16, 1994, Item 5 - Other Events,
related to the Company's petition for reconsideration of the
Washington Commission's September 27, 1994 order.
27
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 28, 1995
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 28,
1995
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)
28
Signatures, continued
Phyllis J. Campbell Director
- ---------------------------
(Phyllis J. Campbell)
John D. Durbin Director
- ---------------------------
(John D. Durbin)
John W. Ellis Director
- ---------------------------
(John W. Ellis)
Director
- ---------------------------
(Daniel J. Evans)
Nancy L. Jacob Director
- ---------------------------
(Nancy L. Jacob)
R. Kirk Wilson Director
- ---------------------------
(R. Kirk Wilson)
29
Puget Sound Power & Light Company
Report of Management: February 28, 1995
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 has 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 and Chief Financial Officer and Controller
Officer (Chief Accounting
Officer)
30
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 32 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, 1994 and 1993, and the consolidated
results of its operations and its cash flows for each of the three years in
the period ended December 31, 1994 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.
As discussed in Notes 13 and 14, effective January 1, 1993, the Company
changed its method of accounting for income taxes and postretirement benefits
other than pensions.
Coopers & Lybrand L.L.P.
Seattle, Washington
February 10, 1995
31
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, 1994, 1993 and 1992........................................33
Consolidated Balance Sheets, December 31, 1994 and 1993...................34
Consolidated Statements of Capitalization, December 31, 1994 and 1993.....36
Consolidated Statements of Earnings Reinvested in the Business
for the years ended December 31, 1994, 1993 and 1992....................37
Consolidated Statements of Cash Flows for the years
ended December 31, 1994, 1993 and 1992..................................38
Notes to Consolidated Financial Statements................................39
SCHEDULE:
II. Valuation and Qualifying Accounts and Reserves for the
years ended December 31, 1994, 1993 and 1992........................60
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.
32
Consolidated Statements of Income
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
Year Ended December 31 1994 1993 1992
- --------------------------------------------------------------------------------------------
(Dollars in Thousands except per share amounts)
Operating Revenues $1,194,058 $1,112,878 $1,024,970
- --------------------------------------------------------------------------------------------
Operating Expenses:
Operation (Note 16):
Purchased and interchanged power 394,758 317,642 236,179
Fuel 47,166 52,654 57,014
Other (Notes 11 and 12) 203,476 177,444 171,555
Maintenance 51,342 53,900 55,706
Depreciation and amortization 115,738 115,690 122,931
Taxes other than federal income taxes (Note 11) 107,821 100,598 94,466
Federal income taxes (Note 13) 80,259 83,970 72,449
- --------------------------------------------------------------------------------------------
Total operating expenses 1,000,560 901,898 810,300
- --------------------------------------------------------------------------------------------
Operating Income 193,498 210,980 214,670
- --------------------------------------------------------------------------------------------
Other Income:
Allowance for funds used during construction
equity portion 530 2,301 443
Miscellaneous (Notes 10, 11 and 13) 12,290 11,277 16,761
- --------------------------------------------------------------------------------------------
Total other income - net 12,820 13,578 17,204
- --------------------------------------------------------------------------------------------
Income Before Interest Charges 206,318 224,558 231,874
- --------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 80,213 82,065 86,702
Allowance for funds used during construction
debt portion (3,667) (2,714) (3,046)
Other interest 5,782 2,915 9,691
Amortization of debt expense,
net of premium (Note 7) 3,931 3,965 2,807
- --------------------------------------------------------------------------------------------
Total interest charges 86,259 86,231 96,154
- --------------------------------------------------------------------------------------------
Net Income 120,059 138,327 135,720
- --------------------------------------------------------------------------------------------
Less Preferred Stock Dividend Accruals 15,731 16,442 13,884
- --------------------------------------------------------------------------------------------
Income for Common Stock $104,328 $121,885 $121,836
- --------------------------------------------------------------------------------------------
Common shares outstanding weighted average 63,632,057 60,930,859 56,283,949
Earnings per common share (Note 1) $1.64 $2.00 $2.16
============================================================================================
The accompanying notes are an integral part of the financial statements.
33
Consolidated Balance Sheets
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
Assets
December 31 1994 1993
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
Utility Plant:
Electric plant, at original cost (Notes 1, 2, 7 and 16) $3,306,854 $3,134,747
Less: Accumulated depreciation 1,039,943 981,535
- --------------------------------------------------------------------------------------------
Net utility plant 2,266,911 2,153,212
- --------------------------------------------------------------------------------------------
Other Property and Investments:
Investment in Bonneville Exchange Power Contract (Note 10) 101,309 108,002
Investment in terminated generating projects -- 12,612
Investment in and advances to subsidiaries 76,517 90,423
Energy conservation loans to customers 1,409 2,284
Other investments, at cost 12,203 15,960
- --------------------------------------------------------------------------------------------
Total other property and investments 191,438 229,281
Current Assets:
Cash (Note 9) 5,284 3,445
- --------------------------------------------------------------------------------------------
Accounts receivable:
Customers 80,503 75,216
Other 27,695 16,170
Less allowance for doubtful accounts 610 523
- --------------------------------------------------------------------------------------------
Total accounts receivable 107,588 90,863
- --------------------------------------------------------------------------------------------
Estimated unbilled revenue 86,745 89,266
PRAM accrued revenues 47,178 37,212
Materials and supplies, at average cost 49,543 52,383
Prepayments and Other 5,260 5,185
- --------------------------------------------------------------------------------------------
Total current assets 301,598 278,354
- --------------------------------------------------------------------------------------------
Long-Term Assets:
Regulatory asset for deferred income taxes (Note 13) 275,296 280,639
PRAM accrued revenues (net of current portion) 63,663 47,795
Unamortized debt expense 8,076 8,550
Unamortized energy conservation charges 239,500 231,331
Other 117,288 111,968
- --------------------------------------------------------------------------------------------
Total long-term assets 703,823 680,283
- --------------------------------------------------------------------------------------------
Total Assets $3,463,770 $3,341,130
============================================================================================
The accompanying notes are an integral part of the financial statements.
34
- -------------------------------------------------------------------------------
Capitalization and Liabilities
December 31 1994 1993
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
Capitalization (see "Consolidated Statements of Capitalization"):
Common equity $1,172,729 $1,186,475
Preferred stock not subject to mandatory redemption 125,000 115,000
Preferred stock subject to mandatory redemption 91,242 93,176
Long-term debt 963,298 1,036,079
- --------------------------------------------------------------------------------------------
Total capitalization 2,352,269 2,430,730
- --------------------------------------------------------------------------------------------
Current Liabilities:
Accounts payable 58,025 53,449
Short-term debt (Notes 8 and 9) 234,454 149,306
Current maturities of long-term debt (Note 7) 108,000 23,000
Accrued expenses:
Taxes 40,337 39,124
Salaries and wages 20,809 26,289
Interest 26,181 23,832
Other 25,018 22,216
- --------------------------------------------------------------------------------------------
Total current liabilities 512,824 337,216
- --------------------------------------------------------------------------------------------
Deferred Income Taxes:
Deferred Income Taxes (Note 13) 541,501 528,665
Investment tax credits 726 1,142
- --------------------------------------------------------------------------------------------
Total deferred income taxes 542,227 529,807
- --------------------------------------------------------------------------------------------
Other Deferred Credits:
Customer advances for construction 21,939 19,131
Other 34,511 24,246
- --------------------------------------------------------------------------------------------
Total other deferred credits 56,450 43,377
- --------------------------------------------------------------------------------------------
Commitments and Contingencies
(Notes 1, 10, 12, 13, 14, 15 and 16) -- --
Total Capitalization and Liabilities $3,463,770 $3,341,130
============================================================================================
The accompanying notes are an integral part of the financial statements.
35
Consolidated Statements of Capitalization
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
December 31 1994 1993
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
Common Equity:
Common stock - ($10 stated value) - 80,000,000 shares
authorized, 63,640,861 and 63,629,416 shares
outstanding (Notes 3 and 15) $ 636,409 $ 636,294
Additional paid-in capital (Notes 5 and 15) 328,753 329,922
Earnings reinvested in the business (Note 6) 207,567 220,259
- --------------------------------------------------------------------------------------------
Total common equity 1,172,729 1,186,475
- --------------------------------------------------------------------------------------------
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
$100 par value:*
Adjustable Rate, Series A - 400,000 shares authorized
and outstanding in 1993 -- 40,000
$25 par value:*
Adjustable Rate, Series B - 2,000,000 shares authorized
and outstanding 50,000 --
- --------------------------------------------------------------------------------------------
Total preferred stock not subject to mandatory redemption 125,000 115,000
- --------------------------------------------------------------------------------------------
Preferred Stock Subject To Mandatory Redemption - cumulative
(Notes 4 and 9):
$100 par value:*
4.84% series - 150,000 shares authorized,
47,956 and 52,061 shares outstanding 4,796 5,206
4.70% series - 150,000 shares authorized,
66,215 and 69,406 shares outstanding 6,621 6,941
8% series - 150,000 shares authorized,
48,253 and 60,296 shares outstanding 4,825 6,029
7.75% series - 750,000 shares authorized and outstanding 75,000 75,000
- --------------------------------------------------------------------------------------------
Total preferred stock subject to mandatory redemption 91,242 93,176
- --------------------------------------------------------------------------------------------
Long-Term Debt (Notes 7 and 9):
First mortgage bonds 894,000 874,000
Guaranteed collateralized bonds 16,000 24,000
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 24 38
Unamortized discount - net of premium (586) (819)
Long-term debt due within one year (108,000) (23,000)
- --------------------------------------------------------------------------------------------
Total long-term debt excluding current maturities 963,298 1,036,079
- --------------------------------------------------------------------------------------------
Total Capitalization $2,352,269 $2,430,730
============================================================================================
* 16,000,000 shares authorized for $25 par value preferred stock
and 3,750,000 shares authorized for $100 par value preferred stock.
The accompanying notes are an integral part of the financial statements.
36
Consolidated Statements of Earnings Reinvested in the Business
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
Year Ended December 31 1994 1993 1992
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
Balance at Beginning of Year $220,259 $210,544 $188,084
Net Income 120,059 138,327 135,720
- --------------------------------------------------------------------------------------------
Total 340,318 348,871 323,804
- --------------------------------------------------------------------------------------------
Deductions:
Dividends Declared:
Preferred stock:
$4.84 per share on 4.84% series 242 252 316
$4.70 per share on 4.70% series 319 327 329
$8.00 per share on 8% series 410 495 532
$7.75 per share on 7.75% series 5,813 5,813 3,713
$1.97 per share on 7.875% series 5,906 5,906 1,870
Adjustable Rate, Series A 700 2,800 2,885
Adjustable Rate, Series B 2,277 -- --
Flexible Dutch Auction Rate Transferable
Securities (Note 3):
Series A -- -- 579
Series B -- 912 2,033
Common stock 117,084 111,498 100,692
Loss on reacquisition of preferred stock -- 609 311
- --------------------------------------------------------------------------------------------
Total deductions 132,751 128,612 113,260
- --------------------------------------------------------------------------------------------
Balance at End of Year (Note 6) $207,567 $220,259 $210,544
============================================================================================
The accompanying notes are an integral part of the financial statements.
37
Consolidated Statements of Cash Flows
Puget Sound Power & Light Company
- --------------------------------------------------------------------------------------------
Year Ended December 31 1994 1993 1992
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
Operating Activities:
Net income $120,059 $138,327 $135,720
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 115,738 115,690 122,931
Deferred income taxes and tax credits - net 17,762 30,149 7,283
Equity portion of AFUDC (530) (2,301) (443)
PRAM accrued revenues (25,835) (42,100) (42,119)
Other 37,813 (15,079) 12,946
Change in certain current assets and
liabilities (Note 18) (5,979) 9,645 (39,307)
- --------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 259,028 234,331 197,011
- --------------------------------------------------------------------------------------------
Investing Activities:
Construction expenditures - excluding equity AFUDC (213,982) (156,123) (185,881)
Additions to energy conservation program (36,648) (64,027) (58,541)
Decrease in energy conservation loans 875 1,688 2,293
Cash received from subsidiary 30,136 -- --
Other (including advances to subsidiaries) (8,116) (438) (21,171)
- --------------------------------------------------------------------------------------------
Net Cash Used by Investing Activities (227,735) (218,900) (263,300)
- --------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in short-term debt 85,148 58,856 (21,340)
Dividends paid (net of newly issued shares
totaling $239,000 in 1994
and $25,658,000 in 1993 (132,513) (102,345) (100,886)
Issuance of common and preferrred stock
(Notes 3, 4 and 5) 50,000 113,377 217,905
Issuance of bonds (Note 7) 85,000 107,460 552,500
Redemption of bonds and notes (73,014) (255,472) (405,912)
Redemption of preferred stock (41,865) (50,643) (51,093)
Issue costs of bonds and stock (2,210) (4,325) (10,382)
- --------------------------------------------------------------------------------------------
Net Cash Provided (Used) by Financing Activities (29,454) (133,092) 180,792
Increase (decrease) in Cash 1,839 (117,661) 114,503
Cash at Beginning of Year 3,445 121,106 6,603
- --------------------------------------------------------------------------------------------
Cash at End of Year $ 5,284 $ 3,445 $121,106
============================================================================================
The accompanying notes are an integral part of the financial statements.
38
Puget Sound Power & Light Company
Notes To Consolidated Financial Statements
- -------------------------------------------------------------------------
1) Summary of Significant Accounting Policies
Significant accounting policies are described below.
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.
Consolidation and Investment in Subsidiaries:
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.
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"). The Washington Commission allows an additional annual overall
rate of return of .90% on the Company's unamortized energy conservation
expenditures and on energy conservation loans to customers made prior to
January 1, 1991.
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. The amount deferred and included in other
long-term assets at December 31, 1994, was approximately $24.1 million.
In its September 21, 1993 order, the Washington Commission terminated,
39
prospectively, the provision for deferral of uninsured storm damage except
for certain losses associated with major catastrophic events. The
Washington Commission in its order did provide for recovery annually of $2.8
million in deferred storm damage costs in retail rates, beginning October 1,
1993. The order also terminated the provision for deferral of other
uninsured losses retroactively, resulting in an after-tax writeoff in 1993
of $2.0 million. At December 31, 1994, the Company had no insurance
coverage for storm damage.
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 1994, 3.1% in 1993 and 3.4% for 1992.
The Company's investments in terminated generating projects were amortized
on a straight-line basis over ten years for regulatory purposes (included in
operating income as "Depreciation and amortization"). The amortization
period on these investments ended in 1994.
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 $1.8 million, $2.7 million and
$3.6 million for 1994, 1993 and 1992, 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 13.)
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 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
40
8.94% effective October 1, 1993. To the extent this rate exceeds the
maximum AFUDC rate 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:
$3,016,000 for 1994; $2,309,000 for 1993; and $3,680,000 for 1992.
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 $3,317,000 in 1994, $4,276,000 in 1993
and $4,454,000 in 1992. Cash inflow related to AFUCE occurs when these
charges are reflected in rates.
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 27, 1994 order, the Washington Commission approved the Company's
latest PRAM filing and the recovery of $53.7 million over the period October
1, 1994 through September 30, 1995. A receivable of approximately $110.8
million was recorded at December 31, 1994 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.
Certain costs have been deferred for amortization in subsequent years, as it
is considered probable that such costs will be recovered through future
rates.
Earnings Per Common Share:
Earnings per common share have been computed based on the weighted average
number of common shares outstanding.
41
2) Property Plant and Equipment
- ----------------------------------------------------------------------------
December 31 1994 1993
- ----------------------------------------------------------------------------
(Dollars in Thousands)
Electric utility plant classified by prescribed
accounts at original cost:
Intangible plant $ 36,458 $ 33,754
Production plant 897,139 897,218
Transmission plant 499,016 404,173
Distribution plant 1,513,264 1,434,390
General plant 246,351 245,348
Construction work in progress 94,067 97,932
Plant held for future use 19,310 20,683
Acquisition adjustments 1,249 1,249
- ----------------------------------------------------------------------------
Total electric utility plant $3,306,854 $3,134,747
============================================================================
42
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, 1992 -- 1,400,000 201,887 55,561,647
Sold to Public:
1992 3,000,000 -- 750,000 2,300,000
1993 -- -- -- 3,450,000
1994 2,000,000 -- -- --
Issued to trustee of
employee investment plan:
1992 -- -- -- 63,085
1993 -- -- -- 130,009
Issued to shareholders under
the stock purchase and
dividend reinvestment plan:
1992 -- -- -- 649,901
1993 -- -- -- 1,474,774
1994 -- -- -- 11,445
Acquired for sinking fund:
1992 -- -- (13,665) --
1993 -- -- (6,459) --
1994 -- -- (19,339) --
Called for redemption
and cancelled:
1992 -- (500,000) -- --
1993 -- (500,000) -- --
1994 -- (400,000) -- --
- ------------------------------------------------------------------------------------------
Shares outstanding
December 31, 1994 5,000,000 -- 912,424 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
43
of the Rights are set forth in a Rights Agreement between the Company and
The Chase Manhattan Bank, N.A., as Rights Agent. The Rights expire on
January 25, 2001, unless earlier redeemed by the Company.
In February 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 $200 million of preferred stock. On March 25,
1992, the Company issued $75 million, 7.75% Series, $100 par value Preferred
Stock. The proceeds were used to retire $50 million principal amount of its
Flexible Dutch Auction Rate Transferable Securities, $100 par value
Preferred Stock ("FLEX DARTS"), Series A and to pay down short-term debt.
On July 21, 1992, the Company issued $75 million, 7.875% Series, $25 par
value Preferred Stock. The proceeds of this issue were used to pay down
short-term debt. The 7.875% Series may be redeemed after July 14, 1997 at
$25 per share plus accrued dividends. On July 1, 1993, the FLEX DARTS
Series B were redeemed with the proceeds from the sale of the Company's
common stock. The weighted average dividend rate for Series B was 3.30% for
1993 and 3.60% for 1992. The weighted average dividend rate for Series A
was 4.18% in the first three months of 1992.
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 5.93% for 1994. The weighted average dividend rate for the ARPS Series
A was 7.00% in the first two months of 1994, 7.00% for 1993 and 7.17% for
1992.
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, 1994,
there were 15,044 shares of the 4.84% Series, 2,785 shares of the 4.70%
Series and 747 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.
44
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 $106.20 per share plus accrued dividends through February
15, 1996 and at per share amounts which decline annually to a price of $100
after February 15, 2007.
5) Additional Paid-in Capital
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
Balance at beginning of year $329,922 $243,874 $198,733
Excess of proceeds over stated values of:
Common stock issued to trustee of
employee investment plan -- 2,234 1,046
Common stock issued under the
stock purchase and
dividend reinvestment plan 124 24,584 10,841
Common stock sold to the public -- 61,669 37,950
Par value over cost of reacquired
preferred stock 68 612 579
Issue costs of common stock -- (3,035) (1,950)
Issue costs of preferred stock (1,361) (16) (3,325)
- ---------------------------------------------------------------------------
Balance at end of year $328,753 $329,922 $243,874
===========================================================================
6) Earnings Reinvested in the Business
Earnings reinvested in the business unrestricted as to payment of cash
dividends on common stock approximated $251 million at December 31, 1994,
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.)
45
7) Long-Term Debt
First Mortgage Bonds and Guaranteed Collateralized Bonds
- --------------------------------------------------------
First Mortgage Bonds at December 31:
Series Due 1994 1993 Series Due 1994 1993
- ----------------------------------------------------------------------------
(Dollars in Thousands) (Dollars in Thousands)
4.75% 1994 $ -- $ 15,000 7.07% 2002 $ 27,000 $ 27,000
8.25% 1995 100,000 100,000 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
9.625% 1997 -- 50,000 6.20% 2003 3,000 3,000
7.875% 1997 100,000 100,000 6.40% 2003 11,000 11,000
6.17% 1998 10,000 10,000 7.70% 2004 50,000 50,000
5.70% 1998 5,000 5,000 7.80% 2004 30,000 --
8.83% 1998 25,000 25,000 8.06% 2006 46,000 46,000
6.50% 1999 16,500 16,500 8.14% 2006 25,000 25,000
6.65% 1999 10,000 10,000 7.75% 2007 100,000 100,000
6.41% 1999 20,500 20,500 8.40% 2007 10,000 10,000
7.25% 1999 50,000 50,000 8.59% 2012 5,000 5,000
6.61% 2000 10,000 10,000 8.20% 2012 30,000 30,000
9.14% 2001 30,000 30,000 7.35% 2024 55,000 --
7.85% 2002 30,000 30,000
- ----------------------------------------------------------------------------
Total First Mortgage Bonds $894,000 $874,000
============================================================================
Guaranteed Collateralized Bonds at December 31:
Series Due 1994 1993 Series Due 1994 1993
- ----------------------------------------------------------------------------
(Dollars in Thousands) (Dollars in Thousands)
8.15% 1994 $ -- 8,000 8.45% 1996 $ 8,000 $ 8,000
8.30% 1995 $ 8,000 8,000
- ----------------------------------------------------------------------------
Total Guaranteed Collateralized Bonds $ 16,000 $ 24,000
============================================================================
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.
46
In February 1994, the Company extinguished $50 million principal amount of
First Mortgage Bonds, 9.625% Series due 1997. The Company redeemed $24.5
million through a tender offer. A portfolio of U.S. Government Treasury
Securities was purchased to defease the remaining $25.5 million of the
bonds. The defeased bonds will be called on October 15, 1995.
Pollution Control Revenue Bonds
- -------------------------------
In June 1986, the Company entered into an agreement with the City of
Forsyth, Montana, (the "City") borrowing $115 million obtained by the City
from the sale of Customized Purchase Pollution Control Revenue Refunding
Bonds due in 2012 (1986 Series) issued to finance the pollution control
facilities of Colstrip Units 3 and 4.
In April 1987, the Company entered into an agreement with the City,
borrowing $23.4 million obtained by the City from the sale of Customized
Purchase Pollution Control Revenue Refunding Bonds due December 1, 2016,
(1987 Series) issued to finance additional pollution control facilities of
Colstrip Unit 4.
On August 7, 1991, the Company refunded $27.5 million of the 1986 Series and
the entire $23.4 million of the 1987 Series with two new series of bonds,
consisting of $27.5 million principal amount of a 7.05% Series due 2021 and
$23.4 million principal amount of a 7.25% Series due 2021. In March 1992,
the Company refunded the remaining $87.5 million of the 1986 Series with a
new series at a rate of 6.80%, maturing in 2022. Each new series of bonds
is 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.
On April 29, 1993, the Company issued $23.46 million Pollution Control
Revenue Refunding Bonds, 5.875% 1993 Series due 2020. The proceeds were
used to refund $16.46 million Pollution Control Revenue Bonds, 5.90% 1973
Series and $7 million Pollution Control Revenue Bonds, 6.30% 1977 Series.
Long-Term Debt Maturities and Sinking Fund Requirements
- --------------------------------------------------------
The principal amounts of long-term debt maturities and sinking fund
requirements for the next five years are as follows:
1995 1996 1997 1998 1999
- ----------------------------------------------------------------------------
(Dollars in Thousands)
Maturities of
long-term debt $108,000 $ 43,000 $100,000 $ 40,000 $ 97,000
- ----------------------------------------------------------------------------
Sinking fund requirements $ 200 $ -- $ -- $ -- $ --
- ----------------------------------------------------------------------------
The sinking fund requirement for the First Mortgage Bonds may be met by
substitution of certain credits as provided in the indenture.
47
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 1/2 of 1 percent or (3) the Eurodollar rate plus 3/8 of 1 percent.
These Credit Agreements require an availability fee of 1/5 of 1% 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: 1994 1993 1992
- ---------------------------------------------------------------------
(Dollars in Thousands)
Short-term borrowings outstanding:
Bank notes $ 94,900 $ 79,300 $ 69,800
Commercial paper notes $139,554 $ 70,006 $ 20,650
Weighted average interest rate 6.24% 3.49% 4.37%
Unused lines of credit (a) $176,500 $152,000 $152,000
- ---------------------------------------------------------------------
(a) Provides liquidity support for outstanding commercial paper in the
amount of $139.6 million, $70.0 million and $20.7 million for 1994,
1993 and 1992, respectively, effectively reducing the available
borrowing capacity under these credit lines to $36.9 million, $82.0
million and $131.3 million, respectively.
9) 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, 1994 and 1993.
1994 1993
------------------ -------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(Dollars in Millions)
Financial Assets:
Cash $ 5.3 $ 5.3 $ 3.4 $ 3.4
Financial Liabilities:
Short-term debt 234.5 234.5 149.3 149.3
Preferred stock subject to
mandatory redemption 91.2 84.4 93.2 93.7
Long-term debt $1,071.9 $1,011.0 $1,059.9 $1,126.0
48
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) Investment in Bonneville Exchange Power Contract
The Company has a five percent interest, as a tenant in common with three
other investor-owned utilities and Washington Public Power Supply System
("WPPSS"), in the WPPSS Unit 3 project. Unit 3 is a partially constructed
1,240,000 kilowatt nuclear generating plant at Satsop, Washington, which was
in a state of extended construction delay instituted by the Bonneville Power
Administration ("BPA") and WPPSS in 1983. Unit 3 was recently terminated by
WPPSS and the other owners. Under the terms of a settlement agreement (the
"Settlement Agreement"), which includes a Settlement Exchange Agreement
("Bonneville Exchange Power Contract") between the Company and BPA dated
September 17, 1985, the Company is receiving electric power (the "Bonneville
Exchange Power") from the federal power system resources marketed by the BPA
for a period of approximately 30.5 years which commenced January 1, 1987.
The Settlement Agreement settled the claims of the Company against WPPSS and
BPA relating to the construction delay of the WPPSS Unit 3 project.
In its general rate case order issued on January 17, 1990, the Washington
Commission found that all WPPSS Unit 3/Bonneville Exchange Power costs had
been prudently incurred. Under terms of the order, approximately two-thirds
or $97 million of the investment in Bonneville Exchange Power is included in
rate base and amortized on a straight-line basis over the remaining 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.
Several issues in the litigation relating to WPPSS Unit 3, including claims
on behalf of WPPSS Unit 5 against the Company and the other Unit 3 owners
seeking recovery of certain common costs, were not settled by the Settlement
Agreement. The claims with respect to WPPSS Unit 3 and Unit 5 common costs,
made in the United States District Court for the Western District of
Washington, arise out of the fact that Unit 3 and Unit 5, which was also
terminated prior to completion, were being constructed adjacent to each
other and were planned to share certain costs. The Company and a number of
the litigants have signed, subject to various conditions, a memorandum of
understanding intended to result in settlement and dismissal of the claims.
Under the memorandum of understanding, the Company's share of the settlement
amount will be $500,000, an expense which was accrued by the Company in
December 1994.
49
11) Supplementary Income Statement Information
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
Taxes:
Real estate and personal property $ 33,050 $ 29,354 $ 30,839
State business 42,241 40,102 35,798
Municipal, occupational and other 25,132 23,064 21,136
Payroll 9,514 9,664 9,517
Other 4,194 3,462 5,300
- ---------------------------------------------------------------------------
Total taxes $114,131 $105,646 $102,590
- ---------------------------------------------------------------------------
Charged to:
Tax expense $107,821 $100,598 $ 94,466
Other accounts, including
construction work in progress 6,310 5,048 8,124
- ---------------------------------------------------------------------------
Total taxes $114,131 $105,646 $102,590
===========================================================================
See "Consolidated Statements of Income" for maintenance and depreciation
expense.
Other operating expenses in 1994 include charges totaling $20.9 million
related to 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.
Advertising, research and development expenses and amortization of
intangibles are not significant. The Company pays no royalties.
12) Leases
The Company classifies leases as operating or capital leases. Capitalized
leases are not material. The Company treats all leases as operating leases
for ratemaking purposes as required by the Washington Commission.
Rental and lease payments for the years ended December 31, 1994, 1993 and
1992 were approximately $13,874,000, $14,016,000, and $13,773,000,
respectively. At December 31, 1994, future minimum lease payments for
noncancelable leases are $9,145,000 for 1995, $9,109,000 for 1996,
$9,062,000 for 1997, $9,018,000 for 1998, $9,050,000 for 1999 and in the
aggregate $35,596,000 thereafter.
50
13) Federal Income Taxes
The details of federal income taxes ("FIT") are as follows:
1994 1993 1992
- ---------------------------------------------------------------------------
Charged to Operating Expense: (Dollars in Thousands)
Current $63,935 $56,908 $67,762
Deferred investment tax credits - net (415) (2,118) (4,018)
Deferred - net 16,739 29,180 8,705
- ---------------------------------------------------------------------------
Total FIT charged to operations $80,259 $83,970 $72,449
===========================================================================
Charged to Miscellaneous Income:
Current $(1,253) $(3,665) $(5,207)
Deferred 1,438 3,087 2,596
- ---------------------------------------------------------------------------
Total FIT charged to miscellaneous income $ 185 $ (578) $(2,611)
===========================================================================
Total FIT $80,444 $83,392 $69,838
===========================================================================
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:
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
- ---------------------------------------------------------------------------
FIT at the statutory rate $70,177 $77,602 $69,890
- ---------------------------------------------------------------------------
Increase (Decrease):
Depreciation expense deducted in the
financial statements in excess of tax
depreciation, net of depreciation
treated as a temporary difference 4,717 4,698 5,295
AFUDC included in income in the financial
statements but excluded from taxable income (2,525) (2,563) (2,438)
Investment tax credit amortization (415) (2,118) (4,018)
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 1,748
Energy conservation expenditures - net 5,607 5,608 (1,245)
Other 2,135 (1,300) 606
- ---------------------------------------------------------------------------
Total FIT $80,444 $83,392 $69,838
===========================================================================
Effective tax rate 40.1% 37.6% 34.0%
===========================================================================
51
The following are the principal components of FIT as reported:
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
- ---------------------------------------------------------------------------
Current FIT $62,682 $53,243 $62,555
===========================================================================
Deferred FIT - other:
Conservation tax settlement 341 (257) (22,645)
Periodic rate adjustment mechanism (PRAM) 9,287 14,959 14,321
Deferred taxes related to insurance
reserves (938) 1,409 596
Terminated generating projects (3,345) (5,735) (6,647)
Reversal of Statement No. 90 present
value adjustments 926 1,477 2,374
Residential Purchase and Sale
Agreement - net (624) 4,136 2,491
Normalized tax benefits of the
accelerated cost recovery system 19,042 19,839 21,237
Energy conservation program (2,253) (2,938) (3,360)
Other (4,259) (623) 2,934
- ---------------------------------------------------------------------------
Total deferred FIT - other $18,177 $32,267 $11,301
===========================================================================
Deferred investment tax credits -
net of amortization $ ( 415) $(2,118) $(4,018)
- ----------------------------------------------------------------------------
Total FIT $80,444 $83,392 $69,838
===========================================================================
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. Under the provision of
Statement No. 109, the Company recorded at the date of adoption an
additional deferred tax liability of approximately $272 million. Because of
prior, and expected future, ratemaking treatment for differences resulting
from flow-through tax accounting, a corresponding $272 million regulatory
asset for income taxes recoverable through future rates was also established
at the date of adoption. At December 31, 1994, the balance of this asset is
$275 million. The effect on net income in 1993 from adoption of Statement
No. 109 was not significant and adoption of Statement No. 109 is not
expected to significantly impact income tax expense in the future.
52
The deferred tax liability at December 31, 1994 and 1993 is comprised of
amounts related to the following types of temporary differences:
1994 1993
------- -------
(Dollars in Thousands)
Utility plant $446,177 $425,210
PRAM 38,795 29,885
Energy conservation charges 35,836 44,548
Contributions in aid of construction (24,075) (21,814)
Bonneville Exchange Power 16,672 18,968
Other 28,096 31,868
------- -------
Total $541,501 $528,665
======= =======
The totals of $542 million and $529 million for 1994 and 1993 consist of
deferred tax liabilities of $576 million and $559 million net of deferred
tax assets of $34 million and $30 million, respectively.
In 1992, the Company reached an agreement with the Internal Revenue Service
settling a number of issues. The net income impact of the settlement was
approximately $1.4 million.
14) Retirement Benefits
The Company has a noncontributory defined benefit pension plan covering
substantially all of its employees. The benefit formula is 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 has 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."
53
Net pension costs for 1994, 1993 and 1992, including $2,752,000 for 1994,
$1,440,000 for 1993 and $811,000 for 1992 which were charged to construction
and other asset accounts, were comprised of the following components:
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
Service cost (benefits earned during
the period) $ 7,244 $ 6,952 $ 6,492
Interest cost on projected benefit
obligation 14,895 14,676 13,743
Actual return on plan assets 4,392 (21,786) (9,426)
Net amortization and deferral (21,539) 5,121 (5,470)
- ---------------------------------------------------------------------------
Net pension costs under FASB Statement No. 87 4,992 4,963 5,339
- ---------------------------------------------------------------------------
Regulatory adjustment 1,263 (2,083) (3,575)
- ---------------------------------------------------------------------------
Net pension costs $ 6,255 $ 2,880 $ 1,764
===========================================================================
Funded Status of Plan
At December 31: 1994 1993
- ---------------------------------------------------------------------------
(Dollars in Thousands)
Actuarial present value of benefit obligations:
Vested $(154,950) $(151,399)
Nonvested (1,029) (1,090)
- ---------------------------------------------------------------------------
Accumulated benefit obligation (155,979) (152,489)
Effect of future compensation levels (39,455) (53,998)
- ---------------------------------------------------------------------------
Total projected benefit obligation (195,434) (206,487)
Plan assets at market value 205,655 214,580
- ---------------------------------------------------------------------------
Plan assets in excess of projected benefit
obligation 10,221 8,093
Unrecognized net gain due to variance
between assumptions and experience (19,453) (14,344)
Prior service cost 10,295 11,232
Transition asset as of January 1, 1986,
being amortized on a straight-line
basis over 18 years (3,774) (4,194)
Regulatory adjustment, cumulative 6,190 7,453
- ---------------------------------------------------------------------------
Prepaid pension cost recognized
in long-term assets on balance sheet $ 3,479 $ 8,240
===========================================================================
Assumptions used for the above calculations are as follows: settlement
(discount) rate for 1994 - 8.25%, for 1993 - 7.5% and for 1992 - 8.5%; rate
of annual compensation increase for 1994 - 5.5%, for 1993 - 5.5%, and for
1992 - 6%; and long-term rate of return on assets for 1994 - 8.5%, for 1993
- - 8.5%, and for 1992 - 9%.
54
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 retirement plans for officer and director level employees.
Expenses for this plan for 1994, 1993 and 1992 were $1,043,000, $651,000,
and $606,000, 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 if they reach normal retirement age while working for the Company.
These benefits are provided principally through an insurance company whose
premiums are based on the benefits paid during the year. The expense in
1992 related to those benefits was $2,025,000.
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 during the working
careers of active employees. 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 1994 and 1993 annual costs under
Statement No. 106 is approximately $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 1994 and 1993, the expenses
recognized for postretirement benefits were $2.4 million and $2.8 million,
respectively, including $.1 million and $.5 million which were disallowed by
the Washington Commission.
15) 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 $3,321,000, $3,520,000, and
$3,317,000 for the years 1994, 1993 and 1992, 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, 1994. The employee Investment Plan eligibility requirements are set
forth in the plan documents.
55
16) Commitments and Contingencies
Commitments
For the twelve months ended December 31, 1994, approximately 25% of the
Company's energy output was obtained at an average cost of approximately
12.1 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 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, 1994, 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 12/31/94(a) % of Kilowatt Costs(b)
Project Exp.Date Exp.Date (Millions) Output Capacity
(Millions)
- ----------------------------------------------------------------------------
Rock Island
Original units 2012 2029 $ 90.0 60.3 )
) 502,000 $ 43.2
Additional units 2012 2029 325.3 100.0 )
Rocky Reach 2011 2006(c) 218.0 38.9 505,311 14.8
Wells 2018 2012(c) 195.3 34.8 292,320 10.3
Priest Rapids 2005 2005(c) 131.2 8.0 71,680 2.3
Wanapum 2009 2005(c) 186.4 10.8 98,280 2.7
- --------------------------------------------------------------------------
Total 1,469,591 $ 73.3
==========================================================================
(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: 69.2% at Rock Island; 30.7% at Rocky Reach; 64.3% at
Priest Rapids; and 40.1% at Wanapum.
56
(b) The components of 1995 costs associated with the interest portion
of debt service are: Rock Island, $26.0 million for all units; Rocky Reach,
$5.2 million; Wells, $3.4 million; Priest Rapids, $.7 million; and Wanapum,
$1.1 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 $73.4 million for 1995, $73.1 million for 1996, $75.7 million
for 1997, $80.7 million for 1998, $82.3 million for 1999, and in the
aggregate $999 million 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 are $468.7 million for 1995,
$484.8 million for 1996, $494.5 million for 1997, $528.0 million for 1998,
$555.2 million for 1999 and in the aggregate $6.062 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 16.0
million, 13.5 million and 12.7 million MWH of firm energy at a cost of
approximately $450.7 million, $353.5 million and $274.6 million for the
years 1994, 1993 and 1992, 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, 1994:
Energy Company's Plant in Accumulated
Source Ownership Service Depreciation
Project (Fuel) Share (%) (Millions) (Millions)
Centralia Coal 7 $ 26.5 $ 15.9
Colstrip 1 & 2 Coal 50 181.4 86.1
Colstrip 3 & 4 Coal 25 443.2 130.8
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
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
57
Company has reached settlements with the EPA on all four sites under which
the Company has paid approximately $7.6 million. To date the Company has
recovered $3.6 million from its insurance companies in connection with
remediation and legal costs and expects to recover an additional $3.1
million in the next twelve months. Based on the best estimates available at
this time, the Company anticipates future costs for environmental
remediation at all sites, including those owned by the Company, will
approximate $3.5 million, which was recorded as an accrued liability at
December 31, 1994.
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. At
December 31, 1994, the estimated recoverable amount for these costs is
approximately $11.9 million.
Other contingencies, arising out of the normal course of the Company's
business, exist at December 31, 1994. 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.
17) 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.
Annual amounts are not generated evenly by quarter during the year due to
the seasonal nature of the utility business.
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
- --------------------------------------------------------------------------
1993 Quarter Ended March 31 June 30 Sept. 30 Dec. 31
- --------------------------------------------------------------------------
(Dollars in Thousands except per share amounts)
Operating revenues $323,974 $237,617 $230,178 $321,109
Operating income $ 72,922 $ 43,039 $ 35,505 $ 59,514
Other income $ 3,718 $ 4,614 $ 3,536 $ 1,712
Net income $ 54,682 $ 26,213 $ 18,071 $ 39,361
Earnings per common share $ 0.86 $ 0.37 $ 0.23 $ 0.56
- --------------------------------------------------------------------------
58
18) 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.
The following provides additional information concerning cash flow
activities:
Year Ended December 31: 1994 1993 1992
- --------------------------------------------------------------------------
(Dollars in Thousands)
Changes in certain current
assets and current liabilities:
Accounts receivable $(16,725) $ (5,050) $(13,848)
Deferred energy costs -- -- (20)
Unbilled revenues 2,521 (14,410) (15,081)
Materials and supplies 2,840 1,054 (1,338)
Prepayments and Other (75) 5,809 (6,346)
Accounts payable 4,576 10,731 (5,948)
Accrued expenses and Other 884 11,511 3,274
- --------------------------------------------------------------------------
Net change in certain current assets
and current liabilities $(5,979) $ 9,645 $(39,307)
==========================================================================
Cash payments:
Interest (net of capitalized interest) $83,959 $80,646 $97,242
Income taxes $63,477 $32,585 $76,050
- --------------------------------------------------------------------------
59
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, 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) $ --
=============================================================================
Year Ended December 31, 1992
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 531 $ 1,981 $ 2,024 $ 488
- -----------------------------------------------------------------------------
Reserves:
Accumulated provision
for self-insurance $ 792 $ 4,610(A) $ 5,315(A) $ 87
=============================================================================
Note (A): Includes charges of $10.3 million in 1993 and $1.8 million in 1992
which were transferred to a deferred asset account.
60
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.
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)
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)
61
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 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)
4.8 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)
4.9 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)
4.10 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)
4.11 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)
4.12 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)
4.13 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)
4.14 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)
4.15 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)
4.16 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)
62
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)
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)
63
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)
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)
64
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)
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)
65
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)
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,
66
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)
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)
67
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)
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
68
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)
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)
69
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)
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
70
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
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)
71
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)
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)
72
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)
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)
73
*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)
*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)
*12-a Statement setting forth computation of ratios of earnings to
fixed charges (1990 through 1994).
*12-b Statement setting forth computation of ratios of earnings to
combined fixed charges and preferred stock dividends (1990 through 1994).
21 List of subsidiaries. (Exhibit 22 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
*23 Consent of accountants.
*27 Financial Data Schedule
_________________________________
*Filed herewith.
74