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UNITED STATES
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, 1997
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 ENERGY, INC.
(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)
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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.
Adjustable Rate Cumulative Preferred
Stock, Series B ($25 Par Value) N. Y. S. E.
7.45% Series II, Preferred Stock
(Cumulative, $25 Par Value) N. Y. S. E.
8.50% Series III, Preferred Stock
(Cumulative, $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)
8.231% Capital Securities
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. / /
The aggregate market value of the voting stock held by non-affiliates of the
registrant at December 31, 1997, was approximately $ 2,549,316,000.
The number of shares of the registrant's common stock outstanding at
February 28, 1998, was 84,560,625.
Documents Incorporated by Reference
The Company's definitive proxy statement for its annual meeting of
shareholders on May 12, 1998, is incorporated by reference in Part III
hereof.
INDEX
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Item Page
No. No.
Part I 1. Business................................................ 1
General................................................. 1
Industry Overview........................................ 2
Regulation and Rates..................................... 3
Electric Utility Operations.............................. 3
Electric Utility Operating Statistics.................... 11
Gas Utility Operations................................... 13
Gas Utility Operating Statistics......................... 17
Construction Financing................................... 18
Environment.............................................. 18
Executive Officers....................................... 20
2. Properties............................................... 22
3. Legal Proceedings........................................ 22
4. Submission of Matters to a Vote of Security Holders...... 22
Part II 5. Market for Registrant's Common Equity and Related
Stockholder Matters...................................... 22
6. Selected Financial Data.................................. 23
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations............ 24
8. Financial Statements and Supplementary Data.............. 34
9. Changes in and Disagreements with Accountant
on Accounting and Financial Disclosure................... 34
Part III (Incorporated by reference from the Company's
definitive proxy statement issued in connection
with the 1998 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...................................... 35
Signatures............................................... 36
Exhibit Index............................................ 79
DEFINITIONS
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AFUDC Allowance for Funds Used During Construction
BPA Bonneville Power Administration
CAAA Clean Air Act Amendments
Cabot Cabot Oil & Gas Corporation
Chelan Public Utility District No. 1 of
Chelan County, Washington
Dth Dekatherm (One Dth is equal to one MMBTu)
EPA Environmental Protection Agency
FERC Federal Energy Regulatory Commission
KW Kilowatts
KWH Kilowatt Hours
MMBTu One Million British Thermal Units
MW Megawatts (one MW equals one thousand KW)
MWH Megawatt Hours
Montana Power The Montana Power Company
NMFS National Marine Fisheries Service
PGA Purchased Gas Adjustment
PRAM Periodic Rate Adjustment Mechanism
PRP Potentially Responsible Party
PUDs Washington Public Utility Districts
PURPA Public Utility Reform and Policy Act
Washington Commission Washington Utilities and Transportation
Commission
WECo Washington Energy Company
WEGM Washington Energy Gas Marketing Company
WNG Washington Natural Gas Company
WPPSS Washington Public Power Supply System
PART I
ITEM 1. BUSINESS
General
Puget Sound Energy, Inc. (the "Company"), formerly Puget Sound Power & Light
Company ("Puget Power"), is an investor-owned public utility incorporated in
the State of Washington furnishing electric and, since February 10, 1997, gas
service in a territory covering approximately 6,000 square miles, principally
in the Puget Sound region of Washington state. On February 10, 1997, the
Company completed a merger (the "Merger") with the Washington Energy Company
("WECo") and its principal subsidiary, Washington Natural Gas Company
("WNG"). Seattle-based WNG provided natural gas distribution service to
approximately 500,000 customers in an area east of Puget Sound that included
Seattle, Tacoma, Everett, Bellevue and Olympia. Puget Power changed its name
to Puget Sound Energy, Inc. effective with the Merger. Certain historical
financial and statistical information contained herein has been restated to
reflect the combined operations of the Company, WECo and WNG and all
references to the Company include the combined entity. Effective with the
merger, WECo's 1996 fiscal year-end was changed from September 30 to December
31 to conform to Puget Power's year-end. Accordingly, financial and
statistical information prior to January 1, 1997, contained herein reflects
fiscal years ended December 31 for Puget Power and September 30 for WECo.
(See discussion of the Merger in Note 1 to the Consolidated Financial
Statements.)
At December 31, 1997, the Company had approximately 871,900 electric
customers, consisting of 773,900 residential, 92,500 commercial, 4,100
industrial and 1,400 other customers and approximately 521,300 gas customers,
consisting of 475,600 residential, 42,600 commercial, 3,000 industrial and
100 other customers. For the year 1997, the Company added approximately
14,600 electric customers and approximately 21,400 gas customers,
representing annualized growth rates of 1.7% and 4.3%, respectively. During
1997, the Company's billed retail tariff revenues from electric utility
operations were derived 46% from residential customers, 36% from commercial
customers, 15% from industrial customers and 3% from wholesale customers, and
the Company's retail tariff revenues from gas utility operations were derived
60% from residential customers, 28% from commercial customers, 9% from
industrial customers and 3% from other customers. During this period, the
largest customer accounted for 2.1% of the Company's utility operating
revenues.
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
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 of electricity to other utilities also vary by quarters and
years depending principally upon streamflow conditions for the generation of
surplus hydro-electric power, customer usage and the energy requirements of
other neighboring utilities. Under the previously effective electric
Periodic Rate Adjustment Mechanism ("PRAM") approved by the Washington
Utilities and Transportation Commission (the "Washington Commission") in
October 1991, earnings were not significantly influenced, up or down, by
sales of surplus electricity to other utilities or by variations in normal
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seasonal weather or hydro conditions. The PRAM, however, ended effective
September 30, 1996, under a stipulated negotiated settlement approved by the
Washington Commission. With the discontinuance of the PRAM, earnings from
electric operations now can be significantly influenced by surplus sales and
variations in weather, hydro conditions and non-firm regional electric energy
prices. Since 1971, the Washington Commission has permitted the Company to
pass on to its customers, through changes in its rates, all changes in the
price of gas purchased from nonaffiliated suppliers through the Purchased Gas
Adjustment ("PGA") mechanism. This mechanism allows the Company to pass
these cost increases or decreases to its customers on a timely basis,
resulting in no material impact on net income from gas operations. (See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Rate Matters.")
During the period from January 1, 1993 through December 31, 1997, the Company
made gross electric utility plant additions of $730 million and retirements
of $136 million. In the five year period ended December 31, 1997, the
Company made gross gas utility plant additions of $447 million and
retirements of $45 million. Gross electric utility plant at December 31,
1997, was approximately $3.6 billion which consisted of 49% distribution, 27%
generation, 16% transmission and 8% general plant and other. Gross gas
utility plant at December 31, 1997, was approximately $1.2 billion which
consisted of 84% distribution, 5% transmission and 11% general plant and
other.
At year-end the Company and its subsidiaries had 3,050 aggregate full-time
equivalent employees, down from approximately 4,350 full-time equivalent
employees at the end of 1992. This represents a workforce reduction of
approximately 30% the last five years.
Industry Overview
The electric and gas industries in the United States are undergoing
significant changes. The focus of these changes is to promote competition
among suppliers of electricity and gas and associated services. In 1996, the
Federal Energy Regulatory Commission ("FERC") issued an order that requires
utilities to provide wholesale open access to electric transmission systems
on terms that are comparable to the utility's own use. A number of states,
including California, have restructured their electric industries to separate
or "unbundle" power generation, transmission and distribution in order to
permit new competitors to enter the market place. In part because electric
rates in the Pacific Northwest have been among the lowest in the nation, the
legislatures in this region, including Washington, have not yet enacted laws
to provide for competition at the retail level. The Washington Commission
has initiated a pilot program, in which the Company participates, that
permits consumers limited direct access to competitive energy suppliers. The
Company is actively monitoring developments in this area and has indicated
its support for the enactment of legislation that provides increased choice
for all electric service customers in the state of Washington.
In order to position itself to respond effectively to future restructuring of
the utility industry, and in anticipation of a competitive environment for
electric energy sales, the Company has recently organized into separate
business units: energy transportation; energy supply and customer solutions.
This reorganization anticipates eventual legislatively mandated unbundling of
power generation from transmission and distribution which would allow
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customers to purchase these services and commodities individually from
different suppliers or, alternatively, as a complete package.
Since 1986, the Company has been offering gas transportation as a separate
service to industrial and commercial customers who choose to purchase their
gas supply directly from producers and gas marketers. The continued
evolution of the natural gas industry, resulting primarily from FERC Orders
436, 500 and 636, has served to increase the ability of large gas end-users
to bypass the Company in obtaining gas supply and transportation services.
Though the Company has not lost any substantial industrial or commercial load
as a result of such bypass, in certain years up to 160 customers annually
have taken advantage of unbundled transportation service; in 1997,
approximately 128 commercial and industrial customers, on average, chose to
use such service.
Regulation and Rates
The Company is subject to the regulatory authority of (1) the Washington
Commission as to retail rates, accounting, the issuance of securities and
certain other matters and (2) the FERC with respect to the transmission of
electric energy, the resale of electric energy at wholesale, accounting and
certain other matters. (See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Rate Matters.")
Electric Utility Operations
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Electric Power Resources
At December 31, 1997, the Company's peak electric power resources were
approximately 5,015,300 KW. The Company's historical peak load of
approximately 4,615,000 KW occurred on December 21, 1990.
During 1997, the Company's total electric energy production was supplied 23%
by its own resources, 29% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydroelectric projects
on the Columbia River, 24% from other firm purchases and 24% from non-firm
purchases.
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The following table shows the Company's electric energy supply resources at
December 31, 1997, and energy production during the year:
Peak Power Resources
at December 31, 1997 1997 Energy Production
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Kilowatts % Kilowatt-Hours %
--------- ---- -------------- ----
(Thousands)
Purchased Resources:
Columbia River
PUD Contracts (Hydro) 1,355,000 26.4% 8,399,909 28.6%
Other Hydro(a) 615,500 12.0% 3,350,193 11.4%
Thermal(a) 1,401,900 27.4% 10,965,820 37.4%
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Total 3,372,400 65.8% 22,715,922 77.4%
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Company-owned Resources:
Hydro 308,200 6.0% 1,566,279 5.3%
Coal 771,900 15.1% 4,951,116 16.9%
Natural gas 673,900 13.1% 123,724 0.4%
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Total Company-owned 1,754,000 34.2% 6,641,119 22.6%
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Total 5,126,400 100.0% 29,357,041 100.0%
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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 Electric Generation Resources.
The Company and other utilities are joint owners of four mine-mouth, coal-
fired, steam-electric generating units at Colstrip, Montana, approximately
100 miles east of Billings, Montana. The Company owns a 50% interest
(330,000 KW) in Units 1 and 2 and a 25% interest (350,000 KW) in Units 3 and
4. The owners of the Colstrip Units purchase coal for the units from Western
Energy Company ("Western Energy"), an affiliate of Montana Power Company
("Montana Power") (one of the joint owners), under the terms of long-term
coal supply agreements. Montana Power has announced that it intends to sell
all of its generating assets, including its interest in Colstrip. Pursuant
to a settlement agreement between the Company, Montana Power and Western
Energy dated February 21, 1997, related to a dispute under a power sales
agreement between Montana Power and the Company, the Company's coal price
has been reduced on an interim basis pending a restructuring of the Colstrip
coal supply arrangements. The Company and the other joint owners are
involved in ongoing negotiations regarding restructuring of the Colstrip
1,2,3 and 4 coal supply arrangements.
The Company owns a 7% interest (91,900 KW) in a coal-fired, steam-electric
generating plant near Centralia, Washington, with a total 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
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Company. The Company and other owners of the Centralia project are reviewing
emissions compliance options that will need to be adopted to meet the Federal
and State emission requirements by the year 2000.
The Company also has the following plants with an aggregate net generating
capability of 982,050 KW: Upper Baker River hydro project (103,000 KW)
constructed in 1959; Lower Baker River hydro project (71,400 KW)
reconstructed in 1960; White River hydro plant (63,400 KW) constructed in
1911 with installation of the last unit in 1924; Snoqualmie Falls hydro plant
(44,000 KW), half the capability of which was installed during the period
1898 to 1910 and half in 1957; and one smaller hydro plant, Electron (26,400
KW), constructed during the period 1904 to 1929; a standby internal
combustion unit (2,750 KW) installed in 1969; an oil-fired combustion turbine
unit (67,500 KW) installed in 1974; four dual-fuel combustion turbine units
(89,100 KW each) installed during 1981; and two dual-fuel combustion turbine
units (123,600 KW each) installed during 1984.
The Company's combustion turbines installed in 1981 and 1984 may be fueled
with either natural gas or distillate oil. Short-term supplies of distillate
fuel may be stored on-site. These plants are operated from time to time for
peaking purposes and to produce energy for sales to other utilities, either
directly or through tolling arrangements.
On December 19, 1997, the Company was issued a 50 year license by FERC for
its existing and operating White River project which includes authorization
to install an additional 14,000 KW generating unit. The Company has filed
for a rehearing with FERC on certain articles of the license. The initial
license for the existing and operating Snoqualmie Falls project expired in
December 1993, and the Company continues to operate this project under a
temporary license. The Company is continuing the FERC application process to
relicense this project. The Company has also applied for a license to expand
its existing 1,750 KW Nooksack Falls project which is currently unlicensed
and not operating because of an electric generator fire in 1996.
Columbia River Electric Energy Supply Contracts
During 1997, approximately 28.6% of the Company's energy output was obtained
at an average cost of approximately 9.4 mills per KWH through long-term
contracts with several of the Washington PUDs owning hydroelectric projects
on the Columbia River.
The Company's purchases 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 proportion to the amount of power annually purchased
by the Company from such project. Such payments are not contingent upon the
projects being operable. These projects are financed through substantially
level debt service payments, and their annual costs may vary over the term of
the contracts as additional financing is required to meet the costs of major
maintenance, repairs or replacements or license requirements.
The Company has contracted to purchase from Chelan County PUD ("Chelan") a
share of the output of the original units of the Rock Island Project which
equaled 57.1% through June 30, 1997. This share decreases gradually to 50%
of the output at July 1, 1999, and remains unchanged thereafter for the
duration of the contract. The Company has also contracted to purchase the
entire output of the additional Rock Island units for the duration of the
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contract, except that the Company's share of output of the additional units
may be reduced up to 10% per year beginning July 1, 2000, subject to a
maximum aggregate reduction of 50%, upon the exercise of rights of withdrawal
by Chelan for use in its local service area. Chelan has given notice of
withdrawal of 5% on July 1, 2000. As of December 31, 1997, the Company's
aggregate annual capacity from all units of the Rock Island Project was
423,000 KW. The Company has contracted to purchase from Chelan 38.9%
(482,750 KW as of December 31, 1997) of the annual output of the Rocky Reach
Project, which percentage remains unchanged for the remainder of the
contract. The Company's share of the annual output of the Wells Project
purchased from Douglas County PUD is currently 31.5% (264,600 KW as of
December 31, 1997) and can be ultimately reduced to 31.3% upon the additional
exercise of withdrawal rights by Douglas County PUD. The Company has
contracted to purchase from Grant County PUD 8.0% (72,570 KW as of
December 31, 1997) of the annual output of the Priest Rapids project and
10.8% (112,100 KW as of December 31, 1997) of the annual output of the
Wanapum project, which percentages remain unchanged for the remainder of the
contracts. (See Note 17 to the Company's Consolidated Financial Statements.)
In 1964, the Company and fifteen other utilities and agencies in the Pacific
Northwest entered into a long-term coordination agreement extending until
June 30, 2003 (the "Coordination Agreement"). This agreement provides for
the coordinated operation of substantially all of the hydroelectric power
plants and reservoirs in the Pacific Northwest. A new Coordination Agreement
was negotiated in 1997 and will replace the prior agreement in February of
1999. Various fishery enhancement measures, including most recently the 1995
"biological opinion" from the National Marine Fisheries Service ("NMFS"),
have reduced the flexibility provided by the Coordination Agreement. (See
"Environment - Federal Endangered Species Act.")
Certain utilities in the northwest United States and Canada are obtaining the
benefits of additional firm power as a result of the ratification of a 1961
treaty between the United States and Canada under which Canada is providing
approximately 15,500,000 acre-feet of reservoir storage on the upper Columbia
River. As a result of this storage, streamflow which would otherwise not be
usable to serve firm regional load is stored and later released during
periods when it is usable. Pursuant to the treaty, one-half of the firm
power benefits produced by the additional storage accrue to Canada. The
Company's benefits from this storage are based upon its percentage
participation in the Columbia River projects and one half of those benefits
must be returned to Canada. Also in 1961, the Company contracted to purchase
17.5% of Canada's share of the power to be returned resulting from such
storage until the beginning of a phased expiration of the contract in 1998.
The Company has also contracted to purchase from the Bonneville Power
Administration ("BPA") supplemental capacity in amounts that decrease
gradually until the beginning of a phased expiration of the contract in 1998.
Negotiations are being conducted regarding replacement of the existing
contracts.
Electric Energy Supply Contracts and Agreements With Other Utilities.
Under a 1985 settlement agreement relating to Washington Public Power Supply
System ("WPPSS") Nuclear Project No. 3, in which the Company has a 5%
interest, the Company is receiving from BPA for approximately 30.5 years,
beginning January 1, 1987, electric power during the months of November
through April. Under the contract, the Company is guaranteed to receive not
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less than 191,667 MWH in each contract year until the Company has received
total deliveries of 5,833,333 MWH.
On April 4, 1988, the Company executed a 15-year contract, with provisions
for early termination by the Company, for the purchase of firm energy supply
from Washington Water Power Company. This agreement calls for the delivery
of 100 MW of capacity and 657,000 MWH of energy from the Washington Water
Power system annually (75 annual average MW). Minimum and maximum delivery
rates are prescribed. Under this agreement, the energy is to be priced at
Washington Water Power's average generation and transmission cost, subject to
certain price ceilings.
On October 27, 1988, the Company executed a 15-year contract for the purchase
of firm power and energy from Pacific Power & Light Company. Under the
terms of the agreement, the Company receives 120 average MW of energy and 200
MW of peak capacity.
On November 23, 1988, the Company executed an agreement to purchase surplus
firm power from BPA. Under the agreement, the Company receives 150 average
MW of energy and 300 MW of peak capacity from BPA between October 1 and March
31 of each contract year. The contract extends for 20 years, ending in 2008.
On October 1, 1989, the Company signed a contract with Montana Power under
which Montana Power provides the Company, from its share of Colstrip Unit 4,
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. Pursuant to a settlement between the Company and Montana Power on
February 21, 1997, the contract remains in effect and the price of power
purchased by the Company is reduced. The settlement also addressed certain
price reductions and restructuring activities in connection with the Colstrip
coal supply arrangements. The Company expects annual reductions in power
supply costs of approximately $13 million as a result of these settlements.
On December 11, 1989, the Company executed a conservation transfer agreement
with Snohomish County PUD. Snohomish County PUD, together with Mason and
Lewis County PUDs, will install conservation measures in their service areas.
The agreement calls for the Company to receive the power saved over the
expected 20-year life of the measures. The agreement calls for BPA to
deliver the conservation power to the Company from March 1, 1990 through
June 30, 2001 and for Snohomish County PUD to deliver the conservation power
for the remaining term of the agreement. Annual power deliveries gradually
increased over the first five years of the agreement and will remain at 6
average MW of energy throughout the remaining 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 seasonally
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. Each party may terminate the contract for various
reasons. The Company has obtained 400,000 KW of transmission rights (similar
in nature to ownership type rights) on the Pacific Northwest-Southwest AC
Intertie. These transmission rights are used, in part, to transmit power
under this agreement.
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In October of 1997 a power exchange agreement between the Company and Powerex
(a British Columbia utility) became effective. Under this agreement Powerex
pays the Company for the right to deliver power to the Company at the
Canadian border in exchange for the Company delivering power to Powerex at
various locations in the United States. The Company also obtained 425,000 KW
of transmission rights (similar in nature to ownership type rights) on the
Westside Northern Intertie in October of 1997. These transmission rights are
used, in part, to transmit power under this agreement.
Electric Energy Supply Contracts and Agreements With Non-Utilities.
As required by the federal Public Utility Reform and Policy Act ("PURPA"),
the Company has entered into long-term firm purchased power contracts with
non-utility generators. The most significant of these are the five contracts
described below which the Company entered into in 1989, 1990 and 1991 with
operators of natural gas-fired cogeneration projects. The Company purchases
the net electrical output of these five projects at fixed and annually
escalating prices which were intended to approximate the Company's avoided
cost of new generation projected at the time these agreements were made.
Principally as a result of dramatic changes in natural gas price levels, the
power purchase prices under these agreements are significantly above the
current market price of power and, based upon projections of future market
prices, are expected to remain well above market for the duration of the
contracts. The Company's estimated payments under these five contracts are
$247 million for 1998, $257 million for 1999, $265 million for 2000, $288
million for 2001, $297 million for 2002 and in the aggregate, $3.1 billion
thereafter through 2014. These payments reflect the Tenaska contract
restructuring described below. The Company continues to seek restructuring
of the other four contracts. When and if retail electric energy prices move
to market levels as a result of electric industry restructuring, the above
market portion of these contract costs may become stranded costs which the
Company plans to seek to recover through transition charges.
On June 29, 1989, the Company executed a 20-year contract to purchase 70
average MW of energy and 80 MW of capacity, beginning October 11, 1991, from
the March Point Cogeneration Company ("March Point"), which owns and operates
a natural gas-fired cogeneration facility known as March Point Phase I,
located at a Texaco refinery in Anacortes, Washington. On December 27, 1990,
the Company executed a second contract (having a term coextensive with the
first contract) to purchase an additional 53 average MW of energy and 60 MW
of capacity, beginning in January 1993, from another natural gas-fired
cogeneration facility owned and operated by March Point, which facility is
known as March Point Phase II and is located at the Texaco refinery in
Anacortes, Washington.
On February 24, 1989, the Company executed a 20-year contract to purchase 108
average MW of energy and 123 MW of capacity, beginning in April 1993, from
Sumas Cogeneration Company, L.P., which owns and operates a natural gas-fired
cogeneration project located in Sumas, Washington.
On September 26, 1990, the Company executed a 15-year contract to purchase
141 average MW of energy and 160 MW of capacity, beginning in July 1993, from
Encogen Northwest L.P. ("Encogen") (a limited partnership having a general
partner that is a subsidiary of Enserch Development Corp.), which owns and
operates a natural-gas fired cogeneration facility located at the Georgia
Pacific mill near Bellingham, Washington.
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On March 20, 1991, the Company executed a 20-year contract to purchase 216
average MW of energy and 245 MW of capacity, beginning in April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas
fired cogeneration project located near Ferndale, Washington. In December
1997 and January 1998, the Company and Tenaska Washington Partners entered
into revised agreements which will lower purchased power costs from the
Tenaska project by restructuring its natural gas supply. The Company paid
$215 million to buy out the project's existing long-term gas supply
contracts, which contained fixed and escalating gas prices that were well
above current and projected future market prices for natural gas. The
Company became the principal natural gas supplier to the project and power
purchase prices under the Tenaska contract were revised to reflect market-
based prices for the natural gas supply. The Company obtained an order from
the Washington Commission creating a regulatory asset related to the $215
million restructuring payment. These revised arrangements are expected to
reduce the Company's power supply costs from the Tenaska project between 15
and 20 percent annually over the remaining 14 year life of the contract, net
of the costs of the restructuring payment. The Company's purchased electric
energy costs associated with the Tenaska contract was $75.7 million in 1997.
Electric Energy Conservation
The Company offers programs designed to help new and existing customers use
electric energy efficiently. The primary emphasis is to provide information
and technical services to enable customers to make energy-efficient choices
with respect to building design, equipment and building systems, appliance
purchases and operating practices.
The Company's electric energy conservation expenditures have historically
been accumulated, included in rate base and amortized to expense over a ten
year period at the direction of the Washington Commission. In June 1995 the
Company sold approximately $202.5 million of its investment in customer-
owned energy conservation measures to a grantor trust, which, in turn,
issued securities backed by a Washington state statute enacted in 1994. On
August 6, 1997, the Company sold an additional $35.2 million of such
conservation investments in a similarly structured transaction
Electric Rates and Regulation
The order approving the Merger, issued by the Washington Commission on
February 5, 1997, contains a rate plan designed to provide a five-year
period of rate certainty for customers and to provide the Company with an
opportunity to achieve a reasonable return on investment. As required under
the Merger order, the Company filed tariffs, effective February 8, 1997,
that resulted in an average decrease of 5.6% related to the PRAM, and an
overall increase in general electric rates of 1.8%, with increases among
rate classes varying between 1.0% and 2.5%. The general rate increase has a
positive impact on earnings while the decrease, reflecting the
discontinuation of the PRAM and collection of previously accrued revenues,
does not affect earnings. The net impact was an average decrease in
electric rates of 3.7%. General rates for electric residential, large
commercial and industrial service will increase by 1.5% on January 1 of each
of the four years beginning in 1998, while those for small commercial,
industrial and lighting electric customers will increase by 1.0% in each of
the following three years.
-9-
On September 22, 1995, the Washington Commission issued a rate order
relating to the Company's fifth annual rate adjustment under the PRAM. In
addition to approval of the rate adjustment, the Commission also agreed,
pursuant to a negotiated settlement, to discontinue the PRAM on September
30, 1996. PRAM accrued revenues of $40.5 million, recorded at December 31,
1996, were recovered in the first quarter of 1997. Over-collection of PRAM
revenues totaling $17.0 million was refunded to customers in the second
quarter of 1997.
With the discontinuance of the PRAM effective October 1, 1996, the annual
regulatory adjustments for variations in weather and hydro conditions
provided for in the PRAM were also discontinued.
-10-
ENERGY DELIVERY OPERATING STATISTICS
Electric Operations:
Year Ended on December 31 1997 1996 1995 1994 1993
- -------------------------------------------------------------------------------------------
Operating revenues by classes:
(thousands)
Residential $ 529,990 $ 554,318 $ 524,748 $ 532,124 $ 502,037
Commercial 414,480 423,139 397,211 375,751 356,586
Industrial 166,473 170,596 168,501 163,574 150,063
Other consumers 32,453 44,125 38,730 38,759 28,189
- -------------------------------------------------------------------------------------------
Operating revenues
billed to consumers (a) 1,143,396 1,192,178 1,129,190 1,110,208 1,036,875
Unbilled revenues -
net increase (decrease) (4,921) 13,201 (6,382) (2,522) 14,409
PRAM accrual (40,777) (74,326) 3,955 25,835 42,100
- -------------------------------------------------------------------------------------------
Total operating revenues
from consumers 1,097,698 1,131,053 1,126,763 1,133,521 1,093,384
Other utilities 133,726 67,716 52,567 60,537 19,494
- -------------------------------------------------------------------------------------------
Total operating revenues $1,231,424 $1,198,769 $1,179,330 $1,194,058 $1,112,878
- -------------------------------------------------------------------------------------------
Number of customers (average):
Residential 767,476 754,097 739,173 723,566 708,123
Commercial 91,517 89,613 87,404 85,203 82,875
Industrial 4,090 3,993 3,908 3,851 3,715
Other 1,389 1,371 1,346 1,325 1,289
- -------------------------------------------------------------------------------------------
Total customers (average) 864,472 849,074 831,831 813,945 796,002
- -------------------------------------------------------------------------------------------
KWH generated, purchased
and interchanged (thousands):
Company generated 6,641,118 5,585,595 6,371,416 7,011,932 6,414,311
Purchased power 22,611,963 20,573,983 17,897,922 16,268,042 14,608,899
Interchanged power (net) 103,959 99,942 48,485 (87,771) 174,478
- -------------------------------------------------------------------------------------------
Total energy output 29,357,040 26,259,520 24,317,823 23,192,203 21,197,688
Losses and company use (1,414,101) (1,322,262) (1,235,457) (1,291,322) (1,096,599)
- -------------------------------------------------------------------------------------------
Total energy sales 27,942,939 24,937,258 23,082,366 21,900,881 20,101,089
- -------------------------------------------------------------------------------------------
(a) Operating revenues in 1997, 1996 and 1995 were reduced by $40.5 million, $41.0 million
and $25.1 million, respectively, as a result of the Company's sale of $237.7 million of its
investment in customer-owned energy conservation measures. (See "Operating revenues" in
Management's Discussion and Analysis and Note 1 to the Consolidated Financial Statements.)
Electric Operations (continued from previous page):
Year Ended on December 31 1997 1996 1995 1994 1993
- --------------------------------------------------------------------------------------------
Electric energy sales, KWH:
(thousands)
Residential 9,319,508 9,350,292 8,972,498 8,913,903 8,974,787
Commercial 7,022,092 6,807,465 6,538,533 6,301,568 6,175,911
Industrial 3,994,748 3,793,966 3,720,641 3,724,931 3,690,473
Other consumers 206,330 205,066 205,232 200,622 196,246
- --------------------------------------------------------------------------------------------
Total energy billed
to consumers 20,542,678 20,156,789 19,436,904 19,141,024 19,037,417
Unbilled energy sales -
net increase (decrease) (45,556) 224,412 (158,920) (72,352) 139,329
- --------------------------------------------------------------------------------------------
Total energy sales
to consumers 20,497,122 20,381,201 19,277,984 19,068,672 19,176,746
Sales to other
electric utilities 7,445,817 4,556,057 3,804,382 2,832,209 924,343
- --------------------------------------------------------------------------------------------
Total energy sales 27,942,939 24,937,258 23,082,366 21,900,881 20,101,089
- --------------------------------------------------------------------------------------------
Per residential customer:
Annual use (KWH) 12,143 12,399 12,139 12,319 12,674
Annual billed revenue $716.88 $762.35 $726.95 $735.42 $708.97
Billed revenue per KWH $.0590 $.0615 $.0599 $.0597 $.0559
Company-owned generation
capability - kilowatts:
Hydro 309,950 309,950 309,950 309,950 309,950
Steam 771,900 771,900 771,900 771,900 857,700
Natural gas/oil 702,350 702,350 702,350 702,350 702,350
- --------------------------------------------------------------------------------------------
Total 1,784,200 1,784,200 1,784,200 1,784,200 1,870,000
- --------------------------------------------------------------------------------------------
Heating degree days 4,599 4,953 3,994 4,341 4,691
% of normal of 30 year
average (4,908) 93.7% 100.9% 81.4% 88.4% 95.6%
Load factor 58.7% 55.5% 56.7% 54.7% 52.5%
-12-
Gas Utility Operations
- ---------------------
Gas Supply
The Company currently purchases a blended portfolio of long-term firm, short-
term firm, and spot gas supplies from a diverse group of major and
independent producers and gas marketers in the United States and Canada. All
of the Company's gas supply is ultimately transported through Northwest
Pipeline Corporation ("NPC"), the sole interstate pipeline delivering
directly into the western Washington area.
Peak Firm
Gas Supply at
December 31,
Dth per Day %
----------- ----
Purchased Gas Supply
- --------------------
British Columbia 212,500 26.0
Alberta 78,000 9.6
United States 75,800 9.3
-----------------
366,300 44.9
-----------------
Purchased Storage Capacity
- --------------------------
Clay Basin 111,800 13.7
Jackson Prairie 47,900 5.9
LNG 70,500 8.7
-----------------
230,200 28.3
-----------------
Owned Storage Capacity
- ----------------------
Jackson Prairie 188,500 23.1
Propane-Air Injection 30,000 3.7
-----------------
218,500 26.8
-----------------
815,000 100.0
=================
All supplies and storage are connected to PSE's Market with Firm
Transportation capacity.
For baseload and peak-shaving purposes, the Company supplements its firm gas
supply portfolio by purchasing natural gas at generally lower prices in
summer, injecting it into underground storage facilities and withdrawing it
during the winter heating season. Storage facilities at Jackson Prairie in
Western Washington and at Clay Basin in Utah are used for this purpose.
Peaking needs are also met by using the Company's gas held in NPC's liquefied
natural gas ("LNG") facility at Plymouth, Washington, and by producing
propane-air gas at a plant owned by the Company and located on its
distribution system.
-13-
The Company expects to meet its firm peak-day requirements for residential,
commercial and industrial markets through its firm gas purchase contracts,
firm transportation capacity, firm storage capacity and other firm peaking
resources. The Company believes that it will be able to acquire incremental
firm gas supply resources which are reliable and reasonably priced, to meet
anticipated growth in the requirements of its firm customers for the
foreseeable future.
Gas Supply Portfolio
For the 1997-98 winter heating season, the Company has contracted for
approximately 26% of its expected peak-day gas supply requirement from
sources originating in British Columbia under a combination of long-term and
winter peaking purchase agreements. Long-term gas supplies from Alberta
represent approximately 10% of the peak-day requirement. Long-term and
winter peaking arrangements with U.S. suppliers and gas stored at Clay Basin
make up approximately 23% of the peak-day portfolio. The balance of the
peak-day requirement is expected to be met with gas stored at Jackson
Prairie, LNG held at NPC's Plymouth facility and propane-air resources, which
represent approximately 29%, 9% and 3%, respectively, of expected peak-day
requirements. During 1997, approximately 46% of gas supplies purchased by
the Company originated from British Columbia while 26% originated in Alberta
and 28% originated in the U.S.
The current firm, long-term gas supply portfolio consists of arrangements
with 18 producers and gas marketers, with no single supplier representing
more than 17% of expected peak-day requirements. Contracts have remaining
terms ranging from less than one year to six years, with an average term of
two years. All gas supply contracts contain market-sensitive pricing
provisions based on several published indices.
The Company's firm gas supply portfolio is structured to capitalize on
regional price differentials when they arise. Gas and services are marketed
outside the Company's service territory ("off-system sales") whenever on-
system customer demand requirements permit. The geographic mix of suppliers
and daily, monthly and annual take requirements permit a high degree of
flexibility in selecting gas supplies during off-peak periods to minimize
costs.
Gas Transportation Capacity
The Company currently holds firm transportation capacity on pipelines owned
by Northwest Pipeline Corporation and PG&E Gas Transmission-Northwest,
formerly known as Pacific Gas Transportation ("PGT"). Accordingly, the
Company pays fixed monthly demand charges for the right, but not the
obligation, to transport specified quantities of gas from receipt points to
delivery points on such pipelines each day for the term or terms of the
applicable agreements.
The Company holds firm capacity on NPC's pipeline totaling 454,533 Dekatherms
per day (one Dekatherm "Dth" is equal to one million British thermal units or
"MMBtu" per day), acquired under several agreements at various times. The
Company has exchanged certain segments of its firm capacity with third
parties to effectively lower transportation costs. The Company's firm
transportation capacity contracts with NPC have remaining terms ranging from
7 to 18 years. However, the Company has either the unilateral right to
extend the contracts under their current terms or the right of first refusal
-14-
to extend such contracts under then current FERC orders. The Company's firm
transportation capacity on PGT's pipeline has a remaining term of 26 years.
Gas Storage Capacity
The Company holds storage capacity in the Jackson Prairie and Clay Basin
underground gas storage facilities attached to NPC's pipeline. The Jackson
Prairie facility, operated and one-third owned by the Company, is used
primarily for intermediate peaking purposes, able to deliver a large volume
of gas over a relatively short time period. Combined with capacity
contracted from NPC's one-third stake in Jackson Prairie, the Company has
peak, firm delivery capacity of over 230,000 Dth per day and total firm
storage capacity of exceeding 6,000,000 Dth at the facility. The location of
the Jackson Prairie facility in the Company's service or market area provides
significant cost savings by reducing the amount of annual pipeline capacity
required to meet peak-day gas requirements. The Company, as Project Operator
of the facility, has recently filed an application with the FERC for
authorization to expand the Jackson Prairie facility. The Company's share of
the expanded project will provide additional firm delivery capacity of over
100,000 Dth per day and additional firm storage capacity of above 1,000,000
Dth at the start of the 1999-2000 heating season, if approved by regulators.
The Company has secured rights to additional firm seasonal pipeline capacity
to be utilized in conjunction with the expanded project.
The Clay Basin storage facility is supply area storage and is withdrawn over
the entire winter, capturing savings due to injecting lower cost gas supplies
during the summer. The Company has maximum firm withdrawal capacity over
100,000 Dth per day from the facility with total storage capacity exceeding
13,000,000 Dth. The capacity is held under two contracts with remaining
terms of 16 and 22 years.
LNG and Propane-Air Resources
LNG and propane-air resources provide gas supply on short notice for short
periods of time. Due to their high cost, these resources are utilized as the
supply of last resort in extreme peak-demand periods, typically lasting a few
hours or days. The Company has long-term contracts for storage of nearly
250,000 Dth of its gas as LNG at NPC's Plymouth facility, which equates to
approximately three and one-half days' supply at maximum daily deliverability
of 70,500 Dth. The Company owns storage capacity for approximately
1.4 million gallons of propane. The propane-air injections facilities are
capable of delivering the equivalent of 30,000 Dth of gas per day for up to
four days directly into the Company's distribution system.
Capacity Release
FERC provided a capacity release mechanism as the means for holders of firm
pipeline and storage entitlements to relinquish temporarily unutilized
capacity to others in order to recoup all or a portion of the cost of such
capacity. Capacity may be released through several methods including open
bidding and by pre-arrangement. The Company continues to successfully
mitigate a substantial portion of the demand charges related to both storage
and pipeline capacity not utilized during off-peak periods. WNG CAP I, a
wholly owned subsidiary of the Company, was formed to provide additional
flexibility and benefits from capacity release. In approving the Company's
last approved PGA, effective May 15, 1995, the Washington Commission allowed
all previously incurred and projected capacity related NPC's demand charges
-15-
to be recovered in rates. Washington Energy Gas Marketing Company, a wholly-
owned subsidiary of the Company, markets excess capacity on the PGT pipeline.
(See Note 17 to the Consolidated Financial Statements.)
Gas Rates and Regulation
The order approving the Merger, issued by the Washington Commission on
February 5, 1997, contains a rate plan designed to provide unchanged rates
for all classes of natural gas customers until January 1, 1999, when rates
will decrease by 1% on gas utility margins.
Beginning in 1971, the Washington Commission permitted WNG and now PSE to
pass on to its customers, through changes in its rates, all changes in the
price of gas purchased from nonaffiliated suppliers through the Purchased Gas
Adjustment (PGA) mechanism. This mechanism allows the Company to pass these
cost increases or decreases to its customers on a timely basis, resulting in
no material impact on net income. The current PGA was approved by the
Washington Commission effective May 15, 1995. This PGA resulted in a pass-
through to customers of an annual reduction of $46.5 million in the cost of
purchased gas. On February 11, 1998, the Company filed a PGA with the
Washington Commission seeking a decrease of $3.8 million in the effective PGA
rates. Simultaneously, the Company filed for a concurrent increase in PGA
rates to "true up" prior period gas costs. The net effect of these two
filings was to increase customers rates by approximately one-fifth of one
percent. The Company expects these two filings to be approved by the
Washington Commission and placed into effect on April 1, 1998.
Gas Rate Redesign.
On May 11, 1995, the Washington Commission ordered the implementation of a
cost-based gas tariff rate design effective May 15, 1995. The order, while
revenue neutral in total, shifted rates and costs, and thus source of margin,
among customer classes. The average margins on transportation service
decreased by 26% and margins on sales to larger volume industrial sales
customers decreased by 27%. The order also raised average residential
margins 4.5%. Firm commercial and smaller industrial average margins were
not materially affected. The changes in transportation and industrial
margins made the utility economically indifferent to customer switching
between transportation and sales service. The Company believes the order
enhances the Company's ability to offer rates that support cost-effective and
responsible growth and customer choice.
The Company is also engaged in the business of leasing gas water heaters for
residential and commercial use. As of December 31, 1997, the Company had gas
water heater equipment leases with customers with original costs and net book
value of approximately $57.3 million and $49.5 million, respectively. Lease
revenues are included in the financial statements as part of Regulated
Utility Sales since the rates charged are subject to the approval of the
Washington Commission. The leases may be terminated on 30 days' written
notice by the customer, in which case the Company removes the equipment at no
charge to the customer. However, most customers elect to purchase the
equipment at a price which approximates net book value of the equipment.
Lease revenues for the 12 months ended December 31, 1997, were approximately
$10.4 million.
-16-
ENERGY DELIVERY OPERATING STATISTICS
Gas Operations:
Twelve Months Ended December 31, 1997 1996 1995 1994 1993
- -------------------------------------------------------------------------------------------
Operating revenues by classes:
(thousands): Regulated utility sales:
Residential firm gas sales $ 246,747 $ 238,560 $ 231,202 $ 206,602 $ 195,936
Commercial firm gas sales 97,233 94,251 97,396 91,749 87,644
Industrial firm gas sales 19,524 20,024 25,860 28,827 23,967
Interruptible gas sales 19,832 23,376 44,511 51,425 44,160
Transportation services 14,631 12,812 10,762 8,399 8,434
Other 11,480 11,085 10,317 9,405 7,712
- -------------------------------------------------------------------------------------------
Total regulated
utility sales $ 409,447 $ 400,108 $ 420,048 $ 396,407 $ 367,853
===========================================================================================
Customers, average number
served:
Residential firm 465,185 440,586 423,195 403,642 383,291
Commercial firm 41,158 39,651 38,378 37,112 35,951
Industrial firm 2,839 2,762 2,754 2,824 2,844
Interruptible 962 1,000 1,037 1,009 988
Transportation 128 106 55 36 68
- -------------------------------------------------------------------------------------------
Total average customers 510,272 484,105 465,419 444,623 423,142
===========================================================================================
Gas volumes
(thousands of therms):
Residential firm sales 434,179 421,727 398,283 371,472 382,118
Commercial firm sales 195,087 188,321 179,725 174,668 177,724
Industrial firm sales 44,563 46,640 55,365 62,698 54,096
Interruptible sales 60,244 72,229 132,316 151,175 127,678
Transportation volumes 277,092 242,299 156,941 119,590 159,765
- -------------------------------------------------------------------------------------------
Total gas volumes 1,011,165 971,216 922,630 879,603 901,381
===========================================================================================
Working gas volumes in
storage at year end
(thousands of therms)
Jackson Prairie 52,430 65,834 65,834 65,834 65,834
Clay Basin 64,930 82,847 130,970 47,557 70,006
Average use per customer:
(therms)
Residential firm 933 957 941 921 998
Commercial firm 4,740 4,749 4,683 4,708 4,903
Industrial firm 15,697 16,886 20,103 22,035 24,618
Interruptible 62,624 72,229 127,595 147,315 129,231
Transportation 2,164,781 2,285,840 2,853,473 3,400,694 2,133,676
Average revenue per customer:
Residential firm $ 530 $ 541 $ 546 $ 512 $ 511
Commercial firm 2,362 2,377 2,538 2,472 2,438
Industrial firm 6,877 7,250 9,390 10,208 8,427
Interruptible 20,615 23,376 42,923 50,966 44,695
Transportation 114,305 120,868 195,673 233,306 124,029
Average revenue per therm
(cents):
Residential firm 56.8 56.6 58.0 55.6 51.3
Commercial firm 49.8 50.0 54.2 52.5 49.3
Industrial firm 43.8 42.9 46.7 46.0 44.3
Interruptible 32.9 32.4 33.6 34.0 34.6
Total sales customers 52.2 51.6 52.1 49.8 47.4
Transportation 5.3 5.3 6.9 7.0 5.3
Weather - degree days 4,599 4,953 3,994 4,341 4,691
% of normal (30-yr avg) 93.7% 100.9% 81.4% 88.4% 95.6%
Note: Data prior to January 1, 1997, is for the period ending September 30.
Construction Financing
The Company estimates its combined electric and gas construction
expenditures, excluding Allowance for Funds Used During Construction
("AFUDC"), for 1998 through 2000 will be approximately $311 million, $274
million and $277 million, respectively. The Company expects cash from
operations (net of dividends and AFUDC) during the period 1998 through 2000
will, on average, be approximately 71% of average estimated construction
expenditures (excluding AFUDC) during the same period. 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 Indentures, Articles of Incorporation and certain loan agreements.
Under the most restrictive tests, at December 31, 1997, the Company could
issue (i) approximately $677 million of additional first mortgage bonds or
(ii) approximately $204 million of additional preferred stock at an assumed
dividend rate of 6.01% or (iii) a combination thereof.
Environment
The Company's operations are subject to environmental regulation by federal,
state and local authorities. 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. (See Note 17 to the Consolidated
Financial Statements for further discussion of environmental sites.)
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
-18-
limits of the CAAA in Phase I (1995). The Company and other joint owners of
the Centralia Project are exploring alternative emission compliance options
and project economics in light of compliance costs to meet the Phase II
limits in the year 2000. All four units at the Colstrip Project, operated by
Montana Power, meet Phase II emission limits.
The Company owns combustion turbine units, most of 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 National Marine Fisheries Service ("NMFS") listed the
Snake River Sockeye as an endangered species pursuant to the federal
Endangered Species Act ("ESA"). 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 1995 the NMFS issued a biological
opinion which has significantly changed the operation of the Federal Columbia
River Power System.
The 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 developed by NMFS shifts 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.
Since the 1991 listings, one more species of salmon has been listed and two
more have been proposed which may further influence operations. Upper
Columbia River steelhead were listed by NMFS in August 1997. Anticipating
the steelhead listing the Mid-Columbia PUD's initiated consultation with the
Federal and state agencies, Native American tribes and non-governmental
organizations to secure operational protection through a long-term settlement
and habitat conservation plan which include fish protection and enhancement
measurement for the next 50 years. The negotiations to reach ageeement have
not been completed at this time.
The proposed listings of Puget Sound chinook salmon and spring chinook for
the upper Columbia would not be final, if approved, until February 1999. The
listing of spring chinook for the upper Columbia should not result in
markedly differing conditions for operations from previous listings in the
area. However, Puget Sound has not experienced ESA listing to date and
listing could cause a number of changes in the region to operations of
government agencies and private entities including the Company. These may
adversely affect hydro plant operations, permit issuance for facilities
construction and increased costs for process and facilities. Because the
Company relies substantially less on hydroelectric energy from the Puget
Sound area than from the Mid-Columbia and because the Company has already
undertaken or agreed to undertake many enhancement measures proposed by the
fishery agencies, the impact of listing for Puget Sound salmon should be
proportionately less than the Columbia River listings.
-19-
EXECUTIVE OFFICERS AT March 16, 1998:
Name Age
- ---------------- --- ---------------------------------------------------
W. S. Weaver 54 President & Chief Executive Officer since January
1998; President and Chairman Unregulated Utilities,
May 1997 - January 1998; Vice Chairman and Chairman
of Unregulated Subsidiaries, February 1997 - May
1997; Executive Vice President and Chief Financial
Officer 1991-1997; Director since 1991.
R. R. Sonstelie 53 Chairman of the Board since February 1997;
President and Chief Executive Officer 1992-1997;
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.
R. E. Davis 44 Vice President Regulation & Utility Planning since
February 1997; Vice President Planning and
Regulation, Washington Natural Gas 1992-1997.
J. W. Eldredge 47 Chief Accounting Officer since 1994;
Corporate Secretary and Controller since 1993.
Controller since 1988; Manager Budgets and
Performance 1987-1988; Manager General Accounting
1984-1987.
D. E. Gaines 40 Treasurer since 1994; Director Strategic
Planning 1992-1994; Manager Financial Planning 1986 -
1992.
W. E. Gaines 42 Vice President Energy Supply since February 1997;
Manager Power Management 1996-1997; Manager
Operations Planning 1986-1996.
R. L. Hawley 48 Vice President and Chief Financial Officer since
March 16, 1998. For more than five years prior to
that time, he was a senior partner with Coopers &
Lybrand L.L.P. and headed Coopers' northwest utility
practice.
T. J. Hogan 46 Vice President Systems Operations since February
1997; Washington Energy Company positions held:
Executive Vice President and Chief Operating Officer
1995-1997; Vice President Supply, Administration and
Corporate Secretary 1994-1995; Vice President Legal
and Corporate Secretary 1991-1994.
S. A. McKeon 52 Vice President and General Counsel since June 1997.
For more than five years prior to that time practiced
law at Perkins Coie.
-20-
S. McLain 41 Vice President Corporate Performance since January
1998; Director Planning and Work Practices 1997-
1998; Various positions in Human Resources,
Operations, Customer Service and Strategic Planning.
G. B. Swofford 56 Vice President Customer Operations since February
1997; Senior Vice President Customer Operations
1994-1997; 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 52 Vice President Corporate Relations since February
1997; Senior Vice President Corporate & Regulatory
Relations 1994-1997; Vice President Strategic
Planning and Regulatory Affairs February 1994 -
May 1994; Vice President Corporate Services 1992-
1994; Director Real Estate 1990-1992.
Officers are elected for one-year terms.
-21-
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 liens of the Company's Mortgage
Indentures.
ITEM 3. LEGAL PROCEEDINGS
See Note 17 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, 1997, was 62,780.
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.
The payment of dividends on common stock is restricted by provisions of
certain covenants applicable to preferred stock and long-term debt contained
in the Company's Articles of Incorporation and electric and gas mortgage
indentures. Funds available for payment of dividends are limited to: (1) net
income available for dividends on common stock accumulated after December 31,
1957, plus $7.5 million under the electric mortgage indenture; and (2) net
income available for dividends on common stock accumulated after September
30, 1989, plus $20 million under the gas mortgage indenture. Under the most
restrictive covenants, earnings reinvested in the business unrestricted as to
payment of cash dividends were approximately $114 million at December 31,
1997. (See Note 7 to the Consolidated Financial Statements.)
Dividends paid and high and low stock prices for each quarter over the last
two years were:
1997(a) 1996(a)
--------------------------- ---------------------------
Price Range Price Range
--------------- Dividends --------------- Dividends
Quarter Ended High Low Paid High Low Paid
- ------------- ------ ------ --------- ------ ------ ---------
March 31 26 23-1/2 $.46 26 23-1/4 $.46
June 30 26-1/2 23-3/4 $.46 25-5/8 23 $.46
September 30 26-15/16 25-1/8 $.46 24-1/2 22-1/4 $.46
December 31 30-3/16 25-1/2 $.46 24 22-1/8 $.46
(a) Data for Puget Sound Power & Light Company prior to February 10, 1997.
-22-
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in thousands
except per share data)
Year ended on December 31 1997 1996 1995 1994 1993
- --------------------------------------------------------------------------------------------
Operating revenue $1,676,902 $1,649,279 $1,631,118 $1,632,485 $1,586,935
Operating income $ 215,866 $ 284,474 $ 270,344 $ 224,772 $ 268,390
Income from continuing
operations $ 125,698 $ 167,351 $ 128,381 $ 79,312 $ 162,974
Income for common stock from
continuing operations $ 107,421 $ 145,170 $ 105,727 $ 58,929 $ 143,819
Basic and diluted earnings
per common share from
continuing operations $ 1.28 $ 1.72 $ 1.26 $ 0.70 $ 1.78
(Note 1 to the financial
statements)
Dividends per common share $ 1.78 $ 1.67 $ 1.67 $ 1.67 $ 1.78
Book value per common share $ 16.06 $ 16.31 $ 16.27 $ 17.01 $ 18.04
- --------------------------------------------------------------------------------------------
Total assets at year-end $4,493,370 $4,227,470 $4,244,568 $4,496,770 $4,386,678
Long-term obligations $1,411,707 $1,165,584 $1,230,499 $ ,253,498 $1,389,479
Redeemable preferred stock $ 78,134 $ 87,839 $ 89,039 $ 91,242 $ 115,724
Corporation obligated,
mandatorily redeemable
preferred securities of
subsidiary trust holding
solely junior subordinated
debentures of the
corporation $ 100,000 -- -- -- --
-23-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion of the Company's business includes some forward-
looking statements that involve risks and uncertainties. Words such as
"estimates," "expects," "anticipates," "plans," and similar expressions
identify forward-looking statements involving risks and uncertainty. Those
risks and uncertainties include, but are not limited to, the ongoing
restructuring of the electric and gas industries and the outcome of
regulatory proceedings related to that restructuring. The ultimate impacts
of both increased competition and the changing regulatory environment on
future results are uncertain, but are expected to fundamentally change how
the Company conducts its business. The outcome of these changes and other
matters discussed below may cause future results to differ materially from
historic results, or from results or outcomes currently expected or sought
by the Company.
Financial Condition and Results of Operations
Financial condition and results of operations for 1997 reflect the results
of Puget Sound Energy, Inc., formerly Puget Sound Power & Light Company
("Puget"). Financial condition and results of operations for 1996 and 1995
reflect combined results for the fiscal years ended December 31 for Puget
and September 30 for WECo.
Net income in 1997 was $123.1 million on operating revenues of $1.677
billion, compared to $165.5 million on operating revenues of $1.649 billion
in 1996 and $101.8 million on operating revenues of $1.631 billion in 1995.
Income for common stock was $105.7 million in 1997, compared to $143.3
million in 1996 and $79.1 million in 1995.
Basic and diluted earnings per share in 1997 were $1.25 on 84.6 million
weighted average common shares outstanding including a $.03 loss per share
from discontinued operations compared to $1.70 on 84.4 million weighted
average common shares outstanding in 1996 including a $.02 loss per share
from discontinued operations and $.94 on 84.2 million weighted average
common shares outstanding in 1995 including a $.32 loss per share from
discontinued operations.
The decrease in net income and basic and diluted earnings per share in 1997
reflects an after-tax charge of $36.3 million (43 cents per share) for costs
related to the merger including transaction expenses, employee separation and
system and facilities integration. Net income also includes an after-tax
charge of $2.6 million (3 cents per share), to write off the Company's
remaining investment in undeveloped coal reserves and related activities in
southeastern Montana (See Note 18 to the Consolidated Financial Statements).
Accordingly, the Company's financial statements reflect these businesses as
discontinued operations. These charges were partially offset by after-tax
interest income of $13.6 million (16 cents per share) related to an income
tax refund received in 1997 for amended returns for prior years.
The 1996 loss from discontinued operations included an after-tax charge of
$.4 million related to undeveloped coal reserves to establish an accounting
reserve for estimated operating losses through disposition. In 1995, WECo
wrote down the carrying value of its coal properties by $34.7 million ($22.6
million after-tax) and wrote off its entire railroad investment of $6.0
million ($3.9 million after-tax) with adoption of SFAS No. 121.
-24-
Results for 1995 also include special charges by the Company of $22.7
million which resulted from: 1) adoption of SFAS No. 121 by Cabot Oil and
Gas Corporation ("Cabot") and the Company which required a large write down
of Cabot's oil and gas properties and a permanent impairment in the carrying
value of the Company's investment in Cabot ($16.1 million after tax). (See
Note 16. of the Consolidated Financial Statements for a discussion of
Cabot); 2) increased losses projected in the future from certain gas
transportation and storage arrangements excluded from the merger of the
Company's former oil and gas exploration subsidiary with Cabot ($3.3 million
after tax); 3) employee severance costs ($2.0 million after tax); and 4)
deferred income taxes relating to tax contingencies ($1.3 million).
Total kilowatt-hour sales to ultimate consumers in 1997 were 20.5 billion,
compared with 20.4 billion in 1996 and 19.3 billion in 1995. Kilowatt-hour
sales to other utilities were 7.4 billion in 1997, 4.6 billion in 1996 and
3.8 billion in 1995.
Total gas volumes sold, including transported gas, were 1,011 million therms
in 1997, 971 million therms in 1996 and 923 million therms in 1995.
-25-
Increase (Decrease) Over Preceding Year
Years Ended December 31
(Dollars in Millions)
1997 1996 1995
- ---------------------------------------------------------------------
Operating revenues
PRAM rate transfer and
general rate increase $152.9 $ 33.8 $ --
PRAM electric revenues (158.6) (37.1) 31.6
BPA Residential Purchase and
Sale Agreement 2.7 (15.8) (25.3)
Electric sales to other utilities 66.0 15.1 (8.0)
Electric revenue sold to conservation trust 0.5 (15.9) (25.1)
Electric load and other changes (45.2) 58.0 1.8
Gas revenue change 9.3 (19.9) 23.6
- ---------------------------------------------------------------------
Total operating revenue changes 27.6 18.2 (1.4)
- ---------------------------------------------------------------------
Operating expenses
Energy Costs:
Purchased electricity 52.6 38.8 33.7
Residential exchange 31.2 (15.1) (24.1)
Purchased gas 1.6 (41.3) (4.5)
Electric generation fuel 0.8 5.0 (11.5)
Utility operations and maintenance 8.2 (15.8) (41.7)
Other operations and maintenance (11.0) 2.7 (14.2)
Depreciation and amortization 17.6 3.2 (6.0)
Merger and related costs 51.0 4.8 --
Taxes other than federal income taxes 4.2 5.5 4.6
Federal income taxes (60.0) 16.2 16.7
- ---------------------------------------------------------------------
Total operating expense changes 96.2 4.0 (47.0)
- ---------------------------------------------------------------------
Other income 26.5 16.4 7.7
Interest charges (0.5) (8.3) 4.2
Discontinued operations (0.8) 24.8 (25.7)
- ---------------------------------------------------------------------
Net income changes $(42.4) $ 63.7 $ 23.4
=====================================================================
The following information pertains to the changes outlined in the table
above:
Operating Revenues - Electric
Electric operating revenues in 1997 increased 2.7% compared to 1996 due to
continued growth in the number of electric customers and an overall average
1.8% general rate increase effective February 8, 1997. However, electric
load and revenues were negatively impacted by temperatures that averaged
5.9% warmer than normal in 1997. Electric revenues during the period of
October 1, 1995 through September 30, 1996 increased as a result of rates
authorized by the Washington Utilities and Transportation Commission (the
"Washington Commission") under the fifth Periodic Rate Adjustment Mechanism
("PRAM") filing. The PRAM was terminated effective September 30, 1996. (See
"Rate Matters.")
-26-
On September 30, 1996, the Washington Commission issued an order granting a
joint motion by the Company and the Washington Commission Staff to transfer
annual revenues of $165.5 million which were being collected in PRAM rates
to the Company's permanent rate schedules. The PRAM rate transfer to
permanent rate schedules and the February 8, 1997, increase in general rates
increased revenues $152.9 million and $33.8 million in the years ended
December 31, 1997 and December 31, 1996, respectively. As a result of the
transfer, PRAM revenues decreased $158.6 million in 1997 compared to the
prior year due to the elimination of the PRAM effective September 30, 1996,
under a stipulated negotiated settlement approved by the Washington
Commission. A $17.0 million overcollection of the PRAM, which resulted from
the pass-through of conservation tax refunds, was refunded to customers in
the second quarter of 1997.
Electric operating revenues for 1997 include a $48.6 million reduction to
reflect an IRS tax refund and related interest received in the first quarter
associated with conservation expenditures for the years 1991-1994. Based on
the Company's agreement with the Washington Commission, the benefit of the
tax refund was passed on to retail customers as a reduction of the PRAM
accrued revenue balance. The $48.6 million reduction in revenues was offset
by reductions in federal and state taxes, by a reduction in interest expense
and an increase in interest income.
Electric revenues have been reduced by virtue of the credit that the Company
received through the Residential Purchase and Sale Agreement with the
Bonneville Power Administration ("BPA"). This agreement enables the
Company's residential and small farm customers to receive the benefits of
lower-cost federal power. A corresponding reduction is included in
purchased and interchanged power expenses. On January 29, 1997, the Company
and the BPA signed a Residential Exchange Termination Agreement. The
Agreement effectively ends the Company's participation in the Residential
Purchase and Sale Agreement in exchange for settlement payments by the BPA
of approximately $237 million over five years. Under the rate plan approved
by the Washington Commission in its merger order, the Company will continue
to reflect, in customers' bills, the current level of Residential Exchange
benefits. Over the five-year period, it is projected that the Company will
credit customers approximately $250 million more than it will receive from
BPA.
Electric revenues in 1997, 1996 and 1995 were reduced by $40.5 million,
$41.0 million and $25.1 million, respectively, as a result of the Company's
sale of revenues associated with $237.7 million of its investment in
conservation assets to a grantor trust. The revenue decrease represents the
portion of rate revenues that were sold and forwarded to the trust. The
impact of this revenue decrease, however, was offset by related reductions
in other utility operations and maintenance and interest expenses.
To meet customer demand, the Company's power supply portfolio includes net
purchases of power under long-term supply contracts. However, depending
principally upon streamflow available for hydroelectric generation and
weather effects on customer demand, from time to time the Company may have
surplus power available for sale at wholesale to other utilities. In
addition, the Company has increased its wholesale surplus power business
through short and intermediate term purchase, sale, arbitrage and other
trading and marketing techniques. Sales to other utilities increased $66.0
million in 1997 compared to 1996 due primarily to increased wholesale power
transactions.
-27-
Operating Revenues - Gas
Regulated gas utility sales revenue in 1997 increased by $9.3 million, from
the prior year on a 0.7% increase in gas volumes sold. Total gas volumes,
including transported gas, increased 4.1% in 1997 from 1996. Utility margin
(the difference between gas revenues and gas purchases) increased by $7.7
million, or 3.5%, in 1997.
Regulated gas utility sales revenue in 1996 decreased by $19.9 million, or
5%, from the prior year on a 5% decrease in gas volumes sold. Total gas
volumes, including transported gas, increased 5% in 1996. The PGA
implemented in May 1995, which reduced rates, and customers switching from
gas sales service to transportation, combined to more than offset the impact
of the May 1995 general rate increase and increases in gas sales due to
customer growth and colder weather. Utility margin increased by $21.4
million, or 11%, due primarily to: the full-year impact of the $17.7 million
general rate increase in May 1995; a 4%, or 19,000 increase in customers;
and additional heating load due to weather that was 3% warmer than normal in
1996 versus 12% warmer than normal in 1995. The May 1995 PGA reduced
revenues but did not impact utility margin. The shifting of customers from
sales service to transportation did not materially impact utility margin, as
most were switching from large volume, interruptible gas sales. Due to the
rate redesign implemented in May 1995, the Company generally earns the same
margin on transportation service as it does on large volume, interruptible
gas sales.
The $23.6 million, or 6%, increase in regulated gas sales revenue in 1995
was largely the result of two general rate increases and customer growth,
partially offset by the impact of the May 1995 PGA, which reduced rates for
a portion of the year. Gas utility margin increased by $28.1 million, or
16%, due primarily to the rate increases and customer growth, and was not
impacted by the PGA. The general rate orders increased gas utility margin
by approximately $18 million in 1995. The impact on gas utility margin in
1995 was less than the full annualized impact of the two rate orders because
of warmer weather and the timing of the May 1995 increase, which was
implemented after the heating season. The Company's rate of growth in new
gas customers remained at approximately 4%, or 21,000 customers, during
1995, increasing firm gas sales volumes by 5% and adding an estimated $6
million in gas utility margin. During 1995, weather did not have a
significant impact on gas utility margin due to the fact that much of the
winter of 1995 was colder than in 1994, while the rest of 1995, when heating
load was lower, was significantly warmer than 1994.
Operating Expenses
Purchased electricity expenses increased $52.6 million in 1997 when compared
to 1996 and $38.8 million in 1996 when compared to 1995. The change in 1997
was due primarily to a $47.5 million increase in secondary power purchases
from other utilities and a $5.4 million increase in transmission wheeling
and associated costs compared to 1996. The increase in 1996 over 1995 was
the result of higher payments for firm power purchases from non-utility
generators and increased secondary power purchases from other utilities.
Purchased electricity expenses increased $33.7 million in 1995 when
compared to 1994. Higher payments for firm power purchases from non-
utility generators and secondary power purchases from other utilities
contributed to an increase of $35.4 million.
-28-
Residential exchange credits associated with the Residential Purchase
and Sale Agreement with BPA decreased $31.2 million in 1997 when
compared to 1996. The primary reason for the decrease was the
Residential Exchange Termination Agreement between the Company and BPA
in January 1997. Residential exchange credits increased $15.1 million
in 1996 as compared to 1995 and $24.1 million in 1995 as compared to
1994. Residential exchange credits received in 1997 were $72 million
and are estimated to be $55.6 million, $39.0 million, $41.0 million and
$27.0 million in the years 1998 through 2001. (See discussion of the
Residential Purchase and Sale Agreement under Operating Revenues.)
Purchased gas expenses increased $1.6 million in 1997 compared to 1996 as a
result of the 0.7% increase in gas volumes sold.
Purchased gas expenses decreased $41.3 million in 1996 compared to 1995.
The decrease resulted from the lower average per-therm cost of gas
established in the May 1995 PGA and the 5% reduction in gas volumes sold.
Purchased gas expenses decreased $4.5 million in 1995 when compared to 1994
due to the PGA implemented in May 1995.
Fuel expense increased $5.0 million in 1996. The increase was due in part
to an Arbitration Panel's decision in 1995 of a dispute involving the coal
supply agreement at the Company's fifty percent-owned Colstrip 1 and 2
plants that resulted in a $4.6 million decrease to fuel expense recorded in
the first quarter of 1995. In addition, the Company recorded a one-time
charge of $1.8 million in the second quarter of 1996 relating to a loss on
the sale of oil stocks at a combustion turbine site.
Fuel expense decreased $11.5 million in 1995 compared to 1994 as the Company
generated less electricity at company-owned coal plants while purchasing
more power on the secondary market. Additionally, the Arbitration Panel's
decision mentioned above resulted in a $4.6 million decrease to fuel expense
in the first quarter of 1995.
Operations and maintenance expenses decreased $2.8 million in 1997 compared
to 1996. Although utility operations and maintenance was up slightly, other
operations and maintenance was down because of decreased sales activity at
the Company's subsidiaries.
Operations and maintenance expenses decreased $13.1 million in 1996 compared
to 1995. The decrease was largely the result of an $11.6 million decrease in
amortization expense associated with the Company's conservation program. In
June 1995, the Company sold, to a grantor trust, approximately $202.5
million of its investment in customer-owned energy conservation measures.
Operations and maintenance expenses decreased $55.9 million in 1995 compared
to 1994. Major factors in the reduction included: 1) $24.8 million due to
decreased charges in 1995 compared to 1994 associated with the Company's
restructuring including employee separation programs and related business
office and service facility consolidations; 2) lower amortization expense of
$14.3 million associated with the Company's sale, in June 1995, of $202.5
million of its investment in customer-owned energy conservation measures,
and 3) a $15.0 million decrease in subsidiary expenses as a result of
decreased sales activity.
Depreciation and amortization expense increased $17.6 million in 1997 from
1996 levels due primarily to capital spending related to adding customers
-29-
and transmission and distribution system improvements. In addition, an
August 1997 Washington Commission Order authorized the Company to record
interest income of $8.3 million related to a conservation tax refund but
required the Company to write-off deferred storm damage costs in the amount
of $7.4 million, and establish a $1.0 million reserve to cover the costs of
a Company retail pilot program.
Depreciation and amortization expense increased $3.2 million in 1996
compared to 1995 due primarily to new plant placed in service. Depreciation
and amortization expense decreased $6.0 million in 1995 from 1994 levels. A
decrease of $12.9 million was attributable to the completion in September
1994 of the 10-year amortization period related to two terminated generating
projects. This decrease was partially offset by the effects of new plant
placed into service.
Taxes other than federal income taxes increased $4.2 million in 1997
compared to 1996 and $5.5 million in 1996 compared to 1995. The increases
were primarily due to higher state property tax payments and higher revenue-
based municipal and state excise tax payments.
Taxes other than federal income taxes increased $4.6 million in 1995
compared to 1994. The increase was primarily the result of increased
municipal and state excise tax payments of $4.5 million and increased
property tax payments of $1.0 million. These increases were partially offset
by lower payroll taxes.
Federal income taxes in 1997 were $60 million less than 1996 due to a number
of factors. An IRS tax refund related to the method of accounting for taxes
on conservation expenditures during the first quarter of 1997 decreased
federal income taxes by $26.5 million. In addition, there was a $17.0
million reduction associated with a decrease in PRAM revenues of $48.6
million. Merger costs expensed in the first quarter further reduced federal
income taxes by $19.3 million.
Federal income taxes increased by $16.2 million in 1996 over 1995. The
increase was primarily due to higher pre-tax utility earnings. Also, there
was a decrease in energy conservation expenditures in 1996 which are
deducted for federal income taxes. Federal income taxes on operations
increased $16.7 million in 1995 over 1994 due primarily to higher pre-tax
operating income during 1995.
Other Income
Other income, net of federal income tax, increased $26.5 million in 1997
from 1996. The increase was due primarily to interest income received from
the IRS on tax refunds for prior years in connection with a plant
abandonment loss, conservation tax refunds and certain additional research
and experimental credits claimed for tax purposes. Other income for 1997
includes after-tax losses of $1.0 million and $5.3 million related to the
sale of an unregulated subsidiary (Washington Energy Services Company) and
operations of a subsidiary, ConnexT.
Total other income increased $16.4 million in 1996 as compared to 1995. The
increase is due primarily to pre-tax charges in 1995 related to Cabot
totaling $24.8 million, partially offset by a $8.7 million deferred tax
benefit of write-downs.
-30-
Other income increased $7.7 million in 1995. The increase is primarily due
to lower special charges in 1995 as compared to 1994. Included in other
income in 1995 were pre-tax charges related to Cabot of $24.8 million, while
charges in 1994 included a pre-tax loss and related federal income taxes on
the merger of Cabot of $30.0 million.
Interest Charges
Interest charges, which consist of interest and amortization on long-term
debt and other interest, decreased $0.5 million in 1997 compared to 1996.
Interest and amortization on long-term debt increased $2.4 million which
included dividend payments on the Company obligated mandatorily redeemable
preferred securities of $4.7 million interest on short-term debt decreased
$1.5 million and capitalized interest (AFUDC) increased $1.3 million
Interest charges decreased $8.3 million in 1996 compared to 1995. Interest
and amortization on long-term debt decreased $8.8 million. Contributing to
the reduced interest expense were five First Mortgage Bond retirements or
redemptions totaling $151 million over the previous 17 months. Other
interest expense increased in 1996 over 1995 due primarily to increased
interest on PGA balances.
Interest charges increased $4.2 million in 1995 compared to 1994. Interest
and amortization on long-term debt decreased $4.4 million due primarily to
the maturity of $100 million in First Mortgage Bonds in August 1995. Other
interest expense increased $8.6 million in 1995 over 1994. The increase was
primarily due to higher weighted-average interest rates and higher average
daily short-term borrowings in 1995 as compared to 1994.
Construction, Capital Resources and Liquidity
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, were $257.9 million in 1997. The Company expects
construction expenditures for the period 1998 through 2000 will be
approximately $311 million, $274 million and $277 million, respectively. The
Company expects cash from operations (net of dividends and AFUDC) during the
period 1998 through 2000 will, on average, be approximately 71% of average
estimated construction expenditures (excluding AFUDC) during the same
period.
In June 1997, the Company issued $100 million of Company obligated,
mandatorily redeemable preferred securities (See Note 5 to the Consolidated
Financial Statements.). In December 1997, 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 $500 million principal
amount of Senior Notes secured by a pledge of First Mortgage Bonds. On
December 22, 1997, the Company issued $300 million of Series A Notes at
7.02%.
Short-term borrowings from banks and the sale of commercial paper are used
to provide working capital for the construction program. At December 31,
1997, the Company had available $375 million in lines of credit with various
banks, which provide credit support for outstanding commercial paper and
bank borrowing of $125 million and $215 million, respectively, effectively
reducing the available borrowing capacity under these lines of credit to $35
million. (See Note 9 to the Consolidated Financial Statements.)
-31-
Under the most restrictive covenants in the Company's Articles of
Incorporation and electric and gas mortgage indentures, earnings reinvested
in the business unrestricted as to payment of cash dividends were
approximately $114 million at December 31, 1997.
Rate Matters - Electric
On September 22, 1995, the Washington Commission issued a rate order
relating to the Company's fifth annual rate adjustment under the PRAM. In
addition to approval of the rate adjustment, the Commission also agreed,
pursuant to a negotiated settlement, to discontinue the PRAM on September
30, 1996. PRAM accrued revenues of $40.5 million, recorded at December 31,
1996, were recovered in the first quarter of 1997. Over-collection of PRAM
revenues were refunded to customers in the second quarter of 1997.
With the discontinuance of the PRAM, the Company no longer has a rate
adjustment mechanism to adjust for changes in cost or variances in hydro and
weather conditions. These variances may now significantly influence
earnings.
On September 30, 1996, the Washington Commission issued an order granting a
joint motion by the Company and the Washington Commission Staff to transfer
annual revenues of $165.5 million which were being collected in PRAM rates
to the Company's permanent rate schedules. As a result of the order, the
Company also wrote off $4.5 million in previously accrued revenues related
to special industrial customer service contracts.
Rate Matters - Gas
In the March 1995 general rate case filing, the Company requested a $35.4
million increase in annual revenues, with $17.8 million of the total to be
granted as interim rate relief in May 1995. The rate case was requested to
cover increased costs related to plant additions and upgrades and higher
costs for financing and general operations. In May 1995, the Washington
Commission issued an order approving a settlement of the case. The
settlement provided an additional $17.7 million in annual revenues,
excluding municipal utility taxes, and reflected an authorized rate of
return on common equity in the range of 11.0% - 11.25%, up from the previous
level of 10.5%. The settlement accepted by the Washington Commission also
stipulated that the Company will be allowed to earn in excess of that range
to the extent that it can do so by managing its cost of service. As part of
the rate case settlement, the Company agreed not to file a general rate case
prior to May 15, 1997. On February 11, 1998, the Company filed a PGA with
the Washington Commission seeking a decrease of $3.8 million in the
effective PGA rates. Simultaneously, the Company filed for a concurrent
increase in PGA rates to "true up" prior period gas costs. The net effect
of these two filings was to increase customer rates by approximately one-
fifth of one percent. The Company expects these two filings to be approved
by the Washington Commission and placed into effect on April 1, 1998.
Year 2000 Conversion
The Company has established a project team to coordinate the identification
and implementation of changes to financial and operational systems and
applications necessary to achieve a year 2000 date conversion with no affect
on customers or disruption to operations. The Company has established
processes for evaluating and managing the risks and costs associated with
-32-
this problem. Major areas of potential business impact have been identified
and initial conversion efforts are underway. The Company is also
communicating with suppliers, financial institutions and others with which it
does business to coordinate year 2000 conversion.
The Company is currently replacing many of its business and operating
computer systems based on vendor supplied software. These are scheduled for
implementation beginning in July 1998. The new systems and software are
year 2000 compatible, thus handling a portion of the Company's year 2000
conversion requirements. The costs of changing the remaining systems to make
them year 2000 compliant are estimated at $5.6 million.
Industry Overview
The electric and gas industries in the United States are undergoing
significant changes. The focus of these changes is to promote competition
among suppliers of electricity and gas and associated services. In 1996, the
Federal Energy Regulatory Commission ("FERC") issued an order that requires
utilities to provide wholesale open access to electric transmission systems
on terms that are comparable to the utility's own use. A number of states,
including California, have restructured their electric industries to separate
or "unbundle" power generation, transmission and distribution in order to
permit new competitors to enter the market place. In part because electric
rates in the Pacific Northwest have been among the lowest in the nation, the
legislatures in this region, including Washington, have not yet enacted laws
to provide for competition at the retail level. The Washington Commission
has initiated a pilot program, in which the Company participates, that
permits consumers limited direct access to competitive energy suppliers. The
Company is actively monitoring developments in this area and has indicated
its support for the enactment of legislation that provides increased choice
for all electric service customers in the state of Washington.
In order to position itself to respond effectively to future restructuring of
the utility industry, and in anticipation of a competitive environment for
electric energy sales, the Company has recently organized into separate
business units: energy transportation; energy supply; and customer
solutions. This reorganization anticipates eventual legislatively mandated
unbundling of power generation from transmission and distribution which would
allow customers to purchase these services and commodities individually from
different suppliers or, alternatively, as a complete package.
The Company has an Optional Large Power Sales Rate for its largest customers.
Customers who elect the Optional Large Power Sales Rate are no longer
considered "core" customers, and the Company no longer has an obligation to
plan for future resources to serve their needs. The non-core customers
receive access to electric energy that is priced at current market cost and
pay a charge for energy delivery (including a charge for conservation
programs) and a transition charge (representing the difference between the
Company's present cost and the current market cost of electric energy and
capacity). The transition charge will be phased out before the end of the
year 2000. Non-core customers also take on the risk that market costs could
become volatile and that electricity could be unavailable on the open market.
Since 1986, the Company has been offering gas transportation as a separate
service to industrial and commercial customers who choose to purchase their
gas supply directly from producers and gas marketers. The continued
evolution of the natural gas industry, resulting primarily from FERC Orders
-33-
436, 500 and 636, has served to increase the ability of large gas end-users
to bypass the Company in obtaining gas supply and transportation services.
Though the Company has not lost any substantial industrial or commercial load
as a result of such bypass, in certain years up to 160 customers annually
have taken advantage of unbundled transportation service; in 1997,
approximately 128 commercial and industrial customers, on average, chose to
use such service.
Other
In July 1996, the Company and several other Northwest electric companies
signed a memorandum of understanding ("MOU") to study the creation of an
independent transmission grid operator called "IndeGO." Participation in
IndeGo was subsequently opened to transmission owners in eight western
states and included public and private utilities and federal power marketing
agencies. However, during 1998, the participating northwest utilities
decided to suspend project activities as a result of uncertainties arising
from regional transmission matters, state electric restructuring initiatives
and public policy matters.
On March 20, 1991, the Company executed a 20-year contract to purchase 216
average MW of energy and 245 MW of capacity, beginning in April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas
fired cogeneration project located near Ferndale, Washington. In December
1997 and January 1998, the Company and Tenaska Washington Partners entered
into revised agreements which will lower purchased power costs from the
Tenaska project by restructuring its natural gas supply. The Company paid
$215 million to buy out the project's existing long-term gas supply
contracts, which contained fixed and escalating gas prices that were well
above current and projected future market prices for natural gas. The
Company became the principal natural gas supplier to the project and power
purchase prices under the Tenaska contract were revised to reflect market-
based prices for the natural gas supply. The Company obtained an order from
the Washington Commission creating a regulatory asset related to the $215
million restructuring payment. These revised arrangements are expected to
reduce the Company's power supply costs from the Tenaska project between 15
and 20 percent annually over the remaining 14 year life of the contract, net
of the costs of the restructuring payment. The Company's purchased electric
energy cost associated with the Tenaska contract was $75.7 million in 1997.
For a discussion of environmental obligations, see Note 17 to the
Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See index on page 41.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE - NONE.
-34-
PART III
Part III is incorporated by reference from the Company's definitive
proxy statement issued in connection with the 1998 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 41.
2) Exhibits - see index on page 79.
(b) Reports on Form 8-K:
1) Form 8-K filed October 24, 1997 - Item 5 - Other Events, and
Item 7- Financial Statements and Exhibits.
2) Form 8-K filed December 11, 1997 - Item 5 - Other Events,
related to a contract-restructuring agreement between the Company and Tenaska
Washington Partners, L.P. approved by the Washington Utilities and
Transportation Commission.
-35-
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 ENERGY, INC.
/s/ William S. Weaver
____________________________________
William S. Weaver
President and
Chief Executive Officer
Date: March 6, 1998
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
___________________________ ____________________________ _____________
/s/ William S. Weaver President, Chief Executive
___________________________ Officer and Director
(William S. Weaver)
/s/ R. R. Sonstelie Chairman of the Board
___________________________
(R. R. Sonstelie)
/s/ James W. Eldredge Corporate Secretary March 6, 1998
___________________________ and Controller and
(James W. Eldredge) Chief Accounting Officer
/s/ Douglas P. Beighle Director
___________________________
(Douglas P. Beighle)
/s/ Charles W. Bingham Director
___________________________
(Charles W. Bingham)
-36-
Signatures, continued
/s/ Phyllis J. Campbell Director
___________________________
(Phyllis J. Campbell)
/s/ Donald J. Covey Director
___________________________
(Donald J. Covey)
Director
___________________________
(Robert L. Dryden)
/s/ John D. Durbin Director
___________________________
(John D. Durbin)
/s/ John W. Ellis Director
___________________________
(John W. Ellis)
Director
___________________________
(Daniel J. Evans)
/s/ Tomio Moriguchi Director
___________________________
(Tomio Moriguchi)
/s/ Sally G. Narodick Director
___________________________
(Sally G. Narodick)
/s/ R. Kirk Wilson Director
___________________________
(R. Kirk Wilson)
-37-
Puget Sound Energy, Inc.
Report of Management:
The accompanying consolidated financial statements of Puget Sound Energy,
Inc. have been prepared under the direction of management, which is
responsible for their integrity and objectivity. The statements have been
prepared in accordance with generally accepted accounting principles and
include amounts based on judgments and estimates by management where
necessary. Management also prepared the other information in the Annual
Report on Form 10-K and is responsible for its accuracy and consistency with
the financial statements.
The Company maintains a system of internal control which, in management's
opinion, provides reasonable assurance that assets are properly safeguarded
and transactions are executed in accordance with management's authorization
and properly recorded to produce reliable financial records and reports. The
system of internal control provides for appropriate division of
responsibility and is documented by written policy and updated as necessary.
The Company's internal audit staff assesses the effectiveness and adequacy of
the internal controls on a regular basis and recommends improvements when
appropriate. Management considers the internal auditor's and independent
auditor's recommendations concerning the Company's internal controls and
takes steps to implement those that they believe are appropriate in the
circumstances.
In addition, Coopers & Lybrand L.L.P., the independent auditors, have
performed audit procedures deemed appropriate to obtain reasonable assurance
about whether the financial statements are free of material misstatement.
The Board of Directors pursues its oversight role for the financial
statements through the audit committee, which is composed solely of outside
Directors. The audit committee meets regularly with management, the internal
auditors and the independent auditors, jointly and separately, to review
management's process of implementation and maintenance of internal accounting
controls and auditing and financial reporting matters. The internal and
independent auditors have unrestricted access to the audit committee.
/s/ William S. Weaver /s/ James W. Eldredge
_______________________ _______________________
William S. Weaver James W. Eldredge
President and Corporate Secretary
Chief Executive Officer and Controller
(Chief Accounting Officer)
-38-
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of
Puget Sound Energy, Inc.
We have audited the consolidated financial statements and the financial
statement schedule of Puget Sound Energy, Inc. (formerly Puget Sound Power &
Light Company) listed on page 41 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 did not audit the consolidated financial statements of Washington
Energy Company ("WECo") and its principal subsidiary, Washington Natural Gas
("WNG"), which statements reflect total assets of $1,034 million as of
December 31, 1996, and total revenues of $426 million and $444 million for
1996 and 1995, respectively. Those statements were audited by other auditors
whose report has been furnished to us and our opinion, insofar as it relates
to the amounts included for WECo and WNG , is based solely on the report of
the other auditors.
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 and the report
of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the
consolidated financial statements referred to above, present fairly, in all
material respects, the consolidated financial position of Puget Sound Energy,
Inc. as of December 31, 1997 and 1996, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1997, 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 Note 1, Puget Sound Energy, Inc. merged with WECo and WNG on
February 10, 1997 in a transaction accounted for as a pooling of interests.
Coopers & Lybrand L.L.P.
Seattle, Washington
February 19, 1998
-39
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Washington Energy Company:
We have audited the consolidated balance sheet and statement of
capitalization of Washington Energy Company (a Washington corporation) and
subsidiaries as of September 30, 1996, and the related consolidated
statements of income, shareholders' earnings (deficit) reinvested in the
business, premium on common stock and cash flows for each of the two years in
the period ended September 30, 1996, and the consolidated balance sheet and
statement of capitalization of Washington Natural Gas Company (a Washington
corporation) and subsidiaries as of September 30, 1996, and the related
consolidated statements of income, shareholder's earnings reinvested in the
business, premium on common stock and cash flows for each of the two years in
the period ended September 30, 1996. These financial statements, which are
not included in this Form 10-K, are the responsibility of the companies'
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
On February 10, 1997, Washington Energy Company and Washington Natural Gas,
in a transaction accounted for as a pooling-of-interests, merged with Puget
Sound Power and Light to form Puget Sound Energy.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Washington Energy Company
and subsidiaries and of Washington Natural Gas Company and subsidiaries as of
September 30, 1996, and the results of their operations and their cash flows
for each of the two years in the period ended September 30, 1996, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Seattle, Washington,
October 31, 1996 (except with respect
to the matter discussed in the third
paragraph above, for which the date is
February 10, 1997)
-40-
Consolidated Financial Statements, Financial Statement Schedule and Exhibits
Covered by the Foregoing Report of Independent Accountants:
Consolidated Statements of Income for the years ended
December 31, 1997, 1996 and 1995........................................42
Consolidated Balance Sheets, December 31, 1997 and 1996...................44
Consolidated Statements of Capitalization,
December 31, 1997 and 1996..............................................46
Consolidated Statements of Earnings Reinvested in the Business
for the years ended December 31, 1997, 1996 and 1995....................48
Consolidated Statements of Cash Flows for the years
ended December 31, 1997, 1996 and 1995..................................49
Notes to Consolidated Financial Statements................................50
Schedule:
II. Valuation and Qualifying Accounts and Reserves for the
years ended December 31, 1997, 1996 and 1995.........................78
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.
Exhibits:
Exhibit Index.............................................................79
-41-
Consolidated Statements of Income
Puget Sound Energy, Inc.
- --------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands
except per share amounts) 1997 1996 1995
- --------------------------------------------------------------------------
Operating Revenues:
Electric $1,231,424 $1,198,769 $1,179,330
Gas 409,447 400,108 420,048
Other 36,031 50,402 31,740
- --------------------------------------------------------------------------
Total operating revenues 1,676,902 1,649,279 1,631,118
- --------------------------------------------------------------------------
Operating Expenses:
Energy Costs:
Purchased electricity 614,929 562,314 523,514
Residential Exchange (71,970) (103,154) (88,004)
Purchased gas 179,287 177,719 219,022
Fuel 41,455 40,645 35,658
Utility operations and maintenance 250,565 242,290 258,058
Other operations and maintenance 21,256 32,234 29,492
Depreciation, depletion and amortization 161,865 144,206 141,008
Merger and related costs 55,789 4,835 --
Taxes other than federal income taxes 160,135 155,969 150,507
Federal income taxes 47,725 107,747 91,519
- --------------------------------------------------------------------------
Total operating expenses 1,461,036 1,364,805 1,360,774
- --------------------------------------------------------------------------
Operating Income 215,866 284,474 270,344
- --------------------------------------------------------------------------
Other Income:
Pre-tax charges related to
unconsolidated affiliate -- -- (24,803)
Deferred tax benefit of write downs -- -- 8,681
Other, net 28,066 1,593 1,213
- --------------------------------------------------------------------------
Total other income 28,066 1,593 (14,909)
- --------------------------------------------------------------------------
Income Before Interest Charges 243,932 286,067 255,435
- --------------------------------------------------------------------------
(Continued)
-42-
Consolidated Statements of Income, continued
Puget Sound Energy, Inc.
- --------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands
except per share amounts) 1997 1996 1995
- --------------------------------------------------------------------------
Interest Charges:
AFUDC (5,205) (3,919) (4,292)
Interest expense 123,439 122,635 131,346
- --------------------------------------------------------------------------
Total interest charges 118,234 118,716 127,054
- --------------------------------------------------------------------------
Income from continuing operations 125,698 167,351 128,381
Discontinued operations:
Loss from operations, net of tax -- (1,386) (26,597)
Loss on disposal, net of tax (2,622) (446) --
- --------------------------------------------------------------------------
Net Income 123,076 165,519 101,784
Less Preferred Stock Dividends accrual 17,806 22,181 22,654
Preferred Stock Redemptions 471 -- --
- --------------------------------------------------------------------------
Income for Common Stock $105,741 $143,338 $79,130
==========================================================================
Common shares outstanding weighted average 84,560 84,418 84,189
==========================================================================
Basic and diluted earnings (loss) per
common share:
From continuing operations $1.28 $1.72 $1.26
From discontinued operations (0.03) (0.02) (0.32)
- --------------------------------------------------------------------------
Basic and diluted earnings
per common share $1.25 $1.70 $0.94
==========================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
-43-
Consolidated Balance Sheets
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------
Assets
December 31
(Dollars in Thousands) 1997 1996
- ----------------------------------------------------------------------------
Utility Plant:
Electric plant, at original cost $3,632,652 $3,479,652
Gas plant 1,231,109 1,129,849
Less: Accumulated depreciation and amortization 1,613,300 1,493,024
- ----------------------------------------------------------------------------
Net utility plant 3,250,461 3,116,477
- ----------------------------------------------------------------------------
Other Property and Investments:
Investment in Bonneville Exchange Power Contract 78,880 86,772
Investment in Cabot 85,027 69,014
Subsidiary properties and investment 72,660 80,770
Other 43,077 43,444
- ----------------------------------------------------------------------------
Total other property and investments 279,644 280,000
- ----------------------------------------------------------------------------
Current Assets:
Cash 7,759 4,335
- ----------------------------------------------------------------------------
Accounts receivable 158,927 160,836
Less: Allowance for doubtful accounts 971 1,700
- ----------------------------------------------------------------------------
Total accounts receivable 157,956 159,136
- ----------------------------------------------------------------------------
Unbilled revenue 122,831 102,409
PRAM accrued revenues -- 40,470
Materials and supplies, at average cost 54,423 61,638
Prepayments and Other 5,420 10,458
- ----------------------------------------------------------------------------
Total current assets 348,389 378,446
- ----------------------------------------------------------------------------
Long-Term Assets:
Regulatory asset for deferred income taxes 258,430 242,454
Unamortized energy conservation charges 6,867 44,673
PURPA buyout costs 215,000 --
Other 134,579 165,420
- ----------------------------------------------------------------------------
Total long-term assets 614,876 452,547
- ----------------------------------------------------------------------------
Total Assets $4,493,370 $4,227,470
============================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
-44-
Capitalization and Liabilities
December 31
(Dollars in Thousands) 1997 1996
- ----------------------------------------------------------------------------
Capitalization
(See "Consolidated Statements of Capitalization"):
Common equity $1,358,077 $1,378,377
Preferred stock not subject
to mandatory redemption 95,488 215,000
Preferred stock subject
to mandatory redemption 78,134 87,839
Corporation obligated, mandatorily
redeemable preferred securities of
subsidiary trust holding solely
junior subordinated debentures of
the corporation 100,000 --
Long-term debt 1,411,707 1,165,584
- ----------------------------------------------------------------------------
Total capitalization 3,043,406 2,846,800
- ----------------------------------------------------------------------------
Current Liabilities:
Accounts payable 116,548 95,736
Short-term debt 372,538 298,122
Current maturities of long-term debt 51,000 100,062
Purchased gas liability 876 41,368
Accrued expenses:
Taxes 73,636 57,419
Salaries and wages 15,326 28,215
Interest 27,704 27,173
Other 33,198 51,906
- ----------------------------------------------------------------------------
Total current liabilities 690,826 700,001
- ----------------------------------------------------------------------------
Deferred Income Taxes 629,018 586,661
- ----------------------------------------------------------------------------
Other Deferred Credits 130,120 94,008
- ----------------------------------------------------------------------------
Commitments and Contingencies -- --
- ----------------------------------------------------------------------------
Total Capitalization and Liabilities $4,493,370 $4,227,470
============================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
-45-
Consolidated Statements of Capitalization
Puget Sound Energy, Inc.
- ------------------------------------------------------------------------------------
December 31 (Dollars in Thousands) 1997 1996
- ------------------------------------------------------------------------------------
Common Equity:
Common stock - ($10 stated value) - 150,000,000 shares
authorized, 84,560,645 and 84,511,245 shares
outstanding $ 845,606 $ 845,112
Additional paid-in capital 450,845 446,910
Unrealized gain on investment 14,954 --
Earnings reinvested in the business 46,672 86,355
- ------------------------------------------------------------------------------------
Total common equity 1,358,077 1,378,377
- ------------------------------------------------------------------------------------
Preferred Stock Not Subject to Mandatory
Redemption - cumulative - $25 par value:*
7.875% series - 3,000,000 shares authorized,
zero & 3,000,000 shares outstanding -- 75,000
Adjustable Rate, Series B - 2,000,000 shares
authorized, 219,506 and 2,000,000 shares outstanding 5,488 50,000
7.45% series II - 2,400,000 shares authorized
and outstanding 60,000 60,000
8.50% series III - 1,200,000 shares authorized
and outstanding 30,000 30,000
- ------------------------------------------------------------------------------------
Total preferred stock not subject to mandatory redemption 95,488 215,000
- ------------------------------------------------------------------------------------
Preferred Stock Subject To Mandatory Redemption - cumulative
$100 par value:*
4.84% series - 150,000 shares authorized,
14,808 & 47,956 shares outstanding 1,481 4,796
4.70% series - 150,000 shares authorized,
4,311 & 56,215 shares outstanding 431 5,621
8% series - 150,000 shares authorized,
12,224 and 24,224 shares outstanding 1,222 2,422
7.75% series - 750,000 shares authorized
and outstanding 75,000 75,000
- ------------------------------------------------------------------------------------
Total preferred stock subject to mandatory redemption 78,134 87,839
- ------------------------------------------------------------------------------------
Corporation obligated, mandatorily redeemable preferred
securities of subsidiary trust holding solely junior
subordinated debentures of the corporation 100,000 --
- ------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds 1,301,000 1,104,060
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 17 19
Unamortized discount - net of premium (170) (293)
Long-term debt due within one year (51,000) (100,062)
- ------------------------------------------------------------------------------------
Total long-term debt excluding current maturities 1,411,707 1,165,584
- ------------------------------------------------------------------------------------
Total Capitalization $3,043,406 $2,846,800
====================================================================================
* 13,000,000 shares authorized for $25 par value preferred stock
and 3,000,000 shares authorized for $100 par value preferred stock.
The accompanying notes are an integral part of the consolidated financial statements.
-47-
Consolidated Statements of Earnings Reinvested in the Business
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands
except per share amounts) 1997 1996 1995
- ----------------------------------------------------------------------------
Balance at Beginning of Year $ 86,355 $ 84,254 $146,228
Net Income 123,076 165,519 101,784
Adjustment to conform fiscal year
of WECo 10,835 -- --
- ----------------------------------------------------------------------------
Total 220,266 249,773 248,012
- ----------------------------------------------------------------------------
Deductions:
Dividends Declared:
Preferred stock:
$4.84 per share on 4.84% series 192 232 232
$4.70 per share on 4.70% series 203 265 276
$8.00 per share on 8% series 122 218 314
$7.75 per share on 7.75% series 5,813 5,813 5,813
$1.97 per share on 7.875% series 3,940 5,906 5,906
$1.86 per share on 7.45% series II 4,470 4,470 4,470
$2.13 per share on 8.50% series III 2,550 2,550 2,656
Adjustable Rate, series B 2,010 2,716 3,115
Common stock 150,591 141,248 140,976
Preferred stock redemptions 3,703 -- --
- ----------------------------------------------------------------------------
Total deductions 173,594 163,418 163,758
- ----------------------------------------------------------------------------
Balance at End of Year $ 46,672 $ 86,355 $ 84,254
- ----------------------------------------------------------------------------
Dividends declared per common share $ 1.78 $ 1.67 $ 1.67
============================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
-48-
Consolidated Statements of Cash Flows
Puget Sound Energy, Inc.
- ---------------------------------------------------------------------------------------
Year Ended December 31 (Dollars in Thousands) 1997 1996 1995
- ---------------------------------------------------------------------------------------
Operating Activities:
Income from continuing operations $125,698 $167,351 $128,381
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation and amortization 161,865 144,206 141,008
Deferred income taxes and tax credits - net 27,422 6,842 11,421
PRAM accrued revenues - net 40,777 74,326 (3,955)
Pretax writedown and equity in undistributed
losses of unconsolidated affiliate 4,044 961 27,826
PURPA buyout costs (215,000) -- --
Other 43,286 (21,918) 4,143
Change in certain current assets and liabilities (58,394) 27,809 34,959
- ---------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 129,698 399,577 343,783
- ---------------------------------------------------------------------------------------
Investing Activities:
Construction expenditures - excluding equity AFUDC (257,900) (205,050) (205,981)
Energy conservation expenditures (4,864) (6,683) (15,156)
Cash received from sale of conservation assets - net 34,372 -- 199,452
Proceeds from property sales 7,013 34,000 --
Other 17,703 (7,384) 882
- ---------------------------------------------------------------------------------------
Net Cash Used by Investing Activities (203,676) (185,117) (20,803)
- ---------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in short-term debt 85,975 (30,921) (30,593)
Dividends paid (169,892) (163,418) (163,758)
Issuance of common and preferred stock 65 3,686 4,824
Issuance of Company obligated mandatorily
redeemable preferred securities 100,000 -- --
Redemption of preferred stock (128,747) (1,200) (1,993)
Issuance of bonds 300,000 34,470 74,280
Redemption of bonds and notes (102,844) (72,612) (193,144)
Other (4,572) (558) (43)
- ---------------------------------------------------------------------------------------
Net Cash Provided by (Used by) Financing Activities 79,985 (230,553) (310,427)
- ---------------------------------------------------------------------------------------
Increase (decrease) in cash
from continuing operations 6,007 (16,093) 12,553
Decrease in cash from
discontinued operations:
Operating activities -- (1,386) (139)
Investing activities (2,622) -- (1,271)
- --------------------------------------------------------------------------------------
Net increase (decrease) in cash 3,385 (17,479) 11,143
Cash at Beginning of Year 4,335 21,814 10,671
Adjustment to conform fiscal year of WECo 39 -- --
- --------------------------------------------------------------------------------------
Cash at End of Year $ 7,759 $ 4,335 $ 21,814
======================================================================================
The accompanying notes are an integral part of the consolidated financial statements.
-49
Puget Sound Energy, Inc.
Notes To Consolidated Financial Statements
- ----------------------------------------------------------------------------
1. Summary of Significant Accounting Policies
Basis of Presentation:
Puget Sound Energy, Inc., formerly Puget Sound Power & Light Company, ("the
Company") is an investor-owned public utility incorporated in the State of
Washington furnishing electric, and since February 10, 1997, gas service in
a territory covering approximately 6,000 square miles, principally in the
Puget Sound region of Washington State. On February 10, 1997, the Company
completed a merger ("the Merger") with the Washington Energy Company
("WECo") and its principal subsidiary, Washington Natural Gas Company
("WNG"). The change of the Company's name was effective with the merger.
Herein, the Company refers to the combined entity; Puget Power and WECo
refer to the individual entities.
The Merger Agreement called for each share of WECo common stock to be
exchanged for 0.86 share of the Company's common stock (approximately
20,921,000 shares of Company stock are expected to be issued). On February
10, 1997, the Company increased the number of authorized shares to
150,000,000. Based on the capitalization of the Company and WECo on
February 10, 1997, holders of the Company's and WECo's common stock held
approximately 75% and 25% respectively, of the aggregate number of
outstanding shares of the merged company's common stock. In addition, the
agreement called for the preferred stock of Washington Natural Gas Company,
a wholly-owned subsidiary of WECo, to be converted into preferred shares of
the merged company.
The order approving the merger, issued by the Washington Utilities and
Transportation Commission ("Washington Commission") contains a rate plan
that is designed to provide a five-year period of rate stability for
customers and provide the Company with an opportunity to achieve a
reasonable return on investment. As required under the merger order, the
Company filed tariffs, effective February 8, 1997, that resulted in an
average electric rate decrease of 5.6% related to the PRAM, and an average
increase in general rates of 1.8% varying between 1.0% and 2.5%, depending
on rate class. The net impact was an average rate decrease of 3.7%,
including a decrease in residential rates of 3.2%. General rates for
electric residential and industrial service will increase by 1.5% on January
1 of each of the four following years, while those for small commercial
customers will increase by 1.0% in each of the following three years.
General rates for all classes of natural gas customers will remain unchanged
until January 1, 1999, when they will decrease sufficiently to reduce
utility margin by 1 percent.
The merger has been structured as a tax-free exchange of shares, and is
accounted for as a pooling of interests for financial statement purposes.
Accordingly, the consolidated financial statements have been retroactively
restated to include the results of operations, financial position and cash
flows of WECo and WNG for all periods prior to consummation of the merger.
Certain amounts have been reclassified to conform to the combined
presentation.
-50-
The consolidated financial statements include the accounts of the Company
and all its significant wholly-owned subsidiaries, after elimination of all
significant intercompany items and transactions. One immaterial subsidiary
is stated on an equity basis.
Financial information prior to January 1, 1997, contained herein reflects
fiscal years ended December 31 for Puget Power and September 30 for WECo.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Utility Plant:
The costs of additions to utility plant, including renewals and betterments,
are capitalized at original cost. Costs include indirect costs such as
engineering, supervision, certain taxes and pension and other employee
benefits, and an allowance for funds used during construction. Replacements
of minor items of property are included in maintenance expense. The
original cost of operating property together with removal cost, less
salvage, is charged to accumulated depreciation when the property is retired
and removed from service.
Accounting for Regulatory Assets:
The Company prepares its financial statements in accordance with Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" ("Statement No. 71"). Statement No. 71
requires the Company to defer certain costs that would otherwise be charged
to expense, if it is probable that future rates will permit recovery of such
costs. Accounting under Statement No. 71 is appropriate as long as: rates
are established by or subject to approval by independent, third-party
regulators; rates are designed to recover the specific enterprise's cost-of-
service; and in view of demand for service, it is reasonable to assume that
rates set at levels that will recover costs can be charged to and collected
from customers. In applying Statement No. 71, the Company must give
consideration to changes in the level of demand or competition during the
cost recovery period. In accordance with Statement No. 71, the Company
capitalizes certain costs in accordance with regulatory authority whereby
those costs will be expensed and recovered in future periods.
-51-
Net regulatory assets and liabilities at December 31, 1997 and 1996 included
the following:
- ----------------------------------------------------------------
(Dollars in Millions) 1997 1996
- ----------------------------------------- ------ ------
Deferred income taxes $258.4 $242.5
PURPA buyout costs 215.0 -.-
Investment in BEP Exchange Contract 78.9 86.8
Unamortized energy conservation charges 6.9 44.7
PRAM accrued revenues -.- 40.5
Storm damage costs 33.4 39.3
Various other costs 68.2 67.9
Deferred gains on property sales (17.5) (15.8)
- ----------------------------------------- ------ -----
Total $643.3 $505.9
================================================================
If the Company, at some point in the future, determines that all or a
portion of the utility operations no longer meets the criteria for continued
application of Statement No. 71, the Company would be required to adopt the
provisions of Statement of Financial Accounting Standards No. 101,
"Regulated Enterprises - Accounting for the Discontinuation of Application
of FASB Statement No. 71" ("Statement No. 101"). Adoption of Statement No.
101 would require the Company to write off the regulatory assets and
liabilities related to those operations not meeting Statement No. 71
requirements. Discontinutation of Statement No. 71 could have a material
impact on the Company's financial statements.
The Securities and Exchange Commission ("SEC") has expressed concern
regarding the continuing applicability of Statement No. 71 to the financial
statements of electric utilities that either have been ordered by regulators
to adopt transition to competition plans or are in the process of
participating with the state legislatures and/or regulators in the
development of such plans. While such plans may call for rate caps or
decreases, they generally provide for recovery of investments in uneconomic
or noncompetitive generating plants and other regulatory assets (together
defined as stranded costs). The SEC is concerned that portions of entities
subject to such plans may not meet the criteria for the continued
application of Statement No. 71. The Emerging Issues Task Force ("EITF") of
the Financial Accounting Standards Board ("FASB") met in May and July of
1997 to address the issues of when such an entity should discontinue the
application of Statement No. 71, and how Statement No. 101 should be applied
to a portion of an entity subject to such a plan. As a result of these
meetings, a consensus was reached that Statement No. 71 should be
discontinued at a date no later than when the details of the transition to
competition plan for all or a portion of the entity subject to such plan are
known. Additionally, the EITF reached a consensus that stranded costs which
are to be recovered through cash flows derived from another portion of the
entity which continues to apply Statement No. 71 should not be written off;
rather, they should be considered regulatory assets of the segment which
will continue to apply Statement No. 71.
The Company's financial statements continue to apply Statement No. 71 for
regulated operations. Although discussions with regulatory authorities
regarding retail competition have occurred and are expected to continue, no
final transition to competition plans for the Company's regulated operations
have yet been adopted or proposed.
-52-
The Company, in prior years, incurred costs associated with its 5% interest
in a now terminated nuclear generating project (identified herein as
"Investment in Bonneville Exchange Power ("BEP")"). Under terms of a
settlement agreement with the Bonneville Power Administration ("BPA"), which
settled claims of the Company relating to construction delays associated
with that project, the Company is receiving, over 30.5 years, power from the
federal power system resources marketed by BPA. Approximately two-thirds of
the Company's investment in BEP is included in rate base and amortized on a
straight-line basis over the life of the contract (amortization is included
in "Purchased and interchanged power"). The remainder of the Company's
investment is being recovered in rates over ten years, without a return
during the recovery period (the related amortization is included in
"Depreciation and Amortization", pursuant to a FERC accounting order).
The Company has recorded a regulatory asset for $215 million related to the
buyout of a gas sales contract of a non-utility generator. A Washington
Commission accounting order approved the payment for deferral and collection
in rates over the remaining life of the energy supply contract.
Operating Revenues:
Operating revenues are recorded on the basis of service rendered, which
include estimated unbilled revenue and, prior to October 1, 1996, 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 as prescribed by the Washington
Commission.
In June 1995, the Company sold approximately $202.5 million of its
investment in customer-owned energy conservation measures to a grantor trust
which, in turn, issued securities backed by a Washington state statute
enacted in 1994. The Company sold an additional investment of $35.2 million
in customer-owned energy conservation measures in August 1997. The proceeds
of the sales were used to pay down short-term debt. The Company recognized
no gain or loss on the sales.
Self-Insurance:
The Company currently has no insurance coverage for storm damage and is
self-insured for a portion of the risk associated with comprehensive
liability, industrial accidents and catastrophic property losses. With
approval of the Washington Commission, the Company is able to defer for
collection in future rates, certain uninsured storm damage costs associated
with major storms.
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. The annual depreciation provision stated as a percent of
average original cost of depreciable electric utility plant was 3.0% in
-53-
1997, 1996 and 1995 and for depreciable gas utility plant was 3.4% in 1997,
3.6% in 1996 and 3.5% for 1995. The Company capitalizes purchased or
internally developed computer software projects and amortizes them over
their original anticipated useful lives.
Federal Income Taxes:
The Company normalizes, with the approval of the Washington Commission,
certain items. Deferred taxes have been determined under Statement of
Financial Accounting Standards No. 109. Investment tax credits are deferred
and amortized based on the average useful life of the related property in
accordance with regulatory and income tax requirements. (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 for gas utility plant
additions was 9.15%, 9.03%, and 8.68% for 1997, 1996 and 1995,
respectively. The allowed AFUDC rate on electric utility plant was 8.94%
during the same period. To the extent amounts calculated using this rate
exceed the AFUDC calculated using the Federal Energy Regulatory Commission
("FERC") formula, the Company capitalizes the excess as a deferred asset,
crediting miscellaneous income. The amounts included in income were:
$2,704,000 for 1997, $2,112,000 for 1996 and $1,614,000 for 1995. The
deferred asset is being amortized over the average useful life of the
Company's non-project utility plant.
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 electric
general rate cases. Under the PRAM, Puget Power was 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 was decoupled from levels of electricity
sales.
Rates established for the PRAM period were 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 varied from amounts allowed under the methodology
established in the PRAM order, the difference was accumulated, without
interest, for rate recovery which was then established in the next PRAM
hearing. In its September 22, 1995 order, the Washington Commission
approved Puget Power's last PRAM filing and the recovery of $71.2 million
over the period October 1, 1995 through September 30, 1996. In addition to
approval of the rate adjustment, the Commission also agreed, pursuant to a
negotiated settlement, to discontinue the PRAM on September 30, 1996, the
-54-
end of the last PRAM period. PRAM accrued revenues of $40.5 million,
recorded at December 31, 1996, were recovered in the first quarter of 1997.
Over-collection of PRAM revenues was refunded to customers in the second
quarter of 1997.
With the discontinuance of the PRAM, the Company no longer has a rate
adjustment mechanism to adjust for changes in cost or variances in hydro and
weather conditions. These variances may now significantly influence
earnings.
PGA Mechanism
Differences between the actual cost of the Company's gas supplies and that
currently allowed by the Washington Commission are deferred and recovered or
repaid through the purchased gas adjustment ("PGA") mechanism.
Off-System Sales and Capacity Release:
The Company had been selling excess gas supplies and entering into gas
supply exchanges with third parties outside of its distribution area since
1992. The Company began releasing to third parties excess interstate gas
pipeline capacity and gas storage rights on a short-term basis in 1993 and
1994, respectively. The Company contracts for firm gas supplies and holds
firm transportation and storage capacity sufficient to meet the expected
peak winter demand for gas for space heating by its firm customers. Due to
the variability in weather and other factors, however, the Company holds
contractual rights to gas supplies and transportation and storage capacity
in excess of its immediate requirements to serve firm customers on its
distribution system for much of the year which, therefore, are available for
third-party gas sales, exchanges and capacity releases. The net proceeds
from such activities are accounted for as reductions in the cost of
purchased gas and passed on to customers through the PGA mechanism, with no
impact on net income. As a result, the Company does not reflect sales
revenue or associated cost of sales for these transactions in its income
statement. The net proceeds from these activities were $16,759,000,
$10,711,000, and $7,374,000 for 1997, 1996 and 1995, respectively.
Risk Management and Energy Trading
The Company's energy related businesses are exposed to risks related to
changes in commodity prices. As part of its business, the Company markets
power to other utilities and power marketers by entering into contracts to
purchase or supply electric energy or natural gas at specified delivery
points and at specified future delivery dates. The Company's energy trading
function manages the Company's core electric and gas supply portfolios as
well as non-core incremental energy supply trading activities.
The Company has established policies and procedures to manage these risks. A
Risk Management Committee separate from the units that create these risks
monitors compliance with the Company's policies and procedures. In addition,
the Audit Committee of the Company's Board of Directors has oversight of the
Risk Management Committee.
-55-
Other:
Debt premium, discount and expenses are amortized over the life of the
related debt. The premiums and costs associated with reacquired debt are
being amortized over the life of the related new issuances, in accordance
with ratemaking treatment.
In October 1995, the FASB issued Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation" ("Statement No. 123").
Statement No. 123 establishes a fair-value based method of accounting for
stock-based compensation plans and encourages entities to adopt that method
in place of the provisions of Accounting Principles Board Opinion No. 25
("APB 25"). The Company intends to continue to apply the provisions of APB
25 in recognizing compensation expense related to its stock-based
compensation plans. Due to the limited number of shares issued under the
Company's stock plans on an annual basis, the amount of the compensation
expense which would be required to be expensed or disclosed is not material.
In June 1997, the FASB issued Statement of Financial Accounting Standards
No. 130, "Reporting Comprehensive Income"("Statement No. 130"), which
establishes rules for reporting and displaying comprehensive income and its
components. Statement No. 130 is effective for fiscal years beginning after
December 15, 1997.
In June 1997, the FASB issued Statement of Financial Accounting Standards
No. 131, "Disclosures about Segments of an Enterprise and Related
Information" ("Statement No. 131"), which establishes requirements that
companies report certain information about operating segments. Statement
No. 131 is effective for fiscal years beginning after December 15, 1997.
While this statement may result in additional financial disclosures, it will
not impact the Company's financial position or results of operations.
In February 1998, the FASB issued Statement of Financial Accounting
Standards No. 132, "Employers Disclosures about Pensions and Other
Postretirement Benefits" ("Statement No. 132"), which standardizes the
disclosure requirements for pensions and other postretirement benefits.
Statement No. 132 is effective for fiscal years beginning after December 15,
1997. While this statement may result in additional financial disclosures,
it will not impact the Company's financial position or results of
operations.
Earnings Per Common Share:
During 1997, the Company adopted Statement of Financial Accounting Standards
No. 128, "Earnings per Share" ("Statement No. 128"). As required under
Statement No. 128, earnings per share data have been restated for all prior
periods presented.
Basic earnings per common share have been computed based on weighted average
common shares outstanding of 84,560,000, 84,418,000 and 84,189,000 for 1997,
1996 and 1995, respectively. Diluted earnings per common share have been
computed based on weighted average common shares outstanding of 84,628,000,
84,449,000 and 84,193,000 for 1997, 1996 and 1995, respectively, which
include the dilutive effect of securities related to employee compensation
plans.
-56-
2. Property Plant and Equipment
- ---------------------------------------------------------------------------
December 31 (Dollars in Thousands) 1997 1996
- ---------------------------------------------------------------------------
Electric and gas utility plant classified by
prescribed accounts at original cost:
Distribution plant $2,674,234 $2,545,155
Production plant 939,211 930,806
Transmission plant 625,779 580,475
General plant 333,140 338,330
Construction work in progress 123,690 83,633
Completed work not classified 58,216 52,248
Intangible plant 78,491 50,880
Underground storage 16,277 12,713
Plant held for future use 10,263 10,802
Other 4,460 4,459
- ---------------------------------------------------------------------------
Total electric and gas utility plant $4,863,761 $4,609,501
===========================================================================
-57-
3. Capital Stock
Preferred Stock
---------------------------
Not Subject to Subject to
Mandatory Mandatory Common
Redemption Redemption Stock
--------------- ---------- ----------
Without
$25 $100 Par Value
Par Par ($10 Stated
Value Value Value)
- -------------------- -------------- ---------- ----------
Shares outstanding
January 1, 1995 8,600,000 912,424 84,034,633
Issued to share-
holders under the
stock purchase
and dividend
reinvestment plan:
1995 -- -- 279,362
1996 -- -- 148,417
1997 -- -- 33,930
Issued pursuant
to employee
compensation plans:
1995 -- -- 26,585
1996 -- -- 21,886
1997 -- -- 17,063
Issued pursuant to
Directors' Stock
Bonus Plan:
1995 -- -- 175
1996 -- -- 187
Acquired for sinking fund:
1995 -- (22,029) --
1996 -- (12,000) --
1997 -- (12,050) --
Called for redemption
and canceled:
1997 (4,780,494) (85,002) --
Fractional share
redemptions in
connection with
Merger exchange:
1997 -- -- (1,593)
- ----------------------------------------------------------------------
Shares outstanding
December 31, 1997 3,819,506 781,343 84,560,645
======================================================================
See "Consolidated Statements of Capitalization" for details on specific
series.
-58-
On January 15, 1991, the Board of Directors declared a dividend of one
preference share purchase right (a "Right") on each outstanding common share
of the Company. The dividend was distributed on January 25, 1991, to
shareholders of record on that date. The Rights will be exercisable only if
a person or group acquires 10 percent or more of the Company's common stock
or announces a tender offer which, if consummated, would result in ownership
by a person or group of 10 percent or more of the common stock. Each Right
entitles the registered holder to purchase from the Company one one-
thousandth of a share of Preference Stock, $50 par value per share, at an
exercise price of $45, subject to adjustments. The description and terms of
the Rights are set forth in a Rights Agreement between the Company and The
Bank of New York, as Rights Agent. The Rights expire on January 25, 2001,
unless earlier redeemed by the Company.
The weighted average dividend rate for the Adjustable Rate Cumulative
Preferred Stock ("ARPS"), Series B ($25 par value) was 5.61% for 1997, 5.49%
for 1996, and 6.05% for 1995. In April and May 1997, the Company purchased
598,500 shares of ARPS, Series B at a price of $24.375 per share. On August
15, 1997, the Company completed a tender offer for various issues of its
preferred stock; 1,181,994 shares of ARPS Series B, $25 par were tendered at
$25.625 per share. 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.
On July 15, 1997, the Company redeemed 3,000,000 shares of its 7.875% Series
Preferred at a redemption price of $25.00 per share.
The 8.50% Series Preferred may be redeemed on or after September 1, 1999, at
par and the 7.45% Series Preferred may be redeemed on or after November 1,
2003, at par.
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, 1997,
there were 39,192 shares of the 4.84% Series, 55,689 shares of the 4.70%
Series and 776 shares of the 8% Series acquired by the Company and available
for future sinking fund requirements. Upon involuntary liquidation, all
preferred shares are entitled to their par value plus accrued dividends.
The preferred stock subject to mandatory redemption may also be redeemed by
the Company at the following redemption prices per share plus accrued
dividends: 4.84% Series, $102; 4.70% Series, $101; and 8% Series, $101.
The 7.75% Series may be redeemed by the Company, subject to certain
restrictions, at $105.17 per share plus accrued dividends through February
15, 1998 and at per share amounts which decline annually to a price of $100
after February 15, 2007.
-59-
On August 15, 1997, the Company completed a tender offer for three series of
preferred stock and the following number of shares of each series were
tendered and redeemed at the noted redemption price per share: 51,854
shares of the 4.70% Series, $100 par value Preferred at $89.32 per share and
33,148 shares of the 4.84% Series $100 par value Preferred at $91.51 per
share.
On February 15, 1998, the Company redeemed all outstanding shares of the 8%
Series, $100 par value Preferred including 12,000 shares for the sinking
fund at par and 224 shares at $101.00 per share.
5. Company-Obligated, Mandatorily Redeemable Preferred Securities
In 1997, the Company formed Puget Sound Energy Capital Trust I (the "TRUST")
for the sole purpose of issuing and selling common and preferred securities
("Trust Securities"). The proceeds from the sale of Trust Securities were
used to purchase Junior Subordinated Debentures ("Debentures") from the
Company. The Debentures are the sole assets of the Trust and the Company
owns all common securities of the Trust.
The Debentures have an interest rate of 8.231% and a stated maturity date of
June 1, 2027. The Trust Securities are subject to mandatory redemption at
par on the stated maturity date of the Debentures. The Trust Securities may
be redeemed earlier, under certain conditions, at the option of the Company.
Dividends relating to preferred securities are included in interest expense.
6. Additional Paid-in Capital
(Dollars in Thousands) 1997 1996 1995
- ---------------------------------------------------------------------------
Balance at beginning of year 446,910 $444,928 $442,954
Excess of proceeds over stated values of
common stock issued 428 2,022 1,934
Par value over cost of reacquired
preferred stock 471 -- 210
Retained earnings adjustment for
preferred redemption 3,036 -- --
Issue costs of common and preferred stock -- (40) (170)
- ---------------------------------------------------------------------------
Balance at end of year $450,845 $446,910 $444,928
===========================================================================
7. Earnings Reinvested in the Business
The payment of dividends on common stock is restricted by provisions of
certain covenants applicable to preferred stock and long-term debt contained
in the Company's Articles of Incorporation and Mortgage Indentures. Under the
most restrictive covenants, earnings reinvested in the business unrestricted
as to payment of cash dividends were approximately $114 million at December
31, 1997.
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, adjustments made as a result of Statement No. 121 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 Company's Articles and Mortgage Indentures. (See Note 1.)
-60-
8. Long-Term Debt
First Mortgage Bonds at December 31:
Series Due 1997 1996
- ----------------------------------------------
(Dollars in Thousands)
7.875% 1997 $ -- $ 100,000
8.125% 1997 -- 3,060
6.17% 1998 10,000 10,000
5.70% 1998 5,000 5,000
8.25% 1998 11,000 11,000
8.83% 1998 25,000 25,000
6.50% 1999 16,500 16,500
6.65% 1999 10,000 10,000
6.41% 1999 20,500 20,500
7.08% 1999 10,000 10,000
7.25% 1999 50,000 50,000
6.61% 2000 10,000 10,000
9.60% 2000 25,000 25,000
8.51 - 8.55% 2001 19,000 19,000
9.14% 2001 30,000 30,000
7.53 - 7.91% 2002 30,000 30,000
7.85% 2002 30,000 30,000
7.07% 2002 27,000 27,000
7.15% 2002 5,000 5,000
7.625% 2002 25,000 25,000
6.23 - 6.31% 2003 28,000 28,000
7.02% 2003 30,000 30,000
6.20% 2003 3,000 3,000
6.40% 2003 11,000 11,000
6.07 & 6.10% 2004 18,500 18,500
7.70% 2004 50,000 50,000
7.80% 2004 30,000 30,000
6.92 & 6.93% 2005 31,000 31,000
6.58% 2006 10,000 10,000
8.06% 2006 46,000 46,000
8.14% 2006 25,000 25,000
7.02 & 7.04% 2007 25,000 25,000
7.75% 2007 100,000 100,000
8.40% 2007 10,000 10,000
6.51 & 6.53% 2008 4,500 4,500
6.61 & 6.62% 2009 8,000 8,000
7.12% 2010 7,000 7,000
8.59% 2012 5,000 5,000
8.20% 2012 30,000 30,000
6.83% & 6.90% 2013 13,000 13,000
7.35 & 7.36% 2015 12,000 12,000
9.57% 2020 25,000 25,000
8.25 - 8.40% 2022 35,000 35,000
7.19% 2023 13,000 13,000
7.35% 2024 55,000 55,000
7.15 & 7.20% 2025 17,000 17,000
7.02% 2027 300,000 --
- ----------------------------------------------
Total First
Mortgage Bonds $1,301,000 $1,104,060
==============================================
-61-
In December 1997, the Company filed a shelf-registration statement for the
offering on a delayed or continuous basis of up to $500 million principal
amount of Senior Notes secured by a pledge of First Mortgage Bonds. On
December 22, 1997, the Company issued $300 million principal amount of
Senior Medium-Term Notes, Series A, due December 1, 2027, bearing interest
at 7.02%.
Substantially all utility properties owned by the Company are subject to the
lien of the Company's mortgage indenture and the WNG mortgage indenture.
Pollution Control Bonds
The Company has outstanding three series of Pollution Control Bonds.
Amounts outstanding were borrowed from the City of Forsyth, Montana ("the
City"). The City obtained the funds from the sale of Customized Pollution
Control Refunding Bonds issued to finance pollution control facilities at
Colstrip Units 3 and 4.
Each series of bonds are collateralized by a pledge of the Company's First
Mortgage Bonds, the terms of which match those of the Pollution Control
Bonds. No payment is due with respect to the related series of First
Mortgage Bonds so long as payment is made on the Pollution Control Bonds.
Interest rates for the 1992 and 1993 series are 6.80% and 5.875%,
respectively. The 1991 series consists of $27.5 million principal amount
bearing interest at 7.05% and $23.4 million principal amount bearing
interest at 7.25%.
Long-Term Debt Maturities:
The principal amounts of long-term debt maturities for the next five years
are as follows:
(Dollars in Thousands) 1998 1999 2000 2001 2002
- -----------------------------------------------------------------------
Maturities of
long-term debt $ 51,000 $107,000 $ 35,000 $ 49,000 $117,000
=======================================================================
9. Short-Term Debt and Other Financing Arrangements
At December 31, 1997, the Company had short-term borrowing arrangements
which included a $375 million line of credit with fourteen banks. The
agreement provides the Company with the ability to borrow at different
interest rate options and includes variable fee levels. The options are:
(1) the higher of the prime rate or the Federal Funds rate plus 1/2 of 1
percent or (2) the Eurodollar rate plus .25 percent. The current
availability fee is .08 percent per annum on the unused loan commitment.
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.
-62-
At December 31: (Dollars in Thousands) 1997 1996 1995
- ---------------------------------------------------------------------------
Short-term borrowings outstanding:
Uncommitted bank borrowings $ 33,000 $ 31,700 $ 44,000
Bank line of credit borrowing 215,000 -- --
Commercial paper notes $124,538 $266,422 $285,043
Weighted average interest rate 6.88% 6.05% 6.54%
Credit availability (a) $375,000 $426,500 $426,500
- ---------------------------------------------------------------------------
(a) Provides liquidity support for outstanding commercial paper and
borrowing from credit line banks in the amount of $339.5 million,
$266.4 million and $285.0 million for 1997, 1996 and 1995,
respectively, effectively reducing the available borrowing capacity
under these credit lines to $35.5 million, $160.1 million, and $141.5
million, respectively.
The Company has, on occasion, entered into interest rate swap agreements to
reduce the impact of changes in interest rates on portions of its floating-
rate, short-term debt. The one agreement outstanding at December 31, 1997
effectively changes the Company's interest rate on outstanding commercial
paper to 9.64% on a notional principal amount of $16.5 million expiring
March 31, 2000.
10. Estimated Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 1997 and 1996:
1997 1997 1996 1996
Carrying Fair Carrying Fair
(Dollars in Millions) Amount Value Amount Value
- --------------------------------------------------------------------------
Financial Assets:
Cash $ 7.8 $ 7.8 $ 4.3 $ 4.3
Financial Liabilities:
Short-term debt $ 372.5 $ 372.5 $ 298.1 $ 298.1
Preferred stock subject to
mandatory redemption $ 78.1 $ 82.5 $ 87.8 $ 88.5
Corporation obligated,
mandatorily redeemable
preferred securities of
subsidiary trust holding
solely junior subordinated
debentures of the
corporation $ 100.0 $ 107.6 $ -- $ --
Long-term debt $1,462.7 $1,547.3 $1,265.6 $1,303.4
Unrecognized financial instruments:
Interest rate swaps -- $ (1.2) $ -- $ (1.7)
- --------------------------------------------------------------------------
The fair value of outstanding bonds including current maturities is
estimated based on quoted market prices.
The preferred stock subject to mandatory redemption and corporation
obligated, mandatorily redeemable preferred securities of subsidiary trust
holding solely junior subordinated debentures of the corporation is
estimated based on dealer quotes.
-63-
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.
The fair value of interest rate swaps (used for hedging purposes) is the
estimated amount that the Company would receive or pay to terminate each
swap agreement at the reporting date, taking into account current interest
rates and the current credit-worthiness of all the parties to each swap.
Derivative instruments have been used by the Company on a limited basis.
The Company has a policy that financial derivatives are to be used only to
mitigate business risk and not for speculative purposes.
11. Supplementary Income Statement Information
(Dollars in Thousands) 1997 1996 1995
- -------------------------------------------------------------------------
Taxes:
Real estate and personal property $ 46,252 $ 43,762 $ 41,627
State business 58,466 60,787 60,695
Municipal, occupational and other 45,252 43,681 41,663
Other 21,242 12,729 12,168
- -------------------------------------------------------------------------
Total taxes $171,212 $160,959 $156,153
- -------------------------------------------------------------------------
Charged to:
Operating expense $160,135 $155,969 $150,507
Other accounts, including
construction work in progress 11,077 4,990 5,646
- -------------------------------------------------------------------------
Total taxes $171,212 $160,959 $156,153
=========================================================================
See "Consolidated Statements of Income" for maintenance and depreciation
expense.
Advertising, research and development expenses and amortization of
intangibles are not significant. The Company pays no royalties.
12. Leases
The Company treats all leases as operating leases for ratemaking purposes as
required by the Washington Commission. Certain leases contain purchase
options, renewal and escalation provisions. Capitalized leases are not
material.
Rental and operating lease expense for the years ended December 31, 1997,
1996 and 1995 were approximately $19,428,000, $19,394,000 and $19,217,000,
respectively. Payments due for the years ended December 31, 1997, 1996 and
1995 for the sublease of properties were approximately $962,000, $1,674,000
and $604,000, respectively.
Future minimum lease payments for noncancelable leases are approximately
$9,854,000 for 1998, $9,923,000 for 1999, $9,233,000 for 2000, $8,946,000
for 2001, $8,607,000 for 2002 and in the aggregate, $10,152,000 thereafter.
Future minimum sublease receipts for noncancelable subleases are $1,354,000
for 1998, $1,620,000 for 1999, $1,454,000 for 2000, $619,000 for 2001,
$617,000 for 2002 and in the aggregate, $360,000 thereafter.
-64-
13. Federal Income Taxes
The details of federal income taxes ("FIT") are as follows:
(Dollars in Thousands) 1997 1996 1995
- --------------------------------------------------------------------------
Charged to Operating Expense:
Current $ 31,672 $111,989 $ 73,562
Deferred - net 16,677 (3,058) 19,152
Deferred investment tax credits (624) (1,184) (1,195)
- --------------------------------------------------------------------------
Total FIT charged to operations $ 47,725 $107,747 $ 91,519
==========================================================================
Charged to Miscellaneous Income:
Current $ 16,709 $ (784) $ (1,851)
Deferred - net (1,902) -- (10,116)
- --------------------------------------------------------------------------
Total FIT charged to miscellaneous income $ 14,807 $ (784) $(11,967)
==========================================================================
Credited to discontinued operations $ (1,412) $ (986) $(14,320)
==========================================================================
Total FIT $ 61,120 $105,977 $ 65,232
==========================================================================
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:
(Dollars in Thousands) 1997 1996 1995
- ---------------------------------------------------------------------------
FIT at the statutory rate $64,469 $95,024 $58,455
- ---------------------------------------------------------------------------
Increase (Decrease):
Depreciation expense deducted in the
financial statements in excess of tax
depreciation, net of depreciation
treated as a temporary difference 7,019 6,603 5,856
AFUDC included in income in the financial
statements but excluded from taxable income (2,774) (2,191) (2,319)
Accelerated benefit on early retirement
of depreciable assets (805) (1,105) (840)
Investment tax credit amortization (624) (1,184) (1,195)
Energy conservation expenditures - net 11,028 3,380 806
Conservation Settlement (26,197) -- --
Other - net 9,004 5,450 4,469
- ---------------------------------------------------------------------------
Total FIT $61,120 $105,977 $65,232
===========================================================================
Effective tax rate 32.9% 39.0% 39.1%
===========================================================================
-65-
The following are the principal components of FIT as reported:
(Dollars in Thousands) 1997 1996 1995
- ---------------------------------------------------------------------------
Current FIT $48,381 $111,205 $71,711
===========================================================================
Deferred FIT - other:
Conservation tax settlement $14,404 $ (759) $ (7)
Periodic rate adjustment mechanism (PRAM) (14,272) (26,014) 1,384
Cabot valuation -- -- (8,681)
Deferred taxes related to insurance
reserves (2,768) (938) (938)
Reversal of Statement No. 90 present
value adjustments 408 552 688
Residential Purchase and Sale
Agreement - net (6,047) (2,178) (4,010)
Normalized tax benefits of the
accelerated cost recovery system 22,575 23,407 25,029
Energy conservation program 5,101 (1,208) 1,412
Environmental remediation (3,092) 1,148 --
WNP 3 tax settlement 21,360 -- --
Merger costs (7,322) -- --
Demand charges (3,558) -- --
Other (12,014) 2,932 (5,841)
- ----------------------------------------------------------------------------
Total deferred FIT - other $14,775 $(3,058) $ 9,036
============================================================================
Deferred investment tax credits -
net of amortization $ (624) $(1,184) $(1,195)
Credited to discontinued operations (1,412) (986) (14,320)
- ----------------------------------------------------------------------------
Total FIT $61,120 $105,977 $65,232
============================================================================
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 for certain temporary differences between tax and
financial statement purposes because they are not allowed for ratemaking
purposes.
The Company calculates its deferred tax assets and liabilities under
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("Statement No. 109"). Statement No. 109 requires recording deferred
tax balances, at the currently enacted tax rate, for all temporary
differences between the book and tax bases of assets and liabilities,
including temporary differences for which no deferred taxes had been
previously provided because of use of flow-through tax accounting for rate-
making purposes. Because of prior, and expected future ratemaking treatment
for temporary differences for which flow-through tax accounting has been
utilized, a regulatory asset for income taxes recoverable through future
rates related to those differences has also been established. At December
31, 1997, the balance of this asset is $258.4 million.
-66-
The deferred tax liability at December 31, 1997 and 1996 is comprised of
amounts related to the following types of temporary differences:
(Dollars in Thousands) 1997 1996
- --------------------------------------------------------------
Utility plant $558,170 $542,399
Investment in Cabot stock 13,435 13,650
PRAM (106) 14,167
Energy conservation charges 74,376 27,242
Contributions in aid of construction (30,350) (29,222)
Bonneville Exchange Power 30,240 11,622
Net operating loss carry-forwards -- (3,212)
Alternative minimum tax credits -- (15,187)
Other (16,747) 25,202
- --------------------------------------------------------------
Total $629,018 $586,661
==============================================================
The totals of $629 million and $587 million for 1997 and 1996 consist of
deferred tax liabilities of $712 million and $663 million net of deferred
tax assets of $83 million and $76 million, respectively.
14. Retirement Benefits
The Company has a defined benefit pension plan covering substantially all of
its employees. Benefits are a function of both age and salary.
Prior to March 1, 1997, the Company had separate defined benefit plans
covering electric and gas employees. Prior to 1997, the plan covering
electric employees had a measurement date of December 31 and the plan
covering gas employees had a measurement date of September 30.
(Dollars in Thousands) 1997 1996 1995
- ---------------------------------------------------------------------------
Service cost (benefits earned
during the period) $ 8,005 $ 8,908 $ 8,292
Interest cost on projected
benefit obligation 20,141 20,156 19,224
Actual return on plan assets (74,226) (47,957) (62,514)
Net amortization and deferral 45,420 20,918 38,839
- ---------------------------------------------------------------------------
Net pension costs under
FASB Statement No. 87 (660) 2,025 3,841
- ---------------------------------------------------------------------------
Regulatory adjustment 1,263 1,263 1,263
- ---------------------------------------------------------------------------
Net pension costs $ 603 $ 3,288 $ 5,104
===========================================================================
-67-
Funded Status of Plan
At December 31 (Dollars in Thousands) 1997 1996
- ----------------------------------------------------------------
Actuarial present value of benefit obligations:
Vested $(266,876) $(228,210)
Non-vested (5,229) ( 3,798)
- ----------------------------------------------------------------
Accumulated benefit obligation (272,105) (232,008)
Effect of future compensation levels (30,519) (56,022)
- ----------------------------------------------------------------
Total projected benefit obligation (302,624) (288,030)
Plan assets at market value 415,270 354,634
- ----------------------------------------------------------------
Plan assets in excess of projected benefit
obligation 112,646 66,604
Unrecognized net gain due to variance
between assumptions and experience (118,798) (72,031)
Prior service cost 17,184 9,237
Transition asset as of January 1, 1986,
being amortized on a straight-line
basis over 18 years (8,794) (2,934)
Regulatory adjustment, cumulative 2,401 3,664
- ----------------------------------------------------------------
Prepaid pension cost recognized
in long-term assets on balance sheet $ 4,639 $ 4,540
================================================================
1997 1996 1995
-------------- ---------- ----------
Assumptions used in the calculations:
Settlement discount rate 7.25 - 7.5% 7.5% 7.5%
Long-term rate-of-return on assets 9% 8.5 - 9% 7.5 - 9%
Compensation increase 5% 5 - 5.5% 5 - 6%
In December 1995, in connection with the proposed merger with WECo, the
Company offered to its employees a Voluntary Separation Plan. A total of
204 employees elected to participate in the Voluntary Separation Plan
resulting in a curtailment gain for 1996 of $1.6 million under Statement of
Financial Accounting Standards No. 88. In addition, curtailment losses under
Statement No. 106 for 1997 of $4.7 million and 1996 of $1.4 million
resulted from the 1995 Voluntary Separation Plan.
Plan assets consist primarily of U.S. Government securities, corporate debt
and equity securities.
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees. These
benefits are provided principally through an insurance company whose
premiums are based on the benefits paid during the year. In 1997, 1996 and
1995, the expenses recognized for post-retirement benefits were $1.7
million, $3.8 million and $2.5 million, respectively.
The Company has supplemental retirement plans for officer and director level
employees. Expenses for these plans for 1997, 1996 and 1995 were
$2,351,000, $1,848,000, and $1,780,000, respectively. A curtailment loss on
these plans of $5.1 million in 1997 is included in merger and related costs.
-68-
15. Employee Investment Plan & Employee Stock Purchase Plan
The Company has qualified employee investment plans under which employee
salary deferrals and after-tax contributions are used to purchase several
different investment fund options including an option to purchase Company
common stock. The Company makes a monthly contribution equal to 100 percent
on up to four percent of participant contributions and 50% on the next four
percent of participant contributions which equates to a maximum contribution
of 6% of eligible earnings. In addition, the Company contributes an amount
equal to one percent of each participant's base pay at the end of the plan
year.
The Company contributions to the Employee Investment Plan were $5,068,100,
$4,102,000 and $4,158,000 for the years 1997, 1996 and 1995, 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, 1997. The Employee Investment Plan eligibility requirements are set
forth in the plan documents.
The Company also has an Employee Stock Purchase Plan which was approved by
shareholders on May 19, 1997, and commenced July 1, 1997, under which
options are granted to eligible employees who elect to participate in the
plan on January 1st and July 1st of each year. Participants are allowed to
exercise those options six months later to the extent of payroll deductions
or cash payments accumulated during that six-month period. The option price
under the Plan is 90% of either the fair market value of the common stock at
the grant date or the fair market value at the exercise date, whichever is
less. The Company contribution to the Plan for the July 1, 1997 - December
31, 1997, offering period was $97,615.
16. Unconsolidated Oil and Gas Affiliate
In May 1994, the Company merged its oil and gas exploration and production
subsidiary, Washington Energy Resources Company ("Resources"), with a
wholly-owned subsidiary of Cabot Oil and Gas Corporation ("Cabot") in a tax-
free exchange. At December 31, 1997, the Company owned 15.4% of Cabot's
outstanding voting securities consisting of 2,133,000 shares of common stock
and 1,134,000 shares of 6% convertible voting preferred stock, stated value
$50. Prior to October 1, 1997, the Company's interest in Cabot's common
stock was accounted for using the equity method because the Company, through
its representation on Cabot's board of directors, had the ability to
exercise significant influence over operating and financial policies of
Cabot. Effective October 1, 1997, the Company discontinued equity method
accounting for Cabot and records its interest as an investment in stock
because the Company no longer has representation on Cabot's board of
directors.
The investment in Cabot common stock has been classified as an available-
for-sale security and is reported at its fair value, based on the closing
price on the NYSE on December 31, 1997, of $41,460,000. The unrealized gain
of $14,954,000 (net of deferred taxes of $8,052,000) is reported as a
separate component of common equity.
No fair value is readily available for the Cabot preferred stock as it is
not publicly traded; however, the fair value of the Company's shares of
Cabot preferred was estimated to be approximately $52,531,000 at December
31, 1997.
-69-
Equity in earnings (losses) from Cabot were $948,000; ($619,000) and
($9,185,000) for 1997, 1996, and 1995, respectively. In addition, the
Company wrote down its investment in Cabot by $18,300,000 ($11,895,000 after
tax) in 1995 to a value which approximated fair market value.
See Note 17 regarding certain gas transportation, storage and other
contractual arrangements of Resources that were excluded from the Cabot
merger and retained by a subsidiary of the Company.
17. Commitments and Contingencies
Commitments:
Electric
For the twelve months ended December 31, 1997, approximately 28.6% of the
Company's energy output was obtained at an average cost of approximately 9.4
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 proportion to the amount of
power annually purchased by the Company from such project. 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, 1997, 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)
Contract License Outstanding ---------------------------
Exp. Exp. 12/31/97(a) % of Kilowatt Costs(b)
Project Date Date (Millions) Output Capacity (Millions)
- ---------------------------------------------------------------------------
Rock Island
Original units 2012 2029 $ 83.7 57.1 )
) 423,000 $ 43.9
Additional units 2012 2029 331.1 100.0 )
Rocky Reach 2011 2006(c) 234.7 38.9 482,750 22.7
Wells 2018 2012(c) 178.2 31.5 264,600 9.3
Priest Rapids 2005 2005(c) 174.2 8.0 72,570 2.1
Wanapum 2009 2005(c) 206.7 10.8 112,100 3.3
- ---------------------------------------------------------------------------
Total 1,355,020 $81.3
===========================================================================
(a) The contracts for purchases initially were generally coextensive
with the term of the PUD bonds associated with the project. Under the terms
of some financings and refinancings, however, long-term bonds were sold to
-70-
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: 43.4% at Rock Island;
45.6% at Rocky Reach; 79.1% at Priest Rapids; and 44.7% at Wanapum.
(b) The components of 1998 costs associated with the interest portion
of debt service are: Rock Island, $23.8 million for all units; Rocky Reach,
$4.8 million; Wells, $2.9 million; Priest Rapids, $0.9 million; and Wanapum,
$1.2 million.
(c) The Company is unable to predict whether the licenses under the
Federal Power Act will be renewed to the current licensees. However, the
FERC has issued orders for Rocky Reach, Wells and Priest Rapids/Wanapum
projects under Section 22 of the Federal Power Act, which affirm the
Company's contractual rights to receive power under existing terms and
conditions even if a new licensee is granted a license prior to expiration
of the contract term.
- -----------------------------
The Company's estimated payments for power purchases from the Columbia River
projects are $81 million for 1998, $82 million for 1999, $84 million for
2000, $87 million for 2001, $90 million for 2002 and in the aggregate, $964
million thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with
other utilities in the region. The Company is generally not obligated to
make payments under these contracts unless power is delivered. The
Company's estimated payments for firm power purchases from other utilities,
excluding the Columbia River projects, are $147 million for 1998, $150
million for 1999, $155 million for 2000, $149 million for 2001, $141 million
for 2002 and in the aggregate, $1.1 billion thereafter through 2037. These
contracts have varying terms and may include escalation and termination
provisions.
As required by the federal Public Utility Reform and Policy Act ("PURPA"),
the Company has entered into long-term firm purchased power contracts with
non-utility generators. The Company purchases the net electrical output of
five significant projects at fixed and annually escalating prices which were
intended to approximate the Company's avoided cost of new generation
projected at the time these agreements were made. Principally, as a result
of dramatic changes in natural gas price levels, the power purchase prices
under these agreements are significantly above the current market price of
power and, based upon projections of future market prices, are expected to
remain well above market for the duration of the contracts. The Company's
estimated payment under these five contracts are $247 million for 1998, $257
million for 1999, $265 million for 2000, $288 million for 2001, $297 million
for 2002 and in the aggregate, $3.1 billion thereafter through 2014. When
and if retail electric energy prices move to market levels as a result of
electric industry restructuring, the above market portion of these contract
costs will become stranded costs which the Company plans to seek to recover
through transition charges.
Total purchased power contracts provided the Company with approximately 15.6
million, 17.1 million and 16.4 million MWH of firm energy at a cost of
approximately $464.5 million, $485.6 million and $478.7 million for the
years 1997, 1996 and 1995, respectively.
-71-
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, 1997:
Company's Share
------------------------------
Energy Company's Plant in Accumulated
Source Ownership Service at cost Depreciation
Project (Fuel) Share (%) (Millions) (Millions)
- -------------- ------ --------- -------------- ------------
Centralia Coal 7 $ 26.8 $ 17.9
Colstrip 1 & 2 Coal 50 186.1 101.6
Colstrip 3 & 4 Coal 25 449.1 166.5
- ------------------------------------------------------------------------
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.
The Company and other joint owners of the Centralia Project are exploring
alternative emission compliance options and project economics in light of
compliance costs to meet the Phase II limits in the year 2000.
Certain purchase commitments have been made in connection with the Company's
construction program.
Gas
Washington Energy Gas Marketing Company ("WEGM"), a wholly-owned subsidiary,
holds firm rights to transport natural gas on the Nova Corporation of
Alberta ("Nova"), Alberta Natural Gas Company ("ANG") and Pacific Gas
Transmission Company ("PGT") pipelines from Alberta, Canada, to the northern
border of California, as well as certain gas storage rights at the Alberta
Energy Company ("AECO") field in Alberta and the Jackson Prairie field in
western Washington. These rights were formerly held by a wholly-owned
subsidiary of Resources but were excluded from the merger of Resources and
Cabot completed in May 1994. Following the merger, WEGM entered into a
five-year contract with IGI Resources ("IGI"), Boise, Idaho, to manage these
rights.
The transportation rights on the PGT pipeline initially consisted of
approximately 25,000 MMBtu per day of annual capacity and 20,000 MMBtu per
day of winter-only capacity to Stanfield, Oregon, and approximately 20,000
MMBtu per day of annual capacity to the California border. WEGM held
similar rights on Nova and ANG. Effective November 1, 1995, WEGM
permanently assigned to IGI all of its Stanfield capacity and associated
rights on Nova and ANG. In addition, WEGM segmented its capacity to
California at Stanfield and permanently assigned 10,000 MMBtu per day of the
Alberta to Stanfield rights to a third party effective November 1, 1995.
WEGM's remaining PGT rights expire in October 2023, and the ANG and Nova
rights expire in October 2008, with annual renewal options. As of December
31, 1997, WEGM has a reserve for future losses associated with these
contractual obligations of $6,527,000. WEGM, as an expansion capacity
holder, has been unable to fully recoup its demand charges, which have been
approximately 70% higher than those paid by holders of vintage capacity. On
September 11, 1996, the FERC approved a request from PGT for the cost of the
expansion capacity to be "rolled in" with the cost of the vintage capacity
-72-
to establish a uniform rate for holders of both types of capacity. This
change will be implemented in two stages over six years with the first stage
effective November 1, 1996. WEGM's annual obligations for future demand
charges through the primary term of WEGM's gas transportation and storage
contracts are as follows: 1998, $2,782,000; 1999, $2,765,000; 2000,
$2,682,000; 2001, $2,682,000; 2002, $2,624,000 and thereafter, $38,822,000.
The IGI management contract provides for incentive payments to IGI based on
actual mitigation of demand charges relative to targets established on an
annual basis.
WEGM initially established the reserve for estimated future losses
associated with the transportation and storage obligations with a
$16,000,000 ($10,400,000 after tax) charge to earnings upon completion of
the merger of Resources and Cabot in May 1994. In the fourth quarter of
1995, WEGM recorded a $5,000,000 ($3,250,000 after tax) charge to increase
the reserve based on an assessment of the likelihood and timing of approval
of rolled-in rates and actual mitigation results in 1995. During 1997, 1996
and 1995, pre-tax losses totaling $2,235,000, $2,652,000 and $5,841,000,
respectively, were charged against the reserve.
The Company has also entered into various firm supply, transportation and
storage service contracts in order to assure adequate availability of gas
supply for its firm customers. Many of these contracts, which have
remaining terms of from one to 26 years, provide that the Company must pay a
fixed demand charge each month, regardless of actual usage. Certain of the
Company's firm gas supply agreements also obligate the Company to purchase a
minimum annual quantity at market-based contract prices. Generally, if the
minimum volumes are not purchased and taken during the year, the Company is
obligated to pay either: 1) a monthly or annual gas inventory charge
calculated as a percentage of the then-current contract commodity price
times the minimum quantity not taken; or 2) pay for gas not taken.
Alternatively, under some of the contracts, the supplier may exercise a
right to reduce its subsequent obligation to provide firm gas to the
Company. The Company incurred demand charges in 1997 for firm gas supply,
firm transportation service and firm storage and peaking service of
$31,402,000, $59,331,000 and $9,004,000, respectively.
The following tables summarize the Company's obligations for future demand
charges through the primary terms of its existing contracts and the minimum
annual take requirements under the gas supply agreements. The quantified
obligations are based on current contract prices and FERC authorized rates,
which are subject to change. Amounts are for the twelve months ended
September 30.
Demand Charge Obligations (in thousands):
2003 &
There-
1998 1999 2000 2001 2002 after Total
----------------------------------------------------------
Firm gas supply $28,520 $26,962 $24,682 $24,658 $24,352 $ 19,564 $148,738
Firm transpor-
tation service 52,258 52,258 52,207 52,155 52,155 207,233 468,266
Firm storage and
peaking service 8,938 8,938 8,938 8,938 8,938 96,463 141,153
----------------------------------------------------------
Total $89,716 $88,158 $85,827 $85,751 $85,445 $323,260 $758,157
==========================================================
-73-
Minimum Annual Take Obligations (in thousands of therms):
2003 &
There-
1998 1999 2000 2001 2002 after Total
---------------------------------------------------------------
Firm gas
supply 590,888 400,302 373,194 359,994 288,094 225,222 2,237,694
================================================================
The Company believes that all demand charges will be recoverable in rates
charged to its customers. Further, pursuant to implementation of FERC Order
No. 636, the Company has the right to resell or release to others any of its
unutilized gas supply or transportation and storage capacity.
The Company does not anticipate any difficulty in achieving the minimum
annual take obligations shown, as such volumes represent less than 73% of
expected annual sales for 1998 and less than 48% of expected sales in
subsequent years.
The Company's current firm gas supply contracts obligate the suppliers to
provide, in the aggregate, annual volumes up to those shown below:
Maximum Supply Available Under Current Firm Supply Contracts (in thousands
of therms):
2003 &
There-
1998 1999 2000 2001 2002 after Total
------- ------- ------ ------- ------- -------- ---------
Total 944,640 641,644 596,044 577,964 497,664 397,870 3,655,826
======= ======= ======= ======= ======= ======= ==========
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 several contaminated
disposal sites and manufactured gas plant sites. The Company has also
instituted an ongoing 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 is also continuing.
During 1992, the Washington Commission issued orders regarding the treatment
of costs incurred by the Company for certain sites under its environmental
remediation program. The orders authorize the Company to accumulate and
defer prudently incurred cleanup costs paid to third parties for recovery in
rates established in future rate proceedings. The Company believes a
significant portion of its past and future environmental remediation costs
are recoverable from either insurance companies, third parties or under the
Washington Commission's order.
The information presented here as it relates to estimates of future
liability is as of December 31, 1997.
-74-
Electric Sites
The Company has expended approximately $14.4 million related to the
remediation activities covered by the Washington Commission's order, of
which approximately $7.4 million has been recovered from insurance carriers.
At December 31, 1997, approximately $1.8 million has been accrued as a
liability for future remediation costs for these and other remediation
activities.
Gas Sites
Five former WNG or predecessor companies manufactured gas plant ("MGP")
sites are currently undergoing investigation, remedial actions or monitoring
actions relating to environmental contamination: 1) Everett, Washington; 2)
"Gas Works Park" in Seattle, Washington; 3) "Tacoma 22nd and A St." Site in
Tacoma, Washington; 4) Chehalis, Washington; and 5) the "Tideflats" area of
Tacoma, Washington. Costs incurred to date total approximately $48.0
million and currently estimated future remediation costs are approximately
$7.7 million. To date, the Company has recovered approximately $55.7
million from insurance carriers.
Based on all known facts and analyses, the Company believes it is not likely
that the identified environmental liabilities will result in a material
adverse impact on the Company's financial position, operating results or
cash flow trends.
Litigation
Other contingencies, arising out of the normal course of the Company's
business, exist at December 31, 1997. 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.
18. Discontinued Operations
On March 5, 1997, the Company conveyed its interests in undeveloped coal
properties through its wholly-owned subsidiary Thermal Energy, Inc. to Wesco
Resources, Inc. effective February 1, 1997. In return for this conveyance,
Wesco Resources, Inc. agreed to assume future coal property obligations and
liabilities and to pay the Company a 2% royalty on coal mined from the
transferred coal properties now held by Wesco Resources, Inc. The Company
has determined, based on a report by mining consultants, that the
development of the transferred coal properties in the foreseeable future is
speculative. As a result, the Company does not expect to receive any
amounts under the 2% royalty agreement. Therefore, in March 1997, the
Company's remaining $4.0 million investment in Thermal Energy, Inc. was
written off to expense and appears in the consolidated financial statements
as discontinued operations. Prior periods have been restated to include
Thermal Energy, Inc. operations as discontinued operations. In 1995, WECo
wrote down the carrying value of its coal properties by $34,700,000
($22,555,000 after tax) with the adoption of Statement No. 121.
Operating results for coal and railroad activities resulted in after tax
losses of $1.4 million and $26.6 million in 1996 and 1995, respectively.
-75-
19. Supplemental Quarterly Financial Data (Unaudited)
The following unaudited amounts, in the opinion of the Company, include all
adjustments (consisting of normal recurring adjustments) necessary for a
fair presentation of the results of operations for the interim periods.
Quarterly amounts vary during the year due to the seasonal nature of the
utility business. Amounts for the individual companies have been combined
based on the respective quarters of their fiscal years.
(Unaudited)
Dollars in thousands except per share amounts)
1997 Quarter First Second Third Fourth
- --------------------------------------------------------------------------
(Dollars in thousands except per share amounts)
Operating revenues $463,319 $352,618 $341,021 $519,944
Operating income $ 56,828 $ 45,233 $ 35,421 $ 78,384
Other income $ 4,884 $ 17,804 $ 6,029 $ (651)
Income from continuing
operations $ 32,608 $ 33,440 $ 11,998 $ 47,652
Net income $ 29,986 $ 33,440 $ 11,998 $ 47,652
Basic and diluted earnings
per common share from
continuing operations $ 0.32 $ 0.33 $ 0.11 $ 0.52
- --------------------------------------------------------------------------
1996 Quarter First Second Third Fourth
- --------------------------------------------------------------------------
Operating revenues $459,291 $414,598 $349,983 $425,407
Operating income $ 87,085 $ 70,241 $ 50,931 $ 76,217
Other income $ 1,419 $ 845 $ 411 $ (1,082)
Income from continuing
operations $ 58,576 $ 41,829 $ 22,286 $ 44,660
Net income $ 58,309 $ 41,410 $ 21,959 $ 43,841
Basic and diluted earnings
per common share from
continuing operations $ 0.63 $ 0.43 $ 0.20 $ 0.46
- --------------------------------------------------------------------------
20. 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.
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The following provides additional information concerning cash flow
activities:
Year Ended December 31: 1997 1996 1995
(Dollars in Thousands)
- --------------------------------------------------------------------------
Changes in certain current
assets and current liabilities:
Accounts receivable $ (4,164) $(22,242) $ 3,769
Unbilled revenue 4,591 (11,104) 6,382
Materials and supplies 3,316 16,737 (763)
Prepayments and other 5,339 1,491 (1,607)
Purchased gas liability (34,966) 25,814 36,815
Accounts payable (1,219) 15,997 (3,128)
Accrued expenses and other (31,291) 1,116 (6,509)
- --------------------------------------------------------------------------
Net change in certain current assets
and current liabilities $(58,394) $27,809 $ 34,959
==========================================================================
Cash payments:
Interest (net of capitalized interest) $119,810 $113,634 $131,807
Income taxes $104,161 $ 98,609 $ 77,608
- --------------------------------------------------------------------------
21. Merger of Puget Power and WECo
Included in consolidated results of operations for the month of January 1997
and for the years ended December 31, 1996 and 1995, are the following
results of the previously separate companies for those periods (Dollars in
Thousands:
Month Ended Year Ended Year Ended
January 31, 1997 December 31, 1996 December 31, 1995
------------------ --------------------- ---------------------
Puget WECo Puget WECo Puget WECo
--------- --------- ---------- --------- ---------- ---------
Revenues $ 123,051 $ 60,486 $1,223,568 $425,711 $1,187,507 $443,611
Net Income 19,671 9,378 $ 135,371 $ 30,148 $ 135,720 $(33,936)
Common Dividends
Declared 29,244 -- $ 117,099 $ 24,149 $ 117,099 $ 23,877
WECo's operations for the three months ended December 31, 1996, have been
reported as an adjustment of $10.8 million to consolidated retained earnings
in the first quarter of 1997. WECo's revenues for the three months ended
December 31, 1996, were $148.6 million, net income was $16.9 million, common
stock issued was $1.0 million and common stock dividends declared were $6.1
million for the same period.
In connection with the merger, the Company recognized direct and indirect
merger-related expenses of $55.8 million during the first quarter of 1997.
The charge consisted primarily of severance costs of $15.5 million, benefit-
related curtailment costs of $9.1 million, transaction costs of $13.7 million
and systems and facilities integration costs of $7.2 million. The
nonrecurring charge reduced net income by approximately $36.3 million or
$0.43 per share. In addition, merger-related costs of $4.8 million were
recognized in the fourth quarter of 1996 by PSPL.
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Puget Sound Energy
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, 1997
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable (A) $1,700 $5,080 $5,809 $ 971
============================================================================
Year Ended December 31, 1996
- ----------------------------
Accounts deducted from
assets on balance sheet:
Allowance for doubtful
accounts receivable $1,865 $5,920 $6,085 $1,700
============================================================================
Year Ended December 31, 1995
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $1,905 $6,327 $6,367 $1,865
============================================================================
(A) Includes additions of $369 and deductions of $384 related to October
through December 1996 for WECo.
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EXHIBIT INDEX
Certain of the following exhibits are filed herewith. Certain other of the
following exhibits have heretofore been filed with the Commission and are
incorporated herein by reference.
2.1 Agreement and Plan of merger dated as of October 18, 1995, among
the Registrant, Washington Energy Company and Washington Natural Gas Company.
(Exhibit 2.1 to Registration No. 333-617)
3-a Restated Articles of Incorporation of the Company. (Included as
Annex F to the Joint Proxy Statement/Prospectus filed February 1, 1996,
Registration No. 333-617)
3-b Restated Bylaws of the Company. (Exhibit 3 to Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission
File No. 1-4393)
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 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)
4.3 Amendment No. 1 dated as of August 30, 1991, to the Rights
Agreement dated as of January 15, 1991, between the Registrant and the Bank
of New York (as successor to The Chase Manhatten Bank, N.A.), as Rights
Agent. (Exhibit 2.1 to Registration Statement on Form 8 filed on August 30,
1991)
4.4 Amendment No. 2 dated as of October 18, 1995, to the Rights
Agreement dated as of January 15, 1991, between the Registrant and The Bank
of New York (as successor to The Chase Manhatten Bank, N.A.), as Rights
Agent. (Exhibit 1 to Registration Statement on Form 8-A/A filed on October
27, 1995)
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4.5 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)
4.6 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)
4.7 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)
4.8 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)
4.9 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)
4.10 Pledge Agreement, dated as of March 1, 1992, by and between the
Company 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)
4.11 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)
4.12 Form of Statement of Relative Rights and Preferences for the
Series II Cumulative Preferred Stock, $25 Par Value (included as Annex F to
the Joint Proxy Statement/Prospectus filed February 1, 1996).
4.13 Form of Statement of Relative Rights and Preferences for the
Series III Cumulative Preferred Stock, $25 Par Value (included as Annex F to
the Joint Proxy Statement/Prospectus filed February 1, 1996).
4.14 Indenture of First Mortgage dated as of April 1, 1957
(incorporated herein by reference to Washington Natural Gas Company Exhibit
4-B, Registration No. 2-14307).
4.15 Sixth Supplemental Indenture dated as of August 1, 1966
(incorporated herein by reference to Washington Natural Gas Company Exhibit
to Form 8-K for month of August 1966, File No. 0-951).
4.16 Twelfth Supplemental Indenture dated as of November 1, 1972
(incorporated herein by reference to Washington Natural Gas Company Exhibit
to Form 8-K for November 1972, File No. 0-951).
4.17 Seventeenth Supplemental Indenture dated as of August 9, 1978
(incorporated herein by reference to Washington Energy Company Exhibit 5-
K.18, Registration No. 2-64428).
4.18 Twenty-sixth Supplemental Indenture dated as of September 1,
1990 (incorporated herein by reference to Washington Natural Gas Company
Exhibit 4-B.19, Form 10-K for the year ended September 30, 1990, File No. 0-
951). -80-
4.19 Twenty-seventh Supplemental Indenture dated as of September 1,
1990 (incorporated herein by reference to Washington Natural Gas Company
Exhibit 4-B.20, Form 10-K for the year ended September 30, 1988, File No. 0-
951).
4.20 Twenty-eighth Supplemental Indenture dated as of July 31, 1991
(incorporated herein by reference to Washington Natural Gas Company exhibit
4-A, Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
4.21 Twenty-ninth Supplemental Indenture dated as of June 1, 1993
(incorporated herein by reference to Exhibit 4-A of Washington Natural Gas
Company's S-3 Registration Statement, Registration No. 33-49599).
4.22 Thirtieth Supplemental Indenture dated as of August 15, 1995
(incorporated herein by reference to Exhibit 4-A of Washington Natural Gas
Company's S-3 Registration Statement, Registration No. 33-61859).
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)
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10.9 Pacific Northwest Coordination Agreement, executed as of
September 15, 1964, among the United States of America, the Company and
most of the other major electrical utilities in the Pacific Northwest.
(Exhibit 13-gg to Registration No. 2-24252)
10.10 Contract dated November 14, 1957, between Public Utility
District No. 1 of Chelan County, Washington and the Company, relating to
the Rocky Reach Project. (Exhibit 4-1-a to Registration No. 2-13979)
10.11 Power Sales Contract, dated as of November 14, 1957, between
Public Utility District No. 1 of Chelan County, Washington and the
Company, relating to the Rocky Reach Project. (Exhibit 4-c-1 to
Registration No. 2-13979)
10.12 Power Sales Contract, dated May 21, 1956, between Public
Utility District No. 2 of Grant County, Washington and the Company,
relating to the Priest Rapids Project. (Exhibit 4-d to Registration No.
2-13347)
10.13 First Amendment to Power Sales Contract dated as of August 5,
1958, between the Company and Public Utility District No. 2 of Grant
County, Washington, relating to the Priest Rapids Development. (Exhibit
13-h to Registration No. 2-15618)
10.14 Power Sales Contract dated June 22, 1959, between Public
Utility District No. 2 of Grant County, Washington and the Company,
relating to the Wanapum Development. (Exhibit 13-j to Registration No.
2-15618)
10.15 Reserve Share Power Sales Contract dated June 22, 1959, between
Public Utility District No. 2 of Grant County, Washington and the Company,
relating to the Priest Rapids Project. (Exhibit 13-k to Registration No. 2-
15618)
10.16 Agreement to Amend Power Sales Contracts dated July 30, 1963,
between Public Utility District No. 2 of Grant County, Washington and the
Company, relating to the Wanapum Development. (Exhibit 13-1 to Registration
No. 2-21824)
10.17 Power Sales Contract executed as of September 18, 1963, between
Public Utility District No. 1 of Douglas County, Washington and the Company,
relating to the Wells Development (Exhibit 13-r to Registration No. 2-21824)
10.18 Reserved Share Power Sales Contract executed as of September 18,
1963, between Public Utility District No. 1 of Douglas County, Washington
and the Company, relating to the Wells Development. (Exhibit 13-s to
Registration No. 2-21824)
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)
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10.21 Contract covering undivided interest in ownership and operation
of Centralia Thermal Plant, dated May 15, 1969. (Exhibit 5-b to
Registration No. 2-3765)
10.22 Construction and Ownership Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-b to
Registration No. 2-45702)
10.23 Operation and Maintenance Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-c to
Registration No. 2-45702)
10.24 Coal Supply Agreement, dated as of July 30, 1971, among The
Montana Power Company, the Company and Western Energy Company. (Exhibit 5-d
to Registration No. 2-45702)
10.25 Power Purchase Agreement with Washington Public Power Supply
System and the Bonneville Power Administration dated February 6, 1973.
(Exhibit 5-e to Registration No. 2-49029)
10.26 Ownership Agreement among the Company, Washington Public Power
Supply System and others dated September 17, 1973. (Exhibit 5-a-29 to
Registration No. 2-60200)
10.27 Contract dated June 19, 1974, between the Company and P.U.D. No.
1 of Chelan County. (Exhibit D to Form 8-K dated July 5, 1974
10.28 Restated Financing Agreement among the Company, lessee, Chrysler
Financial Corporation, owner, Nevada National Bank and Bank of Montreal
(California), trustee, dated December 12, 1974 pertaining to a combustion
turbine generating unit trust. (Exhibit 5-a-35 to Registration No. 2-60200)
10.29 Restated Lease Agreement between the Company, lessee, and the
Bank of California, and National Association, lessor, dated December 12,
1974 for one combustion generating unit. (Exhibit 5-a-36 to Registration
No. 2-60200)
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)
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10.34 Letter Agreement dated March 31, 1980, between the Company and
Manufacturers Hanover Leasing Corporation. (Exhibit b-8 to Registration No.
2-68498)
10.35 Coal Supply Agreement for Colstrip 3 and 4, dated as of July 2,
1980; Amendment No. 1 to Coal Supply Agreement, dated as of July 10, 1981;
and Coal Transportation Agreement dated as of July 10, 1981. (Exhibit 20-a
to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981,
Commission File No. 1-4393)
10.36 Residential Purchase and Sale Agreement between the Company and
the Bonneville Power Administration, effective as of October 1, 1981.
(Exhibit 20-b to Quarterly Report on Form 10-Q for the quarter ended
September 30, 1981, Commission File No. 1-4393)
10.37 Letter of Agreement to Participate in Licensing of Creston
Generating Station, dated September 30, 1981. (Exhibit 20-c to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1981, Commission
File No. 1-4393)
10.38 Power sales contract dated August 27, 1982 between the Company
and Bonneville Power Administration. (Exhibit 10-a to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1982, Commission File No. 1-
4393)
10.39 Agreement executed as of April 17, 1984, between the United
States of America, Department of the Interior, acting through the Bonneville
Power Administration, and other utilities relating to extension energy from
the Hanford Atomic Power Plant No. 1. (Exhibit (10)-47 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1984, Commission File No.
1-4393)
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
-84-
acting by and through the Bonneville Power Administration and the Company,
dated September 17, 1985. (Exhibit B of Exhibit (10)-50 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No.
1-4393)
10.45 Settlement Agreement and Covenant Not to Sue between the
Company and Northern Wasco County People's Utility District, dated
October 16, 1985. (Exhibit (10)-53 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.46 Settlement Agreement and Covenant Not to Sue between the
Company and Tillamook People's Utility District, dated October 16, 1985.
(Exhibit (10)-54 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1985, Commission File No. 1-4393)
10.47 Settlement Agreement and Covenent Not to Sue between the
Company and Clatskanie People's Utility District, dated September 30,
1985. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1985, Commission File No. 1-4393)
10.48 Stipulation and Settlement Agreement between the Company and
Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October
31, 1986. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1986, Commission File No. 1-4393)
10.49 Transmission Agreement dated April 17, 1981, between the
Bonneville Power Administration and the Company (Colstrip Project). (Exhibit
(10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
10.50 Transmission Agreement dated April 17, 1981, between the
Bonneville Power Administration and Montana Intertie Users (Colstrip
Project). (Exhibit (10)-56 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.51 Ownership and Operation Agreement dated as of May 6, 1981,
between the Company and other Owners of the Colstrip Project (Colstrip 3 and
4). (Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
10.52 Colstrip Project Transmission Agreement dated as of May 6, 1981,
between the Company and Owners of the Colstrip Project. (Exhibit (10)-58 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.53 Common Facilities Agreement dated as of May 6, 1981, between the
Company and Owners of Colstrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.54 Agreement for the Purchase of Power dated as of October 29, 1984,
between South Fork II, Inc. and the Company (Weeks Falls Hydroelectric
Project). (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.55 Agreement for the Purchase of Power dated as of October 29, 1984,
between South Fork Resources, Inc. and the Company (Twin Falls Hydroelectric
Project). (Exhibit (10)-61 to Annual Report on Form 10-K for the fiscal year
-85-
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
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)
-86-
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)
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)
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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
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
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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)
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)
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10.97 Memorandum of Understanding between the Company and the
Bonneville Power Administration dated September 18, 1991. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1991,
Commission File No. 1-4393)
10.98 Amendment of Seasonal Exchange Agreement, dated December 4, 1991,
between Pacific Gas and Electric Company and the Company. (Exhibit (10)-107
to Annual Report on Form 10-K for the fiscal year ended December 31, 1991,
Commission File No. 1-4393)
10.99 Capacity and Energy Exchange Agreement, dated as of October 4,
1991, between Pacific Gas and Electric Company and the Company. (Exhibit
(10)-108 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.100 Intertie and Network Transmission Agreement, dated as of October
4, 1991, between Bonneville Power Administration and the Company. (Exhibit
(10)-109 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.101 Amendatory Agreement No. 4, executed June 17, 1991, to the Power
Sales Agreement dated August 27, 1982, between the Bonneville Power
Administration and the Company. (Exhibit (10)-110 to Annual Report on Form
10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.102 Amendment to Agreement for Firm Power Purchase, dated as of
September 30, 1991, between Sumas Energy, Inc. and the Company. (Exhibit
(10)-112 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.103 Centralia Fuel Supply Agreement, dated as of January 1, 1991,
between Pacificorp Electric Operations and the Company and other Owners of
the Centralia Steam-Electric Power Plant. (Exhibit (10)-113 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1991, Commission File No.
1-4393)
10.104 Agreement for Firm Power Purchase dated August 10, 1992, between
Pyrowaste Corporation, Puget Sound Pyroenergy Corporation and the Company.
(Exhibit (10)-114 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, Commission File No. 1-4393)
10.105 Memorandum of Termination dated August 31, 1992, between Encogen
Northwest, L.P. and the Company. (Exhibit (10)-115 to Annual Report on Form
10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.106 Agreement Regarding Security dated August 31, 1992, between
Encogen Northwest, L.P. and the Company. (Exhibit (10)-116 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
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)
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10.108 Subordination Agreement dated December 17, 1992, between the
Company, Encogen Northwest, L.P., Rolls-Royce & Partners Finance Limited and
The First National Bank of Chicago. (Exhibit (10)-118 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-
4393)
10.109 Letter Agreement dated December 18, 1992, between Encogen
Northwest, L.P. and the Company regarding arrangements for the application of
insurance proceeds. (Exhibit (10)-119 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.110 Guaranty of Ensearch Corporation in favor of the Company dated
December 15, 1992. (Exhibit (10)-120 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.111 Letter Agreement dated October 12, 1992, between Tenaska
Washington Partners, L.P. and the Company regarding clarification of issues
under the Agreement for Firm Power Purchase. (Exhibit (10)-121 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1992, Commission
File No. 1-4393)
10.112 Consent and Agreement dated October 12, 1992, between the
Company, and The Chase Manhattan Bank, N.A., as agent. (Exhibit (10)-122 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1992,
Commission File No. 1-4393)
10.113 Settlement Agreement dated December 29, 1992, between the Company
and the Bonneville Power Administration (BPA) providing for power purchase by
BPA. (Exhibit (10)-123 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1992, Commission File No. 1-4393)
10.114 Contract with W. S. Weaver, Executive Vice President & Chief
Financial Officer, dated April 24, 1991. (Exhibit 10.114 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1993, Commission File No. 1-
4393)
10.115 General Transmission Agreement dated as of December 1, 1994,
between the Bonneville Power Administration and the Company (BPA Contract No.
DE-MS79-94BP93947) (Exhibit 10.115 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1994, Commission File No. 1-4393)
10.116 PNW AC Intertie Capacity Ownership Agreement dated as of October
11, 1994 between the Bonneville Power Administration and the Company (BPA
Contract No. DE-MS79-94BP94521) (Exhibit 10.116 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, Commission File No. 1-4393)
10.117 Power Exchange Agreement dated as of September 27, 1995, between
British Columbia Power Exchange Corporation and the Company. (Exhibit 10.117
to Annual Report on Form 10-K for the fiscal year ended December 31, 1996,
Commission File No. 1-4393)
10.118 Contract with W. S. Weaver, Executive Vice President and Chief
Financial Officer, dated October 18, 1996. (Exhibit 10.118 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1996, Commission File No.
1-4393)
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10.119 Contract with S. M. Vortman, Senior Vice President Corporate and
Regulatory Relations, dated October 18, 1996. (Exhibit 10.119 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1996, Commission
File No. 1-4393)
10.120 Contract with G. B. Swofford, Senior Vice President Customer
Operations, dated October 18, 1996. (Exhibit 10.120 to Annual Report on Form
10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393)
10.121 Service Agreement dated September 1, 1987 between Northwest
Pipeline Corporation and Washington Natural Gas Company for SGS-1 firm
storage service at Jackson Prairie (incorporated herein by reference to
Washington Natural Gas Company Exhibit 10-A Form 10-K for the year ended
September 30, 1994, File No. 11271).
10.122 Service Agreement dated April 14, 1993 between Questar Pipeline
Corporation and Washington Natural Gas Company for FSS-1 firm storage
service at Clay Basin (incorporated herein by reference to Washington
Natural Gas Company Exhibit 10-B Form 10-K for the year ended September 30,
1994, File No. 11271).
10.123 Service Agreement dated November 1, 1989, with Northwest
Pipeline Corporation covering liquefaction storage gas service filed under
cover of Form SE dated December 27, 1989.
10.124 Firm Transportation Service Agreement dated October 1, 1990
between Northwest Pipeline Corporation and Washington Natural Gas Company
(incorporated herein by reference to Washington Natural Gas Company Exhibit
10-D Form 10-K for the year ended September 30, 1994, File No. 11271).
10.125 Gas Transportation Service Contract dated June 29, 1990 between
Washington Natural Gas Company and Northwest Pipeline Corporation
(incorporated herein by reference to Washington Natural Gas Company exhibit
4-A Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
10.126 Gas Transportation Service Contract dated July 31, 1991 between
Washington Natural Gas Company and Northwest Pipeline Corporation
(incorporated herein by reference to Washington Natural Gas Company exhibit
4-A Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
10.127 Amendment to Gas Transportation Service Contract dated July 31,
1991 between Washington Natural Gas Company and Northwest Pipeline
Corporation.
10.128 Gas Transportation Service Contract dated July 15, 1994 between
Washington Natural Gas Company and Northwest Pipeline Corporation
10.129 Amendment to Gas Transportation Service Contract dated August
15, 1994 between Washington Natural Gas Company and Northwest Pipeline
Corporation.
10.130 Washington Natural Gas Company Deferred Compensation Plan
effective September 1, 1995.
10.131 Form of Washington Natural Gas Company - Executive Retirement
Compensation Agreement reflecting all amendments through August 16, 1995.
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10.132 Second Washington Energy Company Performance Share Plan (amended
and restated effective October 1, 1991) (incorporated herein by reference to
Washington Energy Company Exhibit 10-L.1, Form 10-K for the year ended
September 30, 1991, File No. 0-8745).
10.133 Washington Energy Company Interim Performance Share Plan
effective December 7, 1994.
10.134 Washington Energy Company Stock Option Plan (incorporated herein
by reference to Exhibit 10-C Washington Energy Company Form 10-Q for the
quarter ended March 31, 1984, File No. 0-8745).
10.135 Amendment to Washington Energy Company Stock Option Plan
(incorporated herein by reference to Washington Energy Company Exhibit 10-S,
Form 10-K for the year ended September 30, 1986, File No. 0-8745).
10.136 Amendment to Washington Energy Company Stock Option Plan dated
as of February 26, 1988 (incorporated herein by reference to Washington
Energy Company Form S-8, Registration No. 33-24221).
10.137 Washington Energy Company Stock Option Plan effective December
15, 1993 (incorporated herein by reference to Washington Energy Company
Exhibit 99, Registration No. 33-55381).
10.138 Washington Energy Company Directors Stock Bonus Plan
(incorporated herein by reference to Washington Energy Company Exhibit 10-O
Form 10-K for the year ended September 30, 1990, File No. 0-8745).
10.139 Employment Agreement between Washington Energy Company,
Washington Natural Gas Company and William P. Vititoe dated January 15, 1994
(incorporated herein by reference to Washington Natural Gas Company Exhibit
10-M.1, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.140 Form of Conditional Executive Employment Contract, filed under
cover of Form SE dated December 27, 1988, (incorporated herein by reference
to Washington Natural Gas Company Exhibit 10-M.2, Form 10-K for the year
ended September 30, 1994, File No. 1-11271).
10.141 Amended and restated Washington Energy Company and subsidiaries
Annual Incentive Plan for Vice Presidents and above, dated October 1994.
10.142 Interest Rate Swap Agreement dated September 27, 1989 between
Thermal Resources, Inc., and the First National Bank of Chicago, filed under
cover of Form SE dated December 27, 1989, (incorporated herein by reference
to Washington Natural Gas Company Exhibit 10-N, Form 10-K for the year ended
September 30, 1994, File No. 1-11271).
10.143 Firm Transportation Service Agreement dated March 1, 1992
between Northwest Pipeline Corporation and Washington Natural Gas Company,
(incorporated herein by reference to Washington Natural Gas Company Exhibit
10-O, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.144 Firm Transportation Service Agreement dated January 12, 1994 be-
tween Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transportation service from Jackson Prairie, (incorporated herein by
reference to Washington Natural Gas Company Exhibit 10-P, Form 10-K for the
year ended September 30, 1994, File No. 1-11271).
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10.145 Firm Transportation Service Agreement dated January 12, 1994 be-
tween Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transportation service from Jackson Prairie, (incorporated herein by
reference to Washington Natural Gas Company Exhibit 10-Q, Form 10-K for the
year ended September 30, 1994, File No. 1-11271).
10.146 Firm Transportation Service Agreement dated January 12, 1994 be-
tween Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transportation service from Plymouth, LNG, (incorporated herein by
reference to Washington Natural Gas Company Exhibit 10-R, Form 10-K for the
year ended September 30, 1994, File No. 1-11271).
10.147 Service Agreement dated July 9, 1991 with Northwest Pipeline
Corporation for SGS-2F Storage Service filed under cover of Form SE dated
December 23, 1991 (incorporated herein by reference to Washington Natural
Gas Company Exhibit 10-S, Form 10-K for the year ended September 30, 1994,
File No. 1-11271).
10.148 Firm Transportation Agreement dated October 27, 1993 between Pa-
cific Gas Transmission Company and Washington Natural Gas Company for firm
transportation service from Kingsgate, (incorporated herein by reference to
Washington Natural Gas Company Exhibit 10-T, Form 10-K for the year ended
September 30, 1994, File No. 1-11271).
10.149 Firm Storage Service Agreement and Amendment dated April 30,
1991 between Questar Pipeline Company and Washington Natural Gas Company for
firm storage service at Clay Basin filed under cover of Form SE dated
December 23, 1991.
*10.150 Employment agreement with R. R. Sonstelie, Chairman of the
Board, dated January 13, 1998.
*10-151 Change in control agreement with J. P. Torgerson, dated August
17, 1995.
*10-152 Change in control agreement with T. J. Hogan, dated August 17,
1995.
*12-a Statement setting forth computation of ratios of earnings to
fixed charges (1993 through 1997).
*12-b Statement setting forth computation of ratios of earnings to
combined fixed charges and preferred stock dividends (1993 through 1997).
*21 Subsidiaries of the Registrant.
*23.1 Consent of independent accountants.
*23.2 Consent of independent accountants.
*27 Financial Data Schedules.
_________________________________
*Filed herewith.
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