UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K/A
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-4393
PUGET SOUND ENERGY, INC.
(Exact name of registrant as specified in its charter)
Washington 91-0374630
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
411 - 108th Avenue N.E., Bellevue, Washington 98004-5515
(Address of principal executive offices)
(425) 454-6363
(Registrant's telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH LISTED
- ---------------------------------------------------------- ---------------------
Common Stock, without par value,
$10 stated value N. Y. S. E.
Preference Share Purchase Rights N. Y. S. E.
7.45% Series II, Preferred Stock
(Cumulative, $25 Par Value) N. Y. S. E.
8.50% Series III, Preferred Stock
(Cumulative, $25 Par Value) N. Y. S. E.
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
- ----------------------------------------------------------
Preferred Stock (Cumulative; $100 Par Value)
Preferred Stock (Cumulative; $25 Par Value)
8.231% Capital Securities
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes/X/ No/ /
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
The aggregate market value of the voting stock held by non-affiliates of
the registrant at December 31, 1998, was approximately $2,353,000,000.
The number of shares of the registrant's common stock outstanding at
February 26, 1999, was 84,560,548.
Documents Incorporated by Reference
The Company's definitive proxy statement for its 1999 Annual Meeting
of Shareholders is incorporated by reference in Part III hereof.
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PART I
ITEM 1. BUSINESS
General
Puget Sound Energy, Inc. (the "Company"), is an investor-owned public
utility incorporated in the State of Washington furnishing electric and gas
service in a territory covering approximately 6,000 square miles, principally in
the Puget Sound region of Washington state.
At December 31, 1998, the Company had approximately 890,800 electric
customers, consisting of 789,800 residential, 95,300 commercial, 4,200
industrial and 1,500 other customers and approximately 543,900 gas customers,
consisting of 497,200 residential, 43,600 commercial, 3,000 industrial and 100
other customers. For the year 1998, the Company added approximately 18,900
electric customers and approximately 22,600 gas customers, representing
annualized growth rates of 2.2% and 4.3%, respectively. During 1998, the
Company's billed retail revenues from electric utility operations were derived
45% from residential customers, 36% from commercial customers, 15% from
industrial customers and 4% from other customers, and the Company's retail
revenues from gas utility operations were derived 61% from residential
customers, 28% from commercial customers, 8% from industrial customers and 3%
from other customers. During this period, the largest customer accounted for
2.4% of the Company's utility operating revenues.
The Company is affected by various seasonal weather patterns throughout
the year and, therefore, operating revenues and associated expenses are not
generated evenly during the year. Variations in energy usage by consumers occur
from season to season and from month to month within a season, primarily as a
result of weather conditions. The Company normally experiences its highest
energy sales in the first and fourth quarters of the year. Sales of electricity
to other utilities also vary by quarters and years depending principally upon
streamflow conditions for the generation of surplus hydro-electric power,
customer usage and the energy requirements of other neighboring utilities.
Earnings from electric operations therefore, since the discontinuance of the
PRAM in 1996, can be significantly influenced by surplus sales and variations in
weather, hydro conditions and non-firm regional electric energy prices. Earnings
from gas operations can be significantly influenced by variations in weather.
The Company has a purchased gas adjustment mechanism in retail rates to recover
variations in gas supply costs. (See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Rate Matters.")
During the period from January 1, 1994 through December 31, 1998, the
Company made gross electric utility plant additions of $729 million and
retirements of $154 million. In the five-year period ended December 31, 1998,
the Company made gross gas utility plant additions of $481 million and
retirements of $52 million. Gross electric utility plant at December 31, 1998,
was approximately $3.8 billion which consisted of 47% distribution, 25%
generation, 16% transmission and 12% general plant and other. Gross gas utility
plant at December 31, 1998, was approximately $1.3 billion which consisted of
82% distribution, 5% transmission and 13% general plant and other.
At year-end the Company had 2,996 aggregate full-time equivalent utility
employees.
Industry Overview
The electric and gas industries in the United States are undergoing
significant changes. The focus of these changes is to promote competition among
suppliers of electricity and gas and associated services. In 1996 and 1997, the
Federal Energy Regulatory Commission ("FERC") issued orders that require
utilities, including the Company, to file open access transmission tariffs that
will make the utilities' electric transmission systems available to wholesale
sellers and buyers on a non-discriminatory basis. A number of states, including
California, have restructured their electric industries to separate or
"unbundle" power generation, transmission and distribution in order to permit
new competitors to enter the market place. In part because electric rates in the
Pacific Northwest have been among the lowest in the nation, certain of the
legislatures in this region, including Washington, have not yet enacted laws to
provide for competition at the retail level. The Washington Commission has
initiated a pilot program, in which the Company participates, that permits
consumers limited direct access to competitive energy suppliers. The Company is
actively monitoring developments in this area and has indicated its support for
the enactment of legislation that would provide increased choice for electric
service customers in the state of Washington.
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In order to position itself to respond effectively to future
restructuring of the utility industry, and in anticipation of a competitive
environment for electric energy sales, the Company in 1997 organized its utility
operations into separate business units: energy delivery; energy supply and
customer solutions. This reorganization accommodates, if it occurs,
legislatively mandated unbundling of power generation from transmission and
distribution which would allow customers to purchase these services and
commodities individually from different suppliers or, alternatively, as a
complete package.
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. Although 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 1998, 123 commercial and
industrial customers, on average, chose to use such service.
Regulation and Rates
The Company is subject to the regulatory authority of (1) the Washington
Commission as to retail rates, accounting, the issuance of securities and
certain other matters and (2) the FERC with respect to the transmission of
electric energy, the resale of electric energy at wholesale, accounting and
certain other matters. (See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Rate Matters.")
Electric Utility Operations
At December 31, 1998, the Company's peak electric power resources were
approximately 5,145,610 KW. The Company's historical peak load of approximately
4,847,000 KW occurred on December 21, 1998.
During 1998, the Company's total electric energy production was supplied
25% by its own resources, 20% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydro-electric projects on
the Columbia River, 29% from other firm purchases and 26% from non-firm
purchases.
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The following table shows the Company's electric energy supply resources
at December 31, 1998, and energy production during the year:
PEAK POWER RESOURCES
AT DECEMBER 31, 1998 1998 ENERGY PRODUCTION
-----------------------------------------------------
KILOWATTS % KILOWATT-HOURS %
(THOUSANDS)
-----------------------------------------------------
Purchased Resources:
Columbia River
PUD Contracts (Hydro) 1,416,000 27.5% 6,471,295 20.1%
Other Hydro (a) 573,760 11.2% 3,015,835 9.3%
Other Producers (a) 1,401,900 27.2% 14,836,079 46.0%
- ------------------------------------------- -------- -------------- ---------
Total Purchased 3,391,660 65.9% 24,323,209 75.4%
- ------------------------------------------- -------- -------------- ---------
Company-owned Resources:
Hydro 308,200 6.0% 1,231,496 3.8%
Coal 771,900 15.0% 5,746,536 17.8%
Natural gas/oil 673,850 13.1% 956,698 3.0%
- ------------------------------------------- -------- -------------- ---------
Total Company-owned 1,753,950 34.1% 7,934,730 24.6%
- ------------------------------------------- -------- -------------- ---------
Total 5,145,610 100.0% 32,257,939 100.0%
- ------------------------------------------- -------- -------------- ---------
(a) Power received from other utilities is classified between hydro and
other producers based on the character of the utility system used to supply the
power or, if the power is supplied from a particular resource, the character of
that resource.
Company-Owned Electric Generation Resources
The Company and other utilities are joint owners of four mine-mouth,
coal-fired, steam-electric generating units at Colstrip, Montana, approximately
100 miles east of Billings, Montana. The Company owns a 50% interest (330,000
KW) in Units 1 and 2 and a 25% interest (350,000 KW) in Units 3 and 4. The
owners of the Colstrip Units purchase coal for the Units from Western Energy
Company ("Western Energy"), an affiliate of Montana Power Company ("Montana
Power") (one of the joint owners), under the terms of long-term coal supply
agreements. In February 1997, the Company, Montana Power and Western Energy
settled a dispute under a power sales agreement between Montana Power and the
Company and entered into an agreement to restructure the mines and plants. In
the third quarter of 1998, Western Energy, the Company and other joint owners of
Units 3 and 4 revised the coal supply contract which reduced the delivered price
of coal for Units 3 and 4 and allows for the joint owners to review and approve
mining plans and budgets.
In November 1998, the Company announced that it had signed an agreement
to sell its interest in the Colstrip plant, as well as associated transmission
facilities to PP&L Global, Inc., of Fairfax, Virginia, a subsidiary of PP&L
Resources, Inc.
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
PacifiCorp. The Company and other owners of the Centralia project are reviewing
emissions compliance options that will need to be adopted to meet Federal and
State emission requirements by the year 2000. The Company has joined with the
other owners of the Centralia project in offering for sale its ownership
interest in the facility. As part of the sale process, the Centralia owners are
reviewing the projected reclamation liability related to the coal mining
operations.
The Company also has the following plants with an aggregate net
generating capability of 982,050 KW: Upper Baker River hydro project (103,000
KW) constructed in 1959; Lower Baker River hydro project (71,400 KW)
reconstructed in 1960; White River hydro plant (63,400 KW) constructed in 1911
with installation of the last unit in 1924; Snoqualmie Falls hydro plant (44,000
KW), half the capability of which was installed during the period 1898 to 1910
and half in 1957; and one smaller hydro plant, Electron (26,400 KW), constructed
during the period 1904 to 1929; a standby internal combustion unit (2,750 KW)
installed in 1969; an oil-fired combustion turbine unit (67,500 KW) installed in
1974; four dual-fuel combustion turbine units (89,100 KW each) installed during
1981; and two dual-fuel combustion turbine units (123,600 KW each) installed
during 1984. All of these generating facilities are located in the Company's
service territory.
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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 are stored on-site. These plants are operated from time to time
for peaking purposes and to produce energy for sales to other utilities, either
directly or through tolling arrangements.
On December 19, 1997, the Company was issued a 50 year license by FERC
for its existing and operating White River project which includes authorization
to install an additional 14,000 KW generating unit. The Company has filed for a
rehearing with FERC on conditions of the license related to measures designed to
enhance salmon runs on the White River, because those conditions may make the
plant uneconomic to operate. The outcome of the Company's appeal before the FERC
is uncertain at this time. The initial license for the existing and operating
Snoqualmie Falls project expired in December 1993, and the Company continues to
operate this project under a temporary license. The Company is continuing the
FERC application process to relicense this project. The Company has also applied
for a license to expand its existing 1,750 KW Nooksack Falls project which is
currently unlicensed and not operating because of an electric generator fire in
1996.
Columbia River Electric Energy Supply Contracts
During 1998, approximately 20.1% of the Company's energy output was
obtained at an average cost of approximately 11.5 mills per KWH through
long-term contracts with several of the Washington PUDs owning hydro-electric
projects on the Columbia River.
The Company's purchases of power from the Columbia River projects is
generally on a "cost of service" basis under which the Company pays a
proportionate share of the annual debt service and operating and maintenance
costs of each project in proportion to the amount of power annually purchased by
the Company from such project. Such payments are not contingent upon the
projects being operable. These projects are financed through substantially level
debt service payments, and their annual costs may vary over the term of the
contracts as additional financing is required to meet the costs of major
maintenance, repairs or replacements or license requirements.
The Company has contracted to purchase from Chelan County PUD ("Chelan")
a share of the output of the original units of the Rock Island Project which
equaled 54.9% through June 30, 1998. 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, 1998, the Company's aggregate annual capacity from all units of the
Rock Island Project was 480,000 KW. The Company has contracted to purchase from
Chelan 38.9% (505,000 KW as of December 31, 1998) 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 31.3% (261,000 KW as of December
31, 1998) upon the additional exercise of withdrawal rights by Douglas County
PUD. The Company has contracted to purchase from Grant County PUD 8.0% (72,000
KW as of December 31, 1998) of the annual output of the Priest Rapids project
and 10.8% (98,000 KW as of December 31, 1998) of the annual output of the
Wanapum project, which percentages remain unchanged for the remainder of the
contracts. (See Note 17 to the Company's Consolidated Financial Statements.)
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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 hydro-electric power
plants and reservoirs in the Pacific Northwest. A new Coordination Agreement was
negotiated in 1997 and will replace the prior agreement in February 1999.
Various fishery enhancement measures, including most recently the 1995
"biological opinion" from the National Marine Fisheries Service ("NMFS"), have
reduced the flexibility provided by the Coordination Agreement. (See
"Environment - Federal Endangered Species Act.")
Certain utilities in the northwest United States and Canada are obtaining
the benefits of additional firm power as a result of the ratification of a 1961
treaty between the United States and Canada under which Canada is providing
approximately 15,500,000 acre-feet of reservoir storage on the upper Columbia
River. As a result of this storage, streamflow which would otherwise not be
usable to serve firm regional load is stored and later released during periods
when it is usable. Pursuant to the treaty, one-half of the firm power benefits
produced by the additional storage accrue to Canada. The Company's benefits from
this storage are based upon its percentage participation in the Columbia River
projects and one-half of those benefits must be returned to Canada. Also in
1961, the Company contracted to purchase 17.5% of Canada's share of the power to
be returned resulting from such storage until a phased expiration of the
contract from 1998 through 2003. The Company has also contracted to purchase
from the Bonneville Power Administration ("BPA") supplemental capacity in
amounts that decrease gradually until a phased expiration of the contract from
1998 through 2003. In 1997, the Company entered into agreements with the Mid
Columbia PUDs which specify the amount of the Company's share of the obligation
to return one-half of the firm power benefits to Canada beginning in 1998 and
continuing until the earlier of the expiration of the PUD contracts or 2024.
Electric Energy Supply Contracts and Agreements With Other Utilities
Under a 1985 settlement agreement relating to Washington Public Power
Supply System ("WPPSS") Nuclear Project No. 3, in which the Company had a 5%
interest, the Company is receiving from BPA for approximately 30.5 years,
beginning January 1, 1987, electric power during the months of November through
April. Under the contract, the Company is guaranteed to receive not 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 Avista Corporation (formerly Washington Water Power Company). This
agreement calls for the delivery of 100 MW of capacity and 657,000 MWH of energy
from the Avista system annually (75 annual average MW). Minimum and maximum
delivery rates are prescribed. Under this agreement, the energy is to be priced
at Avista'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 PacifiCorp. 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. In 1997, the Company elected to terminate the
agreement on June 30, 2001, the date that the purchase was to convert to a
summer-winter exchange.
On October 1, 1989, the Company signed a contract with Montana Power
under which Montana Power provides the Company, from its share of Colstrip Unit
4, 71 average MW of energy (94 MW of peak capacity) over a 21-year period. On
February 27, 1995, the Company delivered to Montana Power notice of termination
of the contract based on Montana Power's failure to arrange for firm contractual
transmission rights for such energy as required by the contract. Pursuant to a
settlement between the Company and Montana Power on February 21, 1997, the
contract remains in effect and the price of power purchased by the Company is
reduced. The settlement also addressed certain price reductions and
restructuring activities in connection with the Colstrip coal supply
arrangements.
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On December 11, 1989, the Company executed a conservation transfer
agreement with Snohomish County PUD. Snohomish County PUD, together with Mason
and Lewis County PUDs, will install conservation measures in their service
areas. The agreement calls for the Company to receive the power saved over the
expected 20-year life of the measures. The agreement calls for BPA to deliver
the conservation power to the Company from March 1, 1990, through June 30, 2001,
and for Snohomish County PUD to deliver the conservation power for the remaining
term of the agreement. Annual power deliveries gradually increased over the
first five years of the agreement and will remain at 6 average MW of energy
throughout the remaining term of the agreement.
The Company executed an exchange agreement with Pacific Gas & Electric
Company which became effective on January 1, 1992. Under the agreement, 300 MW
of capacity together with 413,000 MWH of energy are exchanged seasonally every
year on a unit for unit basis. No payments are made under this agreement.
Pacific Gas & Electric Company is a summer peaking utility and will provide
power during the months of November through February. The Company is a winter
peaking utility and will provide power during the months of June through
September. Each party may terminate the contract for various reasons. The
Company has obtained 400,000 KW of transmission rights (similar in nature to
ownership type rights) on the Pacific Northwest-Southwest AC Intertie to
California. These transmission rights which are used, in part, to transmit power
under this agreement, have been subject to unanticipated limitations and
curtailments over the past several years. The Company is working with BPA to
obtain a restoration of these rights and compensation for damages.
In October 1997 a 10-year power exchange agreement between the Company
and Powerex (a subsidiary of a British Columbia utility) became effective. Under
this agreement Powerex pays the Company for the right to deliver power to the
Company at the Canadian border in exchange for the Company delivering power to
Powerex at various locations in the United States. The Company also obtained
425,000 KW of transmission rights (similar in nature to ownership type rights)
on the Westside Northern Intertie to Canada in October 1997. These transmission
rights which are used, in part, to transmit power under this agreement have been
subject to unanticipated limitations and curtailments. The Company is working
with BPA to obtain a restoration of these rights.
Electric Energy Supply Contracts and Agreements With Non-Utilities
As required by the federal Public Utility Regulatory Policies Act
("PURPA"), the Company entered into long-term firm purchased power contracts
with non-utility generators. The most significant of these are the five
contracts described below which the Company entered into in 1989, 1990 and 1991
with operators of natural gas-fired cogeneration projects. The Company purchases
the net electrical output of these five projects at fixed and annually
escalating prices which were intended to approximate the Company's avoided cost
of new generation projected at the time these agreements were made. Principally
as a result of dramatic changes in natural gas price levels, the power purchase
prices under these agreements are significantly above the current market price
of power and, based upon projections of future market prices, are expected to
remain well above market for the duration of the contracts. The Company's
estimated payments under these five contracts are $280 million for 1999, $284
million for 2000, $308 million for 2001, $313 million for 2002, $318 million for
2003 and in the aggregate, $2.4 billion thereafter through 2012. These payments
reflect the Tenaska contract restructuring described below. The Company
continues to seek restructuring of the other four contracts. If retail electric
energy prices move to market levels as a result of electric industry
restructuring, the Company plans to seek to continue to recover in rates the
above market portion of these contract costs.
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.
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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.
On March 20, 1991, the Company executed a 20-year contract to purchase
216 average MW of energy and 245 MW of capacity, beginning in April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas fired
cogeneration project located near Ferndale, Washington. In December 1997 and
January 1998, the Company and Tenaska Washington Partners entered into revised
agreements which will lower purchased power costs from the Tenaska project by
restructuring its natural gas supply. The Company paid $215 million to buy out
the project's existing long-term gas supply contracts, which contained fixed and
escalating gas prices that were well above current and projected future market
prices for natural gas. The Company became the principal natural gas supplier to
the project and power purchase prices under the Tenaska contract were revised to
reflect market-based prices for the natural gas supply. The Company obtained an
order from the Washington Commission creating a regulatory asset related to the
$215 million restructuring payment. Under terms of the order, the Company is
allowed to accrue as an additional regulatory asset one-half the carrying costs
of the deferred balance over the first five years. These revised arrangements
are expected to reduce the Company's power supply costs from the Tenaska project
between 15 and 20 percent annually over the remaining 13-year life of the
contract, net of the costs of the restructuring payment. The Company's purchased
electric energy cost associated with the Tenaska contract was $80.1 million in
1998.
Energy Trading
On April 1, 1998, the Company and Duke Energy Trading and Marketing
("DETM") of Houston, a unit of Duke Energy Corp., signed an agreement relating
to energy-marketing and trading activities in 14 western States and British
Columbia. The purpose of this agreement is to coordinate the two companies'
activities in serving Puget Sound Energy's native power load with DETM's western
power and natural gas marketing and trading operations. The companies share the
benefits of this coordination proportionally up to certain stipulated amounts
intended to be reflective of the value the companies would have realized from
their respective operations in the absence of the agreement. The companies share
equally any benefits created above the stipulated amounts.
Under the terms of the agreement, DETM performs the forward electric
energy trading function. As a result, the Company's future wholesale "sales to
other utilities" revenues and related "secondary purchase" power expenses, which
previously have reflected trading activity by the Company, will be lower than
amounts which the Company would report absent this agreement. During 1998, the
Company continued to execute in its own name transactions in which electric
energy is delivered within the next 30 days. Therefore, the Company's results
include those transactions. The Company recorded its share of the benefits that
result from the agreement as a credit to purchased power expense. The agreement
provides that forward trading activities will be conducted according to DETM's
energy price risk and credit policies, and that the Company is not responsible
for any losses caused by deviation from these policies. The Company and DETM are
presently considering modifications to the agreement.
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Electric Rates and Regulation
The order approving the merger of the Company, Washington Energy Company
and Washington Natural Gas Company ("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. General electric
tariff rates were stipulated to increase between 1.0% to 1.5% depending on rate
class on January 1, 1999 through 2001, while those for certain customers will
increase by 1.5% in 2002.
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<TABLE>
ELECTRIC UTILITY OPERATING STATISTICS
<CAPTION>
Year Ended on December 31 1998 1997 1996 1995 1994
- --------------------------------- ------------- ------------- ------------- -------------- -------------
<S> <C> <C> <C> <C> <C>
Operating revenues by classes:
(thousands)
- --------------------------------- ------------- ------------- ------------- -------------- -------------
Residential $540,549 $529,990 $554,318 $524,748 $532,124
Commercial 431,752 414,480 423,139 397,211 375,751
180,959 166,473 170,596 168,501 163,574
Industrial
Other 42,952 32,453 44,125 38,730 38,759
consumers
- --------------------------------- ------------- ------------- ------------- -------------- -------------
Operating revenues
billed to consumers (a) 1,196,212 1,143,396 1,192,178 1,129,190 1,110,208
Unbilled revenues -
net increase (decrease) 4,024 (4,921) 13,201 (6,382) (2,522)
PRAM -- (40,777) (74,326) 3,955 25,835
accrual
- --------------------------------- ------------- ------------- ------------- -------------- -------------
Total operating revenues
from consumers 1,200,236 1,097,698 1,131,053 1,126,763 1,133,521
Other utilities and 274,972 133,726 67,716 52,567 60,537
marketers
- --------------------------------- ------------- ------------- ------------- -------------- -------------
Total operating revenues $1,475,208 $1,231,424 $1,198,769 $1,179,330 $1,194,058
- --------------------------------- ------------- ------------- ------------- -------------- -------------
Number of customers (average):
Residential 782,095 767,476 754,097 739,173 723,566
94,118 91,517 89,613 87,404 85,203
Commercial
4,193 4,090 3,993 3,908 3,851
Industrial
1,437 1,389 1,371 1,346 1,325
Other
- --------------------------------- ------------- ------------- ------------- -------------- -------------
Total customers 881,843 864,472 849,074 831,831 813,945
(average)
- --------------------------------- ------------- ------------- ------------- -------------- -------------
KWH generated, purchased and
interchanged (thousands):
Company generated 7,934,730 6,641,118 5,585,595 6,371,416 7,011,932
Purchased power 24,231,978 22,611,963 20,573,983 17,897,922 16,268,042
Interchanged power (net) 91,230 103,959 99,942 48,485 (87,771)
- --------------------------------- ------------- ------------- ------------- -------------- -------------
Total energy output 32,257,938 29,357,040 26,259,520 24,317,823 23,192,203
Losses and company use (1,413,331) (1,414,101) (1,322,262) (1,235,457) (1,291,322)
- --------------------------------- ------------- ------------- ------------- -------------- -------------
Total energy sales 30,844,607 27,942,939 24,937,258 23,082,366 21,900,881
- --------------------------------- ------------- ------------- ------------- -------------- -------------
</TABLE>
(a) Operating revenues in 1998, 1997, 1996 and 1995 were reduced by $46.7
million, $40.5 million, $41.0 million and $25.1 million, respectively, as a
result of the Company's sale of $237.7 million of its investment in
customer-owned energy conservation measures. (See "Operating Revenues-Electric"
in Management's Discussion and Analysis and Note 1 to the Consolidated Financial
Statements.)
11
<PAGE>
(continued from previous page)
<TABLE>
<CAPTION>
YEAR ENDED ON DECEMBER 31 1998 1997 1996 1995 1994
- --------------------------------------------- ------------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Electric energy sales, KWH:
(thousands)
- --------------------------------------------- ------------- ------------ ------------ ------------ ------------
Residential 9,313,652 9,319,508 9,350,292 8,972,498 8,913,903
Commercial 7,191,164 7,022,092 6,807,465 6,538,533 6,301,568
Industrial 4,072,722 3,994,748 3,793,966 3,720,641 3,724,931
Other consumers 284,312 206,330 205,066 205,232 200,622
- --------------------------------------------- ------------- ------------ ------------ ------------ ------------
Total energy billed to consumers 20,861,850 20,542,678 20,156,789 19,436,904 19,141,024
Unbilled energy sales -
net increase (decrease) 43,027 (45,556) 224,412 (158,920) (72,352)
- --------------------------------------------- ------------- ------------ ------------ ------------ ------------
Total energy sales to consumers 20,904,877 20,497,122 20,381,201 19,277,984 19,068,672
Sales to other utilities and marketers 9,939,730 7,445,817 4,556,057 3,804,382 2,832,209
- --------------------------------------------- ------------- ------------ ------------ ------------ ------------
Total energy sales 30,844,607 27,942,939 24,937,258 23,082,366 21,900,881
- --------------------------------------------- ------------- ------------ ------------ ------------ ------------
Per residential customer:
Annual use (KWH) 11,909 12,143 12,399 12,139 12,319
Annual billed revenue $721.09 $716.88 $762.35 $726.95 $735.42
Billed revenue per KWH $.0606 $.0590 $.0615 $.0599 $.0597
Company-owned generation capability - KW:
Hydro 308,200 309,950 309,950 309,950 309,950
Steam 771,900 771,900 771,900 771,900 771,900
Natural gas/oil 673,850 702,350 702,350 702,350 702,350
- --------------------------------------------- ------------- ------------ ------------ ------------ ------------
Total 1,753,950 1,784,200 1,784,200 1,784,200 1,784,200
- --------------------------------------------- ------------- ------------ ------------ ------------ ------------
Heating degree days 4,498 4,599 4,953 3,994 4,341
% of normal of 30 year
average 91.6% 93.7% 100.9% 81.4% 88.4%
Load factor 52.6% 58.7% 55.5% 56.7% 54.7%
</TABLE>
12
<PAGE>
Gas Utility Operations
Gas Supply
The Company currently purchases a blended portfolio of long-term firm,
short-term firm, and spot gas supplies from a diverse group of major and
independent producers and gas marketers in the United States and Canada. All of
the Company's gas supply is ultimately transported through Northwest Pipeline
Corporation ("NPC"), the sole interstate pipeline delivering directly into the
western Washington area.
PEAK FIRM GAS SUPPLY AT DECEMBER 31, 1998 DTH PER DAY %
- ---------------------------------------------- ------------- -------
Purchased Gas Supply
British Columbia 212,400 27.8
Alberta 75,900 9.9
United States 50,900 6.7
- ---------------------------------------------- ------------- -------
Total Purchased Gas Supply 339,200 44.4
- ---------------------------------------------- ------------- -------
Purchased Storage Capacity
Clay Basin 89,900 11.8
Jackson Prairie 47,700 6.2
LNG 69,600 9.1
- ---------------------------------------------- ------------- -------
Total Purchased Storage Capacity 207,200 27.1
- ---------------------------------------------- ------------- -------
Owned Storage Capacity
Jackson Prairie 188,400 24.6
Propane-Air Injection 30,000 3.9
- ---------------------------------------------- ------------- -------
Total Owned Storage Capacity 218,400 28.5
- ---------------------------------------------- ------------- -------
Total Peak Firm Gas Supply 764,800 100.0
- ---------------------------------------------- ------------- -------
All supplies and storage are connected to PSE's market with firm transportation
capacity.
For baseload and peak-shaving purposes, the Company supplements its firm
gas supply portfolio by purchasing natural gas at generally lower prices in
summer, injecting it into underground storage facilities and withdrawing it
during the winter heating season. Storage facilities at Jackson Prairie in
Western Washington and at Clay Basin in Utah are used for this purpose. Peaking
needs are also met by using Company-owned gas held in NPC's liquefied natural
gas ("LNG") facility at Plymouth, Washington, and by producing propane-air gas
at a plant owned by the Company and located on its distribution system.
In 1998, the Company took assignment from Cascade Natural Gas of a
Peaking Gas Supply Service ("PGSS") contract whereby the Company can divert up
to 48,000 MMBTu per day of gas supply away from the Tenaska Cogeneration
Facility and toward the core gas load by causing Tenaska to operate its facility
on distillate fuel and paying any additional costs of such operation.
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.
13
<PAGE>
Gas Supply Portfolio
For the 1998-99 winter heating season, the Company has contracted for
approximately 28% of its expected peak-day gas supply requirement from sources
originating in British Columbia under a combination of long-term and
winter-peaking purchase agreements. Long-term gas supplies from Alberta
represent approximately 10% of the peak-day requirement. Long-term and winter
peaking arrangements with U.S. suppliers and gas stored at Clay Basin make up
approximately 18% of the peak-day portfolio. The balance of the peak-day
requirement is expected to be met with gas stored at Jackson Prairie, LNG held
at NPC's Plymouth facility and propane-air resources, which represent
approximately 31%, 9% and 4%, respectively, of expected peak-day requirements.
During 1998, approximately 46% of gas supplies purchased by the Company
originated from British Columbia while 27% originated in Alberta and 27%
originated in the U.S.
The current firm, long-term gas supply portfolio consists of arrangements
with 16 producers and gas marketers, with no single supplier representing more
than 15% of expected peak-day requirements. Contracts have remaining terms
ranging from less than one year to 13 years, with an average term of 2 years.
All gas supply contracts contain market-sensitive pricing provisions based on
several published indices.
The Company's firm gas supply portfolio is structured to capitalize on
regional price differentials when they arise. Gas and services are marketed
outside the Company's service territory ("off-system sales") whenever on-system
customer demand requirements permit. The geographic mix of suppliers and daily,
monthly and annual take requirements permit a high degree of flexibility in
selecting gas supplies during off-peak periods to minimize costs.
Gas Transportation Capacity
The Company currently holds firm transportation capacity on pipelines
owned by NPC and PG&E Gas Transmission-Northwest, formerly known as Pacific Gas
Transportation ("PGT"). Accordingly, the Company pays fixed monthly demand
charges for the right, but not the obligation, to transport specified quantities
of gas from receipt points to delivery points on such pipelines each day for the
term or terms of the applicable agreements.
The Company holds firm capacity on NPC's pipeline totaling 454,533
Dekatherms per day (one Dekatherm "Dth" is equal to one million British thermal
units or "MMBTu" per day), acquired under several agreements at various times.
The Company has exchanged certain segments of its firm capacity with third
parties to effectively lower transportation costs. The Company's firm
transportation capacity contracts with NPC have remaining terms ranging from 6
to 17 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 current FERC orders. The Company's firm transportation capacity
on PGT's pipeline has a remaining term of 25 years.
Gas Storage Capacity
The Company holds storage capacity in the Jackson Prairie and Clay Basin
underground gas storage facilities adjacent to NPC's pipeline. The Jackson
Prairie facility, operated and one-third owned by the Company, is used primarily
for intermediate peaking purposes, able to deliver a large volume of gas over a
relatively short time period. Combined with capacity contracted from NPC's
one-third stake in Jackson Prairie, the Company has peak, firm delivery capacity
of over 230,000 Dth per day and total firm storage capacity exceeding 6,000,000
Dth at the facility. The location of the Jackson Prairie facility in the
Company's market area provides significant cost savings by reducing the amount
of annual pipeline capacity required to meet peak-day gas requirements. The
Company, as project operator of the facility, received approval from FERC on
September 30, 1998, to expand the Jackson Prairie facility. The Company's share
of the expanded project will provide additional firm delivery capacity of over
100,000 Dth per day and additional firm storage capacity of above 1,000,000 Dth
at the start of the 1999-2000 heating season. The Company has secured rights to
additional firm seasonal pipeline capacity to be utilized in conjunction with
the expanded project.
14
<PAGE>
The Clay Basin storage facility is supply area storage and is withdrawn
over the entire winter, capturing savings due to injecting lower cost gas
supplies during the summer. The Company has maximum firm withdrawal capacity of
over 100,000 Dth per day from the facility with total storage capacity exceeding
13,000,000 Dth. The capacity is held under two contracts with remaining terms of
15 and 21 years.
LNG and Propane-Air Resources
LNG and propane-air resources provide gas supply on short notice for
short periods of time. Due to their high cost, these resources are utilized as
the supply of last resort in extreme peak-demand periods, typically lasting a
few hours or days. The Company has long-term contracts for storage of nearly
250,000 Dth of Company-owned gas as LNG at NPC's Plymouth facility, which
equates to approximately three and one-half days' supply at maximum daily
deliverability of 70,500 Dth. The Company owns storage capacity for
approximately 1.4 million gallons of propane. The propane-air injection
facilities are capable of delivering the equivalent of 30,000 Dth of gas per day
for up to four days directly into the Company's distribution system.
Capacity Release
FERC provided a capacity release mechanism as the means for holders of
firm pipeline and storage entitlements to relinquish temporarily unutilized
capacity to others in order to recoup all or a portion of the cost of such
capacity. Capacity may be released through several methods including open
bidding and by pre-arrangement. The Company continues to successfully mitigate a
substantial portion of the demand charges related to both storage and NPC and
PGT pipeline capacity not utilized during off-peak periods. WNG CAP I, a wholly
owned subsidiary of the Company, was formed to provide additional flexibility
and benefits from capacity release. Washington Energy Gas Marketing
Company("WEGM"), a wholly-owned subsidiary of the Company, also markets excess
capacity on the PGT pipeline. (See Note 17 to the Consolidated Financial
Statements.)
Gas Rates and Regulation
The order approving the Merger, issued by the Washington Commission on
February 5, 1997, contains a rate plan which provided unchanged rates for all
classes of natural gas customers until January 1, 1999, when rates decreased by
1% on gas utility margins.
On March 25, 1998, the WUTC approved the Company's Purchase Gas
Adjustment ("PGA") and deferral amortization (true-up) filing effective April 1,
1998. The PGA filing reflected a reduction in expected gas costs of
approximately $4.3 million. The deferral amortization filing was a refund to
customers for prior period over-collections of gas costs. This filing replaced a
larger deferral amortization refund that had been in effect since May 1995. The
combined filings reduced gas rates to all sales customers less than 1%.
On June 25, 1998, the Company received approval from the Washington
Commission to begin a new performance-based mechanism for strengthening its
gas-supply purchasing and gas-storage practices. The PGA Incentive Mechanism,
which encourages competitive gas purchasing and management of pipeline and
storage-capacity became effective July 1, 1998. Incentive gains and losses from
the three-year program are shared between customers and shareholders. After the
first $0.5 million, which is allocated to customers, gains and losses are shared
40%/60% between the Company and customers up to $26.5 million, and 33%/67%
thereafter. Gains or losses are determined relative to a weighted average index
which is reflective of the Company's gas supply and transportation contract
costs. The Company's share of incentive gains under the PGA Incentive Mechanism
in 1998 were approximately $1.1 million while customers received approximately
$2.0 million.
15
<PAGE>
<TABLE>
GAS UTILITY OPERATING STATISTICS
<CAPTION>
Twelve Months Ended December 31 1998 1997 1996 1995 1994
- --------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
<S> <C> <C> <C> <C> <C>
Operating revenues by classes (thousands):
Regulated utility sales:
Residential sales $253,169 $246,747 $238,560 $231,202 $206,602
Commercial firm sales 96,116 97,233 94,251 97,396 91,749
Industrial firm sales 18,557 19,524 20,024 25,860 28,827
Interruptible sales 22,190 19,832 23,376 44,511 51,425
Transportation services 14,211 14,631 12,812 10,762 8,399
Other 12,308 11,480 11,085 10,317 9,405
- --------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
Total gas operating revenues $416,551 $409,447 $400,108 $420,048 $396,407
- --------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
Customers, average number served
Residential 486,553 465,185 440,586 423,195 403,642
Commercial firm 42,273 41,158 39,651 38,378 37,112
Industrial firm 2,850 2,839 2,762 2,754 2,824
Interruptible 940 962 1,000 1,037 1,009
Transportation 123 128 106 55 36
- --------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
Total customers (average) 532,739 510,272 484,105 465,419 444,623
- --------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
Gas volumes (thousands of therms):
Residential sales 444,611 434,179 421,727 398,283 371,472
Commercial firm sales 193,765 195,087 188,321 179,725 174,668
Industrial firm sales 42,737 44,563 46,640 55,365 62,698
Interruptible sales 72,115 60,244 72,229 132,316 151,175
Transportation volumes 254,368 277,092 242,299 156,941 119,590
- --------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
Total gas volumes 1,007,596 1,011,165 971,216 922,630 879,603
- --------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
Working-gas volumes in storage at year end
(thousands of therms)
Jackson Prairie 37,683 52,430 65,834 65,834 65,834
Clay Basin 58,827 64,930 82,847 130,970 47,557
Average use per customer (therms):
Residential 914 933 957 941 921
Commercial firm 4,584 4,740 4,749 4,683 4,708
Industrial firm 14,995 15,697 16,886 20,103 22,035
Interruptible 76,718 62,624 72,229 127,595 147,315
Transportation 2,068,033 2,164,781 2,285,840 2,853,473 3,400,694
</TABLE>
16
<PAGE>
(continued from prior page)
<TABLE>
<CAPTION>
TWELVE MONTHS ENDED DECEMBER 31 1998 1997 1996 1995 1994
- --------------------------------------- ------------ ------------- ------------ ----------- ------------
<S> <C> <C> <C> <C> <C>
Average revenue per customer:
Residential $ 520 $ 530 $ 541 $ 546 $ 512
Commercial firm 2,274 2,362 2,377 2,538 2,472
Industrial firm 6,511 6,877 7,250 9,390 10,208
Interruptible 23,606 20,615 23,376 42,923 50,966
Transportation 115,537 114,305 120,868 195,673 233,306
Average revenue per therm (cents):
Residential 56.9 56.8 56.6 58.0 55.6
Commercial firm 49.6 49.8 50.0 54.2 52.5
Industrial firm 43.4 43.8 42.9 46.7 46.0
Interruptible 30.8 32.9 32.4 33.6 34.0
Total sales to customers 51.8 52.2 51.6 52.1 49.8
Transportation 5.6 5.3 5.3 6.9 7.0
Weather - degree days 4,498 4,599 4,953 3,994 4,341
% of normal (30-year average) 91.6% 93.7% 100.9% 81.4% 88.4%
</TABLE>
Note: Data prior to January 1, 1997, is for the period ending September 30.
Energy Conservation
The Company offers programs designed to help new and existing customers
use energy efficiently. The primary emphasis is to provide information and
technical services to enable customers to make energy-efficient choices with
respect to building design, equipment and building systems, appliance purchases
and operating practices.
Since May 1997, the Company has recovered electric energy conservation
expenditures through a tariff rider mechanism. The rider mechanism allows the
Company to defer the conservation expenditures and amortize them to expense as
the Company concurrently collects the conservation expenditures in rates over a
one year period. As a result of the rider, there is no effect on earnings per
share.
Since 1995, the Company has been authorized by the Washington Commission
to defer gas energy conservation expenditures and recover them through a tariff
tracker mechanism. The tracker mechanism allows the Company to defer
conservation expenditures and recover them in rates over the subsequent year.
The tracker mechanism also allows the Company to recover an Allowance for Funds
Used to Conserve Energy (AFUCE) on any outstanding balance that is not being
recovered in rates.
Environment
The Company's operations are subject to environmental regulation by
federal, state and local authorities. Due to the inherent uncertainties
surrounding the development of federal and state environmental and energy laws
and regulations, the Company cannot determine the impact such laws may have on
its existing and future facilities. (See Note 17 to the Consolidated Financial
Statements for further discussion of environmental sites.)
Federal Clean Air Act Amendments of 1990
The Company has an ownership interest in coal-fired, steam-electric
generating plants at Centralia, Washington and Colstrip, Montana, which are
subject to the federal Clean Air Act Amendments of 1990 ("CAAA") and other
regulatory requirements.
The Centralia Project and the Colstrip Projects met the sulfur dioxide
limits of the CAAA in Phase I (1995). The Company and other joint owners of the
Centralia Project are exploring alternative emission compliance options and
project economics in light of compliance costs to meet the Phase II limits in
the year 2000. All four units at the Colstrip Project, operated by Montana
Power, meet Phase II emission limits.
17
<PAGE>
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, or that restrictions on emissions of carbon dioxide or other
combustion by-products may not be imposed.
Federal Endangered Species Act
In November 1991, the National Marine Fisheries Service ("NMFS") listed
the Snake River Sockeye as an endangered species pursuant to the federal
Endangered Species Act ("ESA"). Since the Sockeye listing, the Snake River fall
and spring/summer Chinook have also been listed as threatened. In response to
the listings, a team of experts was formed to develop a plan for the recovery
needs of these species. In 1995, the NMFS issued a biological opinion which has
significantly changed the operation of the Federal Columbia River Power System.
The plans developed by NMFS affect the Mid-Columbia projects from which
the Company purchases power on a long-term basis, and will further reduce the
flexibility of the regional hydro-electric system. Although the full impacts are
unknown at this time, the plan developed by NMFS shifts an amount of the
Company's generation from the Mid-Columbia projects from winter periods into the
spring when it is not needed for system loads, and will increase the potential
for spill and loss of generation at the Mid-Columbia projects.
Since the 1991 listings, one more species of salmon has been listed and
two more have been proposed which may further influence operations. Upper
Columbia River Steelhead were listed by NMFS in August 1997. Anticipating the
Steelhead listing, the Mid-Columbia PUDs initiated consultation with the federal
and state agencies, Native American tribes and non-governmental organizations to
secure operational protection through a long-term settlement and habitat
conservation plan which includes fish protection and enhancement measurement for
the next 50 years. The negotiations have concluded among the Chelan and Douglas
County PUDs and various fishery agencies, and final agreement is subject to a
National Environmental Policy Act review and power purchaser approval.
Generally, the agreement obligates the PUDs to achieve certain levels of passage
efficiency for downstream migrants at their hydro-electric facilities and to
fund certain habitat conservation measures. Grant County PUD has yet to reach
agreement on these issues.
The proposed listings of Puget Sound Chinook salmon and spring Chinook
for the upper Columbia will be final, if approved, in March 1999. The listing of
spring Chinook for the upper Columbia should not result in markedly differing
conditions for operations from previous listings in the area. However, Puget
Sound has not experienced ESA listing to date and listing of Puget Sound Chinook
could cause a number of changes to operations of government agencies and private
entities in the region including the Company. These may adversely affect hydro
plant operations, permit issuance for facilities construction and increased
costs for process and facilities. Because the Company relies substantially less
on hydro-electric energy from the Puget Sound area than from the Mid-Columbia
and because the impact on Company operations in the Puget Sound area is not
likely to impair significant generating resources, the impact of listing for
Puget Sound Chinook salmon should be proportionately less than the Columbia
River listings.
18
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of the Company's business includes some
forward-looking statements that involve risks and uncertainties. Words such as
"estimates," "expects," "anticipates," "plans," and similar expressions identify
forward-looking statements involving risks and uncertainty. Those risks and
uncertainties include, but are not limited to, the ongoing restructuring of the
electric and gas industries and the outcome of regulatory proceedings related to
that restructuring. The ultimate impacts of both increased competition and the
changing regulatory environment on future results are uncertain, but are
expected to fundamentally change how the Company conducts its business. The
outcome of these changes and other matters discussed below may cause future
results to differ materially from historic results, or from results or outcomes
currently expected or sought by the Company.
Financial Condition and Results of Operations
Financial condition and results of operations for 1998 and 1997 reflect
the results of Puget Sound Energy, Inc., formerly Puget Sound Power & Light
Company ("Puget"). Financial condition and results of operations for 1996
reflect combined results for the fiscal years ended December 31 for Puget and
September 30 for Washington Energy Company ("WECO"). On February 10, 1997, WECO
and its subsidiary, Washington Natural Gas Company, merged into Puget, which
then changed its name to Puget Sound Energy, Inc.
Net income in 1998 was $169.6 million on operating revenues of $1.907
billion, compared to $123.1 million on operating revenues of $1.677 billion in
1997 and $165.5 million on operating revenues of $1.649 billion in 1996. Income
for common stock was $156.6 million in 1998, compared to $105.7 million in 1997
and $143.3 million in 1996.
Basic and diluted earnings per share in 1998 were $1.85 on 84.6 million
weighted average common shares outstanding compared to $1.25 on 84.6 million
weighted average common shares outstanding in 1997 including a $.03 loss per
share from discontinued operations and $1.70 on 84.4 million weighted average
common shares outstanding in 1996 including a $.02 loss per share from
discontinued operations.
Contributing to the increase in net income and basic and diluted earnings
per share in 1998 compared to 1997 were continued growth in retail electric and
gas customers and a reduction in utility operations and maintenance expense of
approximately $13.6 million or 5% in 1998 compared to 1997. Net income for 1997
included an after-tax charge of $36.3 million ($0.43 per share) for costs
related to the merger including transaction expenses, employee separation and
system and facilities integration. Net income in 1997 also included an after-tax
charge of $2.6 million ($0.03 per share), to write off the Company's remaining
investment in undeveloped coal reserves and related activities in southeastern
Montana (See Note 18 to the Consolidated Financial Statements). These charges in
1997 were partially offset by $13.6 million ($0.16 per share) related to an
income tax refund received in 1997. Excluding the impact of these charges and
credits to income, continuing operations for 1997 produced earnings of $1.55 per
share. Total kilowatt-hour sales to ultimate consumers in 1998 were 20.9
billion, compared with 20.5 billion in 1997 and 20.4 billion in 1996.
Kilowatt-hour sales to other utilities were 9.9 billion in 1998, 7.4 billion in
1997 and 4.6 billion in 1996.
Total gas volumes sold, including transported gas, were 1,008 million
therms in 1998, 1,011 million therms in 1997 and 971 million therms in 1996.
19
<PAGE>
INCREASE (DECREASE) OVER PRECEDING YEAR
YEARS ENDED DECEMBER 31 (DOLLARS IN MILLIONS)
1998 1997 1996
- ------------------------------------------------ --------- ---------- ---------
Operating revenues:
General rate increases $18.5 $16.9 $ --
PRAM electric revenue surcharges/refunds 44.8 (22.6) (37.1)
BPA Residential Purchase and
Sale Agreement (1.2) 2.7 (15.8)
Electric sales to other utilities 141.2 66.0 15.1
Electric revenue sold to conservation trust (6.2) 0.5 (15.9)
Electric load and other changes 46.7 (30.8) 73.1
Gas revenue change 7.1 9.3 (19.9)
Other revenues (20.5) (14.4) 18.7
- ------------------------------------------------ ---------- ---------- --------
Total operating revenue changes 230.4 27.6 18.2
- ------------------------------------------------ --------- ---------- ---------
Operating expenses:
Energy costs:
Purchased electricity 137.2 52.6 38.8
Residential exchange 16.4 31.2 (15.1)
Purchased gas (3.5) 1.6 (41.3)
Electric generation fuel 15.1 0.8 5.0
Utility operations and maintenance (13.6) 8.3 (16.6)
Other operations and maintenance (13.6) (11.0) 2.7
Depreciation and amortization 3.7 17.6 3.2
Merger and related costs (55.8) 51.0 4.8
Taxes other than federal income taxes 1.2 4.1 6.3
Federal income taxes 60.2 (60.0) 16.2
- ------------------------------------------------ --------- ---------- ---------
Total operating expense changes 147.3 96.2 4.0
- ------------------------------------------------ --------- ---------- ---------
Other income (18.9) 26.5 16.4
Interest charges 20.3 (0.5) (8.3)
Discontinued operations 2.6 (0.8) 24.8
- ------------------------------------------------ --------- ----------- --------
Net income changes $ 46.5 $(42.4) $ 63.7
- ------------------------------------------------ --------- ----------- --------
The following information pertains to the changes outlined in the table
above:
Operating Revenues - Electric
Electric operating revenues increased $18.5 million in 1998 and $16.9
million in 1997 when compared to the prior years due to an overall average 1.8%
general rate increase effective February 8, 1997 and an overall average 1.2%
general rate increase effective January 1, 1998.
Electric operating revenues in 1998 increased $44.8 million compared to
1997 as a result of a $48.6 million Periodic Rate Adjustment Mechanism ("PRAM")
revenue reduction in 1997 associated with an IRS 1991-1994 Conservation tax
refund and related interest income. Based on the Company's agreement with the
Washington Commission, the benefit of the tax refund was passed on to retail
customers as a reduction of the PRAM accruedrevenue balance. The $48.6 million
reduction in revenues in 1997 was offset by a decrease in federal, state and
local taxes as well as a decrease in interest expense and a recognition of
interest income.
20
<PAGE>
On September 30, 1996, the PRAM was discontinued pursuant to a negotiated
settlement and 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. A $17.0 million overcollection of the PRAM, which
resulted from the pass-through of conservation tax refunds, was refunded to
customers in 1997.
Electric revenues in 1998, 1997 and 1996 were reduced because 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 related 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 ends
the Company's participation in the Residential Purchase and Sale Agreement with
BPA. As part of the Termination Agreement, the Company will receive payments by
the BPA of approximately $235 million over an approximately 5-year period ending
June 2001. Under the rate plan approved by the Washington Commission in its
merger order, the Company will continue to reflect through the rate stability
period, in customers' bills, the current level of Residential Exchange benefits.
Over the remainder of the Residential Exchange Termination Agreement from
January 1999 through June 2001, it is projected that the Company will credit
customers approximately $172.3 million more than it will receive from BPA during
the following periods:
Dollars in
Period Millions
---------------------------------- -------------------
January - December 1999 $68.0
January - December 2000 67.4
January - June 2001 36.9
-------------------
$172.3
The Company and other investor owned utilities in the northwest region
are participating in the BPA's subscription process pursuant to which
allocations of federal power in the northwest beginning in 2001 will be
determined. Through this process the Company may receive a combination of low
cost energy from the federal power system in the northwest or financial exchange
agreements for the benefit of their residential and small farm customers, which
would be in lieu of the residential and small farm customer benefits required by
the Regional Power Act of 1980. The amount of such BPA power purchases and
financial exchange arrangements that may be available for the Company's
residential and small farm customers, and the BPA rates and contractual terms
and conditions applicable thereto, are generally not established at this time.
Subsequent to the rate stability period, the Company intends to seek regulatory
approval to pass through benefits equal to amounts received from the BPA to its
residential and small farm customers.
Electric revenues in 1998, 1997 and 1996 were reduced by $46.7 million,
$40.5 million and $41.0 million, respectively, as a result of the Company's sale
of revenues associated with $237.7 million of its investment in conservation
assets to a grantor trust. The revenue decrease represents the portion of rate
revenues that were sold and forwarded to the trust. The impact of this revenue
decrease, however, was offset by related reductions in other utility operations
and maintenance and interest expenses.
To meet customer demand, the Company's power supply portfolio includes
net purchases of power under long-term supply contracts. However, depending
principally upon streamflow available for hydro-electric generation and weather
effects on customer demand, from time to time the Company may have surplus power
available for sale at wholesale to other utilities. In addition, the Company has
increased its wholesale surplus power business through short and
intermediate-term purchases, sales, arbitrage and other trading and marketing
techniques. Sales to other utilities increased $141.2 million, $66.0 million and
$15.1 million in 1998, 1997 and 1996, respectively, due primarily to increased
wholesale power transactions. Wholesale sales generally have small margins.
However, there may be certain times when the market price of power may cause
margins to fluctuate.
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Operating Revenues - Gas
Regulated gas utility sales revenue in 1998 increased by $7.1 million
from the prior year on a 2.6% increase in gas volumes sold. Total gas volumes,
including transported gas, decreased 0.35% in 1998 from 1997. The increase in
sales revenue was primarily the result of a 4.4% increase in gas customers
during 1998, decreases in industrial and transportation sales volumes with lower
prices and margins and an increase in residential firm and commercial sales with
higher prices and margins. Utility gas margin (the difference between gas
revenues and gas purchases) increased by $10.6 million, or 4.6 %, in 1998 over
1997.
Regulated gas utility sales revenue in 1997 increased by $9.3 million, or
2.3%, from the prior year on a 0.7% decrease in gas volumes sold. Total gas
volumes, including transported gas, increased 4.1% in 1997 from 1996. Regulated
gas utility sales revenue in 1996 decreased by $19.9 million, or 4.7%, from the
prior year on a 4.8% decrease in gas volumes sold. Total gas volumes, including
transported gas, increased 5.2% in 1996. Other revenues decreased $20.5 million
in 1998 compared to 1997 and $14.4 million in 1997 from 1996 due primarily to
the sale of an unregulated subsidiary (Washington Energy Services Company) in
October 1997.
Operating Expenses
Purchased electricity expenses increased $137.2 million in 1998 when
compared to 1997 and $52.6 million in 1997 when compared to 1996. The increase
in 1998 was due primarily to a $112.3 million increase in secondary power
purchases from other utilities to support wholesale sales and increased payments
of $18.8 million for firm power purchases from non-utility generators. The
increase in 1997 was the result of increased secondary power purchases from
other utilities of $47.5 million and a $5.4 million increase in transmission
wheeling and associated costs compared to 1996. The increase of $38.8 million in
1996 over 1995 was the result of higher payments for firm power purchases from
non-utility generators and increased secondary power purchases from other
utilities.
Residential exchange credits associated with the Residential Purchase and
Sale Agreement with BPA decreased $16.4 million in 1998 when compared to 1997.
The primary reason for the decrease was the Residential Exchange Termination
Agreement between the Company and BPA in January 1997. Residential exchange
credits decreased $31.2 million in 1997 as compared to 1996 and increased $15.1
million in 1996 as compared to 1995. Residential exchange credits received in
1998 were $55.6 million and are estimated to be $39.0 million, $41.0 million and
$27.0 million in the years 1999 through 2001. (See discussion of the Residential
Purchase and Sale Agreement under Operating Revenues.)
Purchased gas expenses decreased $3.5 million in 1998 compared to 1997
despite the 2.6% increase in gas volumes sold. This was primarily the result of
a $5.4 million credit to purchased gas costs in the fourth quarter of 1998 due
to a true-up of gas costs through the PGA mechanism.
Purchased gas expenses increased $1.6 million in 1997 compared to 1996 as a
result of a 0.7% increase in gas volumes sold. Purchased gas expenses decreased
$41.3 million in 1996 compared to 1995. The decrease resulted from the lower
average per-therm cost of gas established in the May 1995 PGA and the 5%
reduction in gas volumes sold.
Electric generation fuel expense increased $15.1 million in 1998
primarily due to the Company generating more electricity at Company-owned
gas-fired combustion turbine plants. These increases were partially offset by
reductions to Colstrip fuel expense. In September 1998, the Company recorded a
reduction of $4.9 million in fuel expense and $3.5 million of interest income
related to the resolution of outstanding issues with the Colstrip fuel supplier.
Electric generation fuel expense increased $5.0 million in 1996 compared
to 1995. The increase was due in part to an arbitration panel's decision in 1995
of a dispute involving the coal supply agreement at the Company's 50%-owned
Colstrip 1 and 2 plants that resulted in a $4.6 million decrease to fuel expense
recorded in the first quarter of 1995. In addition, the Company recorded a
one-time charge of $1.8 million in the second quarter of 1996 relating to a loss
on the sale of oil stocks at a combustion turbine site.
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<PAGE>
Utility operations and maintenance expenses decreased $13.6 million in
1998 compared to 1997. The decrease is primarily the result of the reduction in
operating expenses resulting from consolidation of the joint operations of two
formerly separate electric and gas utilities with overlapping service
territories, the elimination of duplicate administrative functions and the
consolidation of Company facilities.
Utility operations and maintenance expenses increased $8.3 million in
1997 compared to 1996 and decreased $16.6 million in 1996 compared to 1995. The
changes were largely the result of an $11.6 million decrease in amortization
expense in 1995 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.
Other operations and maintenance expenses decreased $13.6 million in 1998
compared to 1997 and $11.0 million in 1997 compared to 1996. The decreases
resulted primarily from the sale of the Company's unregulated subsidiary,
Washington Energy Services Company, in October 1997.
Depreciation and amortization expense increased $3.7 million in 1998
compared to 1997. Depreciation and amortization expense due to capital spending
related to adding customers, distribution and transmission system improvements
and computer software amortization increased $12.3 million in 1998. Partially
offsetting these increases in 1998 were decreases from 1997 as a result of an
August 1997 Washington Commission Order which authorized the Company to record
interest income of $8.3 million related to a conservation tax refund, but
required the Company to expense deferred storm damage costs in the amount of
$7.4 million and establish a $1.0 million reserve to cover the costs of a
Company retail pilot program.
Depreciation and amortization expense increased $17.6 million in 1997
compared to 1996 due primarily to capital spending related to adding customers
and transmission and distribution system improvements. In addition, the
aforementioned Washington Commission Order resulted in a write-off of deferred
storm damage costs in the amount of $7.4 million and the establishment of a $1.0
million reserve to cover the costs of a Company retail pilot program.
Depreciation and amortization expense increased $3.2 million in 1996
compared to 1995 due primarily to new plant placed in service.
Taxes other than federal income taxes increased $4.1 million in 1997
compared to 1996 and $6.3 million in 1996 compared to 1995. The increases were
primarily due to higher state property tax payments and higher revenue-based
municipal and state excise tax payments.
Federal income taxes in 1997 were $60.2 million less than in 1998 and
$60.0 million less than in 1996 as a result of the following factors. An IRS tax
refund related to the method of accounting for taxes on conservation
expenditures during the first quarter of 1997 decreased federal income taxes by
$26.5 million. In addition, there was a $17.0 million reduction associated with
a decrease in PRAM revenues of $48.6 million. Merger costs expensed in the first
quarter of 1997 further reduced federal income taxes by $19.3 million.
Federal income taxes increased by $16.2 million in 1996 over 1995. The
increase was primarily due to higher pre-tax utility earnings. Also, there was a
decrease in energy conservation expenditures in 1996 which are deducted for
federal income taxes.
Other Income
Other income, net of federal income tax, decreased $18.9 million in 1998
from 1997. The decrease was due primarily to the receipt of interest income in
1997 of $13.6 million from the IRS on tax refunds for prior years in connection
with a plant abandonment loss, conservation tax refunds and certain additional
research and experimental credits claimed for tax purposes.
Other income, net of federal income tax, increased $26.5 million in 1997
from 1996. The increase was due primarily to interest income received from the
IRS on tax refunds for prior years as explained in the preceding paragraph.
Other income for 1997 includes after-tax losses of $1.0 million and $5.3 million
related to the sale of an unregulated subsidiary (Washington Energy Services
Company) and operations of a subsidiary, ConneXt, respectively.
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.
23
<PAGE>
Interest Charges
Interest charges, which consist of interest and amortization on long-term
debt and other interest, increased $20.3 million in 1998 compared to 1997
primarily as a result of the issuance of $300 million 7.02% Senior Medium-Term
Notes, Series A, in December 1997, the issuance of $100 million 8.231% Capital
Trust Debentures in June 1997 and the issuance of $200 million 6.74% Senior
Medium-Term Notes, Series A, in June 1998. These increases were partially offset
by the maturity of $151 million Secured Medium-Term Notes during the 15 months
ended December 31, 1998 and the redemption of $30 million 9.14% Secured
Medium-Term Notes, Series A, in June 1998.
Interest charges decreased $0.5 million in 1997 compared to 1996.
Interest and amortization on long-term debt increased $2.4 million which
included dividend payments on the Company-obligated, mandatorily redeemable
preferred securities of $4.7 million. Interest on short-term debt decreased $1.5
million and capitalized interest (AFUDC) increased $1.3 million.
Interest charges decreased $8.3 million in 1996 compared to 1995.
Interest and amortization on long-term debt decreased $8.8 million. Contributing
to the reduced interest expense were five First Mortgage Bond retirements or
redemptions totaling $151 million over the previous 17 months. Other interest
expense increased in 1996 over 1995 due primarily to increased interest on PGA
balances.
Construction, Capital Resources and Liquidity
Current construction expenditures, primarily transmission and
distribution-related, are designed to meet continuing customer growth.
Construction expenditures in 1998 and 1999 also include costs of new accounting
and customer information systems. Construction expenditures, which include
energy conservation expenditures and exclude AFUDC, were $333.3 million in 1998.
The Company expects construction expenditures for the period 1999 through 2001
will be approximately $303 million, $259 million and $252 million, respectively.
Construction expenditure estimates are subject to periodic review and
adjustment.
The Company expects cash from operations (net of dividends and AFUDC)
during the period 1999 through 2001 will, on average, be approximately 68.4% of
average estimated construction expenditures (excluding AFUDC) during the same
period.
In June 1998, the Company issued $200 million 6.74% Senior Medium-Term
Notes, Series A and redeemed $30 million 9.14% Secured Medium-Term Notes, Series
A, due June 2001 at a redemption price of 100%.
In September 1998, the Company filed a shelf-registration statement with
the Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to $500 million principal amount of Senior Notes secured
by a pledge of First Mortgage Bonds. On March 9, 1999, the Company issued $250
million principal amount of Senior Medium-Term Notes, Series B, which consisted
of $150 million principal amount due March 9, 2009 at an interest rate of 6.46%
and $100 million principal amount due March 9, 2029 at an interest rate of 7.0%.
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 electric and gas mortgage indentures, Articles of Incorporation and certain
loan agreements.
Under the most restrictive tests, at December 31, 1998, the Company could
issue either (i) approximately $731 million of additional first mortgage bonds,
(ii) approximately $853 million of additional preferred stock at an assumed
dividend rate of 5.5%, or (iii) a combination thereof.
Short-term borrowings from banks and the sale of commercial paper are
used to provide working capital for the construction program. At December 31,
1998, the Company had available $375 million in lines of credit with various
banks, which provide credit support for outstanding commercial paper and bank
borrowing of $142 million and $25 million, respectively, effectively reducing
the available borrowing capacity under these lines of credit to $208 million.
(See Note 9 to the Consolidated Financial Statements.)
Under the most restrictive covenants in the Company's Articles of
Incorporation and electric and gas mortgage indentures, earnings reinvested in
the business unrestricted as to payment of cash dividends were approximately
$183 million at December 31, 1998.
24
<PAGE>
Rate Matters - Electric
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. General electric tariff rates were
stipulated to increase between 1.0% to 1.5% depending on rate class on January 1
of 1999 through 2001, while those for certain customers will increase by 1.5% in
2002.
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, 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. PRAM accrued revenues of $40.5
million, recorded at December 31, 1996, were recovered in the first quarter of
1997. Over-collection of PRAM revenues were refunded to customers in the second
quarter of 1997.
With the discontinuance of the PRAM, the Company no longer has a rate
adjustment mechanism to adjust for changes in energy or fuel costs or variances
in hydro and weather conditions. These variances may now significantly influence
earnings.
On July 8, 1998, the Washington Commission approved the Company's
requested accounting treatment for its program to reduce costly tree-caused
power outages. The Tree Watch program, which focuses on controlling vegetation
outside the Company's rights-of-way, should improve service reliability for its
customers and result in future savings in outage recovery costs. The five-year,
$43 million program will be treated as an investment that will be amortized over
ten years. The Company expects the Tree Watch investment to be offset by savings
from lower outage restoration and storm damage costs over the same period.
Rate Matters - Gas
The order approving the Merger, issued by the Washington Commission on
February 5, 1997, contains a rate plan which provided unchanged rates for all
classes of natural gas customers until January 1, 1999, when rates decreased by
1% on gas utility margins. See Note 1 to the Consolidated Financial Statements
for a description of the Company's PGA mechanism.
Year 2000 Conversion
Background
The Year 2000 issue results from the use of two digits rather than four
digits in computer hardware and software to define the applicable year. If not
corrected on computer systems that must process dates both before and after
January 1, 2000, two-digit year fields may create processing errors or system
failures. The Company expects to be Year 2000 ready which means that all
mission-critical systems, devices, applications and business relationships have
been evaluated and are suitable for continued use into and beyond the Year 2000,
or contingency plans are in place.
Project Approach and Progress
The number of people working full time on the Company's Year 2000 project
fluctuates between 20 and 40; dozens of additional employees contribute some
time to the effort each month. The Company has established a central project
team to coordinate all Year 2000 activities and identified exposure in three
categories: information technology; embedded chip technology; and external
non-compliance by customers and suppliers. The project team is taking a phased
approach in conducting the Year 2000 project for its internal systems. The
phases include inventory, assessment, planning/prioritizing, remediation,
testing, implementation and contingency planning. In addition, the Company has
engaged outside consultants and technicians to aid in formulating and
implementing its plan. All business units have completed the inventory phase,
and with the exception of the Company's Customer Information System ("CIS")
discussed below, assessment is 95% complete for all business units, with
remediation, testing and implementation scheduled to be completed during the
second quarter of 1999.
25
<PAGE>
The Company has been upgrading mainframe and client server financial and
business applications since 1997 and replacing many of its business systems as
part of its business plans following its merger in 1997. In September 1998, the
Company implemented a Systems, Applications, Products in Data Processing ("SAP")
business system which includes essentially all of the Company's business
applications with the exception of its CIS. This SAP system is Year 2000
compliant. The remainder of applications and operating environments excluding
the CIS are in the remediation/testing phase. Full implementation of those
applications and components of the Company's internal systems are scheduled for
completion by mid-year 1999.
A new CIS, which is designed to be Year 2000 compliant, is currently
being developed by the Company. Development is expected to be completed in 1999.
The Company has also begun implementation activities with respect to the new
system which will continue during 1999. The Company has also elected to
remediate critical elements of its existing CIS for Year 2000 compliance
purposes. The Company has formed a specialized team which has completed the
inventory phase and is currently conducting assessment and remediation
activities for the existing system. The Company expects to complete the
assessment phase of this project early in May of 1999 followed immediately by
remediation and testing activities which are expected to be completed in the
third quarter of 1999.
A specialized embedded systems team has been formed by the Company to
inventory, assess and remediate microprocessor technology in its generation,
transmission and distribution systems for both gas and electric operations. The
inventory and assessment phases of the project are complete. Although some
remediation planning is still in process, significant remediation efforts are
underway and proceeding according to schedule. Testing and implementation are
scheduled to be completed by the end of the second quarter of 1999. Contingency
planning specific to the Year 2000 issue began in November 1998, and initial
reports were submitted to the Washington Commission and the North American
Electric Reliability Council ("NERC"). These plans will be refined and updated
as remediation and test results are analyzed, and are scheduled for finalization
in the third quarter of 1999.
The Company sent letters to its suppliers, financial institutions and other
business partners to coordinate Year 2000 conversion and determine the extent to
which the Company is exposed to third party compliance failures. Approximately
85% of vendors and suppliers have been contacted to date. All third party
assessment is scheduled to be completed in March 1999. If the Company identifies
concerns, it follows up with third parties by telephone. In addition, the
Company schedules meetings with critical vendors described below in order to
assess and monitor compliance measures. Virtually all the vendors and suppliers
who have responded to the Company's written requests and follow up telephone
calls have indicated either that they are year 2000 compliant or that they
expect to be compliant later in 1999. Approximately one-third of the vendors and
suppliers have not yet responded to inquiries from the Company. Company line
managers are seeking to obtain responses from them as well as to develop
alternate sources or other contingency plans for vendors and suppliers who
either do not respond or who indicate that they do not expect to be compliant.
The Company depends upon third parties for a significant portion of its
energy supply and transportation. The majority of the high voltage transmission
facilities used by the Company are owned and operated by Bonneville Power
Administration and the Company's natural gas supplies are transported to its
service area by natural gas pipelines in the western United States and Canada.
The Company purchases 100% of its natural gas supplies and approximately 75% of
its electric power supplies. Major energy suppliers and transporters are
considered critical vendors because their failure to supply or deliver energy to
the Company could adversely affect the reliability of the Company's electric or
gas service to its customers.
In addition, the Company is working with various industry groups
including the NERC and the regional reliability council, the Western Systems
Coordinating Council ("WSCC") during the millennium transition. The United
States Department of Energy has asked NERC to assume a leadership role in
preparing the U.S. electric industry for the transition to the Year 2000.
Costs
While the replacement of business systems under business plans developed
as a result of the Merger are not included in the Company's Year 2000 project,
those replacements substantially reduce the number of internal business
applications that require remediation. In addition to the costs of replacing new
business systems, the Company has expended approximately $3.6 million through
December 31, 1998, on Year 2000 remediation efforts, exclusive of internal labor
costs. Most of the expenditures through 1998 were for costs associated with the
inventory and assessment phases of the Year 2000 project. Although it is
difficult to determine the total remaining costs of implementing the Year 2000
plan, the Company's current estimate is approximately $14 million, most of which
will be expended for the remediation phase. Approximately $3 million of the
remaining expenditures are expected to be capitalized.
26
<PAGE>
Risk Assessment
The electric power supply systems of North America are connected into three
major interconnections called grids. The western grid covers the western third
of the U.S., western Canada and parts of Mexico. The BPA is the largest supplier
of transmission services in the Pacific Northwest. The Company's reasonably
likely worst case scenario is that operational component failures of any entity
connected to the grid could cause other failures in that grid. Such failures
would adversely affect the Company's ability to provide reliable service to its
customers and correspondingly reduce revenues. The Company will need to continue
to assess this risk as the millennium approaches to evaluate the likelihood of
power failures and develop approaches for mitigating the risk of failures.
Much of the natural gas and electric distribution systems are comprised
of wires, poles and pipes containing no embedded chips. However, these systems
do employ some computer components that could be affected by the Year 2000
transition. Since many of the components used by the Company exist in multiple
sub-station locations, there is a risk that a component could be missed, a
component manufacturer could provide erroneous information, or the component
(while deemed and tested compliant) could fail in a specific configuration found
at the Company . The Company has formed a special team to handle these types of
components (embedded systems), and has retained an independent engineering firm
with specific utility experience to assist in the effort. Results of assessment
to date reveal that there are fewer components that are not Year 2000 ready than
initially thought. This is consistent with industry findings published in the
NERC report to the Department of Energy dated January 11, 1999.
The failure to correct a material Year 2000 problem could result in an
interruption in, or a failure of, Company business activities or operations.
Such failures could materially and adversely affect the Company's results of
operations, liquidity and financial condition. Due to the general uncertainty
inherent in the Year 2000 problem, resulting in part from the uncertainty of the
Year 2000 readiness of third-party suppliers and customers, the Company is
unable to determine at this time whether the consequences of Year 2000 failures
will have a material impact on the Company's results of operations, liquidity or
financial condition. The Year 2000 project is expected to significantly reduce
the Company's level of uncertainty about the Year 2000 problem and the Year 2000
readiness of its material vendors. The Company believes that, with the
implementation of new business systems and completion of the project as
scheduled, the possibility of significant interruptions of normal operations
should be reduced.
As discussed above, elements of the Company's current CIS are not Year
2000 compliant. If the current CIS remediation activities are not successful by
the year 2000, certain normal business activities such as customer billing and
collections could be adversely affected by interruptions.
Contingency Plans
The Company is identifying various scenarios that could occur in the
event that Year 2000 issues are not resolved in a timely manner. These efforts
will build upon the work in scenario development and contingency planning that
is being done by the WSCC contingency planning task force. A specialized team is
being formed that will develop contingency plans and update existing emergency
preparedness plans to identify and address risk scenarios for the Company.
Contingency planning is scheduled to continue through the third quarter of 1999.
Forward Looking Statements
Readers are cautioned that forward-looking statements contained in the
Year 2000 update are based on management's best estimates and may be influenced
by factors that could cause actual outcomes and results to be materially
different than projected. Specific factors that might cause differences between
the estimates and actual results include, but are not limited to, the
availability and cost of personnel trained in these areas, the ability to locate
and correct all relevant computer code, timely responses to and corrections by
third-parties and suppliers, the ability to implement new systems in a timely
manner, the ability to implement interfaces between the new systems and the
systems not being replaced, and similar uncertainties. Due to the general
uncertainty inherent in the Year 2000 problem, resulting in part from the
uncertainty of the Year 2000 readiness of third-parties and the interconnection
of global businesses, the Company cannot ensure its ability to timely and
cost-effectively resolve problems associated with Year 2000 issues that may
affect its operations and business, or expose it to third-party liability.
27
<PAGE>
Industry Overview
The electric and gas industries in the United States are undergoing
significant changes. The focus of these changes is to promote competition among
suppliers of electricity and gas and associated services. In 1996 and 1997, the
Federal Energy Regulatory Commission ("FERC") issued orders that require
utilities, including the Company, to file open access transmission tariffs that
will make the utilities' electric transmission systems available to wholesale
sellers and buyers on a non-discriminatory basis. A number of states, including
California, have restructured their electric industries to separate or
"unbundle" power generation, transmission and distribution in order to permit
new competitors to enter the marketplace. In part because electric rates in the
Pacific Northwest have been among the lowest in the nation, certain of the
legislatures in this region, including Washington, have not yet enacted laws to
provide for competition at the retail level. The Washington Commission has
initiated a pilot program, in which the Company participates, that permits
consumers limited direct access to competitive energy suppliers. The Company is
actively monitoring developments in this area and has indicated its support for
the enactment of legislation that would provide increased choice for electric
service customers in the State of Washington.
In order to better position itself to respond to customer needs and
future restructuring of the utility industry, and in anticipation of a
competitive environment for electric energy sales, the Company in 1997 organized
its utility operations into separate business units: energy delivery; energy
supply; and customer solutions
The Company has an Optional Large Power Sales Rate and certain "special
contracts" for its largest customers. Customers who elect the Optional Large
Power Sales Rate are no longer considered "core" customers, and the Company no
longer has an obligation to plan for future resources to serve their needs. The
non-core customers receive access to electric energy that is priced at current
market cost and pay a charge for energy delivery (including a charge for
conservation programs) and a transition charge (representing the difference
between the Company's present cost and the current market cost of electric
energy and capacity). The transition charge will be phased out before the end of
the year 2000. Non-core customers also take on the risk that market costs could
become volatile and that electricity could be unavailable on the open market. In
November 1998, a number of industrial customers filed a complaint with the
Washington Commission that the Company was incorrectly billing for energy under
the Optional Large Power Sales Rate. If the Washington Commission finds that the
Company used an incorrect index, the Company would owe approximately $2.6
million in refunds. However, management believes the proper index has been used
and expects the Company will prevail on this issue.
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. During 1998, an average of 123 commercial and industrial
customers chose to use such service.
Other
On March 20, 1991, the Company executed a 20-year contract to purchase
216 average MW of energy and 245 MW of capacity, beginning in April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas fired
cogeneration project located near Ferndale, Washington. In December 1997 and
January 1998, the Company and Tenaska Washington Partners entered into revised
agreements which will lower purchased power costs from the Tenaska project by
restructuring its natural gas supply. The Company paid $215 million to buy out
the project's existing long-term gas supply contracts, which contained fixed and
escalating gas prices that were well above current and projected future market
prices for natural gas. The Company became the principal natural gas supplier to
the project and power purchase prices under the Tenaska contract were revised to
reflect market-based prices for the natural gas supply. The Company obtained an
order from the Washington Commission creating a regulatory asset related to the
$215 million restructuring payment. Under terms of the order, the Company is
allowed to accrue as an additional regulatory asset one-half the carrying costs
of the deferred balance over the first five years. These revised arrangements
are expected to reduce the Company's power supply costs from the Tenaska project
between 15 and 20 percent annually over the remaining 14 year life of the
contract, net of the costs of the restructuring payment. The Company's purchased
electric energy cost associated with the Tenaska contract was $80.1 million in
1998.
28
<PAGE>
On April 1, 1998, the Company and Duke Energy Trading and Marketing
("DETM") of Houston, a unit of Duke Energy Corp., signed an agreement relating
to energy-marketing and trading activities in 14 western States and British
Columbia. The purpose of this agreement is to coordinate the two companies'
activities in serving Puget Sound Energy's native power load with DETM's Western
power and natural gas marketing and trading operations. The companies share the
benefits of this coordination proportionally up to certain stipulated amounts
intended to be reflective of the value the companies would have realized from
their respective operations in the absence of the agreement. The companies share
equally any benefits created above the stipulated amounts.
Under the terms of the agreement, DETM performs the forward electric
energy trading function. As a result, the Company's future wholesale "sales to
other utilities" revenues and related "secondary purchase" power expenses, which
previously have reflected trading activity by the Company, will be lower than
amounts which the Company would report absent this agreement. During 1998 the
Company continued to execute in its own name transactions in which electric
energy is delivered within the next 30 days. Therefore, the Company's results
include those transactions. The Company recorded its share of the benefits that
resulted from the agreement as a credit to Purchased Power Expense. The
agreement provides that forward trading activities will be conducted according
to DETM's energy price risk and credit policies, and that the Company is not
responsible for any losses caused by deviation from these policies. The Company
and DETM are presently considering modifications to the agreement.
On November 2, 1998, the Company announced it signed an agreement to sell
the Company's 735-megawatt interest in the four-unit, coal-fired Colstrip
generation plant in eastern Montana, as well as associated transmission
facilities. The Company signed the agreement with PP&L Global, Inc., of Fairfax,
Virginia, a subsidiary of PP&L Resources, Inc. Included in the sale are the
Company's 50% interest in Colstrip Units 1 and 2; 25% interest in Units 3 and 4;
and associated Colstrip transmission capacity across Montana. The sales price is
expected to be $549 million before taxes and expenses. The net book value of
these assets and related regulatory assets is approximately $464 million. After
consideration of taxes and other costs, the gain on the sale is expected to be
approximately $37.6 million. The Company expects the Colstrip sale to close in
the second half of 1999. Completion of the sale is contingent on receipt of
acceptable regulatory treatment from the Washington Commission and the FERC.
The Company has also agreed to join with the other owners of the
coal-fired generating plant at Centralia, Washington, by offering for sale its
92 megawatt ownership interest in the facility. As part of the sale process, the
Centralia owners are reviewing the projected reclamation liability related to
the coal mining operations.
In the fourth quarter of 1998, the Company incurred $4.7 million of
transmission and distribution repair costs in connection with restoring electric
service following a severe wind storm that occurred on November 23, 1998. Under
an order established by the Washington Commission, these costs were deferred for
collection in future rates.
For a discussion of Issue 98-10, "Accounting For Contracts Involved in
Energy Trading and Risk Management Activities" issued by the Emerging Issues
Task force of the Financial Accounting Standards Board ("FASB") in 1998, see
Note 1 to the Consolidated Financial Statements.
For a discussion of Statement of Position 98-5, "Reporting on the Costs
of Start-up Activities" ("SOP 98-5") issued by the Accounting Standards
Executive Committee in April 1998, see Note 1 to the Consolidated Financial
Statements.
For a discussion of Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("Statement No.
133") issued by the FASB in June 1998, see Note 1 to the Consolidated Financial
Statements.
29
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Market Risks
The Company is exposed to market risks, including changes in commodity
prices and interest rates.
Commodity Price Risk
The prices of energy commodities and transportation services are subject
to fluctuations due to unpredictable factors including weather, transportation
congestion and other factors which impact supply and demand. This commodity
price risk is a consequence of purchasing energy at fixed and variable prices
and providing deliveries at different tariff and variable prices. Costs
associated with ownership and operation of production facilities are another
component of this risk. The Company may use forward delivery agreements and
option contracts for the purpose of hedging commodity price risk. Unrealized
changes in the market value of these derivatives are deferred and recognized
upon settlement along with the underlying hedged transaction. In addition, the
Company believes its current rate design, including its Optional Large Power
Sales Rate, various special contracts and the PGA mechanism mitigate a portion
of this risk.
Four option contracts entered into directly by the Company were
outstanding at December 31, 1998, and had a market value at that date which
approximated the option premiums paid by the Company.
Operating results are also influenced by the impact of market prices on
the value of physical and derivative commodity contracts entered into by DETM as
part of their agreement with the Company. Changes in the market value of all of
these derivatives are recorded on a mark-to-market basis into income by DETM and
can affect the Company's revenues from the DETM agreement.
DETM measures the market risk of physical and financial contracts entered
into under the DETM Agreement using a value at risk model. The Company's
proportionate share of the value at risk at December 31, 1998 was not material.
Market risk is managed subject to parameters established by the Board of
Directors. A Risk Management Committee separate from the units that create these
risks monitors compliance with the Company's policies and procedures. In
addition, the Audit Committee of the Company's Board of Directors has oversight
of the Risk Management Committee.
Interest rate risk
The Company believes interest rate risks of the Company primarily relate
to the use of short-term debt instruments and new long-term debt financing
needed to fund capital requirements. The Company manages its interest rate risk
through the issuance of mostly fixed-rate debt of various maturities. The
Company does utilize bank borrowings, commercial paper and line of credit
facilities to meet short-term cash requirements. These short-term obligations
are commonly refinanced with fixed rate bonds or notes when needed and when
interest rates are considered favorable. The Company may enter into swap
instruments to manage the interest rate risk associated with these debts, and
one interest rate swap was outstanding as of December 31, 1998. The carrying
amounts and fair values of the Company's fixed rate debt instruments are
described in Note 10 to the Consolidated Financial Statements.
30
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
PUGET SOUND ENERGY, INC.
William S. Weaver
-------------------------------------
William S. Weaver
President and Chief Executive Officer
Date: April 23, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
- ---------------------------- ---------------------------- -------------------
William S. Weaver President, Chief Executive April 23, 1999
- ---------------------------- -------------------
(William S. Weaver) Officer and Director
R. R. Sonstelie Chairman of the Board
- ----------------------------
(R. R. Sonstelie)
Richard L. Hawley Vice President and Chief
- ----------------------------
(Richard L. Hawley) Financial Officer
James W. Eldredge Corporate Secretary
- ----------------------------
(James W. Eldredge) and Controller and
Chief Accounting Officer
Douglas P. Beighle Director
- ----------------------------
(Douglas P. Beighle)
Charles W. Bingham Director
- ----------------------------
(Charles W. Bingham)
Phyllis J. Campbell Director
- ----------------------------
(Phyllis J. Campbell)
31
<PAGE>
SIGNATURE TITLE DATE
- ---------------------------- ---------------------------- -------------------
Donald J. Covey Director
- ----------------------------
(Donald J. Covey)
Robert L. Dryden Director
- ----------------------------
(Robert L. Dryden)
Director
- ----------------------------
(John D. Durbin)
John W. Ellis Director
- ----------------------------
(John W. Ellis)
Daniel J. Evans Director
- ----------------------------
(Daniel J. Evans)
Tomio Moriguchi Director
- ----------------------------
(Tomio Moriguchi)
Sally G. Narodick Director
- ----------------------------
(Sally G. Narodick)
32
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