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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
October 23, 1997 February 10, 1997
___________________________________________________
(Date of earliest
event reported)
PUGET SOUND ENERGY, INC
(Exact name of registrant as specified in its charter)
Washington 1-4393 91-0374630
(State or other (Commission (I.R.S. Employer
jurisdiction of File Number) Identification
incorporation) Number)
411 108th Avenue N.E., Bellevue, Washington 98004-5515
(Address of principal executive offices, zip code)
Registrant's telephone number, including area code:
425/454-6363
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ITEM 5. OTHER EVENTS
For information regarding periods subsequent to those periods contained in
this report, please see the Company's quarterly reports on Form 10-Q for the
periods ending March 31, 1997 and June 30, 1997.
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 contained herein reflects fiscal years ended December
31 for Puget Power and September 30 for WECo. (See "Merger With Washington
Energy Company and Washington Natural Gas Company," below.)
At year-end, the Company had approximately 857,300 electric customers,
consisting of 761,000 residential, 90,500 commercial, 4,100 industrial and
1,400 other customers and approximately 492,700 gas customers, consisting of
448,700 residential, 41,000 commercial, 2,900 industrial and 100 other
customers. For the year 1996, the Company added approximately 16,600
electric customers and approximately 22,200 gas customers, representing
annualized growth rates of 2.0% and 4.7%, respectively. During 1996, the
Company's billed revenues from electric utility operations were derived
47% from residential customers, 35% from commercial customers, 14% from
industrial customers and 4% from sales to other utilities and others, and the
Company's billed revenues from gas utility operations were derived 60% from
residential customers, 23% from commercial customers, 11% from industrial
customers and 6% from other customers. During this period, the largest
single electric customer accounted for 3.3% of the Company's electric utility
operating revenues, and the largest single gas customer accounted for .5% of
the Company's gas 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 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 seasonal weather or hydro
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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 now can be significantly influenced,
up or down, by surplus sales and variations in weather and hydro conditions.
Since 1971, the Washington Commission has permitted WNG, and now WNG to
pass on to its customers, through changes in its rates, all changes in the
price of gas purchased from nonaffiliated suppliers through the 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. (See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Rate Matters.")
During the period from January 1, 1992 through December 31, 1996, the
Company made gross electric utility plant additions of $915 million
and retirements of $131 million. In the five year period ended
September 30, 1996, the Company made gross gas utility plant
additions of $424 million and retirements of $44 million. Gross electric
utility plant at December 31, 1996, was approximately $3.5 billion which
consisted of 47% distribution, 27% generation, 15% transmission and 11%
general plant and other. Gross gas utility plant at September 30, 1996,
was approximately $1.1 billion which consisted of 86% distribution, 4%
transmission and 10% general plant and other.
At year-end the Company and its subsidiaries had 3,261 aggregate full-time
equivalent employees, down from 4,350 aggregate employees at the end of 1992.
This represents a workforce reduction of 25% over the last four years.
Industry Evolution
The U.S. electric utility industry is facing an increasingly competitive
environment, particularly in wholesale electric generation and industrial
customer markets. The National Energy Policy Act of 1992 ("EPACT")
intensified competition in the wholesale electric market by easing
restrictions on wholesale power producers and by allowing the Federal Energy
Regulatory Commission ("FERC") to order access for wholesale sellers to
deliver electric power to wholesale buyers over transmission systems owned by
others. In 1996, FERC issued its landmark Orders 888 and 889, which require
jurisdictional utilities, including the Company, to file wholesale
transmission tariffs providing pricing and terms for transmission access for
wholesale purposes.
The EPACT does not permit the FERC to order transmission access for retail
purposes, but Congress now has pending bills that would require existing
electric utilities to allow competitors to use utility property, including
transmission and distribution facilities, to provide electric service to
retail customers of the existing utilities. Several states, including
California, New Hampshire, Pennsylvania and Rhode Island have enacted
legislation to allow competitors to use utility property of
electric utilities. Most other states, including Washington, are
considering, or have adopted, legislative or regulatory proposals which would
also allow competitors to sell to retail customers of the existing utilities.
In its February 5, 1997 order approving the Merger, the Washington Commission
required the Company to conduct a retail access pilot program. Any
substantial change in utility regulation in Washington state, such as
allowing use of utility property by competitors for retail purposes, would
require legislative action. The major credit rating agencies have expressed
the general view that increased competition is likely to increase business
risks in the electric utility industry, with resulting pressures on utility
credit quality and investor returns.
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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 1996, approximately 106 commercial and industrial customers, on average,
chose to use such service. (See "Gas Utility Operations - Natural Gas
Pipeline Deregulation.")
Merger With Washington Energy Company and Washington Natural Gas Company
Puget Sound Power & Light Company, on February 10, 1997, completed its Merger
with WECo and WNG and was renamed Puget Sound Energy
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 increase
in general electric rates of between 1.0% and 2.5%, depending on rate class.
The general rate increase has a positive impact on earnings while the
decrease, reflecting the discontinuation of the PRAM and collection of
accrued revenues, does not affect earnings. The net impact was an average
decrease in electric rates 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 years beginning in 1998,
while those for small commercial electric 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 gas utility margins by 1%.
On January 29, 1997, the Company and BPA signed a Residential Exchange
Termination Agreement. The Agreement ends the Company's participation in
the Residential Purchase and Sale Agreement with BPA. The Residential
Purchase and Sale Agreement enabled the Company's residential and small farm
customers to receive the benefits of lower-cost federal power. As part of
the Termination Agreement, the Company will receive 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. The Company expects the difference will be made up through the general
rate increases approved in the merger order and additional reductions in
operating expenses.
Regulation and Rates
The Company is subject to the regulatory authority of (1) the Washington
Commission as to rates, accounting, the issuance of securities and certain
other matters and (2) the FERC with respect to the transmission of electric
energy, the resale of electric energy at wholesale, and accounting and
certain other matters. The Washington Commission consists of three
Commissioners, each appointed for a six-year term by the Governor of
Washington state. (See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Rate Matters.")
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Electric Utility Operations
Power Resources
At December 31, 1996, the Company's peak electric power resources
were approximately 5,109,200 KW. The Company's historical peak load
of approximately 4,615,000 KW occurred on December 21, 1990.
During 1996, the Company's total electric energy production was supplied 21%
by its own resources, 32% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydroelectric projects
on the Columbia River, 34% from other firm purchases and 13% from non-firm
purchases.
Peak Power Resources
at December 31, 1996 1996 Energy Production
----------------------- ----------------------
Kilowatts % Kilowatt-Hours %
--------- ---- -------------- ----
(Thousands)
Purchased Resources:
Columbia River
PUD Contracts (Hydro) 1,356,000 26.5 8,488,933 32.3
Other Hydro(a) 570,000 11.2 4,303,931 16.4
Thermal(a) 1,399,000 27.4 7,881,061 30.0
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Total Purchased 3,325,000 65.1 20,673,925 78.7
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Company-owned Resources:
Hydro 309,950 6.1 1,346,434 5.1
Coal 771,900 15.1 4,217,543 16.1
Natural gas/oil 702,350 13.7 21,618 0.1
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Total Company-owned 1,784,200 34.9 5,585,595 21.3
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Total 5,109,200 100.0 26,259,520 100.0
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(a) Power received from other utilities is classified between hydro and
thermal based on the character of the utility system used to supply the
power or, if the power is supplied from a particular resource, the character
of that resource.
Company-Owned Resources.
The Company and other utilities are joint owners of four mine-mouth, coal-
fired, steam-electric generating units at Colstrip, Montana, approximately
100 miles east of Billings. The Company owns a 50% interest (330,000 KW) in
Units 1 and 2 and a 25% interest (350,000 KW) in Units 3 and 4. The owners
of the Colstrip Units purchase coal for the units from Western Energy Company
("Western Energy"), an affiliate of Montana Power Company ("Montana Power")
(one of the joint owners), under the terms of long-term coal supply
agreements.
In 1996, under the Colstrip 3 and 4 Coal Supply Agreement, the owners, other
than Montana Power, gave Western Energy written notice of the existence of an
unusual condition and gross inequity concerning the coal price in accordance
with contract provisions. Pursuant to a settlement agreement between the
Company, Montana Power and Western Energy dated February 21, 1997, the coal
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price has been reduced on an interim basis pending a restructuring of the
Colstrip coal supply arrangements. Pursuant to its settlement agreement, the
Company has withdrawn from participation in, and will forego any benefits
from, the negotiations and potential arbitration regarding the notice of an
unusual condition and a gross inequity.
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
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 2001. Legislation is pending in
the Washington State Legislature which would provide certain tax relief to
the owners of the Centralia Plant in order to help defray costs associated
with emissions compliance.
The Company also has the following plants with an aggregate net generating
capability of 1,012,300 KW: Upper Baker River hydro project (103,000 KW)
constructed in 1959; Lower Baker River hydro project (71,400 KW)
reconstructed in 1968; White River hydro plant (63,400 KW) constructed in
1911 with installation of the last unit in 1924; Snoqualmie Falls hydro plant
(44,000 KW), half the capability of which was installed during the period
1898 to 1910 and half in 1957; two smaller hydro plants, Electron (26,400 KW)
and Nooksack Falls (1,750 KW), constructed during the period 1904 to 1929; a
standby internal combustion unit (2,750 KW) installed in 1969; two oil-fired
combustion turbine units (28,500 KW and 67,500 KW) installed in 1972 and
1974, respectively; four dual-fuel combustion turbine units (89,100 KW each)
installed during 1981; and two dual-fuel combustion turbine units (123,600 KW
each) installed during 1984.
The Company's combustion turbines installed in 1981 and 1984 may be fueled
with 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.
The Company has applied to the FERC for an initial license for its existing
and operating White River project which includes authorization to install an
additional 14,000 KW generating unit. The initial license for the 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
and expects a license to be issued in 1997. 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 electrical fire.
Columbia River Projects.
During 1996, approximately 32% of the Company's energy output was obtained at
an average cost of approximately 8.7 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
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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 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, 1996, 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, 1996) 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% (271,320 KW as of
December 31, 1996) 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% (72,320 KW as of
December 31, 1996) of the annual output of the Priest Rapids project and
10.8% (106,380 KW as of December 31, 1996) of the annual output of the
Wanapum project, which percentages remain unchanged for the remainder of the
contracts. See Note 16 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. Negotiations are being
conducted regarding a possible replacement of the Coordination Agreement.
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. In turn, the Company has 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.
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Contracts and Agreements With Other Utilities.
On September 17, 1985, the Company and BPA entered into a settlement
agreement settling the Company's claims against BPA resulting from BPA's
action in halting construction on Washington Public Power Supply System
("WPPSS") Nuclear Project No. 3, in which the Company has a 5% interest.
Under the settlement agreement, the Company is receiving from BPA for
approximately 30.5 years, beginning January 1, 1987, a certain amount of
electric power during the months of November through April. Under the
contract, the Company is guaranteed to receive not less than 191,667 MWH in
each contract year until the Company has received total deliveries of
5,833,333 MWH.
On April 4, 1988, the Company executed a 15-year contract, with provisions
for early termination by the Company, for the purchase of firm energy supply
from Washington Water Power Company. This agreement calls for the delivery
of 100 MW of capacity and 657,000 MWH of energy from the Washington Water
Power system annually (75 annual average MW). Minimum and maximum delivery
rates are prescribed. Under this agreement, the energy is to be priced at
Washington Water Power's average generation and transmission cost, subject to
certain price ceilings.
On October 27, 1988, the Company executed a 15-year contract for the purchase
of firm power and energy from Pacific Power & Light Company. Under the
terms of the agreement, the Company receives 120 average MW of energy and 200
MW of peak capacity.
On November 23, 1988, the Company executed an agreement to purchase surplus
firm power from BPA. Under the agreement, the Company receives 150 average
MW of energy and 300 MW of peak capacity from BPA between October 1 and March
31 of each contract year. The contract extends for 20 years, ending in 2008.
The sale will convert to a power-for-power exchange on June 30, 2001.
On October 1, 1989, the Company signed a contract with Montana Power under
which Montana Power provides, from its share of Colstrip Unit 4, to the
Company 71 average MW of energy (94 MW of peak capacity) over a 21-year
period. On February 27, 1995, the Company delivered to Montana Power notice
of termination of the contract based on Montana Power's failure to arrange
for firm contractual transmission rights for such energy as required by the
contract. On February 21, 1997, the Company and Montana Power settled the
dispute as fully described in the Company's Current Report on Form 8-K
filed with the Securities and Exchange Commission (the "SEC") on February 27,
1997. Pursuant to the settlement, the contract remains in effect and the
price of power purchased by the Company is reduced. On February 21, 1997, the
Company and Montana Power also agreed to settle their coal supply disputes in
return for certain price reductions and restructuring activities in
connection with the Colstrip coal supply arrangements. Montana Power has
estimated that, beginning in 1997, these agreements will result in an annual
reduction in Montana Power's revenues, before anticipated efficiency gains,
of between $11 and $13 million. The Company expects to realize a reduction
in its power supply costs of approximately the same amount. In addition, the
Company expects reductions in coal taxes and royalties and anticipates
efficiency gains through restructuring.
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
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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. By giving proper notice, either party may
terminate the contract for various reasons.
Contracts and Agreements With Non-Utilities.
As required by the Public Utility Regulatory Policies Act of 1978, P.L. 95-
617 ("PURPA"), the Company has contracted to purchase the net electrical
output from a number of non-utility generators, of which the most significant
are described below. Payments by the Company to owners of these non-utility
generating resources are subject to the delivery of power. See Note 16 to
the Company's Consolidated Financial Statements. A number of these
agreements have escalation provisions providing for periodic increases in the
cost of power, and most of these agreements provide for power purchases at
prices that are now above market prices. These excess contract prices could
become stranded costs in a deregulated electric industry environment.
On February 21, 1985, the Company executed a 50-year contract to purchase 6
average MW of energy and 14 MW of capacity, beginning in December 1990, from
Koma Kulshan Associates, which owns and operates a small hydroelectric
project located near the Company's Upper Baker Dam.
On January 4, 1988, the Company executed a 21-year contract to purchase 15
average MW of energy and 23 MW of capacity, beginning November 1991, from the
City of Spokane, which owns and operates a regional solid waste incineration
project located near Spokane, Washington.
On June 29, 1989, the Company executed a 20-year contract to purchase 70
average MW of energy and 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. In November 1995, March 1996 and November 1996, the
Company delivered notices of breach of contract to March Point based on,
among other things, March Point's failure to maintain generation at agreed-
upon limits, failure to displace generation pursuant to the parties' power
purchase agreements, and failure to provide information essential to the
parties' agreed-upon displacement arrangements. On November 29, 1995, March
Point commenced litigation against the Company in federal court for the
Western District of Washington. March Point requested a declaration of
certain obligations of March Point and the Company under the contracts,
injunctive relief preventing the Company from terminating its contracts with
March Point and damages based on breach of contract. The Company has
answered and filed a counterclaim contending that March Point has breached
the contracts. The Company seeks declaratory relief regarding the parties'
obligations and rights under the contracts, damages based on the breach and
rescission.
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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. In June 1995, the Company
delivered notice of breach of contract to Encogen based on, among other
things, Encogen's failure to provide information essential to the parties'
agreed-upon displacement arrangements. On September 20, 1995, Encogen
commenced litigation against the Company in Whatcom County Superior Court
requesting a declaration of certain obligations of Encogen under the contract
and seeking further relief. The Company has answered and filed a
counterclaim, contending that Encogen has breached the contract and seeking
declaratory relief regarding Encogen's duty to provide certain information.
On March 20, 1991, the Company executed a 20-year contract to purchase 216
average MW of energy and 245 MW of capacity, beginning in April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas
fired cogeneration project located near Ferndale, Washington.
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 O&M 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 its remaining $35.2 million of such
conservation investments in a similarly structured transaction. (See Note 1
to the Company's Consolidated Financial Statements)
Electric Rates and Regulation
In the Washington Commission's September 21, 1993, general rate case order,
the Company was allowed a 10.5% return on common equity and 8.94% return on
rate base, based on a capital structure of 47% debt, 8% preferred stock and
45% common equity.
On September 22, 1995, the Washington Commission issued a rate order
relating to the Companys 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.
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With the discontinuance of the PRAM, the annual regulatory adjustments for
variations in weather and hydro conditions provided for in the PRAM were
also discontinued.
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.
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<TABLE>
Energy Delivery Operating Statistics
Electric Operations:
<CAPTION>
Year Ended on December 31 1996 1995 1994 1993 1992
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues by classes:
(thousands)
Residential $ 554,318 $ 524,749 $ 532,124 $ 502,037 $ 443,490
Commercial 423,139 397,212 375,751 356,586 323,764
Industrial 170,596 168,501 163,574 150,063 138,416
Other consumers 44,125 38,730 38,759 28,189 35,779
- -------------------------------------------------------------------------------------------
Operating revenues
billed to consumers (a) 1,192,178 1,129,192 1,110,208 1,036,875 941,449
Unbilled revenues -
net increase (decrease) 13,201 (6,382) (2,522) 14,409 15,080
PRAM accrual (74,326) 3,953 25,835 42,100 42,119
- -------------------------------------------------------------------------------------------
Total operating revenues
from consumers 1,131,053 1,126,763 1,133,521 1,093,384 998,648
Other utilities 67,716 52,567 60,537 19,494 26,322
- -------------------------------------------------------------------------------------------
Total operating revenues $1,198,769 $1,179,330 $1,194,058 $1,112,878 $1,024,970
- -------------------------------------------------------------------------------------------
Number of customers (average):
Residential 754,097 739,173 723,566 708,123 692,100
Commercial 89,613 87,404 85,203 82,875 80,963
Industrial 3,993 3,908 3,851 3,715 3,659
Other 1,371 1,346 1,325 1,289 1,254
- -------------------------------------------------------------------------------------------
Total customers (average) 849,074 831,831 813,945 796,002 777,976
- -------------------------------------------------------------------------------------------
KWH generated, purchased
and interchanged (thousands):
Total Company generated 5,585,595 6,371,416 7,011,932 6,414,311 7,420,058
Purchased power 20,573,983 17,897,922 16,268,042 14,608,899 13,408,522
Interchanged power (net) 99,942 48,485 (87,771) 174,478 (118,346)
- -------------------------------------------------------------------------------------------
Total energy output 26,259,520 24,317,823 23,192,203 21,197,688 20,710,234
Losses and company use (1,322,262) (1,235,457) (1,291,322) (1,096,599) (1,202,194)
- -------------------------------------------------------------------------------------------
Total energy sales 24,937,258 23,082,366 21,900,881 20,101,089 19,508,040
- -------------------------------------------------------------------------------------------
(a) Operating revenues in 1996 and 1995 were reduced by $41.0 million and
$25.1 million, respectfully, as a result of the Company's sale of $202.5
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.)
12
</TABLE>
<TABLE>
Electric Operations (continued from previous page):
<CAPTION>
Year Ended on December 31 1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Electric energy sales, KWH:
(thousands)
Residential 9,350,292 8,972,498 8,913,903 8,974,787 8,297,293
Commercial 6,807,465 6,538,533 6,301,568 6,175,911 5,945,284
Industrial 3,793,966 3,720,641 3,724,931 3,690,473 3,704,450
Other consumers 205,066 205,232 200,622 196,246 193,563
- --------------------------------------------------------------------------------------------
Total energy billed
to consumers 20,156,789 19,436,904 19,141,024 19,037,417 18,140,590
Unbilled energy sales -
net increase (decrease) 224,412 (158,920) (72,352) 139,329 209,565
- --------------------------------------------------------------------------------------------
Total energy sales
to consumers 20,381,201 19,277,984 19,068,672 19,176,746 18,350,155
Sales to other
electric utilities 4,556,057 3,804,382 2,832,209 924,343 1,157,885
- --------------------------------------------------------------------------------------------
Total energy sales 24,937,258 23,082,366 21,900,881 20,101,089 19,508,040
- --------------------------------------------------------------------------------------------
Per residential customer:
Annual use (KWH) 12,399 12,139 12,319 12,674 11,989
Annual billed revenue $762.35 $726.95 $735.42 $708.97 $640.79
Billed revenue per KWH $.0615 $.0599 $.0597 $.0559 $.0534
Company-owned generation
capability - kilowatts:
Hydro 309,950 309,950 309,950 309,950 309,950
Steam 771,900 771,900 771,900 857,700 857,700
Natural gas/oil 702,350 702,350 702,350 702,350 702,350
- --------------------------------------------------------------------------------------------
Total 1,784,200 1,784,200 1,784,200 1,870,000 1,870,000
- --------------------------------------------------------------------------------------------
Heating degree days 4,953 3,994 4,341 4,691 4,090
% of normal of 30 year
average (4,908) 100.9% 81.4% 88.4% 95.6% 83.3%
Load factor 55.5% 56.7% 54.7% 52.5% 57.0%
</TABLE>
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.
Prior to implementation of FERC Order No. 636 in 1993, WNG purchased a
portion of its firm gas supply from the Northwest Pipeline Corporation
("NPC") under a firm sales agreement. All of the Company's gas supply is
ultimately transported through NPC, the sole interstate pipeline directly
supplying the western Washington area.
For baseload and peak-shaving purposes, the Company supplements its portfolio
of firm gas supply 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
Washington and at Clay Basin in Utah are used for this purpose. Peaking
13
<PAGE>
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 two plants owned by the Company and located on its distribution
system.
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.
Natural Gas Pipeline Deregulation
The implementation of FERC Order No. 636 by NPC in November 1993 completed
the deregulation of its activities as an interstate natural gas pipeline and
unbundled sales services formerly performed by NPC. The complete unbundling
of NPC's services at that date finalized the Company's transition from
purchasing all of its gas supply from NPC prior to 1986 to purchasing all
such gas supplies directly from producers and gas marketers. As part of the
transition, the Company was assigned certain long-term firm gas supply
agreements of NPC effective November 1, 1992 and November 1, 1993. In order
to deliver purchased gas supplies to its distribution system and to provide
transportation service for customer-owned gas, the Company assumed long-
term, firm transportation capacity on the transmission systems of NPC and
Pacific Gas Transmission Company ("PGT"), together with associated demand
charge obligations. The Company also acquired storage capacity with
associated demand charge obligations at Clay Basin in two increments
effective April 1991 and April 1993.
Gas Supply Portfolio
For the 1996-97 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 and firm gas exchange arrangements. 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 22% 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 gas, each of which represents approximately 30%, 9% and 3%,
respectively, of the expected peak requirements.
The current firm, long-term gas supply portfolio consists of arrangements
with 11 producers and gas marketers, with no single supplier representing
more than 10% of the expected peak day requirement. The contracts have
remaining terms that range from less than one year to seven years, with
an average term of three years. All but one of the supply contracts
originally assigned to the Company by NPC have expired. The one remaining
contract, with an Alberta supplier, has a remaining term of seven years.
All of the current gas supply contracts contain market-sensitive pricing
provisions based on various published indices.
The Company's firm gas supply portfolio is structured to take advantage of
regional price differentials and to market gas and services outside the
Company's service territory ("off-system sales") when market opportunities
arise and customer demand requirements permit. The geographic mix of
suppliers and daily, monthly and annual take requirements permit a high
degree of flexibility in sourcing gas supplies in off-peak periods to
14
<PAGE>
minimize costs. During the 12 months ended June 30, September 30, 1996, the
Company's off-system sales totaled approximately 27 billion cubic feet
("BCF") of gas and generated $8.1 million of gross margin ("gross
margin" being gas revenue less cost of gas sold). By way of comparison, the
Company's on-system volumes during the same period totaled approximately
73 BCF. The Company also conducts exchanges of
gas with other suppliers or marketers on different pipelines, which exchanges
generated $1.4 million of gross margin during the 12 months ended September
30, 1996. The savings or gross margin from these off-
system activities does not affect the Company's earnings, but is currently
passed on to the Company's customers through the purchased gas adjustment
("PGA") mechanism approved by the Washington Commission.
Gas Transportation Capacity
The Company currently holds firm transportation capacity on pipelines owned
by NPC and PGT. Accordingly, the Company pays fixed monthly demand charges
for the right, but not the obligation, to transport a specified quantity of
gas from a receipt point to a delivery point 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 million
British thermal units ("MMBtu") per day, acquired under seven agreements at
various times. The Company has exchanged certain segments of its firm
capacity with several parties to effectively lower transportation costs. In
the aggregate, the Company's capacity provides for receipt of 204,761 MMBtu
per day at Sumas on the Washington border with British Columbia, 173,836
MMBtu per day at various points in Wyoming, Colorado, and Utah and 75,936
MMBtu per day at several interconnections with PGT. The Company also holds
seasonal firm capacity from NPC for receipt of 236,298 MMBtu per day at the
Jackson Prairie storage field and 70,500 MMBtu per day at the Plymouth LNG
facility. The latter capacity is available to deliver storage gas to the
Company's distribution system during the heating season. The Company's firm
transportation capacity contracts with NPC have remaining terms ranging from
8 to 19 years. However, the Company has either the unilateral right to
extend the contracts under their current terms or the right of first refusal
to extend such contracts under then current FERC orders.
The Company holds firm transportation capacity on PGT's pipeline totaling
90,392 MMBtu per day from Kingsgate on the Idaho border with British Columbia
to various interconnections with NPC. Gas originating in Alberta is
transported to NPC utilizing this capacity for subsequent delivery by NPC to
the Company's distribution system. The contract for this capacity has a
remaining term of 27 years.
Gas Storage Capacity
The Company holds storage capacity in the Jackson Prairie and Clay Basin
underground gas storage facilities. The Jackson Prairie facility, one-third
owned and operated by the Company, is used primarily for intermediate peaking
purposes as it is designed to deliver a large volume of gas over a relatively
short time period. The Company has peak, firm delivery capacity of 236,298
MMBtu per day and total firm storage capacity of 6,341,660 MMBtu at the
facility. The location of the Jackson Prairie facility in the Company's
service area provides significant cost savings by reducing the amount of
annual pipeline capacity required to meet peak day gas requirements. The
Clay Basin storage facility is intended as a baseload gas supply source as
well as a peaking supply source. The Company has a maximum firm withdrawal
capacity of 111,300 MMBtu per day from the facility with total storage
capacity of 13,419,000 MMBtu. The capacity is held under two contracts with
remaining terms of 17 and 24 years.
15
<PAGE>
LNG and Propane Air
LNG and propane air gas provide gas supply on short notice for short periods
of time. Due to their high cost, these sources are utilized as the supply of
last resort in extreme peak demand periods lasting a few hours or days. The
Company has long-term contracts for storage of 241,700 MMBtu 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 MMBtu. The
Company owns storage capacity for approximately 1.4 million gallons of
propane. The facilities are capable of delivering the equivalent of 30,000
MMBtu of gas per day for up to four days directly into the Company's
distribution system.
Capacity Release
One of the most significant changes resulting from the deregulation of the
natural gas industry is the advent of capacity release to counter the impact
on pipeline customers of the straight fixed variable rate design used by
interstate pipelines. Under this rate design, essentially all pipeline costs
are recovered from customers through fixed monthly demand charges, rather
than volumetrically as in the past. The FERC provided the capacity release
mechanism as the means for holders of firm capacity to relinquish temporarily
unutilized pipeline 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 prearrangement. All capacity available for
release is posted on the electronic bulletin boards of the pipelines. During
the 12 months ended September 30, 1996, the Company utilized
buy/sell and capacity release mechanisms to recoup $1.3 million out of
approximately $28.3 million of demand charges for which the capacity was
not utilized in off-peak periods. WNG CAP I and WNG CAP II, wholly owned
subsidiaries of the Company, were formed to provide additional flexibility
and benefits from capacity release. All savings from capacity release are
currently passed on to the Company's customers through the PGA mechanism. In
addition, off-system sales activities have often bundled the gas commodity or
other commodity services with transportation, which has increased capacity
utilization. In approving the Company's last PGA, effective May 15, 1995,
the Washington Commission allowed all previously incurred and projected
capacity related demand charges to be recovered in rates.
Reallocation of NPC Transition Costs
In May 1994, NPC was ordered by the FERC to modify the previous allocation of
transition costs, totaling $34 million plus interest, incurred in
"unbundling" interstate pipeline services. Under this order, the
Company's share of these costs increased from $1.2 million, which amount
had been previously paid, to $10.4 million, inclusive of interest. The
Company and six other customers filed requests for rehearing. In December
1994, the FERC issued an order denying the rehearing requests and permitting
NPC to bill customers under the modified allocation methodology. Pending the
outcome of an appeal to the United States Court of Appeals, the Company
paid a total of $9.8 million, inclusive of interest, in monthly installments
in 1995 and 1996, representing its share of the reallocated costs. The court
appeal is still pending. The Washington Commission has allowed the
Company to recover the full amount of the increased transition costs as part
of the PGA that went into effect on May 15, 1995.
16
<PAGE>
Gas Rates and Regulation
Since 1971, the Washington Commission has permitted WNG to
pass on to its customers, through changes in its rates, all changes in the
price of gas purchased from nonaffiliated suppliers through the 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. Since a 1991 order disallowing a portion of the cost of gas
purchased from an affiliate, the Washington Commission has authorized
three PGAs with no disallowance of purchased gas costs. Two of the
adjustments, one in 1992 and one in 1993, substantially increased rates and
were allowed on a timely basis. The most recent 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.
March 1995 Rate Case.
In March 1995, WNG filed a general rate case, (the "March 1995 Rate Case")
Docket No. UG-950278, seeking to raise general gas service tariff rates by
8.5%, or $35.4 million, on an annual basis. The filing was requested in
order to reflect the higher costs of capital and increased operating costs as
a result of customer growth. As part of the filing, WNG petitioned that
$17.8 million of the $35.4 million request be granted as interim rate relief.
On May 11, 1995, WNG and the Washington Commission reached a negotiated
settlement of the March 1995 Rate Case. The settlement provided a
$17.7 million annual increase in revenue and margin. The increase reflected
an allowed rate-of-return on common equity in the range of 11% - 11.25%, up
from the previous level of 10.5%. The settlement accepted by the Washington
Commission also stipulated that WNG be allowed to earn in excess of that
range to the extent that it can do so by managing its cost of service. The
new rates became effective May 15, 1995. As part of the settlement, WNG
agreed not to make a general rate case filing prior to May 15, 1997. The
agreement, however, did not preclude filing under the PGA mechanism or for
interim emergency rate relief if conditions warrant.
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 choices 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.
Line Extension and New Customer Addition Policy.
In March 1995, the Washington Commission approved a new tariff for extending
natural gas mains and services to new gas customers. Under the new policy,
main and service extensions that meet or exceed the target rate-of-return,
currently 9.15%, based on an analysis of estimated costs and gas usage, are
provided without requiring economic support from customers. This new policy
17
<PAGE>
helps ensure that new gas customer growth is profitable. If a new main or
service extension is estimated to have a rate-of-return between 6.86% and
9.15%, the customer is required to either make a one-time contribution or pay
a new customer rate, at the customer's choice. A contribution is an advance
payment to cover a portion of the costs of construction. This advance
payment may be refundable over a five-year period based on additional new
customer load which has been added to the new main or service extension since
it was initially installed. The other choice is payment of a nonrefundable
new customer rate for five years. The new customer rate is essentially a
surcharge of 11.5 cents per therm for new residential developments, or 17
cents per therm for single-family residential or small commercial
conversions. If the main extension is estimated to have a rate-of-return of
less than 6.86%, the customer must make a nonrefundable contribution in aid
of construction in addition to either the refundable advance payment or the
new customer rate discussed above.
The Company is also engaged in the business of leasing gas water heaters and
conversion burners for residential and commercial use. As of
September 30, 1996, the Company had approximately 114,000
equipment leases with customers with original costs and net book value of
approximately $71 million and $61 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. Lease revenues for the 12 months ended September 30,
1996 and for the 12 months ended September 30, 1995 were $10,027,000, and
$9,274,000, respectively.
The number of equipment leases has been declining over the last several years
because more customers choose to own rather than lease their gas equipment.
However, lease revenues have increased due to rate increases of approximately
$1 per month per lease for most residential customers in each of the last
three years. 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.
18
<PAGE>
<TABLE>
Gas Operations:
<CAPTION>
Twelve Months Ended September 30 1996 1995 1994 1993 1992
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues by classes:
(thousands): Regulated utility sales:
Residential firm gas sales $ 238,560 $ 231,202 $ 206,602 $ 195,936 $ 152,015
Commercial firm gas sales 94,251 97,396 91,749 87,644 67,393
Industrial firm gas sales 20,024 25,860 28,827 23,967 17,226
Interruptible gas sales 23,376 44,511 51,425 44,160 29,593
Transportation services 12,812 10,762 8,399 8,434 11,231
Other 11,085 10,317 9,405 7,712 7,481
- -------------------------------------------------------------------------------------------
Total regulated
utility sales $ 400,108 $ 420,048 $ 396,407 $ 367,853 $ 284,939
===========================================================================================
Customers, average number
served:
Residential firm 440,586 423,195 403,642 383,291 361,454
Commercial firm 39,651 38,378 37,112 35,951 34,503
Industrial firm 2,762 2,754 2,824 2,844 2,857
Interruptible 1,000 1,037 1,009 988 948
Transportation 106 55 36 68 130
- -------------------------------------------------------------------------------------------
Total average customers 484,105 465,419 444,623 423,142 399,892
===========================================================================================
Gas volumes
(thousands of therms):
Residential firm sales 421,727 398,283 371,472 382,118 301,887
Commercial firm sales 188,321 179,725 174,668 177,724 142,402
Industrial firm sales 46,640 55,365 62,698 54,096 52,019
Interruptible sales 72,229 132,316 151,175 127,678 78,645
Transportation volumes 242,299 156,941 119,590 159,765 199,143
- -------------------------------------------------------------------------------------------
Total gas volumes 971,216 922,630 879,603 901,381 774,096
===========================================================================================
Working gas volumes in
storage at year end
(thousands of therms)
Jackson Prairie 65,834 65,834 65,834 65,834 65,834
Clay Basin 82,847 130,970 47,557 70,006 43,246
Average use per customer:
(therms)
Residential firm 957 941 921 998 835
Commercial firm 4,749 4,683 4,708 4,903 4,127
Industrial firm 16,886 20,103 22,035 24,618 18,208
Interruptible 72,229 127,595 147,315 129,231 82,959
Transportation 2,285,840 2,853,473 3,400,694 2,133,676 1,531,869
Average revenue per customer:
Residential firm $ 541 $ 546 $ 512 $ 511 $ 421
Commercial firm 2,377 2,538 2,472 2,438 1,953
Industrial firm 7,250 9,390 10,208 8,427 6,029
Interruptible 23,376 42,923 50,966 44,695 31,216
Transportation 120,868 195,673 233,306 124,029 86,392
19
</TABLE>
<TABLE>
Gas Operations: (continued)
<CAPTION>
Twelve Months Ended September 30 1996 1995 1994 1993 1992
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Average revenue per therm
(cents):
Residential firm 56.6 58.0 55.6 51.3 50.4
Commercial firm 50.0 54.2 52.5 49.3 47.3
Industrial firm 42.9 46.7 46.0 44.3 33.1
Interruptible 32.4 33.6 34.0 34.6 37.6
Total sales customers 51.6 52.1 49.8 47.4 46.3
Transportation 5.3 6.9 7.0 5.3 5.6
Average cost per therm of
gas sold (cents) (1): 24.4 28.6 29.5 24.0 22.7
Weather - degree days 4,953 3,994 4,341 4,691 4,090
% of normal (30-yr avg) 100.9% 81.4% 88.4% 95.6% 83.3%
</TABLE>
(1) Average Cost Per Therm includes both fixed and variable elements, and it
is not common gas industry practice to allocate these among classes of
customers. Washington Natural does not sell or transport gas to any of its
customers at a loss or on a break-even basis.
Oil and Gas Exploration and Production
The Company has participated in the oil and gas exploration and production
business since 1974. In May 1994, the Company's subsidiary engaged in
such business was merged in a tax-free exchange with a wholly owned
subsidiary of Cabot Oil & Gas Corporation ("Cabot"), based in Houston, Texas.
Through such merger the Company owns 16.4% of Cabot's outstanding voting
securities, consisting of 2,133,000 shares of common stock representing 9.4%
of total common shares outstanding, and 1,134,000 shares of convertible
voting preferred stock. The Company is accounting for its investment in
Cabot's common stock using the equity method, whereby the Company is
recording its proportionate share of Cabot's earnings and losses available to
common shareholders as "Other Income (Expense)." Detailed information
regarding Cabot is available in Cabot's filings with the SEC.
Construction Financing
The Company estimates its combined electric and gas construction
expenditures, excluding Allowance for Funds Used During Construction
("AFUDC"), for 1997 through 1999 will be approximately $247 million, $252
million and $226 million, respectively. The Company expects cash from
operations (net of dividends and AFUDC) during the period 1997 through 1999
will, on average, be approximately 73% 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, 1996, the Company
could issue (i) approximately $1.118 billion of additional first
mortgage bonds or (ii) approximately $645 million of additional preferred
stock at an assumed dividend rate of 6.80% or (iii) a combination
thereof.
20
<PAGE>
Environment
The Company's operations are subject to environmental regulation by federal,
state and local authorities. Capital expenditures for environmental controls
for Company facilities are estimated at $2.3 million for 1997. Due to the
inherent uncertainties surrounding the development of federal and state
environmental and energy laws and regulations, the Company cannot determine
the impact such laws may have on its existing and future facilities.
Federal Comprehensive Environmental Response, Compensation, and Liability Act
and the Washington State Model Toxics Control Act
(See Note 16 to the Consolidated Financial Statements for a discussion of
these 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
limits of the CAAA in Phase I (1995). The Company and other owners of the
Centralia Project, including Pacific Power & Light Company, which operates
the Centralia Project, are reviewing emission compliance options which will
need to be adopted to meet the Phase II limits in the year 2000.
Montana Power, which operates the Colstrip 3 and 4 Project, is working to
meet the Phase II limits in the year 2000. Under the CAAA, allowances may be
used to achieve compliance. It is believed that Units 1 and 2 may have an
excess of allowances above what is currently set for Phase II requirements
and that Units 3 and 4 have sufficient allowances for Phase II
requirements.The Company owns combustion turbine units, 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. 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.
21
<PAGE>
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.Other
species are also proposed for listing as endangered species and could further
restrict regional hydro system flexibility and energy production.
22
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Financial Condition and Results Of Operations
Financial Condition and Results of Operations reflect combined results for
the fiscal years ended December 31 for Puget Power and September 30 for
WECo.
Net income in 1996 was $165.5 million on operating revenues of $1.649
billion, compared to $101.8 million on operating revenues of $1.631 billion
in 1995 and $78.4 million on operating revenues of $1.632 billion in 1994.
Income for common stock was $143.3 million in 1996, compared to $79.1
million in 1995 and $58.0 million in 1994. Income for common stock for all
periods presented includes losses from discontinued operations consisting of
carrying and development costs for undeveloped coal reserves and a related
railroad. The 1994 loss from discontinued operations also includes a loss
on disposition of a biowaste business.
Earnings per share in 1996 were $1.70 on 84.4 million weighted average
common shares outstanding including a $.02 loss per share from discontinued
operations compared to $.94 on 84.2 million weighted average common shares
outstanding in 1995 including a $.32 loss per share from discontinued
operations and $.69 on 83.8 million weighted average common shares
outstanding in 1994 including a $.01 loss per share from discontinued
operations.
In 1996, WECo decided to seek a buyer for its undeveloped coal properties
and to cease development efforts on the associated railroad. Accordingly,
WECo's financial statements reflect these businesses as discontinued
operations. The 1996 loss from discontinued operations includes an after-
tax charge of $.4 million to establish a 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.
Results for 1995 also include special charges of $22.7 million which
resulted from: 1) adoption of SFAS No. 121 by Cabot and WECo 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); 2) increased losses projected in the future from certain
gas transportation and storage arrangements excluded from the merger of
WECo'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).
Results for 1994 include special charges of $55.3 million which resulted
from: 1) the merger of WECo's oil and gas exploration and production
subsidiary with Cabot and reserves established for certain gas
transportation and storage arrangements excluded from the merger ($30.0
million after tax); 2) restructuring and down sizing utility operations
($18.2 million after tax); and 3) other write-offs and reserves established
in connection with gas operations ($7.1 million after tax).
Total kilowatt-hour sales to ultimate consumers in 1996 were 20.4 billion,
compared with 19.3 billion in 1995 and 19.1 billion in 1994. Kilowatt-hour
sales to other utilities were 4.6 billion in 1996, 3.8 billion in 1995 and
2.8 billion in 1994.
23
<PAGE>
Regulated gas utility sales in 1996 decreased by $19.9 million, or 5%, from
1995 on a 5% decrease in gas volumes sold. Total gas volumes, including
transported gas, increased 5% in 1996. Regulated gas sales increased $23.6
million or 6% in 1995 compared to 1994, primarily as a 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.
The preferred stock dividend accrual decreased $0.5 million in 1996 compared
to 1995 due to lower dividend rates on the Adjustable Rate Cumulative
Preferred Stock (OARPSO), Series B ($100 par value). The preferred stock
dividend accrual increased $2.3 million in 1995 compared to 1994 due
primarily to the issuance of the 8.50%, Series III Preferred ($25 par value)
in September 1994. The preferred stock dividend accrual increased $1.2
million in 1994 compared to 1993 due primarily to the issuance of the 7.45%
Series II Preferred ($25 par value) in November 1993. The increase from
this issue was partially offset by a combination of the redemptions of the
$50 million Flexible Dutch Auction Rate Transferable Securities $100 Par
Value Preferred Stock ("FLEX DARTS"), Series B in July 1993 and the $40
million ARPS, Series A in February 1994 and the issuance in February 1994 of
the $50 million ARPS, Series B ($25 par value).
24
<PAGE>
Increase (Decrease) Over Preceding Year
Years Ended December 31
(Dollars in Millions)
1996 1995 1994
- ---------------------------------------------------------------------
Operating revenues
General rate increase $ -- $ -- $ 27.0
PRAM revenues (37.1) 31.6 13.3
BPA Residential Purchase and
Sale Agreement (15.8) (25.3) 2.3
Sales to other utilities 15.1 (8.0) 41.0
Revenue sold to conservation trust (15.9) (25.1) --
Load and other changes 91.8 1.8 (66.6)
Gas revenue change (19.9) 23.6 28.6
- ---------------------------------------------------------------------
Total operating revenue changes 18.2 (1.4) 45.6
- ---------------------------------------------------------------------
Operating expenses
Purchased electricity 18.6 14.8 77.1
Purchased gas (41.3) (4.5) 42.6
Utility operations and maintenance (2.6) (73.3) (13.0)
Other operations and maintenance 3.9 0.7 1.8
Depreciation and amortization 3.7 (6.0) (7.2)
Taxes other than federal income taxes 5.5 4.6 6.4
Federal income taxes 16.2 16.7 (18.5)
- ---------------------------------------------------------------------
Total operating expense changes 4.0 (47.0) 89.2
- ---------------------------------------------------------------------
Other income 16.4 7.7 (35.7)
Interest charges (8.3) 4.2 4.4
Discontinued operations 24.8 (25.7) 11.5
- ---------------------------------------------------------------------
Net income changes $ 63.7 $ 23.4 $(72.2)
=====================================================================
The following information pertains to the changes outlined in the table
above:
Operating Revenues - Electric
Electric revenues since October 1, 1995, increased as a result of rates
authorized by the Washington Utilities and Transportation Commission (the
"Washington Commission") under the fifth Periodic Rate Adjustment Mechanism
("PRAM") filing. Revenues since October 1, 1994, increased as a result of
rates authorized by the Washington Commission under the fourth PRAM filing.
Revenues since October 1, 1993, increased as a result of rates authorized by
the Washington Commission in its general rate order issued on September 21,
1993. The PRAM was terminated effective September 30, 1996. (See "Rate
Matters.")
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
25
<PAGE>
of approximately $237 million over five years. (See "Other" for a discussion
of the Residential Exchange Termination Agreement.)
Electric revenues in 1996 and 1995 have been reduced by $41.0 million and
$25.1 million as a result of the Company's sale of revenues associated with
$202.5 million of its investment in conservation assets to a grantor trust.
The revenue decrease represents the portion of rate revenues that were sold
and forwarded to the trust. The impact of this revenue decrease, however,
was offset by related reductions in other operation and interest expenses.
(See "Other" for a discussion of the sale of conservation assets.)
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 intends to increase its wholesale surplus power
business through short and intermediate term purchase, sale, arbitrage and
other trading and marketing techniques.
Operating Revenues - Gas
Regulated gas utility sales 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 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.
26
<PAGE>
The Company's merchandise sales revenues increased $2.0 million, or 8%, in
1996 compared to a $12 million, or 34%, decline in 1995. The 1996 revenue
increase was due primarily to certain actions taken late in 1995, such as
the major fall marketing campaign, an extensive sales training program and
restructuring of the sales force. Merchandise revenues have been
negatively impacted by the absence of joint marketing, installation and
service activities with the Company since the bulk of the business,
consisting of gas appliance sales, was transferred from the Company to
Washington Energy Services on October 1, 1993.
Operating Expenses
Purchased electricity expenses increased $18.6 million in 1996 when compared
to 1995. Higher payments for firm power purchases from non-utility
generators and increased secondary power purchases from other utilities
contributed an increase of $34.5 million. This increase was partially
offset by increased credits associated with the Residential Purchase and
Sale Agreement with BPA of $15.2 million. (See discussion of the
Residential Purchase and Sale Agreement under "Operating revenues.")
Purchased electricity expenses increased $14.8 million in 1995 when compared
to 1994. Higher payments for firm power purchases from non-utility
generators and increased secondary power purchases from other utilities
contributed an increase of $35.4 million. This increase was partially
offset by increased credits associated with the Residential Purchase and
Sale Agreement with BPA of $24.1 million.
Purchased electricity expenses increased $77.1 million in 1994 when compared
to 1993. Higher payments related to new firm power purchase contracts from
non-utility generators contributed an increase of $89.3 million. Also
contributing to the increase was a reduction in credits associated with the
Residential Purchase and Sale Agreements with BPA of $2.2 million.
Partially offsetting these increases were lower secondary power purchases
from other utilities of $15.6 million.
Purchased gas expenses decreased $41.3 million in 1996 when compared to
1995. The decrease resulted from 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.
The decrease was due to the PGA implemented in May 1995. Purchased gas
expenses increased $42.6 million in 1994 when compared to 1993 due to higher
gas prices during 1994.
Operations and maintenance expenses increased $1.3 million in 1996 compared
to 1995. Contributing to the increase was a $5 million increase in fuel
expense and a $7.8 million increase in transmission and distribution
expenses, caused in part by a severe wind storm in November 1996. These
increases were partially offset by 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 $72.6 million in 1995 compared
to 1994. The reduction was the result of several factors. $24.8 million of
the decrease was 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.
Also contributing to the decrease was 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. $11.5
27
<PAGE>
million of the decrease related to lower fuel expense 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, an
Arbitration Panel's decision of a dispute involving the coal supply
agreement at the Company's fifty percent-owned Colstrip 1 and 2 plants
resulted in a $4.6 million decrease to fuel expense in the first quarter of
1995 pertaining to coal deliveries from August, 1 1991, through March 31,
1995.
Operations and maintenance expenses decreased $11.2 million in 1994 compared
to 1993. Reduced merchandise sales expenses and the deconsolidation of a
subsidiary in the merger with Cabot contributed decreases of $26.6 million
and $23.9 million, respectively. These decreases were partially offset by
increased transmission and distribution expenses, charges related to
voluntary retirement and separation programs and related facility
consolidation expenses.
Depreciation and amortization expense increased $3.7 million in 1996 from
1995 levels due primarily to capital spending to take on more customers,
reinforce the gas distribution system, and add electric plant.
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.
Depreciation and amortization expense decreased $7.2 million in 1994
compared to the prior year. Decreased expenses in 1994 as a result of the
sale of Washington Energy Resources Company to Cabot was partially offset by
increased depreciation expense related to additional plant placed into
service.
Taxes other than federal income taxes increased $5.5 million in 1996
compared to 1995. The increase was primarily due to higher Washington state
property tax payments of $2.1 million and higher revenue-based municipal
and state excise tax payments of $2.1 million.
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. Taxes other than federal taxes increased
$6.4 million in 1994 compared to the prior year. The increase was due
primarily to higher municipal and state excise taxes, which are revenue-
based, and higher Washington and Montana state property tax payments.
Federal income taxes on operations 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. Federal income taxes on operations decreased
$18.5 million over the prior year due primarily to lower pre-tax operating
income during 1994.
28
<PAGE>
Other Income
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.
Other income increased $7.7 million in 1995. The increase is primarily due
to an $8.7 million deferred tax benefit of write downs in 1995, and lower
special charges in 1995 as compared to 1994. Included in other income in
1995 were pretax charges related to Cabot of $24.8 million, while charges in
1994 included a pretax loss and related federal income taxes on the merger
of Cabot of $30.0 million. These increases were partially offset by lower
energy conservation expenditures resulting in a $2.2 million decline in
Allowance for Funds Used to Conserve Energy ("AFUCE") and a $1.4 million
decrease in excess AFUDC over the Federal Energy Regulatory Commission
("FERC") maximum allowed by the Washington Commission.
Other income decreased $35.7 million in 1994. The decrease is primarily due
to Federal income taxes on the merger of Cabot of $23.7 million and a pre-
tax loss on the merger of $6.3 million.
Interest Charges
Interest Charges, which consists of interest and amortization on long-term
debt and other interest, 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.
Interest Charges increased $4.4 million in 1994. Interest and amortization
on long-term debt increased $0.7 million. Other interest expense increased
$3.7 million in 1994 over the prior year. The increase was primarily due to
higher weighted-average interest rates and higher average daily short-term
borrowings in 1994 as compared to 1993.
For a discussion of discontinued operations see Note 17 to the Consolidated
Financial Statements.
Construction and Financing Program
Current construction expenditures are primarily transmission and
distribution-related, designed to meet continuing customer growth.
Construction expenditures, which include energy conservation expenditures
and exclude AFUDC and AFUCE, were $206.8 million in 1996. The Company
expects combined electric and gas construction expenditures for the period
1997 through 1999 will be approximately $247 million, $252 million and $226
million, respectively. The ratio of cash from operations (net of dividends,
AFUDC and AFUCE) to construction expenditures (excluding AFUDC and AFUCE)
was 115.4% in 1996. The Company expects cash from operations (net of
dividends and AFUDC) during the period 1997 through 1999 will, on average,
be approximately 73% of average estimated construction expenditures
(excluding AFUDC) during the same period.
29
<PAGE>
In October 1992, Puget Power filed a shelf registration statement with the
Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to $450 million principal amount of First Mortgage
Bonds. The First Mortgage Bonds can be issued as Secured Medium-Term Notes,
through underwritten offerings, pursuant to delayed delivery contracts or
any combination thereof. These Secured Medium-Term Notes were designated
Series B. As of February 10, 1997, the Company has issued $364 million in
Series B Notes having an average coupon rate of 6.90%.
In August 1995, WNG filed a shelf registration statement with the Securities
and Exchange Commission for the offering, on a delayed or continuous basis,
of up to $150 million principal amount of First Mortgage Bonds, designated
as Secured Medium-Term Notes, Series C. In December 1995, WNG called $30
million of outstanding First Mortgage bonds and paid a premium of $342,000
and issued $35 million of Medium-Term Notes with lower interest rates.
Short-term borrowings from banks and the sale of commercial paper are used
to provide working capital for the construction program. At December 31,
1996, the Company had in place $426.5 million in lines of credit with
several banks, which provided liquidity support for outstanding commercial
paper of $266.4 million, effectively reducing the available borrowing
capacity under these lines of credit to $160.1 million. (See Note 8 to the
Consolidated Financial Statements.)
Rate Matters - Electric
In the Washington Commission's September 21, 1993, general rate case order,
the Company was allowed a 10.5% return on common equity and 8.94% return on
rate base, based on a capital structure of 47% debt, 8% preferred stock and
45% common equity.
On September 22, 1995, the Washington Commission issued a rate order
relating to the Company's fifth annual rate adjustment under the PRAM. 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 annual regulatory adjustments for
variations in weather and hydro conditions provided for in the PRAM were
also discontinued.
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.
30
<PAGE>
Rate Matters - Gas
WNG filed and received rate orders for three general rate cases in the
period from July 1992 to May 1995. The following table shows the filing
dates of each case, the annual margin effect based on normal weather and the
effective date of each rate order:
Date of Annual Margin Effective Date
Filing Increase (Decrease) of Rate Order
------ ------------------- --------------
July 1992 ($15.4 million) October 9, 1993
November 1993 $19.0 million June 2, 1994
March 1995 $17.7 million (1) May 15, 1995
(1) Excluding municipal utility taxes
In the July 1992 filing, WNG had initially sought a $41.4 million rate
increase, which was subsequently reduced to $14.8 million. In September
1993, the Washington Commission issued an order decreasing rates by $15.4
million effective in October 1993. The principal differences in the annual
revenue requirement between WNG's revised rate request and the Washington
Commission's ordered rate reduction were:
(1) approximately $11 million of expenses related to advertising, marketing
and merchandising disallowed by the Washington Commission;
(2) approximately $10 million due to an allowed overall rate of return of
9.15% on a rate base of $483.9 million, compared to WNG's proposed overall
rate of return of 9.98% on $504.0 million of rate base;
(3) $5.2 million related to disallowance of WNG's proposed attrition
allowance; and
(4) $4.8 million associated with the weather normalization calculation.
In November 1993, WNG filed a limited-scope general rate case seeking a
$24.6 million increase in annual revenues. The primary focus was to seek
recovery of additional operating costs and the inclusion in rate base of
utility plant additions since calendar year 1991, which was the base
measurement year used in the prior rate case. In May 1994, the Washington
Commission issued an order approving a settlement of the rate case. The
settlement provided for a $19.0 million increase in annual revenue and an
agreement that WNG would not request an increase in total revenues, other
than PGA filings or in other limited circumstances, prior to March 1, 1995.
In the March 1995 general rate case filing, WNG 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 WNG
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,
WNG agreed not to make a general rate case filing prior to May 15, 1997.
WNG, however, is not precluded from PGA filings or filing for interim or
emergency rate relief if conditions warrant.
31
<PAGE>
The May 1995 order also implemented a rate redesign approved by the
Washington Commission in April 1995. Generally, the rate redesign lowers
rates for transportation customers and large commercial and industrial gas
sales customers, while increasing the rates for residential customers. In a
separate decision in May 1995, the Washington Commission issued an order to
implement a PGA to pass through a $46.5 million annual reduction in the cost
of purchased gas to customers in the form of lower rates.
The Merger
On February 7, 1997, the Boards of the Company and WECo approved the merger
of their respective companies effective February 10, 1997. The merged
company is called Puget Sound Energy, Inc. This announcement followed the
approval by the Washington Commission, on February 5, 1997, of a merger
agreement between the Company, WECo, WNG, the Staff of the Washington
Commission and the Public Counsel Section of the State Attorney General's
Office. Shareholders of the Company and WECo, voting as separate groups
had, on March 20, 1996, already given their approval to an Agreement and
Plan of Merger ("Merger Agreement") between the two companies.
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 merger has been structured as a tax-free exchange
of shares, and is accounted for as a pooling of interests for financial
statement purposes.
The Merger Agreement approvorder approving the merger, issued by the
Washington Commission, contains a rate plan that is designed to provide a
five-year period of rate certainty for customers and provide the Company
with an opportunity to achieve a reasonable return on investment. As
required under the stipulated settlementmerger 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 increase in general rates
of 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
3.24%. General electric rates for residential and industrial customers 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.
In connection with the merger, through December 31, 1996, the Company has
incurred direct merger related costs and indirect costs related to
integration of the operations of the Company and WECo, (including costs
related to a voluntary early separation plan accepted by 277 employees of
the Company - under terms of the plan, certain employees were terminated in
1996 and termination of others was subject to completion of the merger).
Indirect costs of $4.8 million were expensed in the fourth quarter of 1996.
Additional costs of $14.0 million have been deferred and will be expensed in
the first quarter of 1997, as of the merger consummation date.
32
<PAGE>
The Company estimates that additional direct and indirect merger costs of
$56 million, including the $14 million deferred, would be charged to expense
in 1997. These estimates are subject to revision as the integration process
proceeds.
Other
The U.S. electric utility industry is facing an increasingly competitive
environment, particularly in wholesale generation and industrial customer
markets. The National Energy Policy Act of 1992 ("EPACT") intensified
competition in the wholesale electric market by easing restrictions on
wholesale power producers and by allowing the Federal Energy Regulatory
Commission ("FERC") to order access for wholesale sellers to deliver power
to wholesale buyers over transmission systems owned by others. In 1996 FERC
issued its landmark Orders 888 and 889, which require jurisdictional
utilities, including the Company, to file wholesale transmission tariffs
providing pricing and terms for transmission access for wholesale purposes.
The EPACT does not permit the FERC to order transmission access for retail
purposes, but Congress now has pending bills that would require existing
utilities to allow competitors to use utility property, including
transmission and distribution facilities, to provide electric service to
retail customers of the existing utilities. Several states, including
California, New Hampshire and Rhode Island have enacted legislation to allow
such use by competitors of utility property. Most other states, including
Washington, are considering, or have adopted, legislative or regulatory
proposals which would also allow such use of utility property by competitors
to sell to retail customers of the existing utilities. In its February 5,
1997 Order approving the Company's merger with Washington Energy Company
described above, the Washington Commission required the Company to conduct a
retail access pilot program. Any substantial change in utility regulation
in Washington state, such as allowing use of utility property by competitors
for retail purposes, would require legislative action. The major credit
rating agencies have expressed the general view that increased competition
is likely to increase business risks in the electric utility industry, with
resulting pressures on utility credit quality and investor returns.
Since 1986, the Company has been offering gas transportation as a separate
service to industrial and commerical 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 the potential savings provided by unbundled
transportation service; in 1996, approximately 106 commercial and industrial
customers, on average, chose to use such service. In the future, the
Company's large industrial and commercial customers may also choose to
bypass the Company's distribution system by constructing pipelines to
interconnect directly with the interstate pipeline that transports natural
gas to the Pacific Northwest.
The Company and BPA have entered into a letter of intent, subject to various
conditions, regarding pursuit of construction of a joint transmission
project in Whatcom and Skagit counties in northern Washington state, the
northernmost portion of the Company's service territory. The joint project
is intended to provide the Company and BPA with certain transfer capacity
with Canadian utilities and is intended to relieve certain transmission
constraints on the respective systems of BPA and the Company. The joint
33
<PAGE>
project, which is expected to be completed in late 1997, will involve a
combination of existing facility upgrades and new construction.
On May 24, 1996, the Company filed a proposal with the Washington Commission
to create an Optional Large Power Sales Rate for its largest customers.
Under the Company's proposal, customers who elect the Optional Large Power
Sales Rate would no longer be considered "core" customers. Instead, they
would form a new class of "non-core" customers, and the Company would no
longer have an obligation to plan for future resources to serve their needs.
The non-core customers will receive access to electric energy that is priced
at current market cost and will 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 would take on
the risk that market costs could become volatile and that electricity could
be unavailable on the open market. On October 9, 1996, the Washington
Commission approved the Company's proposal and ordered the new optional
large power sales tariff into effect November 1, 1996.
On January 29, 1997, the Company and BPA signed a Residential Exchange
Termination Agreement. The Agreement ends the Company's participation in
the Residential Purchase and Sale Agreement with BPA. The Residential
Purchase and Sale Agreement enabled the Company's residential and small farm
customers to receive the benefits of lower-cost federal power. As part of
the Termination Agreement, the Company will receive 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. The Company expects the difference will be made up through the general
rate increases approved in the merger order and additional reductions in
operating expenses.
On July 12, 1996, the Company and several other Northwest electric companies
signed a memorandum of understanding to study the creation of an independent
transmission grid operator called "IndeGO." Participation in IndeGO would
be open to all transmission owners in the Northwest and would include both
investor-owned utilities and certain government-owned power agencies.
The Company's energy conservation expenditures have historically been
accumulated, included in rate base and amortized to expense over a ten year
period at the direction of the Washington Commission. In June 1995 the
Company sold approximately $202.5 million of its investment in customer-
owned energy conservation measures to a grantor trust, which, in turn,
issued securities backed by a Washington state statute enacted in 1994. The
statute provides that if certain conditions are met, securities could be
issued, backed by a statutory requirement that a portion of rate revenues be
forwarded to the trust to repay those securities. The proceeds of the sale
were used to pay down short-term debt. The Company recognized no gain or
loss on the sale.
The Company is in the process of selectively replacing the High Molecular
Weight ("HMW") underground distribution cable installed during the 1960s and
1970s. The Company installed about 4,800 miles of standard HMW cable
between 1964 and 1979, but the Company and other utilities have experienced
increasing cable failures in recent years. The Company is continuing to
analyze cable failure trends to find ways to mitigate the effect of cable
failures on customer service. To minimize the impact on customers of
increasing cable failures, the Company replaces a certain amount of HMW
34
<PAGE>
cable each year and is beginning to use silicone injection to lengthen the
life of potentially problem cables. The Company so far has replaced 780
miles and injected 20 miles of HMW cable. The Company expects to spend $49
million on additional cable replacement during the period 1997-2000. In
1997 the Company is planning either to replace or use silicone injection on
150 miles of HMW cable.
For a discussion of environmental obligations, see Note 16 to the
Consolidated Financial Statements.
35
<PAGE>
<TABLE>
Selected Financial Data
<CAPTION>
(Dollars in thousands
except per share data)
Year ended on December 31 1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenue $ 1,649,279 $ 1,631,118 $ 1,632,485 $ 1,586,935 $ 1,402,198
Operating income $ 284,474 $ 270,344 $ 224,772 $ 268,390 $ 261,744
Income from continuing
operations $ 167,351 $ 128,381 $ 79,312 $ 162,974 $ 152,323
Income for common stock from
continuing operations $ 145,170 $ 105,727 $ 58,929 $ 143,819 $ 135,712
Common shares outstanding -
weighted average 84,417,601 84,188,841 83,830,017 80,707,419 73,190,689
Earnings per common share
from continuing operations $ 1.72 $ 1.26 $ 0.70 $ 1.78 $ 1.85
(Note 1 to the financial
statements)
Dividends per common share $ 1.67 $ 1.67 $ 1.67 $ 1.78 $ 1.75
Book value per common share $ 16.31 $ 16.27 $ 17.01 $ 18.04 $ 17.39
- --------------------------------------------------------------------------------------------
Total assets at year-end $ 4,227,470 $ 4,244,568 $ 4,496,770 $ 4,386,678 $ 3,907,265
Long-term obligations $ 1,165,584 $ 1,230,499 $ 1,253,498 $ 1,389,479 $ 1,321,672
Redeemable preferred stock $ 87,839 $ 89,039 $ 91,242 $ 115,724 $ 126,570
36
</TABLE>
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
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 39 of this Report on Form 8-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 and financial
statement schedule of Washington Energy Company ("WECo") and its principal
subsidiary, Washington Natural Gas ("WNG"), which statements reflect total
assets of $1,034 million and $979 million as of December 31, 1996 and 1995,
respectively and total revenues of $426 million, $444 million and $432
million for 1996, 1995 and 1994, 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 provides a reasonable basis for our opinion.
In our opinion, based on our audit 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, 1996 and 1995, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1996 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 12, 1997
37
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Washington Energy Company:
We have audited the consolidated balance sheets and statements of
capitalization of Washington Energy Company (a Washington corporation) and
subsidiaries as of September 30, 1996 and 1995, 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 three years
in the period ended September 30, 1996, and the consolidated balance sheets
and statements of capitalization of Washington Natural Gas Company (a
Washington corporation) and subsidiaries as of September 30, 1996 and 1995,
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 three years in the period ended September 30, 1996. These financial
statements, which are not included in this Form 8-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 1995, and the results of their operations and their
cash flows for each of the three 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)
38
<PAGE>
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, 1996, 1995 and 1994........................................40
Consolidated Balance Sheets, December 31, 1996 and 1995...................42
Consolidated Statements of Capitalization,
December 31, 1996 and 1995..............................................44
Consolidated Statements of Earnings Reinvested in the Business
for the years ended December 31, 1996, 1995 and 1994....................45
Consolidated Statements of Cash Flows for the years
ended December 31, 1996, 1995 and 1994..................................46
Notes to Consolidated Financial Statements................................47
Schedule:
II. Valuation and Qualifying Accounts and Reserves for the
years ended December 31, 1996, 1995 and 1994.........................79
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.............................................................81
39
<PAGE>
Consolidated Statements of Income
Puget Sound Energy, Inc.
- --------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands
except per share amounts) 1996 1995 1994
- --------------------------------------------------------------------------
Operating Revenues:
Electric $1,198,769 $1,179,330 $1,194,058
Gas 400,108 420,048 396,407
Other 50,402 31,740 42,020
- --------------------------------------------------------------------------
Total operating revenue 1,649,279 1,631,118 1,632,485
- --------------------------------------------------------------------------
Operating Expenses:
Energy Costs:
Purchased electricity 428,172 409,541 394,758
Purchased gas 177,719 219,022 223,502
Fuel 40,645 35,658 47,166
Utility operations and maintenance 303,410 311,022 372,819
Other operations and maintenance 6,421 2,497 1,774
Depreciation, depletion and amortization 144,722 141,008 146,971
Taxes other than federal income taxes 155,969 150,507 145,907
Federal income taxes 107,747 91,519 74,816
- --------------------------------------------------------------------------
Total operating expenses 1,364,805 1,360,774 1,407,713
- --------------------------------------------------------------------------
Operating Income 284,474 270,344 224,772
- --------------------------------------------------------------------------
Other Income:
Pre-tax loss on merger of subsidiary -- -- (6,304)
Federal income tax on merger of subsidiary -- -- (23,711)
Pre-tax charges related to
unconsolidated affiliate -- (24,803) --
Deferred tax benefit of write downs -- 8,681 --
Other, net 1,593 1,213 7,443
- --------------------------------------------------------------------------
Total other income 1,593 (14,909) (22,572)
- --------------------------------------------------------------------------
Income Before Interest Charges 286,067 255,435 202,200
- --------------------------------------------------------------------------
(Continued)
40
<PAGE>
Consolidated Statements of Income, continued
Puget Sound Energy, Inc.
- --------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands
except per share amounts) 1996 1995 1994
- --------------------------------------------------------------------------
Interest Charges:
AFUDC (3,919) (4,292) (3,667)
Other interest 122,635 131,346 126,555
- --------------------------------------------------------------------------
Total interest charges 118,716 127,054 122,888
- --------------------------------------------------------------------------
Income from continuing operations 167,351 128,381 79,312
Discontinued operations:
Loss from operations, net of tax (1,386) (26,597) (130)
Loss on disposal, net of tax (446) -- (799)
- --------------------------------------------------------------------------
Net Income 165,519 101,784 78,383
Less Preferred Stock Dividends accrual 22,181 22,654 20,383
- --------------------------------------------------------------------------
Income for Common Stock $143,338 $79,130 $58,000
==========================================================================
Common shares outstanding weighted average 84,418 84,189 83,830
==========================================================================
Earnings (Loss) per common share:
From continuing operations $1.72 $1.26 $0.70
From discontinued operations (.02) (.32) (.01)
- --------------------------------------------------------------------------
Earnings per common share $1.70 $0.94 $0.69
==========================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
41
<PAGE>
Consolidated Balance Sheets
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------
Assets
December 31
(Dollars in Thousands) 1996 1995
- ----------------------------------------------------------------------------
Utility Plant:
Electric plant, at original cost $3,479,652 $3,400,723
Gas plant 1,129,849 1,044,617
Less: Accumulated depreciation and amortization 1,493,024 1,392,413
- ----------------------------------------------------------------------------
Net utility plant 3,116,477 3,052,927
- ----------------------------------------------------------------------------
Other Property and Investments:
Investment in Bonneville Exchange Power Contract 86,772 94,241
Investment in Cabot 69,014 69,975
Subsidiary properties and investment 80,770 104,608
Other 43,444 30,705
- ----------------------------------------------------------------------------
Total other property and investments 280,000 299,529
- ----------------------------------------------------------------------------
Current Assets:
Cash 4,335 21,814
- ----------------------------------------------------------------------------
Accounts receivable 160,836 138,759
Less: Allowance for doubtful accounts 1,700 1,865
- ----------------------------------------------------------------------------
Total accounts receivable 159,136 136,894
- ----------------------------------------------------------------------------
Unbilled revenue 102,409 91,305
PRAM accrued revenues 40,470 59,123
Materials and supplies, at average cost 61,638 78,375
Prepayments and Other 10,458 11,949
- ----------------------------------------------------------------------------
Total current assets 378,446 399,460
- ----------------------------------------------------------------------------
Long-Term Assets:
Regulatory asset for deferred income taxes 242,454 256,320
PRAM accrued revenues (net of current portion) -- 55,673
Unamortized energy conservation charges 44,673 41,068
Other 165,420 139,591
- ----------------------------------------------------------------------------
Total long-term assets 452,547 492,652
- ----------------------------------------------------------------------------
Total Assets $4,227,470 $4,244,568
============================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
42
<PAGE>
Capitalization and Liabilities
December 31
(Dollars in Thousands) 1996 1995
- ----------------------------------------------------------------------------
Capitalization
(See "Consolidated Statements of Capitalization"):
Common equity $1,378,377 $1,372,590
Preferred stock not subject
to mandatory redemption 215,000 215,000
Preferred stock subject
to mandatory redemption 87,839 89,039
Long-term debt 1,165,584 1,230,499
- ----------------------------------------------------------------------------
Total capitalization 2,846,800 2,907,128
- ----------------------------------------------------------------------------
Current Liabilities:
Accounts payable 95,736 79,739
Short-term debt 298,122 329,043
Current maturities of long-term debt 100,062 73,140
Purchased gas liability 41,368 15,554
Accrued expenses:
Taxes 57,419 47,882
Salaries and wages 28,215 27,802
Interest 27,173 27,291
Other 51,906 60,622
- ----------------------------------------------------------------------------
Total current liabilities 700,001 661,073
- ----------------------------------------------------------------------------
Deferred Income Taxes 586,661 593,685
- ----------------------------------------------------------------------------
Other Deferred Credits 94,008 82,682
- ----------------------------------------------------------------------------
Commitments and Contingencies -- --
- ----------------------------------------------------------------------------
Total Capitalization and Liabilities $4,227,470 $4,244,568
============================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
43
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statements of Capitalization
Puget Sound Energy, Inc.
- ------------------------------------------------------------------------------------
December 31 (Dollars in Thousands) 1996 1995
- ------------------------------------------------------------------------------------
<S> <C> <C>
Common Equity:
Common stock - ($10 stated value) - 150,000,000 shares
authorized, 84,511,245 and 84,340,755 shares
outstanding $ 845,112 $ 843,408
Additional paid-in capital 446,910 444,928
Earnings reinvested in the business 86,355 84,254
- ------------------------------------------------------------------------------------
Total common equity 1,378,377 1,372,590
- ------------------------------------------------------------------------------------
Preferred Stock Not Subject to Mandatory
Redemption - cumulative - $25 par value:*
7.875% series - 3,000,000 shares authorized and outstanding 75,000 75,000
Adjustable Rate, Series B - 2,000,000 shares
authorized and outstanding 50,000 50,000
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 215,000 215,000
- ------------------------------------------------------------------------------------
Preferred Stock Subject To Mandatory Redemption - cumulative
$100 par value:*
4.84% series - 150,000 shares authorized,
47,956 shares outstanding 4,796 4,796
4.70% series - 150,000 shares authorized,
56,215 shares outstanding 5,621 5,621
8% series - 150,000 shares authorized,
24,224 and 36,224 shares outstanding 2,422 3,622
7.75% series - 750,000 shares authorized
and outstanding 75,000 75,000
- ------------------------------------------------------------------------------------
Total preferred stock subject to mandatory redemption 87,839 89,039
- ------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds 1,104,060 1,134,200
Guaranteed collateralized bonds -- 8,000
Pollution control revenue bonds:
Revenue refunding 1991 series, due 2021 50,900 50,900
Revenue refunding 1992 series, due 2022 87,500 87,500
Revenue refunding 1993 series, due 2020 23,460 23,460
Other notes 19 21
Unamortized discount - net of premium (293) (442)
Long-term debt due within one year (100,062) (73,140)
- ------------------------------------------------------------------------------------
Total long-term debt excluding current maturities 1,165,584 1,230,499
- -----------------------------------------------------------------------------------
Total Capitalization $2,846,800 $2,907,128
====================================================================================
* 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.
44
</TABLE>
<PAGE>
Consolidated Statements of Earnings Reinvested in the Business
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands
except per share amounts) 1996 1995 1994
- ----------------------------------------------------------------------------
Balance at Beginning of Year $ 84,254 $146,228 $228,716
Net Income 165,519 101,784 78,383
- ----------------------------------------------------------------------------
Total 249,773 248,012 307,099
- ----------------------------------------------------------------------------
Deductions:
Excess premium, preferred redemption -- -- 673
Dividends Declared:
Preferred stock:
$4.84 per share on 4.84% series 232 232 242
$4.70 per share on 4.70% series 265 276 319
$8.00 per share on 8% series 218 314 410
$0.77 per share on 8.875% series C -- -- 23
$0.73 per share on 8.750% series F -- -- 22
$0.18 per share on 8.750 series I -- -- 88
$7.75 per share on 7.75% series 5,813 5,813 5,813
$1.97 per share on 7.875% series 5,906 5,906 5,906
$1.86 per share on 7.45% series II 4,470 4,470 3,824
$2.13 per share on 8.50% series III 2,550 2,656 --
Adjustable Rate, series A -- -- 700
Adjustable Rate, series B 2,716 3,115 2,277
$0.43 per share on 5.00% series A -- -- 9
$0.52 per share on 6.00% series A -- -- 13
Common stock 141,248 140,976 140,552
- ----------------------------------------------------------------------------
Total deductions 163,418 163,758 160,871
- ----------------------------------------------------------------------------
Balance at End of Year $ 86,355 $ 84,254 $146,228
- ----------------------------------------------------------------------------
Dividends declared per common share $ 1.67 $ 1.67 $ 1.67
============================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
45
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------------------
Year Ended December 31 (Dollars in Thousands) 1996 1995 1994
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Activities:
Income from continuing operations $167,351 $128,381 $ 79,312
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation and amortization 144,722 141,008 146,971
Deferred income taxes and tax credits - net 6,842 11,421 (5,690)
PRAM accrued revenues - net 74,326 (3,955) (25,835)
Pre-tax loss on merger of unconsolidated subsidiary -- -- 6,304
Pretax writedown and equity in undistributed
(income) losses of unconsolidated affiliate 961 27,826 (699)
Deferred tax on merger of
unconsolidated subsidiary -- -- 24,784
Other (22,434) 4,143 13,103
Change in certain current assets and liabilities 27,809 34,959 38,164
- ----------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 399,577 343,783 276,414
- ----------------------------------------------------------------------------------------
Investing Activities:
Construction expenditures - excluding equity AFUDC (205,050) (205,981) (297,140)
Energy conservation expenditures (6,683) (15,156) (36,648)
Cash received from sale of conservation assets - net -- 199,452 --
Proceeds from property sales 34,000 -- --
Proceeds from merger of unconsolidated subsidiary -- -- 63,661
Investment in unconsolidated subsidiary prior to merger -- -- (20,760)
Other (7,384) 882 22,972
- ----------------------------------------------------------------------------------------
Net Cash Used by Investing Activities (185,117) (20,803) (267,915)
- ----------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in short-term debt (30,921) (30,593) 64,832
Dividends paid (163,418) (163,758) (160,871)
Issuance of common and preferred stock 3,686 4,824 144,229
Redemption of preferred stock (1,200) (1,993) (65,086)
Issuance of bonds 34,470 74,280 85,000
Redemption of bonds and notes (72,612) (193,144) (76,354)
Other (558) (43) (1,299)
- ----------------------------------------------------------------------------------------
Net Cash Used by Financing Activities (230,553) (310,427) (9,549)
- ----------------------------------------------------------------------------------------
Increase (decrease) in cash
from continuing operations (16,093) 12,553 (1,050)
Decrease in cash from
discontinued operations:
Operating activities (1,386) (139) (3,609)
Investing activities -- (1,271) (1,164)
- ---------------------------------------------------------------------------------------
Net increase (decrease) in cash (17,479) 11,143 (5,823)
Cash at Beginning of Year 21,814 10,671 16,494
- ---------------------------------------------------------------------------------------
Cash at End of Year $ 4,335 $ 21,814 $ 10,671
=======================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
46
</TABLE>
<PAGE>
Puget Sound Energy, Inc.
Notes To Consolidated Financial Statements
- ----------------------------------------------------------------------------
1. Summary of Significant Accounting Policies
Significant accounting policies are described below.
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 Commission, contains a rate plan that is designed to provide a
five-year period of rate certainty 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 increase in general rates
of 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.
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 the equity basis.
47
<PAGE>
Financial information for WECo herein is as of its fiscal year-end,
September 30, 1996 and 1995, and for the three years in the period ended
September 30, 1996.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Utility Plant:
The costs of additions to utility plant, including renewals and betterments,
are capitalized at original cost. Costs include indirect costs such as
engineering, supervision, certain taxes and pension and other benefits, and
an allowance for funds used during construction. Replacements of minor
items of property are included in maintenance expense. The original cost of
operating property together with removal cost, less salvage, is charged to
accumulated depreciation when the property is retired and removed from
service.
Accounting for Regulatory Assets:
The Company prepares its financial statements in accordance with Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" ("Statement No. 71"). Statement No. 71
requires the Company to defer certain costs that would otherwise be charged
to expense, if it is probable that future rates will permit recovery of such
costs. Accounting under Statement No. 71 is appropriate as long as: rates
are established by or subject to approval by independent, third-party
regulators; rates are designed to recover the specific enterprise's cost-of-
service; and in view of demand for service, it is reasonable to assume that
rates set at levels that will recover costs can be charged to and collected
from customers. In applying Statement No. 71, the Company must give
consideration to changes in the level of demand or competition during the
cost recovery period. In accordance with Statement No. 71, the Company
capitalizes certain costs in accordance with regulatory authority whereby
those costs will be expensed and recovered in future periods.
Net regulatory assets at December 31, 1996 and 1995 included the following:
- ----------------------------------------------------------------
(Dollars in Millions) 1996 1995
- ----------------------------------------- ------ ------
Deferred income taxes $242.5 $256.3
Investment in BEP Exchange Contract 86.8 94.2
Unamortized energy conservation charges 44.7 41.1
PRAM accrued revenues 40.5 114.8
Storm damage costs 39.3 27.3
Various other costs 67.9 70.9
- ----------------------------------------- ------ -----
Total $521.7 $604.6
================================================================
If the Company, at some point in the future, determines that all or a
portion of the utility operations no longer meets the criteria for continued
application of Statement No. 71, the Company would be required to adopt the
provisions of Statement of Financial Accounting Standards No. 101,
"Regulated Enterprises - Accounting for the Discontinuation of Application
of FASB Statement No. 71." Adoption of Statement No. 101 would require the
48
<PAGE>
Company to write off the regulatory assets and liabilities related to those
operations not meeting Statement No. 71 requirements.
The Company, in prior years, incurred costs associated with 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).
Operating Revenues:
Operating revenues are recorded on the basis of service rendered, which
include estimated unbilled revenue and revenue accrued under the Periodic
Rate Adjustment Mechanism ("PRAM").
Energy Conservation:
The Company accumulates energy conservation expenditures which are included
in rate base and amortized to expense as prescribed by the Washington
Utilities and Transportation Commission ("Washington Commission").
In June 1995, the Company sold approximately $202.5 million of its
investment in customer-owned energy conservation measures to a grantor trust
which, in turn, issued securities backed by a Washington state statute
enacted in 1994. The proceeds of the sale were used to pay down short-term
debt. The Company recognized no gain or loss on the sale.
Self-Insurance:
Prior to October 1, 1993, provision was made by Puget Power for uninsured
storm damage, comprehensive liability, industrial accidents and catastrophic
property losses, with the approval of the Washington Commission, on the
basis of the amount of outside insurance in effect and historical losses.
To the extent actual costs varied from the provision, the difference was
deferred for incorporation into future rates.
In its September 21, 1993 order, the Washington Commission terminated,
prospectively, the provision for deferral of uninsured storm damage except
for certain losses associated with major storms. At December 31, 1996, Puget
Power had no insurance coverage for storm damage and is self-insured for a
portion of the risk associated with comprehensive liability, industrial
accidents and catastrophic property losses. The amount of uninsured storm
damage costs deferred under the regulatory treatment approved by the
Washington Commission at December 31, 1996 was $39.3 million, which includes
$14.7 million of costs deferred as a result of a severe snowstorm in late
December 1996.
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
49
<PAGE>
average original cost of depreciable electric utility plant was 3.0% in
1996, 1995 and 1994 and for depreciable gas utility plant was 3.6% in 1996
and 3.5% for 1995 and 1994.
The Company's investments in terminated generating projects were amortized
on a straight-line basis over the ten year period ending in 1994 (included
in operating expenses under "Depreciation and amortization").
Amounts recoverable through rates related to investments in terminated
generating projects and the Bonneville Exchange Power Contract were adjusted
to their present value in prior years in accordance with Statement of
Financial Accounting Standards No. 90 ("Statement No. 90"). These
adjustments result in reduced net amortization expense over the recovery
periods, the effect of which is included in other income in the amount, net
of federal income tax expense, of $1.1 million, $1.3 million and $1.8
million for 1996, 1995 and 1994, respectively.
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. (See Note 12.)
Allowance for Funds Used During Construction:
The Allowance for Funds Used During Construction ("AFUDC") represents the
cost of both the debt and equity funds used to finance utility plant
additions during the construction period. The amount of AFUDC recorded in
each accounting period varies depending principally upon the level of
construction work in progress and 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 9.03%, 8.68% and 8.72% for 1996, 1995 and 1994, 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: $2,112,000 for
1996; $1,614,000 for 1995; and $3,016,000 for 1994. The deferred asset is
being amortized over the average useful life of the Company's non-project
utility plant.
Allowance For Funds Used to Conserve Energy:
The Washington Commission has authorized the Company to capitalize, as part
of energy conservation costs, related carrying costs calculated at a rate
established by the Washington Commission. This Allowance for Funds Used to
Conserve Energy ("AFUCE") has been credited as a non-cash item to
miscellaneous income in the amount of $780,000 in 1996, $1,530,000 in 1995,
and $3,370,000 in 1994. Cash inflow related to AFUCE occurs when these
charges are reflected in rates, or when the underlying asset is sold to a
third party. AFUCE related to electric energy conservation was discontinued
with the PRAM on September 30, 1996.
50
<PAGE>
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
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 were refunded to customers in the second
quarter of 1997.
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:
WECo has been selling excess gas supplies and entering into gas supply
exchanges with third parties outside of its distribution area since 1992.
WECo 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 $10,711,500,
$7,374,000 and $3,997,000 for 1996, 1995 and 1994, respectively.
51
<PAGE>
Other:
Debt premium, discount and expenses are amortized over the life of the
related debt.
In March 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
("Statement No. 121"). Statement No. 121 requires that long-lived assets and
certain intangibles be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of the asset may not be
recoverable. If impairment has occurred, an impairment loss must be
recognized. Statement No. 121 was implemented in 1995 by WECo and is
discussed in Notes 15 and 17. Adoption of this standard did not have a
material impact on Puget Power.
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. The difference in expense between Statement No. 123 and
APB 25 is not material.
In June 1996, the FASB issued Statement of Financial Accounting Standards
No. 125, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities" ("Statement No. 125"). Statement No. 125
provides consistent standards for distinguishing sales of financial assets
from transactions that are secured borrowings. A company is required to
recognize such transactions as sales when control has been surrendered and
the transferred assets are presumptively isolated beyond the reach of the
transferor and its creditors. Statement No. 125 will be effective for
transactions occuring after December 31, 1996. When effective Statement No.
125 will impact the Company's accounting for sales of merchandise and gas
accounts receivable. Under Statement No. 125, all such receivable sales
under the Company's current sales agreement occuring after December 31, 1996
would be accounted for as secured borrowings.
Earnings Per Common Share:
Earnings per common share have been computed based on the weighted average
number of common shares outstanding.
52
<PAGE>
2. Property Plant and Equipment
- ---------------------------------------------------------------------------
December 31 (Dollars in Thousands) 1996 1995
- ---------------------------------------------------------------------------
Electric and gas utility plant classified by prescribed
accounts at original cost:
Distribution plant $2,545,155 $2,418,366
Production plant 930,806 909,085
Transmission plant 580,475 549,149
General plant 338,330 330,988
Construction work in progress 83,633 112,404
Completed work not classified 52,248 55,878
Intangible plant 50,880 38,952
Underground storage 12,713 10,414
Plant held for future use 10,802 15,644
Gas stored underground - non current 2,893 2,894
Acquisition adjustments 1,566 1,566
- ---------------------------------------------------------------------------
Total electric and gas utility plant $4,609,501 $4,445,340
===========================================================================
53
<PAGE>
3. Capital Stock
Preferred Stock
-------------------------------------
Not Subject to Subject to
Mandatory Mandatory Common
Redemption Redemption Stock
- ------------------- ------------------ ---------------- ----------
Without
$25 $100 $25 $100 Par Value
Par Par Par Par ($10 Stated
Value Value Value Value Value)
- ------------------- --------- ------- ------- ------- ----------
Shares outstanding
January 1, 1994 3,000,000 475,480 480,000 961,763 83,677,199
Sold to Public:
1994 5,600,000 -- -- -- --
Issued to share-
holders under the
stock purchase
and dividend
reinvestment plan:
1994 -- -- -- -- 324,381
1995 -- -- -- -- 279,362
1996 -- -- -- -- 148,417
Issued pursuant
to employee
compensation plans:
1994 -- -- -- -- 32,890
1995 -- -- -- -- 26,585
1996 -- -- -- -- 21,886
Issued pursuant to
Directors' Stock
Bonus Plan:
1994 -- -- -- -- 163
1995 -- -- -- -- 175
1996 -- -- -- -- 187
Acquired for sinking fund:
1994 -- -- -- (19,339) --
1995 -- -- -- (22,029) --
1996 -- -- -- (12,000) --
Called for redemption
and canceled:
1994 -- (475,480) (480,000) (30,000) --
- ------------------------------------------------------------------------
Shares outstanding
December 31, 1996 8,600,000 -- -- 878,395 84,511,245
========================================================================
See "Consolidated Statements of Capitalization" for details on specific
series.
54
<PAGE>
On January 15, 1991, the Board of Directors declared a dividend of one
preference share purchase right (a "Right") on each outstanding common share
of the Company. The dividend was distributed on January 25, 1991, to
shareholders of record on that date. The Rights will be exercisable only if
a person or group acquires 10 percent or more of the Company's common stock
or announces a tender offer which, if consummated, would result in ownership
by a person or group of 10 percent or more of the common stock. Each Right
entitles the registered holder to purchase from the Company one one-
thousandth of a share of Preference Stock, $50 par value per share, at an
exercise price of $45, subject to adjustments. The description and terms of
the Rights are set forth in a Rights Agreement between the Company and The
Bank of New York, as Rights Agent. The Rights expire on January 25, 2001,
unless earlier redeemed by the Company. On October 18, 1995, the Company's
Board of Directors approved an amendment to the Rights Agreement which
precludes the merger with WECo from triggering any rights under the Rights
Agreement.
On February 3, 1994, the Company issued $50 million, Adjustable Rate
Cumulative Preferred Stock ("ARPS"), Series B ($25 par value). The proceeds
were used to retire the $40 million principal amount of its ARPS Series A
($100 par value). The weighted average dividend rate for the ARPS Series B
was 5.49% for 1996, 6.05% for 1995 and 5.93% for 1994. The weighted average
dividend rate for the ARPS Series A was 7.00% in the first two months of
1994.
For each quarterly period, dividends on the ARPS Series B, determined in
advance of such period, will be set at 83% of the highest of three interest
rates as defined in the Statement of Relative Rights and Preferences for
ARPS Series B. The dividend rate for any dividend period will in no event
be less than 4% per annum or greater than 10% per annum. The Company may
redeem the ARPS Series B at any time on not less than 30 days notice at
$27.50 per share on or prior to February 1, 1999, and at $25 per share
thereafter, plus in each case accrued dividends to the date of redemption;
provided however, that no shares shall be redeemed prior to February 1,
1999, if such redemption is for the purpose or in anticipation of refunding
such share at an effective interest or dividend cost to the Company of less
than 5.37% per annum.
On September 15, 1994, the Company sold 1,200,000 shares of 8.50% cumulative
preferred stock, $25 par value. The preferred stock is redeemable on or
after September 1, 1999, at par value.
In 1994, the Company sold 2,400,000 shares of 7.45% cumulative preferred
stock, $25 par value. The preferred stock is redeemable on or after
November 1, 2003, at par value.
In 1994, the Company redeemed early five series of preferred stock. A total
of 585,480 shares, including 510,000 shares subject to mandatory redemption,
with an aggregate par value of $22,548,000 was redeemed at an average
premium of 2.4%.
At September 30, 1996, WECo had outstanding incentive stock options for
approximately 415,000 shares at grant prices ranging from $13.38 to $21.38.
All options granted include a stock appreciation right issued in tandem with
the option grant.
55
<PAGE>
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, 1996,
there were 9,044 shares of the 4.84% Series, 6,785 shares of the 4.70%
Series and 776 shares of the 8% Series acquired by the Company and available
for future sinking fund requirements. Upon involuntary liquidation, all
preferred shares are entitled to their par value plus accrued dividends.
The preferred stock subject to mandatory redemption 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, 1997 and at per share amounts which decline annually to a price of $100
after February 15, 2007.
5. Additional Paid-in Capital
(Dollars in Thousands) 1996 1995 1994
- ----------------------------------------------------------------------------
Balance at beginning of year $444,928 $442,954 $443,918
Excess of proceeds over stated values of
common stock issued 2,022 1,934 3,006
Par value over (under) cost of reacquired
preferred stock -- 210 (424)
Issue costs of common and preferred stock (40) (170) (3,546)
- ---------------------------------------------------------------------------
Balance at end of year $446,910 $444,928 $442,954
===========================================================================
6. Earnings Reinvested in the Business
Earnings reinvested in the business unrestricted as to payment of cash
dividends on common stock approximated $254 million at December 31, 1996,
under the provisions of the most restrictive covenants applicable to
preferred stock and long-term debt contained in the Company's Articles of
Incorporation and mortgage indenture and WNG's mortgage indenture. 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 aforementioned Articles and indentures. (See Note 1.)
56
<PAGE>
7. Long-Term Debt
First Mortgage Bonds at December 31:
Series Due 1996 1995
- ----------------------------------------------
(Dollars in Thousands)
5.25% 1996 $ -- $ 20,000
4.85% 1996 -- 15,000
7.875% 1997 100,000 100,000
8.125% 1997 3,060 3,200
10.25% 1997 -- 30,000
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 --
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 --
57
<PAGE>
7. Long-Term Debt, continued
First Mortgage Bonds at December 31:
Series Due 1996 1995
- ----------------------------------------------
(Dollars in Thousands)
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 --
- ----------------------------------------------
Total First
Mortgage Bonds $1,104,060 $1,134,200
==============================================
Guaranteed Collateralized Bonds at December 31:
Series Due 1996 1995
- ----------------------------------------------
(Dollars in Thousands)
- ----------------------------------------------
8.45% 1996 $ -- $ 8,000
- ----------------------------------------------
Total Guaranteed
Collateralized Bonds $ -- $ 8,000
==============================================
The Company unconditionally guaranteed all payments of principal, premium
and interest on each series of the Guaranteed Collateralized Bonds issued in
1986 by its wholly-owned subsidiary.
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%.
58
<PAGE>
Long-Term Debt Maturities:
The principal amounts of long-term debt maturities for the next five years
are as follows:
(Dollars in Thousands) 1997 1998 1999 2000 2001
- -----------------------------------------------------------------------
Maturities of
long-term debt $103,060 $ 51,000 $107,000 $ 35,000 $ 49,000
========================================================================
The $30,000,000 of 10.25% bonds due in 1997 were called early and redeemed
with a premium of 1.14% in December 1995.
8. Short-Term Debt and Other Financing Arrangements
At December 31, 1996, the Company had short-term borrowing arrangements
which included a $250 million line of credit with nine banks, $100 million
line of credit with four banks, a $75 million line of credit with five banks
and a $1.5 million line with another two banks. In February 1997, the
Company replaced these credit lines with a new $400 million line of credit
with 15 banks. The agreement provides the Company with the ability to
borrow at different interest rate options. For the new $400 million line of
credit, the options are: (1) the higher of the prime rate or the Federal
Funds rate plus 1/2 of 1 percent or (2) the Eurodollar rate plus .30
percent. The new agreement requires an availability fee of .09 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.
At December 31, 1996 the Company had an agreement with Cooperative
Receivables Corporation ("CRC") whereby it could sell to CRC up to $90
million principal amount of undivided interests in merchandise and gas
accounts receivable at face value. At December 31, 1996, $13 million of
outstanding merchandise and gas receivables had been sold under the
agreement, and $9.7 million of eligible receivables had not been sold under
the arrangement. This agreement was terminated effective with the merger.
At December 31: (Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Short-term borrowings outstanding:
Bank notes $ 31,700 $ 44,000 $130,801
Commercial paper notes $266,422 $285,043 $228,835
Weighted average interest rate 6.05% 6.54% 6.26%
Unused lines of credit (a) $426,500 $426,500 $326,500
- ---------------------------------------------------------------------------
(a) Provides liquidity support for outstanding commercial paper in the
amount of $266.4 million, $285.0 million and $228.7 million for 1996,
1995 and 1994, respectively, effectively reducing the available
borrowing capacity under these credit lines to $160.1 million, $141.5
million, and $97.8 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, 1996
effectively changes the Company's interest rate on outstanding commercial
59
<PAGE>
paper to 9.64% on a notional principal amount of $16.5 million expiring
March 31, 2000.
9. Estimated Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 1996 and 1995:
1996 1996 1995 1995
Carrying Fair Carrying Fair
(Dollars in Millions) Amount Value Amount Value
- --------------------------------------------------------------------------
Financial Assets:
Cash $ 4.3 $ 4.3 $ 21.8 $ 21.8
Financial Liabilities:
Short-term debt $ 298.1 $ 298.1 $ 329.0 $ 329.0
Preferred stock subject to
mandatory redemption $ 87.8 $ 88.5 $ 89.0 $ 91.2
Long-term debt $1,265.6 $1,303.4 $1,303.6 $1,366.4
Unrecognized financial instruments:
Interest rate swaps $ -.- $ (1.7) $ -.- $ (2.6)
- --------------------------------------------------------------------------
The fair value of outstanding bonds including current maturities is
estimated based on quoted market prices.
The preferred stock subject to mandatory redemption is estimated based on
dealer quotes.
The carrying value of short-term debt is considered to be a reasonable
estimate of fair value. The carrying amount of cash, which includes
temporary investments with maturities of 3 months or less, is also
considered to be a reasonable estimate of fair value.
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.
60
<PAGE>
10. Supplementary Income Statement Information
(Dollars in Thousands) 1996 1995 1994
- -------------------------------------------------------------------------
Taxes:
Real estate and personal property $ 43,762 $ 41,627 $ 40,585
State business 60,787 60,695 58,837
Municipal, occupational and other 43,681 41,663 39,073
Payroll 8,650 8,638 10,607
Other 4,079 3,530 4,208
- -------------------------------------------------------------------------
Total taxes $160,959 $156,153 $153,310
- -------------------------------------------------------------------------
Charged to:
Operating expense $155,969 $150,507 $145,907
Other accounts, including
construction work in progress 4,990 5,646 7,403
- -------------------------------------------------------------------------
Total taxes $160,959 $156,153 $153,310
=========================================================================
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.
11. Leases
The Company treats all leases as operating leases for ratemaking purposes as
required by the Washington Commission. Certain leases contain purchase
options, renewal and escalation provisions. Capitalized leases are not
material.
Rental and operating lease expense for the years ended December 31, 1996,
1995 and 1994 were approximately $19,394,000, $19,217,000 and $17,924,000,
respectively. Payments due for the years ended December 31, 1996, 1995 and
1994 for the sublease of properties were approximately $1,674,000, $604,000
and $529,000, respectively.
Future minimum lease payments for noncancelable leases are approximately
$12,801,000 for 1997, $12,085,000 for 1998, $10,631,000 for 1999, $9,669,000
for 2000, $9,290,000 for 2001, and in the aggregate, $36,387,000 thereafter.
Future minimum sublease receipts for noncancelable subleases are $918,000
for 1997, $845,000 for 1998, $820,000 for 1999, $766,000 for 2000, $500,000
for 2001, and in the aggregate, $791,000 thereafter.
61
<PAGE>
12. Federal Income Taxes
The details of federal income taxes ("FIT") are as follows:
(Dollars in Thousands) 1996 1995 1994
- --------------------------------------------------------------------------
Charged to Operating Expense:
Current $111,989 $ 73,562 $ 57,898
Deferred - net (3,058) 19,152 18,114
Deferred investment tax credits (1,184) (1,195) (1,196)
- --------------------------------------------------------------------------
Total FIT charged to operations $107,747 $ 91,519 $ 74,816
==========================================================================
Charged to Miscellaneous Income:
Current $ (784) $ (1,851) $ (2,505)
Deferred - net -- (10,116) 25,192
- --------------------------------------------------------------------------
Total FIT charged to miscellaneous income $ (784) $(11,967) $ 22,687
==========================================================================
Credited to discontinued operations $ (986) $(14,320) $ (500)
==========================================================================
Total FIT $105,977 $ 65,232 $ 97,003
==========================================================================
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) 1996 1995 1994
- ---------------------------------------------------------------------------
FIT at the statutory rate $95,024 $58,455 $61,385
- ---------------------------------------------------------------------------
Increase (Decrease):
Depreciation expense deducted in the
financial statements in excess of tax
depreciation, net of depreciation
of depreciation treated as a
temporary difference 6,603 5,856 5,707
AFUDC included in income in the financial
statements but excluded from taxable income (2,191) (2,319) (2,525)
Accelerated benefit on early retirement
of depreciable assets (1,105) (840) (847)
Tax credit on gas produced from tight
sands formation -- -- 1,413
Investment tax credit amortization (1,184) (1,195) (1,196)
Energy conservation expenditures - net 3,380 806 5,607
Cabot merger and related reserves -- -- 25,254
Other - net 5,450 4,469 2,205
- ---------------------------------------------------------------------------
Total FIT $105,977 $65,232 $97,003
===========================================================================
Effective tax rate 39.0% 39.1% 55.3%
===========================================================================
62
<PAGE>
The following are the principal components of FIT as reported:
(Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Current FIT $111,205 $71,711 $55,393
===========================================================================
Deferred FIT - other:
Conservation tax settlement (759) (7) 341
Periodic rate adjustment mechanism (PRAM) (26,014) 1,384 9,287
Cabot merger -- -- 24,484
Cabot valuation -- (8,681) --
Deferred taxes related to insurance
reserves (938) (938) (938)
Terminated generating projects -- -- (3,345)
Reversal of Statement No. 90 present
value adjustments 552 688 926
Residential Purchase and Sale
Agreement - net (2,178) (4,010) (624)
Normalized tax benefits of the
accelerated cost recovery system 23,407 25,029 22,214
Energy conservation program (1,208) 1,412 (1,768)
Environmental remediation 1,148 -- (2,445)
Other 2,932 (5,841) (4,826)
- ----------------------------------------------------------------------------
Total deferred FIT - other $ (3,058) $ 9,036 $43,306
============================================================================
Deferred investment tax credits -
net of amortization (1,184) (1,195) (1,196)
Credited to discontinued operations (986) (14,320) (500)
- ----------------------------------------------------------------------------
Total FIT $105,977 $65,232 $97,003
============================================================================
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, 1996, the balance of this asset is $242 million.
The deferred tax liability at December 31, 1996 and 1995 is comprised of
amounts related to the following types of temporary differences:
63
<PAGE>
(Dollars in Thousands) 1996 1995
- --------------------------------------------------------------
Utility plant $542,399 $523,029
Investment in Cabot stock 13,650 14,826
PRAM 14,167 40,181
Energy conservation charges 27,242 34,051
Contributions in aid of construction (29,222) (28,698)
Bonneville Exchange Power 11,622 14,217
Net operating loss carry-forwards (3,212) (18,625)
Alternative minimum tax credits (15,187) (5,813)
Other 25,202 20,517
- --------------------------------------------------------------
Total $586,661 $593,685
==============================================================
The totals of $587 million and $594 million for 1996 and 1995 consist of
deferred tax liabilities of $663 million and $674 million net of deferred
tax assets of $76 million and $80 million, respectively.
13. Retirement Benefits
At December 31, 1996, the Company had separate defined benefit pension plans
covering substantially all electric and gas employees
Electric operations employees
- -----------------------------
Pension benefits are a function of both years of service and the average of
the five highest consecutive years of basic earnings within the last ten
years of employment. The Company funds pension cost using the "frozen entry-
age" actuarial cost method.
Net pension costs for 1996, 1995 and 1994, including $1,564,000 for 1996,
$1,966,000 for 1995 and $2,752,000 for 1994 which were charged to
construction and other asset accounts, were comprised of the following
components:
(Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Service cost (benefits earned
during the period) $ 6,792 $ 6,129 $ 7,244
Interest cost on projected
benefit obligation 16,365 15,656 14,895
Actual return on plan assets (38,474) (53,810) 4,392
Net amortization and deferral 18,064 35,335 (21,539)
- ---------------------------------------------------------------------------
Net pension costs under
FASB Statement No. 87 2,747 3,310 4,992
- ---------------------------------------------------------------------------
Regulatory adjustment 1,263 1,263 1,263
- ---------------------------------------------------------------------------
Net pension costs $ 4,010 $ 4,573 $ 6,255
===========================================================================
64
<PAGE>
Funded Status of Plan
At December 31 (Dollars in Thousands) 1996 1995
- ---------------------------------------------------------------------------
Actuarial present value of benefit obligations:
Vested $(182,805) $(181,367)
Non-vested (3,274) (1,387)
- ----------------------------------------------------------------------------
Accumulated benefit obligation (186,079) (182,754)
Effect of future compensation levels (46,411) (41,566)
- ----------------------------------------------------------------------------
Total projected benefit obligation (232,490) (224,320)
Plan assets at market value 282,886 254,844
- ----------------------------------------------------------------------------
Plan assets in excess of projected benefit
obligation 50,396 30,524
Unrecognized net gain due to variance
between assumptions and experience (52,250) (34,584)
Prior service cost 7,819 9,606
Transition asset as of January 1, 1986,
being amortized on a straight-line
basis over 18 years (2,934) (3,354)
Regulatory adjustment, cumulative 3,664 4,927
- ---------------------------------------------------------------------------
Prepaid pension cost recognized
in long-term assets on balance sheet $ 6,695 $ 7,119
===========================================================================
1996 1995 1994
---------- --------- ---------
Assumptions used in the calculations:
Settlement discount rate 7 1/2% 7 1/2% 8 1/4%
Long-term rate-of-return on assets 9% 9% 8 1/2%
Compensation increase 5% 5% 5 1/2%
In December 1995, in connection with the proposed merger with WECo, Puget
Power 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.
Plan assets consist primarily of U.S. Government securities, corporate debt
and equity securities.
In addition to providing pension benefits, Puget Power 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.
Effective January 1, 1993, Puget Power adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" ("Statement No. 106") which requires the costs
associated with Post-retirement benefits to be accrued over the period of
employment. Puget Power is recognizing the impact of Statement No. 106 by
amortizing its transition obligation of $24.9 million to expense over 20
years. The resulting 1996, 1995 and 1994 annual costs under Statement No.
106 were approximately $2.8 million, $3.6 million, and $3.8 million,
65
<PAGE>
respectively. In addition, a curtailment loss under Statement No. 106 for
1996 of $1.4 million resulted from the 1995 Voluntary Separation Plan
discussed above.
In the rate order issued by the Washington Commission on September 21, 1993,
the Washington Commission approved adoption of accrual accounting for Post-
retirement benefits. For rate purposes, the difference between accrual and
pay-as-you-go accounting will be phased in over five years. The Washington
Commission's calculation of Statement No. 106 costs for rate purposes
differs from the Company's cost by an insignificant amount. In 1996, 1995
and 1994, the expenses recognized for Post-retirement benefits were $3.8
million, $2.5 million and $2.4 million, respectively.
Gas operations employees
- ------------------------
Pension benefits are based on annual compensation and length of service.
WECo's policy is to fund the plan annually at the level necessary to provide
benefits attributable to service to date and for benefits expected to be
earned in the future.
As required by SFAS No. 87, WECo follows the projected unit credit method
for determining pension expense for financial reporting purposes.
Application of this accounting method on October 1, 1987, resulted in a
transition gain (excess of plan assets over projected benefit obligations)
of $14,584,000, which is being amortized over 18 years. The entry-age
normal actuarial cost method continues to be used for funding purposes.
The following tables set forth the plan's funded status and the pension
liability recognized in the consolidated financial statements:
(Dollars in Thousands) 1996 1995
- ----------------------------------------------------------------
Actuarial present value of accumulated
benefit obligations:
Vested $45,405 $39,319
Non-vested 524 599
- ----------------------------------------------------------------
Total $45,929 $39,918
================================================================
Projected benefit obligations for
service rendered to date $55,540 $49,819
Plan assets at fair value, primarily
marketable stocks, bonds and short-
term investments 71,748 64,248
- ----------------------------------------------------------------
Plan assets in excess of projected
benefit obligations 16,208 14,429
Unrecognized amounts:
Prior service cost 1,418 1,568
Net gains (12,488) (10,770)
Net transition gain (7,293) (8,103)
- -----------------------------------------------------------------
Net pension liability included
in the balance sheet $(2,155) $(2,876)
=================================================================
66
<PAGE>
(Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Net pension cost includes:
Service cost of benefits earned
during the period $ 2,116 $ 2,163 $ 2,577
Interest cost on projected benefit
obligations 3,791 $ 3,568 $ 3,238
Actual return on Plan assets (9,483) (8,704) (1,870)
Amortization of net transition gain (810) (810) (810)
Unrecognized prior service cost 149 149 165
Amortization of deferred gains (598) (275) (456)
Current asset gain (loss) deferred 4,113 4,440 (2,376)
- ---------------------------------------------------------------------------
Net pension cost (income) $ (722) $ 531 $ 468
===========================================================================
Assumptions used in the calculations:
Weighted-average discount rate 7 1/2% 7 1/2% 7 1/2%
Long-term rate-of-return on assets 8 1/2% 7 1/2% 7 1/2%
Compensation increase 5 1/2% 6% 6%
The Company has supplemental retirement plans for officer and director level
employees. Expenses for these plans for 1996, 1995 and 1994 were
$1,848,000, $1,780,000, and $2,037,000, respectively.
14. Employee Investment Plan & Employee Stock Purchase Plan
The Company has qualified employee Investment Plans for both electric and
gas employees under which employee salary deferrals and after-tax
contributions are used to purchase several different investment fund
options. The Company made a monthly contribution equal to 50% for gas
employees and 55% for electric employees of the basic contribution of each
participating employee. The basic contribution is limited to 6% of the
employee's eligible earnings. All Company contributions are used to
purchase Company common stock on the open market or directly from the
Company.
The Company contributions to the plan were $4,102,000, $4,158,000 and
$4,485,000 for the years 1996, 1995 and 1994, 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, 1996. The employee Investment Plan eligibility requirements are set
forth in the plan documents.
WECo also had an employee stock purchase plan, under which options were
granted to eligible employees who elect to participate in the plan on
January 1st and July 1st of each year. Participants were 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 was 90% of the fair market value of the common stock at the
grant date or 100% of the fair market value at the exercise date, whichever
is less; but in no event less than the par value of the common stock.
15. Unconsolidated Oil and Gas Affiliate
On May 2, 1994, WECo merged its oil and gas exploration and production
subsidiary, Washington Energy Resources Company ("Resources"), with a wholly-
owned subsidiary of Cabot in a tax-free exchange. WECo received 2,133,000
shares of Cabot Class A common stock and 1,134,000 shares of 6% convertible
voting preferred stock of Cabot, stated value $50, in exchange for all the
67
<PAGE>
outstanding capital stock of Resources, in addition to the repayment of
$63,661,000 of intercompany debt. The 1,134,000 shares of Cabot preferred
stock are convertible into 1,972,174 shares of Cabot Class A common stock
and are entitled to that number of votes on shareholder matters, making the
Company the holder of 16.6% of Cabot's total voting securities. As part of
the transaction, Cabot increased its board of directors from nine to eleven
and appointed two directors nominated by WECo to fill the new positions.
WECo recorded a net loss on the merger of $25,110,000, after providing for
deferred taxes of approximately $29,600,000. In 1995, WECo resolved certain
merger-related issues with Cabot, which resulted in an additional charge to
earnings of $503,000 ($327,000 after tax).
The following table details WECo's investment in Cabot as of September 30,
1996, 1995 and 1994, and earnings and dividends received from the investment
during each year (dollars in thousands):
1996 1995 1994
- ------------------------------------------------------------------------
Investment in Cabot $69,014 $69,975 $97,801
Percentage of total Cabot common stock 9.4% 9.4% 9.4%
Percentage of voting interest in Cabot 16.6% 16.6% 16.6%
Pre-tax income
Preferred dividends accrued $ 3,402 $ 3,402 $ 1,418
Equity in (loss) (619) (9,185) (573)
Investment impairment write down -- (18,300) --
Dividends received
Preferred 3,402 3,402 567
Common 341 341 171
- ------------------------------------------------------------------------
At September 30, 1996, the carrying value of WECo's investment in Cabot
exceeded WECo's proportionate interest in the underlying equity of Cabot by
$6,800,000. The Company is amortizing this remaining balance on a straight-
line basis over 16 years. Based on the closing price on the NYSE on
September 30, 1996, the aggregate fair value of WECo's investment in Cabot
common stock was $31,462,000. No fair value is readily available for the
Cabot preferred stock as it is not publicly traded; however, the fair value
of WECo's shares of Cabot preferred was estimated to be approximately
$48,000,000 at September 30, 1996.
WECo's interest in Cabot's common stock is being accounted for using the
equity method because WECo, through its representation on Cabot's board of
directors, has the ability to exercise significant influence over operating
and financial policies of Cabot.
The decrease in value of WECo's investment in Cabot from 1994 to 1995 was
primarily a result of WECo charges totaling $24,803,000 ($16,122,000 after
tax) in 1995 related to the adoption of SFAS No. 121 by Cabot and to
recognize a permanent impairment in the carrying value of WECo's investment
in Cabot. Cabot elected early adoption of SFAS No. 121 and recognized
$113,900,000 of pre-tax impairment losses related to oil and gas producing
properties in its fiscal quarter ended September 30, 1995. Under the equity
method of accounting, WECo recognized its 9.4% share of the impairment write
down, which totaled $6,503,000 after Cabot's income tax provision
($4,227,000 after WECo's income tax provision). In addition, WECo wrote
down its investment in Cabot by an additional $18,300,000 ($11,895,000 after-
tax) to a value which approximated the fair market value of the Cabot
securities held by WECo. Both charges resulted primarily from the decline
in natural gas prices during 1995 and lower projections of future natural
gas prices.
68
<PAGE>
See Note 16 regarding certain gas transportation, storage and other
contractual arrangements of Resources that were excluded from the Cabot
merger and retained by a subsidiary of WECo.
16. Commitments and Contingencies
Commitments:
Electric
For the twelve months ended December 31, 1996, approximately 32% of the
Company's energy output was obtained at an average cost of approximately 8.7
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, 1996, 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. 12/31/96(a) % of Kilowatt Costs(b)
Project Date Date (Millions) Output Capacity (Millions)
- ---------------------------------------------------------------------------
Rock Island
Original units 2012 2029 $ 84.5 57.1 )
) 423,000 $ 45.4
Additional units 2012 2029 320.9 100.0 )
Rocky Reach 2011 2006(c) 200.0 38.9 482,750 19.3
Wells 2018 2012(c) 183.9 32.3 271,320 9.9
Priest Rapids 2005 2005(c) 186.8 8.0 72,320 2.2
Wanapum 2009 2005(c) 209.1 10.8 106,380 2.8
- ---------------------------------------------------------------------------
Total 1,355,770 $79.6
===========================================================================
(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
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: 70.7% at Rock Island;
31.8% at Rocky Reach; 71.3% at Priest Rapids; and 46.3% at Wanapum.
69
<PAGE>
(b) The components of 1997 costs associated with the interest portion
of debt service are: Rock Island, $24.2 million for all units; Rocky Reach,
$5.3 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. In the past
twelve months, 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 $80 million for 1997, $79 million for 1998, $81 million for
1999, $83 million for 2000, $84 million for 2001 and in the aggregate $1.05
billion thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with
other utilities and non-utility generators in the region. The Company is
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 and non-utility generators, excluding the Columbia
River projects, are $422 million for 1997, $441 million for 1998, $464
million for 1999, $481 million for 2000, $509 million for 2001 and in the
aggregate $5 billion thereafter through 2024. These contracts have varying
terms and may include escalation and termination provisions.
Total purchased power contracts provided the Company with approximately 17.1
million, 16.4 million and 16.0 million MWH of firm energy at a cost of
approximately $485.6 million, $478.7 million and $450.7 million for the
years 1996, 1995 and 1994, respectively.
The following table indicates the Company's percentage ownership and the
extent of the Company's investment in jointly-owned generating plants in
service at December 31, 1996:
Company's Share
------------------------------
Energy Company's Plant in Accumulated
Source Ownership Service at cost Depreciation
Project (Fuel) Share (%) (Millions) (Millions)
- -------------- ------ --------- -------------- ------------
Centralia Coal 7 $ 27.4 $ 17.3
Colstrip 1 & 2 Coal 50 184.7 96.4
Colstrip 3 & 4 Coal 25 450.3 154.6
- ------------------------------------------------------------------------
Financing for a participant's ownership share in the projects is provided
for by such participant. The Company's share of related operating and
maintenance expenses is included in corresponding accounts in the
Consolidated Statements of Income.
Certain purchase commitments have been made in connection with the Company's
construction program.
70
<PAGE>
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 September
30, 1996, WEGM has a reserve for future losses associated with these
contractual obligations of $9,505,000. 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
to establish a uniform rate for holders of both types of capacity. Rates
will be rolled in, 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: 1997, $2,833,000; 1998, $2,782,000; 1999,
$2,782,000; 2000, $2,782,000; 2001, $2,782,000; and thereafter, $40,690,000.
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 1996, 1995
and 1994, pre-tax losses totaling $2,652,000, $5,841,000 and $3,001,000,
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 27 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.
71
<PAGE>
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 1996 for firm gas supply,
firm transportation service, and for firm storage and peaking service of
$31,900,000, $53,221,000 and $9,738,000 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):
2002 &
There-
1997 1998 1999 2000 2001 after Total
----------------------------------------------------------
Firm gas supply $30,952 $30,821 $29,833 $26,875 $26,875 $ 65,375 $210,731
Firm transpor-
tation service 55,933 55,933 55,933 55,933 55,933 240,796 520,461
Firm storage and
peaking service 11,943 11,943 11,943 11,943 11,943 172,027 231,742
----------------------------------------------------------
Total $98,828 $98,697 $97,709 $94,751 $94,751 $478,198 $962,934
==========================================================
Minimum Annual Take Obligations (in thousands of therms):
2002 &
There-
1997 1998 1999 2000 2001 after Total
---------------------------------------------------------------
Firm gas
supply 373,192 354,942 249,092 230,844 230,844 604,020 2,042,934
================================================================
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 53% of
expected annual sales for 1997 and less than 48% of expected sales in
subsequent years.
72
<PAGE>
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):
2002 &
There-
1997 1998 1999 2000 2001 after Total
------- ------- ------- ------- ------- --------- ---------
Total 713,575 695,325 567,575 503,700 503,700 1,255,600 4,239,475
======= ======= ======= ======= ======= ========= =========
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, 1996 for electric sites and September 30,
1996 for gas sites.
Electric Sites
The Company has expended approximately $14.3 million related to the
remediation activities covered by the Washington Commission's order, of
which approximately $5.7 million has been recovered from insurance carriers.
At December 31, 1996, approximately $2.1 million has been accrued as a
liability for future remediation costs for these and other remediation
activities. At December 31, 1996, an asset of approximately $10.0 million
has been recorded related to expected future recoveries.
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.
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(a) Everett
The Company is conducting an independent remedial action at the Everett
site. Current analysis indicates that the reserve for investigation and
remediation costs of $3,250,000, previously established, is currently
sufficient to cover the expected costs at the site. Investigation and
feasibility costs of $463,000 have been incurred through September 30, 1996.
The Everett site was previously owned and operated by other companies who
are potentially liable parties ("PLPs") for the remediation of the site.
The cost estimate reflects the total cost expected to remediate the site
before contributions by other PLPS.
(b) Gas Works Park
The Company sold the site of a former manufactured gas plant at Lake Union,
now known as "Gas Works Park," to the City of Seattle in 1962. The City of
Seattle, in a letter dated February 24, 1995, requested that the Company
participate in a cleanup of this site. The Company believes that the
contract, by which it conveyed the land to the City of Seattle, presents
substantial defenses that mitigate its exposure for environmental
remediation costs which may be incurred at this site.
On July 15, 1996, the City of Seattle completed a preliminary study that
estimated that the remediation costs were in the range of $4.9 million to
$8.6 million. The Company anticipates that in order to resolve this matter
with the City of Seattle, the potential cost may approximate $3,000,000
which has been accrued.
(c) Tacoma 22nd and A St. Site and Thea Foss Waterway
The Company was the former owner of land, located upland from the Thea Foss
Waterway in Tacoma, Washington where a MGP was operated by several other
companies. This site ("22nd and A St.") was acquired after the plant was
closed. The site was later sold in parcels to several buyers. Five
parties, including the Company, have been designated as PLPs at this site.
In May 1996, a consultant to the PLPs estimated the cost of remediating the
Tacoma 22nd and A St. site to be approximately $4,000,000, exclusive of any
remediation costs which may arise in connection with the adjacent Thea Foss
Waterway. Because there are multiple PLPs, the Company believes, based on
currently available information, that its maximum exposure is approximately
$700,000, which has been recorded as a liability.
The City of Tacoma has undertaken an investigation study of contamination in
the Thea Foss Waterway. The extent of the contamination related to possible
MGP operation is not currently known, but the Company has been designated a
Potentially Responsible Party ("PRP") by the U.S. Environmental Protection
Agency ("EPA").
(d) Chehalis
The Company has completed significant source control and installed
groundwater monitoring wells as part of an independent cleanup action. In
1997, the Company expects to complete groundwater monitoring at the site, at
which time a determination will be made as to what, if any, additional
remedial measures are required. As of September 30, 1996, the financial
statements include a reserve of $283,000, which is sufficient to cover
remaining costs at the site, assuming that further remedial measures are not
required.
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(e) Tideflats
The remediation activities at the Tideflats site were completed as of July
1995, and confirmed by the EPA in a letter dated September 28, 1995.
Ongoing monitoring and maintenance costs are being expensed as incurred and
are not material.
In June 1991, a lawsuit was filed in Washington State Superior Court, King
County, Washington ("Superior Court"), against certain insurance companies
that provided insurance applicable to the Tideflats site at various times
dating back to the 1940's. On June 10, 1994, the Superior Court entered a
final judgment in favor of the Company. Under the terms of the final
judgment, the Company was entitled to collect its present and future
uncompensated reasonable and necessary costs in remediating the site from
the policies of certain insurer defendants in the action. During 1995, the
Company settled its lawsuit with the insurance carriers in consideration of
their dismissal of the appeal of the Superior Court judgment regarding
coverage of the Tideflats remediation costs. In September 1995, the Company
received approximately $29,000,000 in final settlement of all remaining
claims against insurance carriers regarding this site. As a result of this
settlement and amounts previously received, WECo has recovered substantially
all the remediation costs which had been deferred.
(f) Expected Recoveries
The Company's financial statements as of year-end 1996, include
environmental receivables related to these MGP sites totaling $10,164,000
primarily for expected recoveries from insurance carriers, based upon the
successful litigation against its insurers regarding the Tideflats site, and
other PLPs. Although the factual situations at the other sites differ in
some respects from the factual situation at the Tideflats site, the Company
believes, based on the precedents established in the Tideflats case and
discussion with legal counsel, that it is probable that it has insurance
coverage sufficient to recover costs not recovered from other PLPs. In the
event that recoveries from insurance and other PLPs are not sufficient, the
Company, under an agreement with the Washington Commission, will seek
recovery of such unreimbursed costs in future customer rates.
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
(a) Alleged Securities Violations
A class-action lawsuit was filed against WECo and two of its officers,
(collectively, "the Defendants"), in U.S. District Court, Western District
of Washington ("District Court"), in February 1994, alleging violations of
state and federal securities act provisions and associated violations of
Washington state law. The essence of the complaint concerned alleged
disclosure violations regarding the nature or the extent of the financial
risk associated with the 1992 utility rate request filing of WNG. In May
1994, the Defendants filed a motion to dismiss the lawsuit. On July 25,
1994, the District Court issued an Order Granting Defendants' Motion To
Dismiss and entered a judgment dismissing the action. The plaintiffs
appealed to the Ninth Circuit Court of Appeals ("Court of Appeals"). On May
15, 1996, the Court of Appeals upheld WNG's motion to dismiss. The
plaintiffs did not pursue a timely appeal to the U.S. Supreme Court, thus
concluding this matter.
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(b) Alleged Anti-Trust Violations
On September 6, 1994, Cost Management Services, Inc. ("Cost Management"), a
Mercer Island, Washington, company involved in the purchase and resale of
natural gas, filed an action against WNG in District Court. Cost Management
alleged that WNG monopolized or attempted to monopolize the market for the
sale of natural gas in central western Washington. Cost Management also
alleged WNG failed to charge its customers in accordance with the prices,
terms and conditions set forth in tariffs filed by WNG with the WUTC and
that it wrongfully interfered with Cost Management's relationships with its
customers. Cost Management sought injunctive relief and damages in an
unspecified amount. WNG filed a motion to dismiss the lawsuit, which was
granted on May 5, 1995. In dismissing Cost Management's action the court
ruled that the state action doctrine provides antitrust immunity for conduct
pursuant to a clearly articulated and actively supervised state policy,
where unfettered competition is replaced with regulation. In dismissing the
federal antitrust claims, the court declined to retain jurisdiction over
Cost Management's state law claims, which were dismissed without prejudice.
Cost Management then filed its state claims in Superior Court. That case
was stayed by agreement of the parties, pending resolution of the federal
court action. Cost Management filed an appeal of the federal court
dismissal in the Court of Appeals. The parties on November 22, 1995 filed
briefs with the Court of Appeals and arguments were presented on August 8,
1996. The Court of Appeals issued a decision which reversed the District
Court's dismissal of the case and remanded the case to the District Court
for rehearing. The Court of Appeals ruled if Cost Management's claims were
assumed to be true for purposes of the Appellate Review, the lower court's
dismissal was improper. No ruling was made on the merits of any of Cost
Management's claims. Neither the outcome or the financial exposure from
this lawsuit can be predicted at this time.
Other contingencies, arising out of the normal course of the Company's
business, exist at December 31, 1996. The ultimate resolution of these
issues is not expected to have a material adverse impact on the financial
condition, results of operations or liquidity of the Company.
17. Discontinued Operations
In September 1996, WECo decided to seek a buyer for its undeveloped coal
properties and to cease development efforts on the associated railroad.
Accordingly, the consolidated financial statements of the Company reflect
these activities as discontinued operations. The 1996 loss from
discontinued operations does not include any asset write downs, but does
include estimated losses of $446,000, net of $240,000 of income taxes, until
disposal is completed. 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
SFAS No. 121.
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Summarized operating results for the coal and railroad activities are as
follows:
Years Ended December 31, 1996 1995 1994
- ------------------------------------------------------------------------
(Dollars in thousands)
Net Sales $ -- $ -- $ --
- ---------------------
Loss from operations before
income taxes 2,133 40,919 200
Income tax benefit (747) (14,322) (70)
Loss from operations, net
of income tax $ 1,386 $26,597 $ 130
========================================================================
In August 1993, WECo decided to sell Unisyn, its biowaste technology
business, and reported Unisyn as a discontinued operation in that year. In
August 1994, WECo sold the stock of its wholly-owned subsidiaries, Thermal
Efficiency, Inc., and Holdings Northwest, Inc., which jointly owned Unisyn.
The 1994 results include a loss in excess of the estimated loss recorded in
1993 of $799,000, net of $430,000 of income taxes, realized upon disposition
of the two subsidiaries.
18. 1995 and 1994 Restructuring and Other Charges
In 1995, WECo recorded a $3,150,000 ($2,000,000 after-tax) charge for
severance costs related to a 4% reduction in its work force. The work-force
reduction, which affected only salaried employees, was part of ongoing
organizational change efforts initiated in 1994. In addition, WECo recorded
a charge of $1,250,000 for federal tax contingencies.
In 1994, Puget Power and WECo recognized $39,200,000 ($25,500,000 after
tax) of restructuring and other one-time charges. Charges totaling
$28,000,000 ($18,200,000 after tax) related to restructuring and downsizing
utility operations and included employee severance and facility
consolidation costs.
The 1994 charges also included provisions by WECo for estimated
environmental investigation, legal and remediation costs associated with
certain former manufactured gas plant sites and the write-off of certain
deferred environmental-related costs. These charges totaled $2,231,000
($1,450,000 after tax). WECo recorded an additional $3,351,000 ($2,178,000
after tax) charge related to supplemental executive retirement contracts.
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.
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(Unaudited)
1996 Quarter First Second Third Fourth
- --------------------------------------------------------------------------
(Dollars in thousands except per share amounts)
Operating revenues $459,372 $414,609 $350,018 $425,280
Operating income $ 87,614 $ 70,460 $ 51,135 $ 75,265
Other income $ 1,065 $ 795 $ 413 $ (680)
Net income $ 58,309 $ 41,410 $ 21,960 $ 43,840
Earnings per common share $ 0.63 $ 0.43 $ 0.19 $ 0.45
- --------------------------------------------------------------------------
1995 Quarter First Second Third Fourth
- --------------------------------------------------------------------------
(Dollars in thousands except per share amounts)
Operating revenues $496,519 $421,247 $328,953 $384,399
Operating income $ 95,404 $ 67,319 $ 44,486 $ 63,135
Other income $ 1,320 $ 1,038 $ 1,269 $(18,536)
Net income $ 63,863 $ 35,846 $ 15,150 $(13,075)
Earnings per common share $ 0.69 $ 0.36 $ 0.11 $ (0.22)
- --------------------------------------------------------------------------
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.
The following provides additional information concerning cash flow
activities:
Year Ended December 31: 1996 1995 1994
(Dollars in Thousands)
- --------------------------------------------------------------------------
Changes in certain current
assets and current liabilities:
Accounts receivable $(22,242) $ 3,769 $ 3,151
Unbilled revenue (11,104) 6,382 2,521
Materials and supplies 16,737 (763) 14,664
Prepayments and other 1,491 (1,607) 486
Purchased gas liability 25,814 36,815 2,608
Accounts payable 15,997 (3,128) 27,793
Accrued expenses and other 1,116 (6,509) (13,059)
- --------------------------------------------------------------------------
Net change in certain current assets
and current liabilities $ 27,809 $ 34,959 $ 38,164
==========================================================================
Cash payments:
Interest (net of capitalized interest) $113,634 $131,807 $119,427
Income taxes $ 98,609 $ 77,608 $ 68,657
- --------------------------------------------------------------------------
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21. Merger of Puget Power and WECo
Included in consolidated results of operations for the years ended December
31, 1996, 1995 and 1994, are the following results of the previously separate
companies for those periods:
YEAR ENDED DECEMBER 31, 1996
(Dollars in Thousands)
-------------------------------------------------
Puget WECo Consolidated
------------- ------------- ------------
Revenues $1,223,568 $425,711 $1,649,279
Net Income $ 135,371 $ 30,148 $ 165,519
Common Dividends Declared $ 117,099 $ 24,149 $ 141,248
YEAR ENDED DECEMBER 31, 1995
(Dollars in Thousands)
-------------------------------------------------
Puget WECo Consolidated
------------- ------------- ------------
Revenues $1,187,507 $443,611 $1,631,118
Net Income $ 135,720 $(33,936) $ 101,784
Common Dividends Declared $ 117,099 $ 23,877 $ 140,976
YEAR ENDED DECEMBER 31, 1994
(Dollars in Thousands)
--------------------------------------------------
Puget WECo Consolidated
-------------- -------------- ------------
Revenues $1,200,460 $432,025 $1,632,485
Net Income $ 120,059 $(41,676) $ 78,383
Common Dividends Declared $ 117,084 $ 23,468 $ 140,552
In connection with the merger, through December 31, 1996, the Company has
incurred direct merger related costs and indirect costs related to
integration of the operations of the Company and WECo, (including costs
related to a voluntary early separation plan accepted by 277 employees of
the Company - under terms of the plan, certain employees were terminated in
1996 and termination of others was subject to completion of the merger).
Indirect costs of $4.8 million were expensed in the fourth quarter of 1996.
Additional costs of $14.0 million have been deferred and will be expensed in
the first quarter of 1997, as of the merger consummation date.
The Company estimates that additional direct and indirect merger costs of
$56 million, including the $14 million deferred, would be charged to expense
in 1997. These estimates are subject to revision as the integration process
proceeds.
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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, 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
=============================================================================
Year Ended December 31, 1994
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 800 $6,469 $5,364 $1,905
=============================================================================
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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)
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)
<PAGE>
4.6 Loan Agreement dated August 1, 1991, betweeen 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 fo 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, 1996
(incorporated herein by reference to Washington Natural Gas Company Exhibit
to Form 8-K for the 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 Washignton 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).
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).
<PAGE>
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
(incoporated 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 Exhbiit 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)
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)
<PAGE>
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 the 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 Deveopment. (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 Devleopment. (exhibit 13-s to
Registration No. 2-21824)
10.19 Exchange Agreement dated April 12, 1963, between the United
States of America, Department of the Interior, acting through the Bonneville
Power Administrator and Washington Public Power Supply System and the
Company, relating to the Hanford Project. (Exhibit 13-u to Registration
2-21824)
10.20 Replacement Power Sales Contract dated April 12, 1963, between
the United States of America, Department of the Interior, acting through the
Bonneville Power Administrator and the Company, relating to the Hanford
Project. (Exhibit 13-v to Registration No. 2-21824)
10.21 Contract covering undivided interest in ownership and operation
of Centralia Thermal Plant, dated May 15, 1969. (Exhibit 5-b to
Registration No. 2-3765)
10.22 Construction and Ownership Agreement dated as of July 30, 1971,
between the Montana Power Company and the Company. (Exhibit 5-b to
Registration No. 2-45702)
<PAGE>
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 Febrary 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 5-1-35 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 5-1-36 to Registration
No. 2-60200)
10.30 Financing Agreement Supplement and Amendment among the Company,
lessee, Chrysler Financial Corporation, owner, The Bank of California,
National Association, trustee, Pacific Mutual Life Insurance Company,
Bankers Life Company, and the Franklin Life Insurance Company, lenders,
dated as of March 26, 1975, pertaining to a combustion turbine generating
unit trust. (Exhibit 5-a-37 to Registration No. 2-60200)
10.31 Lease Agreement Supplement and Amendment between the Company,
lessee, and the Bank of California, National Association, lessor, dated as
of March 26, 1975 for one combustion turbine generating unit. (Exhibit
5-a-38 to Registration No. 2-60200)
10.32 Exchange Agreement executed August 13, 1964, between the United
States of America, Columbia Storage Power Exchange and the Company, relating
to Canadian Entitlement. (Exhibit 13-ff to Registration No. 2-24252)
10.33 Loan Agreement dated as of December 1, 1980 and related
documents pertaining to Whitehorn turbine construction trust financing.
(Exhibit 10.52 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1980, Commission File No. 1-4393.
10.34 Letter Agreement dated March 31, 1980, between the Company and
Manufacturers Hanover Leasing Corporation. (Exhbiit 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)
<PAGE>
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 Administraiton 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 betweeen Washington Public Power Supply System and the
Company. (Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1985, Commission File No. 1-4393)
10.43 Irrevocable Offer of Washington Public Power Supply System
Nuclear Project No. 3 Capability for Acquisition executed by the Company,
dated September 17, 1985. (Exhibit A of Exhibit (10)-50 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No.
1-4393)
10.44 Settlement Exchange Agreement ("Bonneville Exchange Power
Contract") executed by the United States of America Department of Energy
acting by and through the Bonnevillle 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)
<PAGE>
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 Costrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to
Annual Report on Form 10-K for the fiscal year ended Decmber 31, 1987,
Commission File NO. 1-4393)
10.54 Agreement for the purchase of Power dated as of October 29, 1984,
between South Fork II, Inc. and the Company (Weeks Falls Hydroelectric
Project). (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.55 Agreement for the Purchase of Power dated as of October 29, 1984,
between South Fork Resources, Inc. and the Company (Twin Falls Hydroelectric
Project). (Exhibit (10)-61 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.56 Agreement for Firm Purchase Power dated as of January 4, 1988,
between the City of Spokane, Washington, and the Company (Spokane Waste
Combustion Project). (Exhibit (10)-62 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File NO. 1-4393)
10.57 Agreement for Evaluating, Planning and Licensing dated as of
February 21, 1985 and Agreement for Purchase of Power dated as of February
21, 1985 between Pacific Hydropower Associates and the Company (Koma Kulshan
Hydroelectric Project). (Exhibit (10)-63 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.58 Power Sales Agreement dated as of August 1, 1986, between Pacific
Power & Light Company and the Company. (Exhibit (10)-64 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1987, Commission File No.
1-4393)
<PAGE>
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 Comany (Fredrickson Generating
Station). (Exhibit (10)-70 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.65 Settlement Agreement dated April 24, 1987, between Public Utility
District No. 1 of Chelan County, the National Marine Fisheries
Service, the State of Washington, the State of Oregon, the Confederated
Tribes and Bands of the Yakima Indian Nation, Colville Indian Reservation,
Umatilla Indian Reservation, the National Wildlife Federation and the Company
(Rock Island Project). (Exhibit (10)-71 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.66 Amendment No. 2 dated as of September 1, 1981, and Amendment No.
3 dated Septmeber 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 Adminsitration dated Augut 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, 19888, 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)
<PAGE>
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 Administraiton 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 for the quarter
ended September 30, 1989, Commission File No. 1-4393)
10.76 Agreement for Firm Power Purchase (Thermal Project), dated as of
June 29, 1989, between San Juan Energy Company and the Company. (Exhibit
(10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30,
1989, Commission File NO. 1-4393)
10.77 Agreement for Verification of Transfer, Assignment and
Assumption, dated as of September 15, 1989, betweeen 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 betweeen 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 Bonnevillle Power Adminstrator 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)
<PAGE>
10.81 Amendment No. 1 to Agreement for the Assignment of Power for 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, betweeen 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 continuing operations
National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the
Confederated Tribes and Bands of the Yakima Indian Nation, the Confederated
Tribes of the Umatilla Reservation, and the Confederated Tribes of the
Colville Reservation. (Exhibit (10)-95 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File no. 1-4393)
10.87 Agreement for Firm Power Purchase dated July 23, 1990, between
Trans-Pacific Geothermal Corporation, a Nevada corporation, and the Company.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March
31, 1991, Commission File No. 1-4393)
10.88 Agreement for Firm Power Purchase dated July 18, 1990, between
Wheelabrator Pierce, Inc., a Delaware corporation, and the Company. (Exhibit
(10)-2 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991,
Commission File No. 1-4393)
10.89 Agreement for Firm Power Purchase dated September 26, 1990,
between Encogen Northwest, L.P., A Delaware Corporation and the Company.
(Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended March
31, 1991, Commission File No. 1-4393)
10.90 Agreement for Firm Power Purchase (Thermal Project) dated
December 27, 1990, among March Point Cogeneration Company, a California
general partnership comprising San Juan Energy Company, a California
corporation; Texas-Anacortes Cogeneration Company, a Delaware corporation;
and the Company. (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the
quarter ended March 31, 1991, Commission File No. 1-4393)
<PAGE>
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)
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,
betweeen 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, betweeen 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 Decmeber 31,
1991, Commission File No. 1-4393)
<PAGE>
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)
10.108 Subordination Agreement dated December 17, 1992, betweeen 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, betweeen 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, betweeen the Company
and the Bonnevillle 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)
<PAGE>
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 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)
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 betweeen
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).
<PAGE>
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.
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 for 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 10-0
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).
<PAGE>
10.143 Firm Transportation Service Agreement dated March 1, 1992
betweeen 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
between Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transporation 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).
10.145 Firm Transportation Service Agreement dated January 12, 1994
between 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
betweeen 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 Sevice 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
Pacific 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.
*12-a Statement setting forth computation of ratios of earnings to
fixed charges (1992 through 1996).
*12-b Statement setting forth computation of ratios of earnings to
combined fixed charges and preferred stock dividends (1992 through 1996).
*21 Subsidiaries of the Registrant.
*23 Consent of accountants.
*27 Financial Data Schedule
________________________________________
*Filed herewith.
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
PUGET SOUND ENERGY, INC
Date: October 23, 1997
James W. Eldredge
-------------------------------
James W. Eldredge
Corporate Secretary
and Controller
<PAGE>
<TABLE>
Exhibit 12a
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
<CAPTION>
Year Ended December 31
------------------------------------------------
1996 1995 1994 1993 1992
------------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR FIXED CHARGES
Pre-tax income:
Net income from continuing operations
per statement of income $167,351 $128,382 $ 79,312 $163,812 $153,942
Federal income taxes 107,747 91,519 74,816 93,702 76,114
Federal income taxes charged to
other income - net (1,608) (12,068) 22,687 (418) (1,781)
Capitalized interest (600) (660) (400) (791) (1,205)
Undistbuted (earnings) or losses
of less-than-fifty-percent-owned
entities 460 8,325 743 -- (567)
------------------------------------------------
Total $273,350 $215,498 $177,158 $256,305 $226,503
Fixed charges:
Interest expense $122,635 $131,346 $126,555 $120,962 $131,029
Other interest 600 660 400 791 1,205
Portion of rentals representative
of the interest factor 4,187 5,150 5,555 5,570 5,991
------------------------------------------------
Total $127,422 $137,156 $132,510 $127,323 $138,225
Earnings available for combined
fixed charges $400,772 $352,654 $309,668 $383,628 $364,728
================================================
RATIO OF EARNINGS TO FIXED CHARGES 3.15x 2.57x 2.34x 3.01x 2.64x
</TABLE>
<PAGE>
<TABLE>
Exhibit 12b
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
(Dollars in Thousands)
<CAPTION>
Year Ended December31
------------------------------------------------
1996 1995 1994 1993 1992
------------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR COMBINED FIXED
CHARGES AND PREFERRED DIVIDEND REQUIREMENTS
Pretax income:
Net income from continuing operations
per statement of income $167,351 $128,382 $ 79,312 $163,812 $153,942
Federal income taxes 107,747 91,519 74,816 93,702 76,114
Federal income taxes charged to
other income - net (1,608) (12,068) 22,687 (418) (1,781)
------------------------------------------------
Subtotal 273,490 207,833 176,815 257,096 228,275
Capitalized interest (600) (660) (400) (791) (1,205)
Undistributed (earnings) or losses
of less-than-fifty-percent-owned
entities 460 8,325 743 -- (567)
------------------------------------------------
Total $273,350 $215,498 $177,158 $256,305 $226,503
Fixed charges:
Interest expense $122,635 $131,346 $126,555 $120,962 $131,029
Other interest 600 660 400 791 1,205
Portion of rentals representative
of the interest factor 4,187 5,150 5,555 5,570 5,991
-------------------------------------------------
Total $127,422 $137,156 $132,510 $127,323 $138,225
Earnings available for combined
fixed charges and preferred
dividend requirements $400,772 $352,654 $309,668 $383,628 $364,728
================================================
DIVIDEND REQUIREMENT:
Fixed charges above $127,422 $137,156 $132,510 $127,323 $138,225
Preferred dividend requirements below 36,249 36,674 45,441 29,904 24,476
------------------------------------------------
Total $163,671 $173,830 $177,951 $157,227 $162,701
================================================
RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED DIVIDEND REQUIREMENTS 2.45 2.03 1.74 2.44 2.24
COMPUTATION OF PREFERRED DIVIDEND
REQUIREMENTS:
(a) Pre-tax income $273,490 $207,833 $176,815 $257,096 $228,275
(b) Net income $167,351 $128,382 $ 79,312 $163,812 $153,942
(c) Ratio of (a) to (b) 1.6342 1.6189 2.2294 1.5695 1.4829
(d) Preferred dividends $ 22,181 $ 22,654 $ 20,383 $ 19,054 $ 16,506
Preferred dividend requirements
[(d) multiplied by (c)] $ 36,249 $ 36,674 $ 45,441 $ 29,904 $ 24,476
================================================
</TABLE>
Exhibit 21
SUBSIDIARIES
- -----------------
1. Puget Western, Inc.
(A Washington corporation)
2. Puget Sound Energy Company
(A Washington corporation)
3. ConnexT
(A Washington corporation)
4. Puget Energy, Inc.
(A Washington corporation)
5. Hydro Energy Development Corporation
(A Washington corporation)
6. Thermal Energy, Inc.
(A Washington corporation)
7. Thermrail, Inc.
(A Washington corporation)
8. WECO Finance Company
(A Washington corporation)
9. Washington Energy Gas Marketing Company
(A Washington corporation)
10. Washington Energy Gas Services Company
(A Washington corporation)
Exhibit 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements
of Puget Sound Energy, Inc. (formerly Puget Sound Power & Light Company) on
Form S-3 (File No. 33-26818) and Form S-8 (File Nos. 33-27396 and 333-23393)
of our report dated February 12, 1997, on our audits of the consolidated
financial statements and financial statement schedule of Puget Sound Energy,
Inc. as of December 31, 1996 and 1995, and for the years ended December 31,
1996, 1995 and 1994, which report is included in this Current Report on Form
8-K.
Coopers & Lybrand L.L.P.
Seattle, Washington
October 23, 1997
<PAGE>
Exhibit 23.2
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference of our report included in this Form 8-K as it relates to Washington
Energy Company and Washington Natural Gas Company (the Companies), into Puget
Sound Energy, Inc.'s previously filed Registration Statement File Nos.
33-26818, 33-27396 and 333-23393. It should be noted that we have not audited
any financial statements of the Companies subsequent to September 30, 1996
or performed any audit procedures subsequent to the date of our report.
ARTHUR ANDERSEN LLP
Seattle, Washington
October 21, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000081100
<NAME> PUGET SOUND ENERGY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,116,477
<OTHER-PROPERTY-AND-INVEST> 279,999
<TOTAL-CURRENT-ASSETS> 378,446
<TOTAL-DEFERRED-CHARGES> 0
<OTHER-ASSETS> 452,547
<TOTAL-ASSETS> 4,227,470
<COMMON> 845,112
<CAPITAL-SURPLUS-PAID-IN> 446,910
<RETAINED-EARNINGS> 86,355
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,378,377
87,839
215,000
<LONG-TERM-DEBT-NET> 1,165,584
<SHORT-TERM-NOTES> 31,700
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 266,422
<LONG-TERM-DEBT-CURRENT-PORT> 100,062
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 982,486
<TOT-CAPITALIZATION-AND-LIAB> 4,227,470
<GROSS-OPERATING-REVENUE> 1,649,279
<INCOME-TAX-EXPENSE> 107,747
<OTHER-OPERATING-EXPENSES> 1,257,058
<TOTAL-OPERATING-EXPENSES> 1,364,805
<OPERATING-INCOME-LOSS> 284,474
<OTHER-INCOME-NET> 1,593
<INCOME-BEFORE-INTEREST-EXPEN> 286,067
<TOTAL-INTEREST-EXPENSE> 118,716
<NET-INCOME> 165,519
22,181
<EARNINGS-AVAILABLE-FOR-COMM> 143,338
<COMMON-STOCK-DIVIDENDS> 141,248
<TOTAL-INTEREST-ON-BONDS> 96,060
<CASH-FLOW-OPERATIONS> 394,578
<EPS-PRIMARY> 1.70
<EPS-DILUTED> 1.70
</TABLE>
