UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
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)
1
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.
2
DEFINITIONS
AFUDC Allowance for Funds Used During Construction
BPA Bonneville Power Administration
CAAA Clean Air Act Amendments
Cabot Cabot Oil & Gas Corporation
Chelan Public Utility District No. 1 of Chelan County, Washington
Dth Dekatherm (One Dth is equal to one MMBTu)
EPA Environmental Protection Agency
FERC Federal Energy Regulatory Commission
KW Kilowatts
KWH Kilowatt Hours
MMBTu One Million British Thermal Units
MW Megawatts (one MW equals one thousand KW)
MWH Megawatt Hours
Montana Power The Montana Power Company
NERC North American Electric Reliability Council
NMFS National Marine Fisheries Service
PGA Purchased Gas Adjustment
PRAM Periodic Rate Adjustment Mechanism
PRP Potentially Responsible Party
PUDs Washington Public Utility Districts
PURPA Public Utility Regulatory Policies Act
WECo Washington Energy Company
WEGM Washington Energy Gas Marketing Company
Washington Commission Washington Utilities and Transportation Commission
WNG Washington Natural Gas Company
WSCC Western Systems Coordinating Council
3
INDEX
Item Page
Part I
1. Business 5
General 5
Industry Overview 5
Regulation and Rates 6
Electric Utility Operations 6
Electric Utility Operating Statistics 13
Gas Utility Operations 15
Gas Utility Operating Statistics 18
Energy Conservation 19
Environment 20
Executive Officers 22
2. Properties 23
3. Legal Proceedings 23
4. Submission of Matters to a Vote of Security Holders 23
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 23
6. Selected Financial Data 25
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 26
8. Financial Statements and Supplementary Data 38
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 38
Part III (Incorporated by reference from the Company's definitive
proxy statement issued in connection with the 1999 Annual
Meeting of Shareholders)
10. Directors and Executive Officers of the Registrant
11. Executive Compensation
12. Security Ownership of Certain Beneficial Owners and Management
13. Certain Relationships and Related Transactions
Part IV Exhibits, Financial Statement Schedules and
Reports on Form 8-K 38
Signatures 39
Exhibit Index 80
4
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.
5
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.
6
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.
7
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 certain articles of the license because certain
restrictions placed on the operation of the plant may make it 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.)
8
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.
9
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.
10
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.
11
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.
12
ELECTRIC UTILITY OPERATING STATISTICS
Year Ended on December 31 1998 1997 1996 1995 1994
- --------------------------------- ------------- ------------- ------------- -------------- -------------
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
- --------------------------------- ------------- ------------- ------------- -------------- -------------
(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.)
13
(continued from previous page)
YEAR ENDED ON DECEMBER 31 1998 1997 1996 1995 1994
- --------------------------------------------- ------------- ------------ ------------ ------------ ------------
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%
14
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.
15
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.
16
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.
17
GAS UTILITY OPERATING STATISTICS
Twelve Months Ended December 31 1998 1997 1996 1995 1994
- --------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
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
18
(continued from prior page)
TWELVE MONTHS ENDED DECEMBER 31 1998 1997 1996 1995 1994
- --------------------------------------- ------------ ------------- ------------ ----------- ------------
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%
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.
19
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.
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.
20
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.
21
EXECUTIVE OFFICERS AT DECEMBER 31, 1998:
NAME AGE OFFICES
- --------------------- -------- --------------------------------------------------------------------------------
W. S. Weaver 54 President & Chief Executive Officer since January 1998; President, May 1997
- January 1998; Vice Chairman and Chairman of Unregulated Subsidiaries,
February 1997 - May 1997; Executive Vice President and Chief Financial
Officer 1991-1997; Director since 1991.
R. R. Sonstelie 53 Chairman of the Board since February 1997; President and Chief Executive
Officer 1992-1997; President and Chief Operating Officer 1991-1992;
President and Chief Financial Officer 1987-1991; Executive Vice President
1985-1987; Senior Vice President Finance 1983-1985; Vice President
Engineering and Operations 1980-1983; Director since 1987.
J. W. Eldredge 48 Chief Accounting Officer since 1994; Corporate Secretary and Controller
since 1993; Controller since 1988.
D. E. Gaines 41 Treasurer since 1994; Director Strategic Planning 1992-1994; Manager
Financial Planning 1986 - 1992.
W. A. Gaines 43 Vice President Energy Supply since February 1997; Manager Power Management
1996-1997; Manager Operations Planning 1986-1996.
D.A. Graham 58 Vice President Human Resources since April 1998; Director Human Resources
1989-1998.
R. L. Hawley 49 Vice President and Chief Financial Officer since March 1998. For more than
five years prior to that time, he was a partner with Coopers & Lybrand
L.L.P. (now PricewaterhouseCoopers LLP).
T. J. Hogan 47 Vice President Systems Operations since February 1997; Washington Energy
Company positions held: Executive Vice
President and Chief Operating Officer
1995-1997; Vice President Supply,
Administration and Corporate Secretary
1994-1995; Vice President Legal and
Corporate Secretary 1991-1994.
S. A. McKeon 52 Vice President and General Counsel since June 1997. For more than five years
prior to that time he was a partner at Perkins Coie LLP.
S. McLain 42 Vice President Corporate Performance since December 1997; Director Planning
and Work Practices 1997; various positions in Human Resources, Operations,
Customer Service and Strategic Planning 1988-1997.
J. Quintana 50 Vice President External Affairs since April 1998. For more than five years
prior to that time, he was Sr. Vice President Public Affairs for the Rockey
Company, a public relations consulting firm.
G. B. Swofford 57 Vice President Customer Operations since February 1997; Senior Vice
President Customer Operations 1994-1997; Vice President Divisions and
Customer Services 1991-1994; Vice President Rates and Customer Programs
1986-1991.
Officers are elected for one-year terms.
22
ITEM 2. PROPERTIES
The principal electric generating plants and underground gas storage
facilities owned by the Company are described under Item 1 - "Business -
Electric Utility Operations and Gas Utility Operations." The Company owns its
transmission and distribution facilities and various other properties.
Substantially all properties of the Company are subject to the liens of the
Company's Mortgage Indentures.
ITEM 3. LEGAL PROCEEDINGS
See Note 17 to the Consolidated Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS
None
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS.
The Company's common stock is traded on the New York Stock Exchange
(symbol PSD). The number of stockholders of record of the Company's common stock
at December 31, 1998, was 58,650.
The Company has paid dividends on its common stock each year since 1943
when such stock first became publicly held. Future dividends will be dependent
upon earnings, the financial condition of the Company and other factors.
The payment of dividends on common stock is restricted by provisions of
certain covenants applicable to preferred stock and long-term debt contained in
the Company's Articles of Incorporation and electric and gas mortgage
indentures. Under the most restrictive covenants, earnings reinvested in the
business unrestricted as to payment of cash dividends were approximately $183
million at December 31, 1998. (See Note 7 to the Consolidated Financial
Statements.)
23
Dividends paid and high and low stock prices for each quarter over the
last two years were:
1998 1997 (A)
- ----------------- ------------------------- --------------- ------------------------ -------------
PRICE RANGE DIVIDENDS PRICE RANGE DIVIDENDS
QUARTER ENDED HIGH LOW PAID HIGH LOW PAID
- ----------------- ------------ ------------ --------------- ------------- ---------- -------------
March 31 30-1/4 26-5/8 $.46 26 23-1/2 $.46
June 30 28-5/8 25 $.46 26-1/2 23-3/4 $.46
September 30 28 24-1/16 $.46 26-15/16 25-1/8 $.46
December 31 29 25-7/8 $.46 30-3/16 25-1/2 $.46
(A) Data for Puget Sound Power & Light Company prior to February 10, 1997
24
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in thousands except per share data)
YEAR ENDED DECEMBER 31 1998 1997 1996 1995 1994
- ------------------------------------------- ----------- ----------- ----------- ----------- -----------
Operating revenue $1,907,340 $1,676,902 $1,649,279 $1,631,118 $1,632,485
Operating income 298,980 215,866 284,474 270,344 224,772
Income from continuing
operations 169,612 125,698 167,351 128,381 79,312
Income for common stock from
continuing operations 156,609 107,421 145,170 105,727 58,929
Basic and diluted earnings
per common share from
continuing operations (Note 1 to the 1.85 1.28 1.72 1.26 0.70
financial statements)
Dividends per common share 1.84 1.78 1.67 1.67 1.67
Book value per common share 16.00 16.06 16.31 16.27 17.01
- ------------------------------------------- ----------- ----------- ----------- ----------- -----------
Total assets at year-end $4,720,689 $4,493,370 $4,227,470 $4,244,568 $4,496,770
Long-term obligations 1,474,748 1,411,707 1,165,584 1,230,499 1,253,498
Redeemable preferred stock 73,162 78,134 87,839 89,039 91,242
Corporation obligated,
mandatorily redeemable
preferred securities of
subsidiary trust holding
solely junior subordinated
debentures of the
corporation 100,000 100,000 -- -- --
- ------------------------------------------- ----------- ----------- ----------- ----------- -----------
25
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.
26
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 accrued revenue 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.
27
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.
28
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.
29
Utility operations and maintenance expenses decreased $13.6 million in
1998 compared to 1997. The decrease is primarily the result of improved
operating efficiencies.
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.
30
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.
31
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 result 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 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.
32
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 actiities 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 is also communicating with 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.
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. 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, of which approximately $3 million will be capitalized.
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. Operational
component failures of any entity connected to the grid could cause other
failures in that grid. 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.
33
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.
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.
34
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.
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.
35
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.
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.
36
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.
37
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See index on page 44.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
PART III
Part III is incorporated by reference from the Company's definitive proxy
statement issued in connection with the 1999 Annual Meeting of Shareholders.
Certain information regarding executive officers is set forth in Part I.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1) Financial statement schedule - see index on page 44.
2) Exhibits - see index on page 80.
(b) Reports on Form 8-K:
1) Form 8-K filed November 13, 1998 - Item 5 - Other Events, and Item 7
- - Exhibits, related to an Asset Purchase Agreement for the sale of the Company's
interest in the Colstrip coal-fired generating plant.
38
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
PUGET SOUND ENERGY, INC.
/s/ William S. Weaver
-------------------------------------
William S. Weaver
President and Chief Executive Officer
Date: March 4, 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
- ---------------------------- ---------------------------- -------------------
/s/ William S. Weaver President, Chief Executive March 4, 1999
- ---------------------------- -------------------
(William S. Weaver) Officer and Director
/s/ R. R. Sonstelie Chairman of the Board
- ----------------------------
(R. R. Sonstelie)
/s/ James W. Eldredge Corporate Secretary
- ----------------------------
(James W. Eldredge) and Controller and
Chief Accounting Officer
/s/ Douglas P. Beighle Director
- ----------------------------
(Douglas P. Beighle)
/s/ Charles W. Bingham Director
- ----------------------------
(Charles W. Bingham)
/s/ Phyllis J. Campbell Director
- ----------------------------
(Phyllis J. Campbell)
39
SIGNATURE TITLE DATE
- ---------------------------- ---------------------------- -------------------
/s/ Donald J. Covey Director
- ----------------------------
(Donald J. Covey)
/s/ Robert L. Dryden Director
- ----------------------------
(Robert L. Dryden)
/s/ John D. Durbin Director
- ----------------------------
(John D. Durbin)
Director
- ----------------------------
(John W. Ellis)
/s/ Daniel J. Evans Director
- ----------------------------
(Daniel J. Evans)
/s/ Tomio Moriguchi Director
- ----------------------------
(Tomio Moriguchi)
/s/ Sally G. Narodick Director
- ----------------------------
(Sally G. Narodick)
40
REPORT OF MANAGEMENT
PUGET SOUND ENERGY, INC.
The accompanying consolidated financial statements of Puget Sound Energy,
Inc. have been prepared under the direction of management, which is responsible
for their integrity and objectivity. The statements have been prepared in
accordance with generally accepted accounting principles and include amounts
based on judgments and estimates by management where necessary. Management also
prepared the other information in the Annual Report on Form 10-K and is
responsible for its accuracy and consistency with the financial statements.
The Company maintains a system of internal control which, in management's
opinion, provides reasonable assurance that assets are properly safeguarded and
transactions are executed in accordance with management's authorization and
properly recorded to produce reliable financial records and reports. The system
of internal control provides for appropriate division of responsibility and is
documented by written policy and updated as necessary. The Company's internal
audit staff assesses the effectiveness and adequacy of the internal controls on
a regular basis and recommends improvements when appropriate. Management
considers the internal auditor's and independent auditor's recommendations
concerning the Company's internal controls and takes steps to implement those
that they believe are appropriate in the circumstances.
In addition, PricewaterhouseCoopers LLP, the independent auditors, have
performed audit procedures deemed appropriate to obtain reasonable assurance
about whether the financial statements are free of material misstatement.
The Board of Directors pursues its oversight role for the financial
statements through the audit committee, which is composed solely of outside
Directors. The audit committee meets regularly with management, the internal
auditors and the independent auditors, jointly and separately, to review
management's process of implementation and maintenance of internal accounting
controls and auditing and financial reporting matters. The internal and
independent auditors have unrestricted access to the audit committee.
/s/ William S. Weaver /s/ Richard L. Hawley /s/ James W. Eldredge
- ---------------------- ------------------------- -----------------------------
William S. Weaver Richard L. Hawley James W. Eldredge
President and Chief Vice President and Chief Corporate Secretary and
Executive Officer Financial Officer Controller
(Chief Accounting Officer)
41
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of Puget Sound Energy, Inc.
In our opinion, based upon our audits and the report of other auditors,
the consolidated financial statements listed on page 44 of this Annual Report on
Form 10-K present fairly, in all material respects, the financial position of
Puget Sound Energy, Inc. and its subsidiaries (the "Company") at December 31,
1998 and 1997, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule listed on page 44 of this document presents fairly,
in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and the financial statement schedule are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements and the financial statement schedule based on our audits.
The consolidated financial statements give retroactive effect to the February
10, 1997 merger of Washington Energy Company ("WECo") and its principal
subsidiary, Washington Natural Gas ("WNG"), in a transaction accounted for as a
pooling of interests which is discussed in Note 1 to the consolidated financial
statements. We did not audit the consolidated financial statements and the
financial statement schedule of WECo and its principal subsidiary, WNG, which
statements reflect total revenues of $426 million for the year ended December
31, 1996. Those financial statements and the financial statement schedule were
audited by other auditors whose report thereon has been furnished to us, and our
opinion expressed herein, insofar as it relates to the amounts included in the
year ended December 31, 1996 for WECo and WNG, is based solely on the report of
the other auditors. We conducted our audits of these financial statements in
accordance with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits and the report of other auditors provide a reasonable
basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Seattle, Washington
February 11, 1999
42
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Washington Energy Company:
We have audited the consolidated statements of income, shareholders'
earnings (deficit) reinvested in the business, premium on common stock and cash
flows of Washington Energy Company (a Washington corporation) and subsidiaries
for the year ended September 30, 1996, and the consolidated statements of
income, shareholders' earnings reinvested in the business, premium on common
stock and cash flows of Washington Natural Gas Company (a Washington
corporation) and subsidiaries for the year ended September 30, 1996. These
financial statements, which are not included in this Form 10-K, are the
responsibility of the companies' management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
On February 10, 1997, Washington Energy Company and its principal
subsidiary Washington Natural Gas Company, in a transaction accounted for as a
pooling-of-interests, merged with Puget Sound Power and Light to form Puget
Sound Energy.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the results of operations of Washington Energy
Company and subsidiaries and of Washington Natural Gas Company and subsidiaries
and their cash flows for the year ended September 30, 1996, in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Seattle, Washington,
October 31, 1996 (except with respect to the
matter discussed in the third paragraph above,
for which the date is February 10, 1997)
43
Consolidated Financial Statements, Financial Statement Schedule and Exhibits
Covered by the Foregoing Report of Independent Accountants
CONSOLIDATED FINANCIAL STATEMENTS: PAGE
Consolidated Statements of Income for the years ended December 31,
1998, 1997 and 1996 45
Consolidated Balance Sheets, December 31, 1998 and 1997 46-47
Consolidated Statements of Capitalization, December 31, 1998
and 1997 48
Consolidated Statements of Earnings Reinvested in the Business
for the years ended December 31, 1998, 1997 and 1996 49
Consolidated Statements of Comprehensive Income for the years
ended December 31, 1998, 1997 and 1996 49
Consolidated Statements of Cash Flows for the years
ended December 31, 1998, 1997 and 1996 50
Notes to Consolidated Financial Statements 51
Schedule:
II. Valuation and Qualifying Accounts and Reserves for the
years ended December 31, 1998, 1997 and 1996
All other schedules have been omitted because of the absence of the
conditions under which they are required, or because the information
required is included in the financial statements or the notes thereto.
Financial statements of the Company's subsidiaries are not filed
herewith inasmuch as the assets, revenues, earnings and earnings
reinvested in the business of the subsidiaries are not material in
relation to those of the Company.
Exhibits:
Exhibit Index 80
44
Consolidated Statements of
INCOME
(FOR YEARS ENDED DECEMBER 31; DOLLARS IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS) 1998 1997 1996
------------------------------------------------------ ---------------- ---------------- ---------------
Operating Revenues:
Electric $1,475,208 $1,231,424 $1,198,769
Gas 416,551 409,447 400,108
Other 15,581 36,031 50,402
- ------------------------------------------------------ ---------------- ---------------- ---------------
Total operating revenues 1,907,340 1,676,902 1,649,279
- ------------------------------------------------------ ---------------- ---------------- ---------------
Operating Expenses:
Energy costs:
Purchased electricity 752,148 614,929 562,314
Residential Exchange (55,562) (71,970) (103,154)
Purchased gas 175,805 179,287 177,719
Fuel 56,557 41,455 40,645
Utility operations and maintenance 237,835 251,390 243,085
Other operations and maintenance 7,614 21,256 32,234
Depreciation, depletion and amortization 165,587 161,865 144,206
Merger and related costs -- 55,789 4,835
Taxes other than federal income taxes 160,472 159,310 155,174
Federal income taxes 107,904 47,725 107,747
- ------------------------------------------------------ ---------------- ---------------- ---------------
Total operating expenses 1,608,360 1,461,036 1,364,805
- ------------------------------------------------------ ---------------- ---------------- ---------------
Operating Income 298,980 215,866 284,474
- ------------------------------------------------------ ---------------- ---------------- ---------------
Other Income 9,192 28,066 1,593
- ------------------------------------------------------ ---------------- ---------------- ---------------
Income Before Interest Charges 308,172 243,932 286,067
- ------------------------------------------------------ ---------------- ---------------- ---------------
Interest Charges:
AFUDC (7,580) (5,205) (3,919)
Interest expense 146,140 123,439 122,635
- ------------------------------------------------------ ---------------- ---------------- ---------------
Total interest charges 138,560 118,234 118,716
- ------------------------------------------------------ ---------------- ---------------- ---------------
Income from Continuing Operations 169,612 125,698 167,351
Discontinued Operations:
Loss from operations, net of tax -- -- (1,386)
Loss on disposal, net of tax -- (2,622) (446)
- ------------------------------------------------------ ---------------- ---------------- ---------------
Net Income 169,612 123,076 165,519
- ------------------------------------------------------ ---------------- ---------------- ---------------
Less Preferred Stock Dividends Accrual 13,003 17,806 22,181
Preferred Stock Redemptions -- 471 --
- ------------------------------------------------------ ---------------- ---------------- ---------------
Income for Common Stock $156,609 $105,741 $143,338
- ------------------------------------------------------ ---------------- ---------------- ---------------
Common Shares Outstanding Weighted Average 84,561 84,560 84,418
- ------------------------------------------------------ ---------------- ---------------- ---------------
Basic and Diluted Earnings (Loss) Per Common Share:
From continuing operations $1.85 $1.28 $1.72
From discontinued operations -- (0.03) (0.02)
- ------------------------------------------------------ ---------------- ---------------- ---------------
Basic and diluted earnings per common share $1.85 $1.25 $1.70
- ------------------------------------------------------ ---------------- ---------------- ---------------
The accompanying notes are an integral part of the consolidated financial
statements.
45
Consolidated Balance Sheets
ASSETS
(AT DECEMBER 31; DOLLARS IN THOUSANDS) 1998 1997
- ----------------------------------------------------- ------------------ -----------------
Utility Plant:
Electric plant $3,827,685 $3,632,652
Gas plant 1,324,323 1,231,109
Less: Accumulated depreciation and amortization 1,721,096 1,613,300
- ----------------------------------------------------- ------------------ -----------------
Net utility plant 3,430,912 3,250,461
- ----------------------------------------------------- ------------------ -----------------
Other Property and Investments:
Investment in Bonneville Exchange Power Contract 70,537 78,880
Other 192,863 200,764
- ----------------------------------------------------- ------------------ -----------------
Total other property and investments 263,400 279,644
- ----------------------------------------------------- ------------------ -----------------
Current Assets:
Cash 25,278 7,759
- ----------------------------------------------------- ------------------ -----------------
Accounts receivable 201,980 158,927
Less: Allowance for doubtful accounts (1,021) (971)
- ----------------------------------------------------- ------------------ -----------------
Total accounts receivable 200,959 157,956
- ----------------------------------------------------- ------------------ -----------------
Unbilled revenues 126,740 122,831
Purchased gas receivable 5,492 --
Materials and supplies, at average cost 58,534 54,423
Prepayments and other 7,296 5,420
- ----------------------------------------------------- ------------------ -----------------
Total current assets 424,299 348,389
- ----------------------------------------------------- ------------------ -----------------
Long-Term Assets:
Regulatory asset for deferred income taxes 241,406 258,430
PURPA buyout costs 221,802 215,000
Other 138,870 141,446
- ----------------------------------------------------- ------------------ -----------------
Total long-term assets 602,078 614,876
===================================================== ================== =================
Total Assets $4,720,689 $4,493,370
===================================================== ================== =================
The accompanying notes are an integral part of the consolidated financial
statements.
46
Consolidated Balance Sheets
CAPITALIZATION AND LIABILITIES
(AT DECEMBER 31; DOLLARS IN THOUSANDS) 1998 1997
- ------------------------------------------------------------------ -------------- --------------
Capitalization:
(See "Consolidated Statements of Capitalization"):
Common equity $1,352,680 $1,358,077
Preferred stock not subject to mandatory redemption 95,075 95,488
Preferred stock subject to mandatory redemption 73,162 78,134
Corporation obligated, mandatorily redeemable preferred
securities of subsidiary trust holding solely junior
subordinated debentures of the corporation 100,000 100,000
Long-term debt 1,474,748 1,411,707
- ------------------------------------------------------------------ -------------- --------------
Total capitalization 3,095,665 3,043,406
- ------------------------------------------------------------------ -------------- --------------
Current Liabilities:
Accounts payable 167,691 124,899
Short-term debt 450,905 372,538
Current maturities of long-term debt 107,000 51,000
Purchased gas liability -- 876
Accrued expenses:
Taxes 72,883 73,636
Salaries and wages 16,053 15,326
Interest 39,062 27,704
Other 23,008 24,847
- ------------------------------------------------------------------ -------------- --------------
Total current liabilities 876,602 690,826
- ------------------------------------------------------------------ -------------- --------------
Deferred Income Taxes 628,554 629,018
- ------------------------------------------------------------------ -------------- --------------
Other Deferred Credits 119,868 130,120
- ------------------------------------------------------------------ -------------- --------------
Commitments and Contingencies -- --
================================================================== ============== ==============
Total Capitalization and Liabilities $4,720,689 $4,493,370
================================================================== ============== ==============
The accompanying notes are an integral part of the consolidated financial
statements.
47
Consolidated Statements of
CAPITALIZATION
(AT DECEMBER 31; DOLLARS IN THOUSANDS) 1998 1997
- ------------------------------------------------------------------------------- -------------- --------------
Common Equity:
Common stock ($10 stated value) - 150,000,000 shares
authorized, 84,560,561 and 84,560,645 shares outstanding $845,606 $845,606
Additional paid-in capital 450,724 450,845
Earnings reinvested in the business 47,548 46,672
Accumulated other comprehensive income - net 8,802 14,954
- ------------------------------------------------------------------------------- -------------- --------------
Total common equity 1,352,680 1,358,077
- ------------------------------------------------------------------------------- -------------- --------------
Preferred Stock Not Subject to Mandatory Redemption - cumulative - $25 par
value: (a) Adjustable Rate, Series B - 2,000,000 shares
authorized, 203,006 and 219,506 shares outstanding 5,075 5,488
7.45% series II - 2,400,000 shares authorized and outstanding 60,000 60,000
8.50% series III - 1,200,000 shares authorized
and outstanding 30,000 30,000
- ------------------------------------------------------------------------------- -------------- --------------
Total preferred stock not subject to mandatory redemption 95,075 95,488
- ------------------------------------------------------------------------------- -------------- --------------
Preferred Stock Subject To Mandatory Redemption - cumulative
$100 par value:*
4.84% series - 150,000 shares authorized,
14,808 shares outstanding 1,481 1,481
4.70% series - 150,000 shares authorized,
4,311 shares outstanding 431 431
8% series - 150,000 shares authorized,
-0- and 12,224 shares outstanding -- 1,222
7.75% series - 750,000 shares authorized, 712,500 and 750,000
shares outstanding 71,250 75,000
- ------------------------------------------------------------------------------- -------------- --------------
Total preferred stock subject to mandatory redemption 73,162 78,134
- ------------------------------------------------------------------------------- -------------- --------------
Corporation obligated, mandatorily redeemable preferred
securities of subsidiary trust holding solely junior
subordinated debentures of the corporation 100,000 100,000
- ------------------------------------------------------------------------------- -------------- --------------
Long-Term Debt:
First mortgage bonds and senior notes 1,420,000 1,301,000
Pollution control revenue bonds:
Revenue refunding 1991 series, due 2021 50,900 50,900
Revenue refunding 1992 series, due 2022 87,500 87,500
Revenue refunding 1993 series, due 2020 23,460 23,460
Other notes 12 17
Unamortized discount - net of premium (124) (170)
Long-term debt due within one year (107,000) (51,000)
- ------------------------------------------------------------------------------- -------------- --------------
Total long-term debt excluding current maturities 1,474,748 1,411,707
- ------------------------------------------------------------------------------- -------------- --------------
Total Capitalization $3,095,665 $3,043,406
- ------------------------------------------------------------------------------- -------------- --------------
(a) 13,000,000 shares authorized for $25 par value preferred stock and 3,000,000
shares authorized for $100 par value preferred stock.
The accompanying notes are an integral part of the consolidated financial
statements.
48
Consolidated Statements of
EARNINGS REINVESTED
(FOR YEARS ENDED DECEMBER 31; DOLLARS IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS) 1998 1997 1996
------------------------------------------------ --------------- -------------- ------------
Balance at Beginning of Year $ 46,672 $ 86,355 $ 84,254
Net Income 169,612 123,076 165,519
Adjustment to conform fiscal year of WECo -- 10,835 --
- ------------------------------------------------ --------------- -------------- -------------
Total 216,284 220,266 249,773
- ------------------------------------------------ --------------- -------------- -------------
Deductions:
Dividends declared:
Preferred stock:
Adjustable Rate Series B 272 2,010 2,716
$1.86 per share on 7.45% series II 4,470 4,470 4,470
$2.13 per share on 8.50% series III 2,550 2,550 2,550
$4.84 per share on 4.84% series 72 192 232
$4.70 per share on 4.70% series 20 203 265
$8.00 per share on 8% series 25 122 218
$7.75 per share on 7.75% series 5,667 5,813 5,813
$1.97 per share on 7.875% series -- 3,940 5,906
Common Stock 155,591 150,591 141,248
Preferred stock redemptions 69 3,703 --
- ------------------------------------------------ --------------- -------------- -------------
Total deductions 168,736 173,594 163,418
- ------------------------------------------------ --------------- -------------- -------------
Balance at End of Year $ 47,548 $46,672 $86,355
- ------------------------------------------------ --------------- -------------- -------------
Dividends Declared Per Common Share $1.84 $1.78 $1.67
- ------------------------------------------------ --------------- -------------- -------------
Consolidated Statements of
COMPREHENSIVE INCOME
(FOR YEARS ENDED DECEMBER 31; DOLLARS IN THOUSANDS) 1998 1997 1996
- ------------------------------------------------------- ------------- ------------- -------------
Net Income $169,612 $123,076 $165,519
Other comprehensive income, net of tax:
Unrealized holding gains (losses) on available
for sale securities (6,152) 14,954 --
- ------------------------------------------------------- ------------- ------------- -------------
Comprehensive Income $163,460 $138,030 $165,519
- ------------------------------------------------------- ------------- ------------- -------------
The accompanying notes are an integral part of the consolidated financial
statements.
49
Consolidated Statements of
CASH FLOW
(FOR YEARS ENDED DECEMBER 31; DOLLARS IN THOUSANDS) 1998 1997 1996
- ------------------------------------------------------------------ -------------- ---------------- ---------------
Operating Activities:
Income from continuing operations $169,612 $125,698 $167,351
Adjustments to reconcile income from continuing
operations to net cash provided by operating activities:
Depreciation and amortization 165,587 161,865 144,206
Deferred income taxes and tax credits - net 16,560 27,422 6,842
PRAM accrued revenues - net -- 40,777 74,326
Pretax write-down and equity in undistributed
losses of unconsolidated affiliate -- 4,044 961
PURPA buyout costs -- (215,000) --
Other (14,792) 43,286 (21,918)
Change in certain current assets and liabilities (22,692) (58,394) 27,809
- ------------------------------------------------------------------ -------------- ---------------- ---------------
Net cash provided by operating activities 314,275 129,698 399,577
- ------------------------------------------------------------------ -------------- ---------------- ---------------
Investing Activities:
Construction expenditures - excluding equity AFUDC (335,471) (257,900) (205,050)
Energy conservation expenditures (6,745) (4,864) (6,683)
Cash received from sale of conservation assets - net -- 34,372 --
Proceeds from property sales 6,877 7,013 34,000
Other 1,967 17,703 (7,384)
- ------------------------------------------------------------------ --------------- ---------------- ---------------
Net cash used by investing activities (333,372) (203,676) (185,117)
- ------------------------------------------------------------------ --------------- ---------------- ---------------
Financing Activities:
Increase (decrease) in short-term debt 78,367 85,975 (30,921)
Dividends paid (168,667) (169,892) (163,418)
Issuance of common and preferred stock -- 65 3,686
Issuance of company obligated, mandatorily
redeemable preferred securities -- 100,000 --
Redemption of preferred stock (5,454) (128,747) (1,200)
Issuance of bonds 200,000 300,000 34,470
Redemption of bonds and notes (81,004) (102,844) (72,612)
Other 13,374 (4,572) (558)
- ------------------------------------------------------------------ -------------- ---------------- ----------------
Net cash provided (used) by financing activities 36,616 79,985 (230,553)
- ------------------------------------------------------------------ -------------- ---------------- ----------------
Increase (Decrease) in cash from continuing operations 17,519 6,007 (16,093)
Decrease in cash from discontinued operations:
Operating activities -- -- (1,386)
Investing activities -- (2,622) --
- ------------------------------------------------------------------ -------------- ----------------- --------------
Net Increase (Decrease) in Cash 17,519 3,385 (17,479)
Cash at Beginning of Year 7,759 4,335 21,814
Adjustment to conform fiscal year of WECo -- 39 --
- ------------------------------------------------------------------ -------------- ---------------- ---------------
Cash at End of Year $25,278 $7,759 $4,335
- ------------------------------------------------------------------ -------------- ---------------- ---------------
The accompanying notes are an integral part of the consolidated financial
statements.
50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
Puget Sound Energy, Inc., formerly Puget Sound Power & Light Company
("the Company"), is an investor-owned public utility incorporated in the State
of Washington furnishing electric, and since February 10, 1997, gas service in a
territory covering approximately 6,000 square miles, principally in the Puget
Sound region of Washington state. On February 10, 1997, the Company completed a
merger ("the Merger") with Washington Energy Company ("WECo") and its principal
subsidiary, Washington Natural Gas Company ("WNG"). The change of the Company's
name was effective with the merger. Herein, the Company refers to the combined
entity; Puget Power and WECo refer to the individual entities.
The merger has been structured as a tax-free exchange of shares, and is
accounted for as a pooling of interests for financial statement purposes.
Accordingly, the consolidated financial statements have been retroactively
restated to include the results of operations, financial position and cash flows
of WECo and WNG for all periods prior to consummation of the merger. Financial
information prior to January 1, 1997, contained herein reflects fiscal years
ended December 31 for Puget Power and September 30 for WECo. Certain
reclassifications have been made to the 1997 and 1996 financial statements to
conform to the 1998 presentation with no effect impact on consolidated net
income, total assets or common equity.
The consolidated financial statements include the accounts of the Company
and all its significant wholly-owned subsidiaries, after elimination of all
significant intercompany items and transactions. One immaterial subsidiary is
stated on an equity basis.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period.
Actual results could differ from those estimates.
UTILITY PLANT
The costs of additions to utility plant, including renewals and
betterments, are capitalized at original cost. Costs include indirect costs such
as engineering, supervision, certain taxes and pension and other employee
benefits, and an allowance for funds used during construction. Replacements of
minor items of property are included in maintenance expense. The original cost
of operating property together with removal cost, less salvage, is charged to
accumulated depreciation when the property is retired and removed from service.
REGULATORY ASSETS & AGREEMENTS
The Company prepares its financial statements in accordance with Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" ("Statement No. 71"). Statement No. 71 requires the Company
to defer certain costs that would otherwise be charged to expense, if it is
probable that future rates will permit recovery of such costs. Accounting under
Statement No. 71 is appropriate as long as: rates are established by or subject
to approval by independent, third-party regulators; rates are designed to
recover the specific enterprise's cost-of-service; and in view of demand for
service, it is reasonable to assume that rates set at levels that will recover
costs can be charged to and collected from customers. In applying Statement No.
71, the Company must give consideration to changes in the level of demand or
competition during the cost recovery period. In accordance with Statement No.
71, the Company capitalizes certain costs in accordance with regulatory
authority whereby those costs will be expensed and recovered in future periods.
51
Net regulatory assets and liabilities at December 31, 1998 and 1997,
included the following:
(DOLLARS IN MILLIONS) 1998 1997
- -------------------------------------------- -------------- --------------
Deferred income taxes $241.4 $258.4
PURPA buyout costs 221.8 215.0
Investment in BEP Exchange Contract 70.5 78.9
Unamortized energy conservation charges 7.1 6.9
Storm damage costs 34.6 33.4
Various other costs 63.0 68.2
Deferred gains on property sales (17.2) (17.5)
- -------------------------------------------- -------------- --------------
Total $621.2 $643.3
- -------------------------------------------- -------------- --------------
If the Company, at some point in the future, determines that all or a
portion of the utility operations no longer meets the criteria for continued
application of Statement No. 71, the Company would be required to adopt the
provisions of Statement of Financial Accounting Standards No. 101, "Regulated
Enterprises - Accounting for the Discontinuation of Application of FASB
Statement No. 71" ("Statement No. 101"). Adoption of Statement No. 101 would
require the Company to write off the regulatory assets and liabilities related
to those operations not meeting Statement No. 71 requirements. Discontinuation
of Statement No. 71 could have a material impact on the Company's financial
statements.
The Emerging Issues Task Force ("EITF") of the Financial Accounting
Standards Board ("FASB") met in May and July of 1997 to address the issues of
when an entity should discontinue the application of Statement No. 71, and how
Statement No. 101 should be applied to a portion of an entity subject to a
transition-to-competition plan. As a result of these meetings, a consensus was
reached that Statement No. 71 should be discontinued at a date no later than
when the details of the transition-to-competition plan for all or a portion of
the entity subject to such plan are known. Additionally, the EITF reached a
consensus that stranded costs which are to be recovered through cash flows
derived from another portion of the entity which continues to apply Statement
No. 71 should not be written off; rather, they should be considered regulatory
assets of the segment which will continue to apply Statement No. 71.
The Company's financial statements continue to apply Statement No. 71 for
regulated operations. Although discussions with regulatory authorities regarding
retail competition have occurred and are expected to continue, no final
transition to competition plans for the Company's regulated operations have yet
been adopted or proposed.
The Company, in prior years, incurred costs associated with its 5%
interest in a now-terminated nuclear generating project (identified herein as
"Investment in Bonneville Exchange Power ("BEP")"). Under terms of a settlement
agreement with the Bonneville Power Administration ("BPA"), which settled claims
of the Company relating to construction delays associated with that project, the
Company is receiving, over 30.5 years, power from the federal power system
resources marketed by BPA. Approximately two-thirds of the Company's investment
in BEP is included in rate base and amortized on a straight-line basis over the
life of the contract (amortization is included in "Purchased and interchanged
power"). The remainder of the Company's investment is being recovered in rates
over ten years, without a return during the recovery period (the related
amortization is included in "Depreciation and Amortization", pursuant to a FERC
accounting order).
The Company has recorded a regulatory asset for $215 million related to
the buyout of a gas sales contract of a non-utility generator. A Washington
Commission accounting order approved the payment for deferral and collection in
rates over the remaining life of the energy supply contract. 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.
52
The Company also has agreements under which ConneXt, a wholly owned
subsidiary of the Company, performs certain billing and customer information
technology functions. Under an accounting order approved by the Washington
Commission, the Company records payments to ConneXt as if such costs were paid
to third-party providers and these costs will be reviewed in a future rate
filing.
OPERATING REVENUES
Operating revenues are recorded on the basis of service rendered, which
includes estimated unbilled revenue and, prior to October 1, 1996, revenue
accrued under the Periodic Rate Adjustment Mechanism ("PRAM").
ENERGY CONSERVATION
The Company accumulates energy conservation expenditures which are
included in rate base and amortized to expense as prescribed by the Washington
Commission.
In June 1995, the Company sold approximately $202.5 million of its
investment in customer-owned energy conservation measures to a grantor trust
which, in turn, issued securities backed by a Washington state statute enacted
in 1994. The Company sold an additional investment of $35.2 million in
customer-owned energy conservation measures in August 1997. The proceeds of the
sales were used to pay down short-term debt. The Company recognized no gain or
loss on the sales.
SELF-INSURANCE
The Company currently has no insurance coverage for storm damage and is
self-insured for a portion of the risk associated with comprehensive liability,
industrial accidents and catastrophic property losses. With approval of the
Washington Commission, the Company is able to defer for collection in future
rates certain uninsured storm damage costs associated with major storms.
DEPRECIATION AND AMORTIZATION
For financial statement purposes, the Company provides for depreciation
on a straight-line basis. The depreciation of automobiles, trucks, power
operated equipment and tools is allocated to asset and expense accounts based on
usage. The annual depreciation provision stated as a percent of average original
cost of depreciable electric utility plant was 3.0% in 1998, 1997 and 1996 and
for depreciable gas utility plant was 3.4% in 1998 and 1997 and 3.6% in 1996.
FEDERAL INCOME TAXES
The Company normalizes, with the approval of the Washington Commission,
certain items. Deferred taxes have been determined under Statement of Financial
Accounting Standards No. 109. Investment tax credits are deferred and amortized
based on the average useful life of the related property in accordance with
regulatory and income tax requirements. (See Note 13)
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The Allowance for Funds Used During Construction ("AFUDC") represents the
cost of both the debt and equity funds used to finance utility plant additions
during the construction period. The amount of AFUDC recorded in each accounting
period varies depending principally upon the level of construction work in
progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of
utility plant and is credited as a non-cash item to other income and interest
charges currently. Cash inflow related to AFUDC does not occur until these
charges are reflected in rates.
The AFUDC rate allowed by the Washington Commission for gas utility plant
additions was 9.15% in 1998 and 1997 and 9.03% in 1996. The allowed AFUDC rate
on electric utility plant was 8.94% during the same period. To the extent
amounts calculated using this rate exceed the AFUDC calculated using the Federal
Energy Regulatory Commission ("FERC") formula, the Company capitalizes the
excess as a deferred asset, crediting miscellaneous income. The amounts included
in income were: $3,409,000 for 1998, $2,704,000 for 1997 and $2,112,000 for
1996. The deferred asset is being amortized over the average useful life of the
Company's non-project utility plant.
53
PERIODIC RATE ADJUSTMENT MECHANISM
In April 1991, the Washington Commission issued an order establishing a
PRAM designed to operate as an interim rate adjustment mechanism between
electric general rate cases. Under the PRAM, Puget Power was allowed to request
annual rate adjustments, on a prospective basis, to reflect changes in certain
costs as set forth in the PRAM order. Also, under terms of the order, recovery
of certain costs was decoupled from levels of electricity sales.
Rates established for the PRAM period were subject to future adjustment
based on actual customer growth and variations in certain costs, principally
those affected by hydro and weather conditions. To the extent revenue billed to
customers varied from amounts allowed under the methodology established in the
PRAM order, the difference was accumulated, without interest, for rate recovery
which was then established in the next PRAM hearing. In its September 22, 1995,
order, the Washington Commission approved Puget Power's last PRAM filing and the
recovery of $71.2 million over the period October 1, 1995, through September 30,
1996. In addition to approval of the rate adjustment, the Commission also
agreed, pursuant to a negotiated settlement, to discontinue the PRAM on
September 30, 1996, the end of the last PRAM period. PRAM accrued revenues of
$40.5 million, recorded at December 31, 1996, were recovered in the first
quarter of 1997. Over-collection of PRAM revenues was refunded to customers in
the second quarter of 1997.
With the discontinuance of the PRAM, the Company no longer has a rate
adjustment mechanism to adjust for changes in energy or fuel costs or variances
in hydro and weather conditions. These variances may now significantly influence
earnings.
PGA MECHANISM
Differences between the actual cost of the Company's gas supplies and
that currently allowed by the Washington Commission are deferred and recovered
or repaid through the purchased gas adjustment ("PGA") mechanism.
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.
OFF-SYSTEM SALES AND CAPACITY RELEASE
The Company has been selling excess gas supplies and entering into gas
supply exchanges with third parties outside of its distribution area since 1992.
The Company began releasing to third parties excess interstate gas pipeline
capacity and gas storage rights on a short-term basis in 1993 and 1994,
respectively. The Company contracts for firm gas supplies and holds firm
transportation and storage capacity sufficient to meet the expected peak winter
demand for gas for space heating by its firm customers. Due to the variability
in weather and other factors, however, the Company holds contractual rights to
gas supplies and transportation and storage capacity in excess of its immediate
requirements to serve firm customers on its distribution system for much of the
year which, therefore, are available for third-party gas sales, exchanges and
capacity releases. The net proceeds from such activities are accounted for as
reductions in the cost of purchased gas and passed on to customers through the
PGA mechanism, with no direct impact on net income. As a result, the Company
does not reflect sales revenue or associated cost of sales for these
transactions in its income statement. The net proceeds from these activities
were $22,071,881, $16,759,000 and $10,711,000 for 1998, 1997 and 1996,
respectively.
54
RISK MANAGEMENT AND ENERGY TRADING
The Company's energy related businesses are exposed to risks related to
changes in commodity prices. As part of its business, the Company markets power
to other utilities and power marketers by entering into contracts to purchase or
supply electric energy or natural gas at specified delivery points and at
specified future delivery dates. The Company's energy trading function manages
the Company's core electric and gas supply portfolios as well as non-core
incremental energy supply trading activities.
The Company enters into futures and options for the purpose of hedging
commodity price picks. Gains or losses on these derivatives are deferred and
recognized upon settlement along with the underlying sales or purchase contract.
The Company has established policies and procedures to manage these risks. A
Risk Management Committee separate from the units that create these risks
monitors compliance with the Company's policies and procedures. In addition, the
Audit Committee of the Company's Board of Directors has oversight of the Risk
Management Committee.
OTHER
Debt premium, discount and expenses are amortized over the life of the
related debt. The premiums and costs associated with reacquired debt are being
amortized over the life of the related new issuances, in accordance with
ratemaking treatment.
In June 1997, the FASB issued Statement of Financial Accounting Standards
No. 130, "Reporting Comprehensive Income" ("Statement No. 130"), which
establishes rules for reporting and displaying comprehensive income and its
components. In June 1997, the FASB issued Statement of Financial Accounting
Standards No. 131, "Disclosures about Segments of an Enterprise and Related
Information" ("Statement No. 131"), which established requirements that
companies report certain information about operating segments. In February 1998,
the FASB issued Statement of Financial Accounting Standards No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits" ("Statement No.
132"), which standardizes the disclosure requirements for pensions and other
postretirement benefits. The Company adopted these statements in 1998 which
resulted in additional financial disclosures but no impact on the Company's
financial position or results of operations.
During 1998, the EITF of the FASB released Issue 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities" ("EITF
98-10"). EITF 98-10 addresses accounting for the purchase and sale of energy
trading contracts. The conclusion reached by the EITF was that such energy
trading contracts should be recorded at fair value with the mark-to-market gains
or losses recorded in current earnings. EITF 98-10 is effective for fiscal years
beginning after December 15, 1998. The Company does not consider its current
operations to meet the definition of trading activities as described by EITF
98-10, other than the activities entered into on the Company's behalf through
the contract with DETM. These activities are currently accounted for using fair
value and mark-to-market accounting. Accordingly, the Company has concluded that
the adoption of EITF 98-10 will not have a material impact on the Company's
financial position or results of operations.
In April 1998, the Accounting Standards Executive Committee issued
Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities"
("SOP 98-5"). SOP 98-5 is effective for fiscal years beginning after December
15, 1998. SOP 98-5 provides guidance on the financial reporting of start-up
costs and organization costs. It requires costs of start-up activities and
organization costs to be expensed as incurred. The Company has not yet
determined the impact that the adoption of SOP 98-5 will have on its financial
position or results of operations.
In June 1998, the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities"
("Statement No. 133"). Statement No. 133 is effective for the fiscal year ending
December 31, 2000. Statement No. 133 requires that all derivative instruments be
recorded on the balance sheet at their fair value. Changes in the fair value of
derivatives are recorded each period in current earnings or other comprehensive
income, depending on whether a derivative is designated as part of a hedge
transaction and, if it is, the type of hedge transaction. The Company has not
yet determined the impact that the adoption of Statement No. 133 will have on
its financial statements or the timing of adoption.
55
EARNINGS PER COMMON SHARE
During 1997, the Company adopted Statement of Financial Accounting
Standards No. 128, "Earnings per Share" ("Statement No. 128"). As required under
Statement No. 128, earnings per share data have been restated for all prior
periods presented.
Basic earnings per common share have been computed based on weighted
average common shares outstanding of 84,561,000, 84,560,000 and 84,418,000 for
1998, 1997 and 1996, respectively. Diluted earnings per common share have been
computed based on weighted average common shares outstanding of 84,768,000,
84,628,000 and 84,449,000 for 1998, 1997 and 1996, respectively, which include
the dilutive effect of securities related to employee compensation plans.
NOTE 2.
PROPERTY PLANT AND EQUIPMENT
DECEMBER 31 (DOLLARS IN THOUSANDS) 1998 1997
- ----------------------------------------------- ------------- -------------
Electric and gas utility plant classified
by Prescribed accounts at original cost:
Distribution plant $2,794,906 $2,674,234
Production plant 943,808 939,211
Transmission plant 641,526 625,779
General plant 375,612 333,140
Construction work in progress 266,242 123,690
Completed work not classified -- 58,216
Intangible plant 99,776 78,491
Underground storage 16,307 16,277
Plant held for future use 9,016 10,263
Other 4,815 4,460
- ----------------------------------------------- ------------- -------------
Total electric and gas utility plant $5,152,008 $4,863,761
- ----------------------------------------------- ------------- -------------
56
Note 3.
Capital Stock
PREFERRED STOCK
------------------------------------------
NOT SUBJECT TO SUBJECT TO COMMON STOCK
MANDATORY MANDATORY
REDEMPTION REDEMPTION WITHOUT PAR VALUE
$25 PAR VALUE $100 PAR VALUE ($10 STATED VALUE)
- -------------------------------------------- ------------------- ------------------- ------------------------
SHARES OUTSTANDING JANUARY 1, 1996 8,600,000 890,395 84,340,755
- -------------------------------------------- ------------------- ------------------- ------------------------
Issued to Shareholders Under the Stock
Purchase and Dividend Reinvestment Plan:
1996 -- -- 148,417
1997 -- -- 33,930
- -------------------------------------------- ------------------- ------------------- ------------------------
Issued Pursuant to Employee Compensation
Plans:
1996 -- -- 21,886
1997 -- -- 17,063
- -------------------------------------------- ------------------- ------------------- ------------------------
Issued Pursuant to Directors' Stock Bonus
Plan:
1996 -- -- 187
- -------------------------------------------- ------------------- ------------------- ------------------------
Acquired for Sinking Fund:
1996 -- (12,000) --
1997 -- (12,050) --
1998 -- (49,500) --
- -------------------------------------------- ------------------- -------------------- -----------------------
Called for Redemption and Canceled:
1997 (4,780,494) (85,002) --
1998 (16,500) (224) --
- -------------------------------------------- -------------------- ------------------- -----------------------
Fractional Share Redemptions in
Connection with Merger Exchange:
1997 -- -- (1,593)
1998 -- -- (84)
- -------------------------------------------- ------------------- ------------------- ------------------------
Shares outstanding December 31, 1998 3,803,006 731,619 84,560,561
- -------------------------------------------- ------------------- ------------------- ------------------------
See "Consolidated Statements of Capitalization" for details on specific series.
On January 15, 1991, the Board of Directors declared a dividend of one
preference share purchase right (a "Right") on each outstanding common share of
the Company. The dividend was distributed on January 25, 1991, to shareholders
of record on that date. The Rights will be exercisable only if a person or group
acquires 10 percent or more of the Company's common stock or announces a tender
offer which, if consummated, would result in ownership by a person or group of
10 percent or more of the common stock. Each Right entitles the registered
holder to purchase from the Company one one-thousandth of a share of Preference
Stock, $50 par value per share, at an exercise price of $45, subject to
adjustments. The description and terms of the Rights are set forth in a Rights
Agreement between the Company and The Bank of New York, as Rights Agent. The
Rights expire on January 25, 2001, unless earlier redeemed by the Company.
57
The weighted average dividend rate for the Adjustable Rate Cumulative
Preferred Stock ("ARPS"), Series B ($25 par value) was 4.83% for 1998, 5.61% for
1997 and 5.49% for 1996. The Company reacquired 16,500 shares of ARPS Series B
through open-market purchases during 1998 and redeemed the remaining ARPS on
February 2, 1999 at $25 par plus accrued dividends through February 2, 1999.
The 8.50% and 7.45% Series Preferred may be redeemed at par on or after
September 1, 1999, and November 1, 2003, respectively.
NOTE 4.
PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
The Company is required to deposit funds annually in a sinking fund
sufficient to redeem the following number of shares of each series of preferred
stock at $100 per share plus accrued dividends: 4.84% Series and 4.70% Series,
3,000 shares each and 7.75% Series, 37,500 shares. All previous sinking fund
requirements have been satisfied. At December 31, 1998, there were 36,192 shares
of the 4.84% Series and 52,689 shares of the 4.70% Series acquired by the
Company and available for future sinking fund requirements. Upon involuntary
liquidation, all preferred shares are entitled to their par value plus accrued
dividends.
The preferred stock subject to mandatory redemption may also be redeemed
by the Company at the following redemption prices per share plus accrued
dividends: 4.84% Series, $102 and 4.70% Series, $101. The 7.75% Series may be
redeemed by the Company, subject to certain restrictions, at $104.65 per share
plus accrued dividends through February 15, 1999, and at per share amounts which
decline annually to a price of $100 after February 15, 2007.
On February 15, 1998, the Company redeemed all outstanding shares of the
8% Series, $100 par value Preferred including 12,000 shares for the sinking fund
at par and 224 shares at $101.00 per share.
NOTE 5.
COMPANY-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES
In 1997, the Company formed Puget Sound Energy Capital Trust I (the
"Trust") for the sole purpose of issuing and selling common and preferred
securities ("Trust Securities"). The proceeds from the sale of Trust Securities
were used to purchase Junior Subordinated Debentures ("Debentures") from the
Company. The Debentures are the sole assets of the Trust and the Company owns
all common securities of the Trust.
The Debentures have an interest rate of 8.231% and a stated maturity date
of June 1, 2027. The Trust Securities are subject to mandatory redemption at par
on the stated maturity date of the Debentures. The Trust Securities may be
redeemed earlier, under certain conditions, at the option of the Company.
Dividends relating to preferred securities are included in interest expense.
58
NOTE 6.
ADDITIONAL PAID-IN CAPITAL
(DOLLARS IN THOUSANDS) 1998 1997 1996
- -------------------------------------------- ----------- ------------ ----------
Balance at beginning of year $450,845 $446,910 $444,928
Excess of proceeds over stated values of
common stock issued -- 428 2,022
Par value over cost of reacquired
preferred stock -- 471 --
Retained earnings adjustment for
preferred redemption -- 3,036 --
Issue costs and other expenses (121) -- (40)
- -------------------------------------------- ----------- ------------ ----------
Balance at end of year $450,724 $450,845 $446,910
- -------------------------------------------- ----------- ------------ ----------
NOTE 7.
EARNINGS REINVESTED IN THE BUSINESS
The payment of dividends on common stock is restricted by provisions of
certain covenants applicable to preferred stock and long-term debt contained in
the Company's Articles of Incorporation and Mortgage Indentures. Under the most
restrictive covenants, earnings reinvested in the business unrestricted as to
payment of cash dividends were approximately $183 million at December 31, 1998.
The adjustments made to the carrying value of costs associated with the
terminated generating projects and Bonneville Exchange Power as a result of
Statement No. 90, adjustments made as a result of Statement No. 121 and the
disallowance of certain terminated generating project costs by the Washington
Commission do not impact the amount of earnings reinvested in the business for
purposes of payment of dividends on common stock under the terms of the
Company's Articles and Mortgage Indentures. (See Note 1.)
59
NOTE 8.
LONG-TERM DEBT
FIRST MORTGAGE BONDS AND SENIOR NOTES
(At December 31; dollars in thousands):
Series Due 1998 1997
- ---------------- -------- -------------- ----------------
6.17% 1998 -- 10,000
5.70% 1998 -- 5,000
8.25% 1998 -- 11,000
8.83% 1998 -- 25,000
6.50% 1999 16,500 16,500
6.65% 1999 10,000 10,000
6.41% 1999 20,500 20,500
7.08% 1999 10,000 10,000
7.25% 1999 50,000 50,000
6.61% 2000 10,000 10,000
9.60% 2000 25,000 25,000
8.51 - 8.55% 2001 19,000 19,000
9.14% 2001 -- 30,000
7.53 - 7.91% 2002 30,000 30,000
7.85% 2002 30,000 30,000
7.07% 2002 27,000 27,000
7.15% 2002 5,000 5,000
7.625% 2002 25,000 25,000
6.23 - 6.31% 2003 28,000 28,000
7.02% 2003 30,000 30,000
6.20% 2003 3,000 3,000
6.40% 2003 11,000 11,000
6.07 & 6.10% 2004 18,500 18,500
7.70% 2004 50,000 50,000
7.80% 2004 30,000 30,000
6.92 & 6.93% 2005 31,000 31,000
6.58% 2006 10,000 10,000
8.06% 2006 46,000 46,000
8.14% 2006 25,000 25,000
7.02 & 7.04% 2007 25,000 25,000
7.75% 2007 100,000 100,000
8.40% 2007 10,000 10,000
6.51 & 6.53% 2008 4,500 4,500
6.61 & 6.62% 2009 8,000 8,000
7.12% 2010 7,000 7,000
8.59% 2012 5,000 5,000
8.20% 2012 30,000 30,000
60
Series Due 1998 1997
- ---------------- -------- -------------- ----------------
6.83% & 6.90% 2013 13,000 13,000
7.35 & 7.36% 2015 12,000 12,000
6.74% 2018 200,000 --
9.57% 2020 25,000 25,000
8.25 - 8.40% 2022 35,000 35,000
7.19% 2023 13,000 13,000
7.35% 2024 55,000 55,000
7.15 & 7.20% 2025 17,000 17,000
7.02% 2027 300,000 300,000
- ---------------- -------- -------------- ----------------
Total $1,420,000 $1,301,000
- ---------------- -------- -------------- ----------------
On June 15, 1998, the Company issued $200 million principal amount of 6.74%
Senior Medium Term Notes, Series A. The Notes are due June 15, 2018.
On June 22, 1998, the Company redeemed $30 million principal amount of
First Mortgage Bonds, 9.14% Series due June 21, 2001, at a redemption price of
100%.
In September 1998, the Company filed a shelf-registration statement for
the offering on a delayed or continuous basis of up to $500 million principal
amount of Senior Notes secured by a pledge of First Mortgage Bonds.
Substantially all utility properties owned by the Company are subject to
the lien of the Company's electric and gas mortgage indentures.
POLLUTION CONTROL BONDS
The Company has outstanding three series of Pollution Control Bonds.
Amounts outstanding were borrowed from the City of Forsyth, Montana ("the
City"). The City obtained the funds from the sale of Customized Pollution
Control Refunding Bonds issued to finance pollution control facilities at
Colstrip Units 3 and 4.
Each series of bonds are collateralized by a pledge of the Company's
First Mortgage Bonds, the terms of which match those of the Pollution Control
Bonds. No payment is due with respect to the related series of First Mortgage
Bonds so long as payment is made on the Pollution Control Bonds. Interest rates
for the 1992 and 1993 series are 6.80% and 5.875%, respectively. The 1991 series
consists of $27.5 million principal amount bearing interest at 7.05% and $23.4
million principal amount bearing interest at 7.25%.
LONG-TERM DEBT MATURITIES
The principal amounts of long-term debt maturities for the next five
years are as follows:
(DOLLARS IN THOUSANDS) 1999 2000 2001 2002 2003
- -------------------------- -------- -------- -------- -------- --------
Maturities of
long-term debt $107,000 $ 35,000 $ 19,000 $117,000 $ 72,000
61
NOTE 9.
SHORT-TERM DEBT AND OTHER FINANCING ARRANGEMENTS
At December 31, 1998, the Company had short-term borrowing arrangements
which included a $375 million line of credit with thirteen banks. The agreement
provides the Company with the ability to borrow at different interest rate
options and includes variable fee levels. The options are: (1) the higher of the
prime rate or the Federal Funds rate plus 1/2 of 1 percent or (2) the Eurodollar
rate plus .25 percent. The current availability fee is .08 percent per annum on
the unused loan commitment.
In addition, the Company has agreements with several banks to borrow on
an uncommitted, as available, basis at money-market rates quoted by the banks.
There are no costs, other than interest, for these arrangements. The Company
also uses commercial paper to fund its short-term borrowing requirements.
AT DECEMBER 31: (DOLLARS IN THOUSANDS) 1998 1997 1996
------------------------------------- -------- -------- --------
Short-term borrowings outstanding:
Commercial paper notes $142,105 $124,538 $266,422
Bank line of credit borrowing $25,000 $215,000 --
Uncommitted bank borrowings $283,800 $33,000 $31,700
Weighted average interest rate 5.90% 6.88% 6.05%
Credit availability (a) $375,000 $375,000 $426,500
(a) Provides liquidity support for outstanding commercial paper and
borrowing from credit line banks in the amount of $167.1 million, $339.5 million
and $266.4 million for 1998, 1997 and 1996 respectively, effectively reducing
the available borrowing capacity under these credit lines to $207.9 million,
$35.5 million and $160.1 million, respectively.
The Company has, on occasion, entered into interest rate swap agreements
to reduce the impact of changes in interest rates on portions of its
floating-rate, short-term debt. The one agreement outstanding at December 31,
1998, effectively changes the Company's interest rate on outstanding commercial
paper to 9.64% on a notional principal amount of $16.5 million expiring March
31, 2000.
62
NOTE 10.
ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair
values of the Company's financial instruments at December 31, 1998 and 1997:
1998 1998 1997 1997
CARRYING FAIR CARRYING FAIR
(DOLLARS IN MILLIONS) AMOUNT VALUE AMOUNT VALUE
- --------------------------------------------- ----------- ----------- ------------ ----------
Financial Assets:
Cash $ 25.3 $ 25.3 $ 7.8 $ 7.8
Cabot common stock $40.0 $40.0 $41.5 $41.5
Cabot preferred stock $ 51.6 $51.6 $51.6 $51.6
Financial Liabilities:
Short-term debt $450.9 $450.9 $372.5 $372.5
Preferred stock subject to
mandatory redemption $73.2 $75.8 $ 78.1 $ 82.5
Corporation obligated, mandatorily
redeemable preferred securities of
subsidiary trust holding solely
junior subordinated debentures of
the corporation $100.0 $109.3 $100.0 $107.6
Long-term debt $1,581.7 $1,686.0 $1,462.7 $1,547.3
Unrecognized financial instruments:
Interest rate swaps -- $(1.3) -- $(1.2)
- --------------------------------------------- ----------- ------------ ----------- -----------
The fair value of outstanding bonds including current maturities is
estimated based on quoted market prices.
The preferred stock subject to mandatory redemption and corporation
obligated, mandatorily redeemable preferred securities of subsidiary trust
holding solely junior subordinated debentures of the corporation is estimated
based on dealer quotes.
The carrying value of short-term debt is considered to be a reasonable
estimate of fair value. The carrying amount of cash, which includes temporary
investments with original maturities of 3 months or less, is also considered to
be a reasonable estimate of fair value.
The fair value of interest rate swaps (used for hedging purposes) is the
estimated amount that the Company would receive or pay to terminate each swap
agreement at the reporting date, taking into account current interest rates and
the current credit-worthiness of all the parties to each swap.
Derivative instruments have been used by the Company on a limited basis.
The Company has a policy that financial derivatives are to be used only to
mitigate business risk and not for speculative purposes.
63
NOTE 11.
SUPPLEMENTARY INCOME STATEMENT INFORMATION
(DOLLARS IN THOUSANDS) 1998 1997 1996
- -------------------------------------- ------------- ------------- ------------
Taxes:
Real estate and personal property $ 40,422 $ 46,252 $ 43,762
State business 62,855 58,466 60,787
Municipal, occupational and other 48,090 45,252 43,681
Other 20,010 21,242 12,729
- -------------------------------------- ------------- ------------- ------------
Total taxes $171,377 $171,212 $160,959
- -------------------------------------- ------------- ------------- ------------
Charged to:
Operating expense $160,472 $159,310 $155,174
Other accounts, including
construction work in progress 10,905 11,902 5,785
- -------------------------------------- ------------- ------------- ------------
Total taxes $171,377 $171,212 $160,959
- -------------------------------------- ------------- ------------- ------------
See "Consolidated Statements of Income" for maintenance and depreciation
expense.
Advertising, research and development expenses and amortization of
intangibles are not significant. The Company pays no royalties.
NOTE 12.
LEASES
The Company treats all leases as operating leases for ratemaking purposes
as required by the Washington Commission. Certain leases contain purchase
options, renewal and escalation provisions. Capitalized leases are not material.
Rental and operating lease expense for the years ended December 31, 1998,
1997 and 1996, were approximately $17,798,000, $19,428,000 and $19,394,000,
respectively. Payments due for the years ended December 31, 1998, 1997 and 1996,
for the sublease of properties were approximately $1,242,000, $962,000 and
$1,674,000, respectively.
Future minimum lease payments for noncancelable leases are approximately
$14,562,000 for 1999, $14,762,000 for 2000, $13,501,000 for 2001, $13,040,000
for 2002, $10,833,000 for 2003 and in the aggregate, $7,137,000 thereafter.
Future minimum sublease receipts for noncancelable subleases are $1,883,000 for
1999, $1,681,000 for 2000, $669,000 for 2001, $669,000 for 2002, $390,000 for
2003 and in the aggregate, $0 thereafter.
64
NOTE 13.
FEDERAL INCOME TAXES
The details of federal income taxes ("FIT") are as follows:
(DOLLARS IN THOUSANDS) 1998 1997 1996
- -------------------------------------------- ---------- ----------- ----------
Charged to Operating Expense:
Current $90,696 $ 31,672 $111,989
Deferred - net 17,948 16,677 (3,058)
Deferred investment tax credits (740) (624) (1,184)
- -------------------------------------------- ---------- ----------- ----------
Total FIT charged to operations 107,904 47,725 107,747
- -------------------------------------------- ---------- ----------- ----------
Charged to Miscellaneous Income:
Current 5,601 16,709 (784)
Deferred - net (648) (1,902) --
- -------------------------------------------- ---------- ----------- -----------
Total FIT charged to miscellaneous income 4,953 14,807 (784)
- -------------------------------------------- ---------- ----------- -----------
Credited to discontinued operations -- (1,412) (986)
- -------------------------------------------- ---------- ----------- ----------
Total FIT $112,857 $ 61,120 $105,977
- -------------------------------------------- ---------- ----------- ----------
The following is a reconciliation of the difference between the amount of
FIT computed by multiplying pre-tax book income by the statutory tax rate, and
the amount of FIT in the Consolidated Statements of Income:
(DOLLARS IN THOUSANDS) 1998 1997 1996
- ------------------------------------------------- --------- --------- ----------
FIT at the statutory rate $98,864 $64,469 $95,024
- ------------------------------------------------- --------- --------- ----------
Increase (Decrease):
Depreciation expense deducted in the
financial statements in excess of tax
depreciation, net of depreciation
treated as a temporary difference 7,756 7,019 6,603
AFUDC included in income in the financial
statements but excluded from taxable income (3,953) (2,774) (2,191)
Accelerated benefit on early retirement
of depreciable assets (1,241) (805) (1,105)
Investment tax credit amortization (740) (624) (1,184)
Energy conservation expenditures - net 12,754 11,028 3,380
Conservation Settlement -- (26,197) --
Other - net (583) 9,004 5,450
- ------------------------------------------------- --------- --------- ----------
Total FIT $112,857 $61,120 $105,977
- ------------------------------------------------- --------- --------- ----------
Effective tax rate 40.0% 33.2% 39.0%
- ------------------------------------------------- --------- --------- ----------
65
The following are the principal components of FIT as reported:
(DOLLARS IN THOUSANDS) 1998 1997 1996
- -------------------------------------------------- ------------- --------------- --------------
Current FIT $96,297 $48,381 $111,205
- -------------------------------------------------- ------------- --------------- --------------
Deferred FIT - other:
Conservation tax settlement 3,257 14,404 (759)
Periodic rate adjustment mechanism (PRAM) 107 (14,272) (26,014)
Deferred taxes related to insurance reserves (1,224) (2,768) (938)
Reversal of Statement No. 90 present
Value adjustments 255 408 552
Residential Purchase and Sale Agreement - net 3,441 (6,047) (2,178)
Normalized tax benefits of the
Accelerated cost recovery system 20,118 22,575 23,407
Energy conservation program (2,437) 5,101 (1,208)
Environmental remediation (2,946) (3,092) 1,148
WNP 3 tax settlement (826) 21,360 --
Merger costs 42 (7,322) --
Demand charges 3,273 (3,558) --
Other (5,760) (12,014) 2,932
- -------------------------------------------------- --------------- ------------- --------------
Total deferred FIT - other 17,300 14,775 (3,058)
- -------------------------------------------------- ------------- --------------- --------------
Deferred investment tax credits -
net of amortization (740) (624) (1,184)
Credited to discontinued operations -- (1,412) (986)
- -------------------------------------------------- ------------- --------------- --------------
Total FIT $112,857 $61,120 $105,977
- -------------------------------------------------- ------------- --------------- --------------
Deferred tax amounts shown above result from temporary differences for
tax and financial statement purposes. Deferred tax provisions are not recorded
in the income statement for certain temporary differences between tax and
financial statement purposes because they are not allowed for ratemaking
purposes.
The Company calculates its deferred tax assets and liabilities under
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("Statement No. 109"). Statement No. 109 requires recording deferred tax
balances, at the currently enacted tax rate, for all temporary differences
between the book and tax bases of assets and liabilities, including temporary
differences for which no deferred taxes had been previously provided because of
use of flow-through tax accounting for rate-making purposes. Because of prior
and expected future ratemaking treatment for temporary differences for which
flow-through tax accounting has been utilized, a regulatory asset for income
taxes recoverable through future rates related to those differences has also
been established. At December 31, 1998, the balance of this asset is $241.4
million.
66
The deferred tax liability at December 31, 1998 and 1997, is comprised of
amounts related to the following types of temporary differences
(DOLLARS IN THOUSANDS) 1998 1997
- --------------------------------------- ------------- --------------
Utility plant $567,642 $558,170
Investment in Cabot stock 13,435 13,435
Energy conservation charges 57,919 74,376
Contributions in aid of construction (31,874) (30,350)
Bonneville Exchange Power 26,513 30,240
Other (5,081) (16,853)
- --------------------------------------- ------------- --------------
Total $628,554 $629,018
- --------------------------------------- ------------- --------------
The totals of $628.6 million and $629.0 million for 1998 and 1997 consist
of deferred tax liabilities of $712.2 million and $712.0 million net of deferred
tax assets of $83.6 million and $83.0 million, respectively.
NOTE 14.
RETIREMENT BENEFITS
The Company has a defined benefit pension plan covering substantially all
of its employees. Benefits are a function of both age and salary. Additionally,
the Company maintains a non-qualified supplemental retirement plan for officers
and certain director-level employees.
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees. These benefits
are provided principally through an insurance company whose premiums are based
on the benefits paid during the year.
Prior to March 1, 1997, the Company had separate defined benefit plans
covering electric and gas employees. Prior to 1997, the plan covering electric
employees had a measurement date of December 31 and the plan covering gas
employees had a measurement date of September 30.
PENSION BENEFITS OTHER BENEFITS
(DOLLARS IN THOUSANDS) 1998 1997 1998 1997
--------------------------- -----------------------
Change in benefit obligation
Benefit obligation at beginning of year $325,063 $293,535 $27,433 $26,243
Service cost 8,550 8,268 229 216
Interest cost 22,862 21,412 1,985 1,895
Amendments 2,540 2,828 -- -
Actuarial (gain)/loss 15,272 3,532 1,896 884
Mergers, sales and closures -- 16,304 -- --
Benefits paid (21,865) (20,816) (2,105) (1,805)
- --------------------------------------------------------------------------------- -----------------------
Benefit obligation at end of year $352,422 $325,063 $29,438 $27,433
- --------------------------------------------------------------------------------- -----------------------
Change in plan assets
Fair value of plan assets at beginning of year $415,270 $354,634 $14,445 $13,718
Actual return on plan assets 67,544 80,548 570 803
Employer contribution 3,246 904 1,222 1,729
Benefits paid (21,865) (20,816) (2,105) (1,805)
- --------------------------------------------------------------------------------- -----------------------
Fair value of plan assets at end of year $464,195 $415,270 $14,132 $14,445
- --------------------------------------------------------------------------------- -----------------------
67
(continued from previous page)
PENSION BENEFITS OTHER BENEFITS
(DOLLARS IN THOUSANDS) 1998 1997 1998 1997
---------------------------- ---------------------------
Funded status $111,773 $90,207 $(15,306) $(12,988)
Unrecognized actuarial (gain)/loss (133,189) (117,841) (1,532) (3,822)
Unrecognized prior service cost 25,510 26,301 (463) (497)
Unrecognized net initial (asset)/obligation (7,563) (8,794) 8,775 9,402
- ----------------------------------------------------------------------------------- -----------------------------
Net amount recognized $(3,469) $(10,127) $(8,526) $(7,905)
- ----------------------------------------------------------------------------------- -----------------------------
Amounts recognized on statement of
financial position consist of:
Prepaid benefit cost $8,900 $2,238 $(8,526) $(7,905)
Accrued benefit liability (22,988) (16,828) --
Intangible asset 10,619 4,463 --
- ----------------------------------------------------------------------------------- -----------------------------
Net amount recognized $(3,469) $(10,127) $(8,526) $(7,905)
- ----------------------------------------------------------------------------------- -----------------------------
In accounting for pension and other benefits costs under the plans, the
following weighted average actuarial assumptions were used:
PENSION BENEFITS OTHER BENEFITS
1998 1997 1996 1998 1997 1996
------------ ----------- ------------ ----------- ------------ ------------
Discount rate 7% 7.25-7.5% 7.5% 7% 7.25% 7.5%
Return on plan assets 9.75% 9% 8.5-9% 6-8.5% 6-8.5% 6-8.5%
Rate of compensation increase 5% 5% 5-5.5% -- -- --
Medical Trend Rate -- -- -- 7.5% 7.5% 8%
- ---------------------------------------- ------------ ----------- ------------ ----------- ------------ ------------
PENSION BENEFITS OTHER BENEFITS
1998 1997 1996 1998 1997 1996
------------ ----------- ------------ ----------- ------------ ------------
Components of net periodic benefit
cost:
(DOLLARS IN THOUSANDS)
Service cost $8,550 $8,268 $6,958 $229 $216 $424
Interest cost 22,862 21,412 16,715 1,985 1,895 2,157
Expected return on plan assets (33,744) (27,997) (20,944) (867) (821) (687)
Amortization of prior service cost 3,330 2,247 1,258 (34) (34) 32
Recognized net actuarial
(gain)/loss (3,180) (1,144) (3) (97) (204) (230)
Amortization of transition (1,230) (1,095) (420) 627 627 1,057
(asset)/obligation
Plan curtailments, mergers -- 5,138 (1,613) 712 1,418
- ---------------------------------------- ------------ ----------- --------- ----------- ------------ ------------
Net pension benefit cost under (3,412) 6,829 1,951 1,843 2,391 4,171
FASB Statement No. 87
Regulatory adjustment 1,263 1,263 1,263 -- -- --
- ---------------------------------------- ------------- ------------- --------- ----------- ------------ ------------
Net periodic benefit cost $(2,149) $8,092 $3,214 $1,843 $2,391 $4,171
- ---------------------------------------- ------------- ------------- --------- ----------- ------------ ------------
68
The projected benefit obligation, accumulated benefit obligation, and
fair value of plan assets for the pension plans with accumulated benefit
obligations in excess of plan assets were $27.7 million, $23.0 million, and $0,
respectively, as of December 31, 1998.
The assumed medical inflation rate is 7.5% in 1998 decreasing to 6% in
2003. A 1% change in the assumed medical inflation rate would have the following
effects:
1998 1997
1% 1% 1% 1%
(DOLLARS IN THOUSANDS) INCREASE DECREASE INCREASE DECREASE
----------------------------------- ---------------------------------
Effect on service and interest cost $690 $(671) $643 $(625)
components
Effect on postretirement benefit obligation $ 45 $(44) $42 $(41)
In December 1995, in connection with the proposed merger with WECo, the
Company offered to its employees a Voluntary Separation Plan. A total of 204
employees elected to participate in the Voluntary Separation Plan resulting in a
curtailment gain for 1996 of $1.6 million under Statement of Financial
Accounting Standards No. 88. In addition, curtailment losses under Statement No.
106 for 1997 of $4.7 million and 1996 of $1.4 million resulted from the 1995
Voluntary Separation Plan. Also in connection with the merger was a curtailment
loss of $5.1 million in 1997 related to the supplemental retirement plans.
NOTE 15.
EMPLOYEE INVESTMENT PLAN & EMPLOYEE STOCK PURCHASE PLAN
The Company has qualified Employee Investment Plans under which employee
salary deferrals and after-tax contributions are used to purchase several
different investment fund options. The Company makes a monthly contribution
equal to 100% on up to 4% of participant contributions and 50% on the next 4% of
participant contributions which equates to a maximum contribution of 6% of
eligible earnings. In addition, the Company contributes an amount equal to 1% of
each participant's base pay at the end of the plan year.
The Company contributions to the Employee Investment Plan were
$6,141,400, $5,068,100 and $4,102,000 for the years 1998, 1997 and 1996,
respectively. The shareholders have authorized the issuance of up to 2,000,000
shares of common stock under the plan, of which 959,142 were issued through
December 31, 1998. The Employee Investment Plan eligibility requirements are set
forth in the plan documents.
The Company also has an Employee Stock Purchase Plan which was approved
by shareholders on May 19, 1997, and commenced July 1, 1997, under which options
are granted to eligible employees who elect to participate in the plan on
January 1st and July 1st of each year. Participants are allowed to exercise
those options six months later to the extent of payroll deductions or cash
payments accumulated during that six-month period. The option price under the
plan is 90% of either the fair market value of the common stock at the grant
date or the fair market value at the exercise date, whichever is less. The
Company contributions to the Plan were $98,237 and $97,615 for 1998 and 1997,
respectively.
69
NOTE 16.
INVESTMENT IN CABOT OIL AND GAS
In May 1994, the Company merged its oil and gas exploration and
production subsidiary, Washington Energy Resources Company ("Resources"), with a
wholly-owned subsidiary of Cabot Oil and Gas Corporation ("Cabot") in a tax-free
exchange. At December 31, 1998, the Company owned 15.4% of Cabot's outstanding
voting securities consisting of 2,133,000 shares of common stock and 1,134,000
shares of 6% convertible voting preferred stock, stated value $50. Prior to
October 1, 1997, the Company's interest in Cabot's common stock was accounted
for using the equity method because the Company, through its representation on
Cabot's board of directors, had the ability to exercise significant influence
over operating and financial policies of Cabot. Effective October 1, 1997, the
Company discontinued equity-method accounting for Cabot and records its interest
as an investment in stock because the Company no longer has representation on
Cabot's board of directors. Equity in earnings (losses) from Cabot were $948,000
and ($619,000) for 1997 and 1996, respectively.
The investment in Cabot common stock has been classified as an
available-for-sale security and is reported at its fair value, based on the
closing price on the NYSE on December 31, 1998, of $31,995,000. The unrealized
gain of $8,802,000 (net of deferred taxes of $4,739,000) is reported as a
separate component of common equity. No fair value is readily available for the
Cabot preferred stock as it is not publicly traded; however, its cost basis of
$51,619,000 is believed to be a reasonable approximation of fair value at
December 31, 1998.
See Note 17 regarding certain gas transportation, storage and other
contractual arrangements of Resources that were excluded from the Cabot merger
and retained by a subsidiary of the Company.
NOTE 17.
COMMITMENTS AND CONTINGENCIES
Commitments - Electric
For the twelve months ended December 31, 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 public
utility districts ("PUDs") owning hydro-electric projects on the Columbia River.
The purchase of power from the Columbia River projects is generally on a
"cost-of-service" basis under which the Company pays a proportionate share of
the annual cost of each project in direct proportion to the amount of power
annually purchased by the Company from such project. Such payments are not
contingent upon the projects being operable. These projects are financed through
substantially level debt service payments, and their annual costs should not
vary significantly over the term of the contracts unless additional financing is
required to meet the costs of major maintenance, repairs or replacements or
license requirements. The Company's share of the costs and the output of the
projects is subject to reduction due to various withdrawal rights of the PUDs
and others over the lives of the contracts.
As of December 31, 1998, the Company was entitled to purchase portions of
the power output of the PUDs' projects as set forth in the following tabulation:
70
BONDS COMPANY'S ANNUAL AMOUNT
OUTSTANDING PURCHASABLE (APPROXIMATE)
-------------------------------------------------
CONTRACT LICENSE (A) 12/31/98 (B) % OF MEGAWATT COSTS (C)
PROJECT EXP. DATE EXP. DATE (MILLIONS) OUTPUT CAPACITY (MILLIONS)
- ---------------------- ---------------- ------------------- ------------------- ------------- ----------------- -----------------
Rock Island
Original units 2012 2029 72.2 53.9 480 $39.1
Additional units 2012 2029 319.7 100.0
Rocky Reach 2011 2006 227.2 38.9 505 20.8
Wells 2018 2012 172.5 31.3 261 9.0
Priest Rapids 2005 2005 171.9 8.0 72 2.1
Wanapum 2009 2005 194.7 10.8 98 3.2
----------------- -----------------
Total 1,416 $74.2
(a) The Company is unable to predict whether the licenses under the
Federal Power Act will be renewed to the current licensees. The FERC has issued
orders for Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section
22 of the Federal Power Act, which affirm the Company's contractual rights to
receive power under existing terms and conditions even if a new licensee is
granted a license prior to expiration of the contract term.
(b) The contracts for purchases initially were generally coextensive with
the term of the PUD bonds associated with the project. Under the terms of some
financings and refinancings, however, long-term bonds were sold to finance
certain assets whose estimated useful lives extend beyond the expiration date of
the power sales contracts. Of the total outstanding bonds sold for each project,
the percentage of principal amount of bonds which mature beyond the contract
expiration date are: 43.7% at Rock Island; 52.2% at Rocky Reach; 80.2% at Priest
Rapids; and 47.8% at Wanapum.
(c) The components of 1998 costs associated with the interest portion of
debt service are: Rock Island, $23.6 million for all units; Rocky Reach, $4.8
million; Wells, $2.7 million; Priest Rapids, $0.9 million; and Wanapum, $1.2
million.
The Company's estimated payments for power purchases from the Columbia
River projects are $82 million for 1999, $80 million for 2000, $80 million for
2001, $80 million for 2002, $78 million for 2003 and in the aggregate, $685
million thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts
with other utilities in the region. The Company is generally not obligated to
make payments under these contracts unless power is delivered. The Company's
estimated payments for firm power purchases from other utilities, excluding the
Columbia River projects, are $151 million for 1999, $157 million for 2000, $151
million for 2001, $143 million for 2002, $132 million for 2003 and in the
aggregate, $1.0 billion thereafter through 2037. These contracts have varying
terms and may include escalation and termination provisions.
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 Company purchases the net electrical output of
five significant projects at fixed and annually escalating prices which were
intended to approximate the Company's avoided cost of new generation projected
at the time these agreements were made. Principally, as a result of dramatic
changes in natural gas price levels, the power purchase prices under these
agreements are significantly above the current market price of power and, based
upon projections of future market prices, are expected to remain well above
market for the duration of the contracts. The Company's estimated payment under
these five contracts are $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. 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.
71
The following table summarizes the Company's obligations for future power
purchases.
2004 &
THERE-
(In Millions) 1999 2000 2001 2002 2003 AFTER TOTAL
- ------------------------------ ---------- ---------- ---------- ---------- ---------- ------------ ------------
Columbia River Projects $82 $80 $80 $80 $78 $685 $1,085
Other Utilities 151 157 151 143 132 1,000 1,734
Non-Utility Generators 280 284 308 313 318 2,400 3,903
- ------------------------------ ---------- ---------- ---------- ---------- ---------- ------------ ------------
Total $513 $521 $539 $536 $528 $4,085 $6,722
- ------------------------------ ---------- ---------- ---------- ---------- ---------- ------------ ------------
Total purchased power contracts provided the Company with approximately
15.8 million, 15.6 million and 17.1 million MWH of firm energy at a cost of
approximately $481.6 million, $464.5 million and $485.6 million for the years
1998, 1997 and 1996, respectively.
As part of its electric operations and in connection with the 1997
restructuring of the Tenaska Power Purchase Agreement the Company is obligated
to deliver to Tenaska up to 48,000 MMBtu per day of natural gas for operation of
Tenaska's cogeneration facility. This obligation continues for the remaining
term of the agreement, provided that no deliveries are required during the month
of May. The price paid by Tenaska for this gas is reflective of the daily price
of gas at the U.S./Canada border near Sumas, Washington.
The following table indicates the Company's percentage ownership and the
extent of the Company's investment in jointly-owned generating plants in service
at December 31, 1998:
COMPANY'S SHARE
------------------------------------------
ENERGY COMPANY'S PLANT IN SERVICE ACCUMULATED
PROJECT SOURCE (FUEL) OWNERSHIP SHARE AT COST DEPRECIATION
(%) (MILLIONS) (MILLIONS)
- ----------------------- ----------------- -------------------- ------------------- ----------------------
Centralia Coal 7% $ 26.7 $ 18.5
Colstrip 1 & 2 Coal 50% 187.1 106.6
Colstrip 3 & 4 Coal 25% 452.1 181.0
Financing for a participant's ownership share in the projects is provided
for by such participant. The Company's share of related operating and
maintenance expenses is included in corresponding accounts in the Consolidated
Statements of Income. The Company and other joint owners of the Centralia
Project are exploring alternative emission compliance options and project
economics in light of compliance costs to meet the Phase II limits in the year
2000 and other regulations.
In November, 1998, the Company announced that it 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 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 Federal Energy Regulatory Commission. The Company
has also joined with the other owners of the Centralia project in offering for
sale its ownership interest in the facility.
Certain purchase commitments have been made in connection with the
Company's construction program.
GAS
The Company has also entered into various firm supply, transportation and
storage service contracts in order to assure adequate availability of gas supply
for its firm customers. Many of these contracts, which have remaining terms from
one to 25 years, provide that the Company must pay a fixed demand charge each
month, regardless of actual usage. Certain of the Company's firm gas supply
agreements also obligate the Company to purchase a minimum annual quantity at
market-based contract prices. Generally, if the minimum volumes are not
purchased and taken during the year, the Company is obligated to pay either: 1)
a monthly or annual gas inventory charge calculated as a percentage of the
then-current contract commodity price times the minimum quantity not taken; or
2) pay for gas not taken. Alternatively, under some of the contracts, the
supplier may exercise a right to reduce its subsequent obligation to provide
firm gas to the Company. The Company incurred demand charges in 1998 for firm
gas supply, firm transportation service and firm storage and peaking service of
$29,571,000, $52,917,000 and $8,832,000, respectively.
72
The following tables summarize the Company's obligations for future
demand charges through the primary terms of its existing contracts and the
minimum annual take requirements under the gas supply agreements. The quantified
obligations are based on current contract prices and FERC authorized rates,
which are subject to change.
DEMAND CHARGE OBLIGATIONS
2004 &
THERE-
(In Thousands) 1999 2000 2001 2002 2003 AFTER TOTAL
- ---------------------------------- -------- -------- -------- -------- -------- --------- ---------
Firm gas supply $29,580 $27,271 $27,271 $26,941 $23,442 $ 17,382 $151,887
Firm transportation service 51,331 51,331 51,279 51,227 51,227 136,291 392,686
Firm storage & peaking service 8,885 8,885 8,885 8,885 8,885 87,481 131,906
- ---------------------------------- -------- -------- -------- -------- -------- --------- ---------
Total $89,796 $87,487 $87,435 $87,053 $83,554 $241,154 $676,479
- ---------------------------------- -------- -------- -------- -------- -------- --------- ---------
MINIMUM ANNUAL TAKE OBLIGATIONS
2004 &
THERE-
(In thousands of therms) 1999 2000 2001 2002 2003 AFTER TOTAL
- --------------------------- -------- -------- -------- -------- -------- -------- ----------
Firm gas supply 472,443 333,957 333,957 329,157 278,132 121,835 1,869,481
The Company believes that all demand charges will be recoverable in rates
charged to its customers. Further, pursuant to implementation of FERC Order No.
636, the Company has the right to resell or release to others any of its
unutilized gas supply or transportation and storage capacity.
The Company does not anticipate any difficulty in achieving the minimum
annual take obligations shown, as such volumes represent less than 57% of
expected annual sales for 1999 and less than 39% of expected sales in subsequent
years.
The Company's current firm gas supply contracts obligate the suppliers to
provide, in the aggregate, annual volumes up to those shown below:
MAXIMUM SUPPLY AVAILABLE UNDER CURRENT FIRM SUPPLY CONTRACTS
2004 &
THERE-
(In thousands of therms) 1999 2000 2001 2002 2003 AFTER TOTAL
- ------------------------ -------- -------- -------- -------- -------- -------- ----------
Firm gas supply 663,402 511,489 511,489 505,489 444,739 289,209 2,925,817
Washington Energy Gas Marketing Company ("WEGM"), a wholly-owned
subsidiary, holds firm rights to transport natural gas on the Nova Corporation
of Alberta ("Nova"), Alberta Natural Gas Company ("ANG") and PG&E Gas
Transmission - Northwest pipelines from Alberta, Canada, to the northern border
of California, as well as certain gas storage rights at the Alberta Energy
Company ("AECO") field in Alberta and the Jackson Prairie field in western
Washington. These rights were formerly held by a wholly-owned subsidiary of
Resources but were excluded from the merger of Resources and Cabot completed in
May 1994. Following the merger, WEGM entered into a five-year contract with IGI
Resources ("IGI"), Boise, Idaho, to manage these rights.
73
The transportation rights on the PGT pipeline initially consisted of
approximately 25,000 MMBtu per day of annual capacity and 20,000 MMBtu per day
of winter-only capacity to Stanfield, Oregon, and approximately 20,000 MMBtu per
day of annual capacity to the California border. WEGM held similar rights on
Nova and ANG.
Effective November 1, 1995, WEGM permanently assigned to IGI all of its
Stanfield capacity and associated rights on Nova and ANG. In addition, WEGM
segmented its capacity to California at Stanfield and permanently assigned
10,000 MMBtu per day of the Alberta to Stanfield rights to a third party
effective November 1, 1995. WEGM's remaining PGT rights expire in October 2023,
and the ANG and Nova rights expire in October 2008, with annual renewal options.
WEGM, as an expansion capacity holder, has been unable to fully recoup its
demand charges, which have been approximately 70% higher than those paid by
holders of vintage capacity. On September 11, 1996, the FERC approved a request
from PGT for the cost of the expansion capacity to be "rolled in" with the cost
of the vintage capacity to establish a uniform rate for holders of both types of
capacity. This change will be implemented in two stages over six years with the
first stage effective November 1, 1996. WEGM's annual obligations for future
demand charges through the primary term of WEGM's gas transportation and storage
contracts are as follows: 1999, $2,847,000; 2000, $2,843,000; 2001, $2,829,000;
2002, $2,819,000; 2003, $2,296,000 and thereafter, $33,413,000. The IGI
management contract provides for incentive payments to IGI based on actual
mitigation of demand charges relative to targets established on an annual basis.
As of December 31, 1998, WEGM has a reserve for future losses associated
with these contractual obligations of $4,611,000. WEGM initially established the
reserve for estimated future losses associated with the transportation and
storage obligations with a $16,000,000 ($10,400,000 after tax) charge to
earnings upon completion of the merger of Resources and Cabot in May 1994. In
the fourth quarter of 1995, WEGM recorded a $5,000,000 ($3,250,000 after tax)
charge to increase the reserve based on an assessment of the likelihood and
timing of approval of rolled-in rates and actual mitigation results in 1995.
During 1998, 1997 and 1996, pre-tax losses totaling $1,916,000, $2,235,000 and
$2,652,000, respectively, were charged against the reserve.
CONTINGENCIES
The Company is subject to environmental regulation by federal, state and
local authorities. The Company has been named a Potentially Responsible Party by
the Environmental Protection Agency ("EPA") at several contaminated disposal
sites and manufactured gas plant sites. The Company has implemented an ongoing
program to test, replace and remediate certain underground storage tanks as
required by federal and state laws. Remediation and testing of Company vehicle
service facilities and storage yards is also continuing.
During 1992, the Washington Commission issued orders regarding the
treatment of costs incurred by the Company for certain sites under its
environmental remediation program. The orders authorize the Company to
accumulate and defer prudently incurred cleanup costs paid to third parties for
recovery in rates established in future rate proceedings. The Company believes a
significant portion of its past and future environmental remediation costs are
recoverable from either insurance companies, third parties or under the
Washington Commission's order.
The information presented here as it relates to estimates of future
liability is as of December 31, 1998.
ELECTRIC SITES
The Company has expended approximately $14.5 million related to the
remediation activities covered by the Washington Commission's order, of which
approximately $7.5 million has been recovered from insurance carriers. At
December 31, 1998, approximately $1.8 million has been accrued as a liability
for future remediation costs for these and other remediation activities.
74
GAS SITES
Five former WNG or predecessor companies manufactured gas plant ("MGP")
sites are currently undergoing investigation, remedial actions or monitoring
actions relating to environmental contamination: 1) Everett, Washington; 2) "Gas
Works Park" in Seattle, Washington; 3) "Tacoma 22nd and A St." Site in Tacoma,
Washington; 4) Chehalis, Washington; and 5) the "Tideflats" area of Tacoma,
Washington. Legal and remedial costs incurred to date total approximately $50.9
million and currently estimated future remediation costs are approximately $7.0
million. Work at both the Chehalis and Tideflats sites is substantially
completed. To date, the Company has recovered approximately $59 million from
insurance carriers and other third parties.
Based on all known facts and analyses, the Company believes it is not
likely that the identified environmental liabilities will result in a material
adverse impact on the Company's financial position, operating results or cash
flow trends.
LITIGATION
Other contingencies, arising out of the normal course of the Company's
business, exist at December 31, 1998. The ultimate resolution of these issues is
not expected to have a material adverse impact on the financial condition,
results of operations or liquidity of the Company.
NOTE 18.
DISCONTINUED OPERATIONS
On March 5, 1997, the Company conveyed its interests in undeveloped coal
properties through its wholly-owned subsidiary Thermal Energy, Inc. to Wesco
Resources, Inc. effective February 1, 1997. The Company's remaining $4.0 million
investment in Thermal Energy, Inc. was written off to expense and appears in the
consolidated financial statements as discontinued operations. Prior periods have
been restated to include Thermal Energy, Inc. operations as discontinued
operations.
75
NOTE 19.
SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
The following unaudited amounts, in the opinion of the Company, include
all adjustments (consisting of normal recurring adjustments) necessary for a
fair presentation of the results of operations for the interim periods.
Quarterly amounts vary during the year due to the seasonal nature of the utility
business.
(UNAUDITED; DOLLARS IN THOUSANDS EXCEPT PER-SHARE AMOUNTS)
- ----------------------------- ----------------- ------------------ ------------------- ----------------
1998 Quarter First Second Third Fourth
- ----------------------------- ----------------- ------------------ ------------------- ----------------
Operating revenues $522,069 $365,525 $427,357 $592,389
Operating income $ 99,257 $ 50,012 (a)$ 53,217 $ 96,494
Other income $1,160 $3,512 (a) $ 1,433 $3,087
Net income $ 66,003 $ 19,542 $ 21,091 $ 62,976
Basic and diluted earnings
per common share $ 0.74 $ 0.19 $ 0.21 $ 0.71
- ----------------------------- ----------------- ------------------ ------------------- ----------------
(UNAUDITED; DOLLARS IN THOUSANDS EXCEPT PER-SHARE AMOUNTS)
- ------------------------------ ----------------- ------------------ ------------------- ----------------
1997 Quarter First Second Third Fourth
- ------------------------------ ----------------- ------------------ ------------------- ----------------
Operating revenues $463,319 $352,618 $341,021 $519,944
Operating income $ 56,828 $ 45,233 $ 35,421 $ 78,384
Other income $4,884 $ 17,804 $6,029 $ (651)
Income from continuing
Operations $ 32,608 $ 33,440 $ 11,998 $ 47,652
Net income $ 29,986 $ 33,440 $ 11,998 $ 47,652
Basic and diluted earnings
per common share from
Continuing operations $ 0.32 $ 0.33 $ 0.11 $ 0.52
- ------------------------------ ----------------- ------------------ ------------------- ----------------
(a) Operating income and other income in the amount of $3.4 million and
$4.3 million, respectively, were reclassed to conform third quarter 1998 Form
10-Q with year-end presentation.
76
NOTE 20.
CONSOLIDATED STATEMENT OF CASH FLOWS
For purposes of the Statement of Cash Flows, the Company considers all
temporary investments to be cash equivalents. These temporary cash investments
are securities held for cash management purposes, having maturities of three
months or less. The net change in current assets and current liabilities for
purposes of the Statement of Cash Flows excludes short-term debt, current
maturities of long-term debt and the current portion of PRAM accrued revenues.
At December 31, 1998, $15,710,000 related to a book overdraft was included in
accounts payable.
The following provides additional information concerning cash flow
activities:
- ------------------------------------------------------------------ ------------- -------------- --------------
(YEAR ENDED DECEMBER 31; DOLLARS IN THOUSANDS) 1998 1997 1996
- ------------------------------------------------------------------ ------------- -------------- --------------
Changes in certain current assets and current liabilities:
Accounts receivable $(43,003) $ (4,164) $(22,242)
Unbilled revenue (3,909) 4,591 (11,104)
Materials and supplies (4,111) 3,316 16,737
Prepayments and other (1,876) 5,339 1,491
Purchased gas liability (6,368) (34,966) 25,814
Accounts payable 27,082 7,132 15,997
Accrued expenses and other 9,493 (39,642) 1,116
- ------------------------------------------------------------------ ------------- -------------- --------------
Net change in certain current assets
and current liabilities $(22,692) $(58,394) $27,809
- ------------------------------------------------------------------ ------------- --------------- -------------
Cash payments:
Interest (net of capitalized interest) $131,567 $119,810 $113,634
Income taxes $119,664 $104,161 $ 98,609
- ------------------------------------------------------------------ ------------- -------------- --------------
NOTE 21.
MERGER OF PUGET POWER AND WECO
Included in consolidated results of operations for the month of January
1997 and for the year ended December 31, 1996, are the following results of the
previously separate companies for those periods (Dollars in Thousands):
MONTH ENDED YEAR ENDED
JANUARY 31, 1997 DECEMBER 31, 1996
PUGET WECO PUGET WECO
------------- ----------- ------------- -----------
Revenues $123,051 $60,486 $1,223,568 $425,711
Net Income $19,671 $9,378 $ 135,371 $ 30,148
Common Dividends Declared $29,244 -- $ 117,099 $ 24,149
WECo's operations for the three months ended December 31, 1996, have been
reported as an adjustment of $10.8 million to consolidated retained earnings in
the first quarter of 1997. WECo's revenues for the three months ended December
31, 1996, were $148.6 million, net income was $16.9 million, common stock issued
was $1.0 million and common stock dividends declared were $6.1 million for the
same period.
77
In connection with the merger, the Company recognized direct and indirect
merger-related expenses of $55.8 million during the first quarter of 1997. The
charge consisted primarily of severance costs of $15.5 million, benefit-related
curtailment costs of $9.1 million, transaction costs of $13.7 million and
systems and facilities integration costs of $7.2 million. The nonrecurring
charge reduced net income by approximately $36.3 million or $0.43 per share. In
addition, merger-related costs of $4.8 million were recognized in the fourth
quarter of 1996 by Puget Power.
NOTE 22.
SEGMENT INFORMATION
The Company primarily operates in one business segment, Regulated Utility
Operations. The Company's regulated utility operation generates, purchases and
sells electricity and purchases, transports and sells natural gas. The Company's
service territory covers approximately 6,000 square miles in the state of
Washington.
Principal non-utility lines of business include real estate investment
and development, home security services and energy-related services. Reconciling
items between segments are not material.
Financial data for business segments are as follows:
(DOLLARS IN THOUSANDS)
Regulated
1998 UTILITY OTHER TOTAL
- -----------------------------------------------------------------------------
Revenues $1,891,759 $15,581 $1,907,340
Depreciation & Amortization 165,491 96 165,587
Federal Income Tax 106,967 937 107,904
Operating Income 292,337 6,643 298,980
Interest Charges, net of AFUDC 138,560 0 138,560
Net Income 170,435 (823) 169,612
Total Assets 4,630,501 90,188 4,720,689
- -----------------------------------------------------------------------------
REGULATED
1997 UTILITY OTHER TOTAL
- -----------------------------------------------------------------------------
Revenues $1,640,871 $36,031 $1,676,902
Depreciation & Amortization 161,402 463 161,865
Federal Income Tax 34,230 13,495 47,725
Operating Income 215,126 740 215,866
Interest Charges, net of AFUDC 117,258 976 118,234
Net Income 123,872 (796) 123,076
Total Assets 4,414,396 78,974 4,493,370
- -----------------------------------------------------------------------------
REGULATED
1996 UTILITY OTHER TOTAL
- -----------------------------------------------------------------------------
Revenues $1,598,877 $50,402 $1,649,279
Depreciation & Amortization 143,613 593 144,206
Federal Income Tax 105,236 2,511 107,747
Operating Income 269,652 14,822 284,474
Interest Charges, net of AFUDC 108,688 10,028 118,716
Net Income 171,144 (5,625) 165,519
Total Assets 4,049,113 178,357 4,227,470
- -----------------------------------------------------------------------------
78
SCHEDULE II.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(DOLLARS IN THOUSANDS)
ADDITIONS
BALANCE AT CHARGED TO BALANCE
BEGINNING COSTS AND AT END
OF PERIOD EXPENSES DEDUCTIONS OF PERIOD
--------- ----------- ----------- ---------
- ---------------------------------
YEAR ENDED DECEMBER 31, 1998
- ---------------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 971 $5,905 $5,855 $1,021
- --------------------------------- ------------ ----------- ----------- ---------
YEAR ENDED DECEMBER 31, 1997
- ---------------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable (a) $1,700 $5,080 $5,809 $971
- --------------------------------- ------------ ----------- ----------- ---------
YEAR ENDED DECEMBER 31, 1996
- ---------------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $1,865 $5,920 $6,085 $1,700
- --------------------------------- ------------ ----------- ----------- ---------
(a) Includes additions of $369 and deductions of $384 related to October
through December 1996 for WECo.
79
EXHIBIT INDEX
Certain of the following exhibits are filed herewith. Certain other of
the following exhibits have heretofore been filed with the Commission and are
incorporated herein by reference.
2.1 Agreement and Plan of Merger dated as of October 18, 1995, among the
Registrant, Washington Energy Company and Washington Natural Gas Company.
(Exhibit 2.1 to Registration No. 333-617)
3-a Restated Articles of Incorporation of the Company. (Included as Annex
F to the Joint Proxy Statement/Prospectus filed February 1, 1996, Registration
No. 333-617)
3-b Restated Bylaws of the Company. (Exhibit 3 to Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No.
1-4393)
4.1 Fortieth through Seventy-seventh Supplemental Indentures defining the
rights of the holders of the Company's First Mortgage Bonds. (Exhibit 2-d to
Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347; Exhibits 2-e
through and including 2-k to Registration No. 2-60200; Exhibit 4-h to
Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No. 2-60200;
Exhibits 2-m to Registration No. 2-37645; Exhibit 2-o through and including 2-s
to Registration No. 2-60200; Exhibit 5-b to Registration No. 2-62883; Exhibit
2-h to Registration No. 2-65831; Exhibit (4)-j-1 to Registration No. 2-72061;
Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No.
1-4393; Exhibits (4)(a) and (4)(b) to Company's Current Report on Form 8-K,
dated April 22, 1986; Exhibit (4)a to Company's Current Report on Form 8-K,
dated September 5, 1986; Exhibit (4)-b to Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1986, Commission File No. 1-4393;
Exhibit (4)-c to Registration No. 33-18506; Exhibit (4)-b to Annual Report on
Form 10-K for the fiscal year ended December 31, 1989, Commission File No.
1-4393; Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended
December 31, 1990, Commission File No. 1-4393; Exhibits (4)-b and (4)-c to
Registration No. 33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit
(4)-a to Registration No. 33-53056; Exhibit 4.3 to Registration No. 33-63278;
Exhibit 4.25 to Registration No. 333-41181; and Exhibit 4.27 to Current Report
on Form 8-K dated March 5, 1999.)
4.2 Rights Agreement, dated as of January 15, 1991, between the Company
and The Chase Manhattan Bank, N.A., as Rights Agent. (Exhibit 2.1 to
Registration Statement on Form 8-A filed on January 17, 1991, Commission File
No. 1-4393)
4.3 Amendment No. 1 dated as of August 30, 1991, to the Rights Agreement
dated as of January 15, 1991, between the Registrant and the Bank of New York
(as successor to The Chase Manhattan Bank, N.A.), as Rights Agent. (Exhibit 2.1
to Registration Statement on Form 8 filed on August 30, 1991)
4.4 Amendment No. 2 dated as of October 18, 1995, to the Rights Agreement
dated as of January 15, 1991, between the Registrant and The Bank of New York
(as successor to The Chase Manhattan Bank, N.A.), as Rights Agent. (Exhibit 1 to
Registration Statement on Form 8-A/A filed on October 27, 1995)
4.5 Pledge Agreement dated August 1, 1991, between the Company and The
First National Bank of Chicago, as Trustee. (Exhibit (4)-j to Registration No.
33-45916)
4.6 Loan Agreement dated August 1, 1991, between the City of Forsyth,
Rosebud County, Montana and the Company. (Exhibit (4)-k to Registration No.
33-45916)
4.7 Statement of Relative Rights and Preferences for the Adjustable Rate
Cumulative Preferred Stock, Series B ($25 Par Value). (Exhibit 1.1 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File No.
1-4393)
4.8 Statement of Relative Rights and Preferences for the Preference Stock,
Series R, $50 Par Value. (Exhibit 1.5 to Registration Statement on Form 8-A
filed February 14, 1994, Commission File No. 1-4393)
4.9 Statement of Relative Rights and Preferences for the 7 3/4% Series
Preferred Stock Cumulative, $100 Par Value. (Exhibit 1.6 to Registration
Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
4.10 Pledge Agreement, dated as of March 1, 1992, by and between the
Company and Chemical Bank relating to a series of first mortgage bonds. (Exhibit
4.15 to Annual Report on Form 10-K for the fiscal year ended December 31, 1993,
Commission File No. 1-4393)
80
4.11 Pledge Agreement, dated as of April 1, 1993, by and between the
Company and The First National Bank of Chicago, relating to a series of first
mortgage bonds. (Exhibit 4.16 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, Commission File No. 1-4393)
4.12 Form of Statement of Relative Rights and Preferences for the Series
II Cumulative Preferred Stock, $25 Par Value (included as Annex F to the Joint
Proxy Statement/Prospectus filed February 1, 1996).
4.13 Form of Statement of Relative Rights and Preferences for the Series
III Cumulative Preferred Stock, $25 Par Value (included as Annex F to the Joint
Proxy Statement/Prospectus filed February 1, 1996).
4.14 Indenture of First Mortgage dated as of April 1, 1957 (incorporated
herein by reference to Washington Natural Gas Company Exhibit 4-B, Registration
No. 2-14307).
4.15 Sixth Supplemental Indenture dated as of August 1, 1966
(incorporated herein by reference to Washington Natural Gas Company Exhibit to
Form 8-K for month of August 1966, File No. 0-951).
4.16 Twelfth Supplemental Indenture dated as of November 1, 1972
(incorporated herein by reference to Washington Natural Gas Company Exhibit to
Form 8-K for November 1972, File No. 0-951).
4.17 Seventeenth Supplemental Indenture dated as of August 9, 1978
(incorporated herein by reference to Washington Energy Company Exhibit 5-K.18,
Registration No. 2-64428).
4.18 Twenty-sixth Supplemental Indenture dated as of September 1, 1990
(incorporated herein by reference to Washington Natural Gas Company Exhibit
4-B.19, Form 10-K for the year ended September 30, 1990, File No. 0-951).
4.19 Twenty-seventh Supplemental Indenture dated as of September 1, 1990
(incorporated herein by reference to Washington Natural Gas Company Exhibit
4-B.20, Form 10-K for the year ended September 30, 1988, File No. 0-951).
4.20 Twenty-eighth Supplemental Indenture dated as of July 31, 1991
(incorporated herein by reference to Washington Natural Gas Company Exhibit 4-A,
Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
4.21 Twenty-ninth Supplemental Indenture dated as of June 1, 1993
(incorporated herein by reference to Exhibit 4-A of Washington Natural Gas
Company's S-3 Registration Statement, Registration No. 33-49599).
4.22 Thirtieth Supplemental Indenture dated as of August 15, 1995
(incorporated herein by reference to Exhibit 4-A of Washington Natural Gas
Company's S-3 Registration Statement, Registration No. 33-61859).
10.1 Assignment and Agreement, dated as of August 13, 1964, between Public
Utility District No. 1 of Chelan County, Washington and the Company, relating to
the Rock Island Project. (Exhibit 13-b to Registration No. 2-24262)
10.2 First Amendment, dated as of October 4, 1961, to Power Sales Contract
between Public Utility District No. 1 of Chelan County, Washington and the
Company, relating to the Rocky Reach Project. (Exhibit 13-d to Registration No.
2-24252)
10.3 Assignment and Agreement, dated as of August 13, 1964, between Public
Utility District No. 1 of Chelan County, Washington and the Company, relating to
the Rocky Reach Project. (Exhibit 13-e to Registration No. 2-24252)
10.4 Assignment and Agreement, dated as of August 13, 1964, between Public
Utility District No. 2 of Grant County, Washington and the Company, relating to
the Priest Rapids Development. (Exhibit 13-j to Registration No. 2-24252)
10.5 Assignment and Agreement, dated as of August 13, 1964, between Public
Utility District No. 2 of Grant County, Washington and the Company, relating to
the Wanapum Development. (Exhibit 13-n to Registration No. 2-24252)
10.6 First Amendment, dated February 9, 1965, to Power Sales Contract
between Public Utility District No. 1 of Douglas County, Washington and the
Company, relating to the Wells Development. (Exhibit 13-p to Registration No.
2-24252)
10.7 First Amendment, executed as of February 9, 1965, to Reserved Share
Power Sales Contract between Public Utility District No. 1 of Douglas County,
Washington and the Company, relating to the Wells Development. (Exhibit 13-r to
Registration No. 2-24252)
10.8 Assignment and Agreement, dated as of August 13, 1964, between Public
Utility District No. 1 of Douglas County, Washington and the Company, relating
to the Wells Development. (Exhibit 13-u to Registration No. 2-24252)
81
10.9 Pacific Northwest Coordination Agreement, executed as of September
15, 1964, among the United States of America, the Company and most of the other
major electrical utilities in the Pacific Northwest. (Exhibit 13-gg to
Registration No. 2-24252)
10.10 Contract dated November 14, 1957, between Public Utility District No.
1 of Chelan County, Washington and the Company, relating to the Rocky Reach
Project. (Exhibit 4-1-a to Registration No. 2-13979)
10.11 Power Sales Contract, dated as of November 14, 1957, between Public
Utility District No. 1 of Chelan County, Washington and the Company, relating to
the Rocky Reach Project. (Exhibit 4-c-1 to Registration No. 2-13979)
10.12 Power Sales Contract, dated May 21, 1956, between Public Utility
District No. 2 of Grant County, Washington and the Company, relating to the
Priest Rapids Project. (Exhibit 4-d to Registration No. 2-13347)
10.13 First Amendment to Power Sales Contract dated as of August 5, 1958,
between the Company and Public Utility District No. 2 of Grant County,
Washington, relating to the Priest Rapids Development. (Exhibit 13-h to
Registration No. 2-15618)
10.14 Power Sales Contract dated June 22, 1959, between Public Utility
District No. 2 of Grant County, Washington and the Company, relating to the
Wanapum Development. (Exhibit 13-j to Registration No. 2-15618)
10.15 Reserve Share Power Sales Contract dated June 22, 1959, between
Public Utility District No. 2 of Grant County, Washington and the Company,
relating to the Priest Rapids Project. (Exhibit 13-k to Registration No.
2-15618)
10.16 Agreement to Amend Power Sales Contracts dated July 30, 1963, between
Public Utility District No. 2 of Grant County, Washington and the Company,
relating to the Wanapum Development. (Exhibit 13-1 to Registration No. 2-21824)
10.17 Power Sales Contract executed as of September 18, 1963, between
Public Utility District No. 1 of Douglas County, Washington and the Company,
relating to the Wells Development (Exhibit 13-r to Registration No. 2-21824)
10.18 Reserved Share Power Sales Contract executed as of September 18,
1963, between Public Utility District No. 1 of Douglas County, Washington and
the Company, relating to the Wells Development. (Exhibit 13-s to Registration
No. 2-21824)
10.19 Exchange Agreement dated April 12, 1963, between the United States
of America, Department of the Interior, acting through the Bonneville Power
Administration and Washington Public Power Supply System and the Company,
relating to the Hanford Project. (Exhibit 13-u to Registration 2-21824)
10.20 Replacement Power Sales Contract dated April 12, 1963, between the
United States of America, Department of the Interior, acting through the
Bonneville Power Administrator and the Company, relating to the Hanford Project.
(Exhibit 13-v to Registration No. 2-21824)
10.21 Contract covering undivided interest in ownership and operation of
Centralia Thermal Plant, dated May 15, 1969. (Exhibit 5-b to Registration No.
2-3765)
10.22 Construction and Ownership Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-b to Registration
No. 2-45702)
10.23 Operation and Maintenance Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-c to Registration
No. 2-45702)
10.24 Coal Supply Agreement, dated as of July 30, 1971, among The Montana
Power Company, the Company and Western Energy Company. (Exhibit 5-d to
Registration No. 2-45702)
10.25 Power Purchase Agreement with Washington Public Power Supply System
and the Bonneville Power Administration dated February 6, 1973. (Exhibit 5-e to
Registration No. 2-49029)
10.26 Ownership Agreement among the Company, Washington Public Power Supply
System and others dated September 17, 1973. (Exhibit 5-a-29 to Registration No.
2-60200)
10.27 Contract dated June 19, 1974, between the Company and P.U.D No. 1 of
Chelan County. (Exhibit D to Form 8-K dated July 5, 1974)
82
10.28 Restated Financing Agreement among the Company, lessee, Chrysler
Financial Corporation, owner, Nevada National Bank and Bank of Montreal
(California), trustee, dated December 12, 1974 pertaining to a combustion
turbine generating unit trust. (Exhibit 5-a-35 to Registration No. 2-60200)
10.29 Restated Lease Agreement between the Company, lessee, and the Bank
of California, and National Association, lessor, dated December 12, 1974 for one
combustion generating unit. (Exhibit 5-a-36 to Registration No. 2-60200)
10.30 Financing Agreement Supplement and Amendment among the Company,
lessee, Chrysler Financial Corporation, owner, The Bank of California, National
Association, trustee, Pacific Mutual Life Insurance Company, Bankers Life
Company, and The Franklin Life Insurance Company, lenders, dated as of March 26,
1975, pertaining to a combustion turbine generating unit trust. (Exhibit 5-a-37
to Registration No. 2-60200)
10.31 Lease Agreement Supplement and Amendment between the Company,
lessee, and The Bank of California, National Association, lessor, dated as of
March 26, 1975 for one combustion turbine generating unit. (Exhibit 5-a-38 to
Registration No. 2-60200)
10.32 Exchange Agreement executed August 13, 1964, between the United
States of America, Columbia Storage Power Exchange and the Company, relating to
Canadian Entitlement. (Exhibit 13-ff to Registration No. 2-24252)
10.33 Loan Agreement dated as of December 1, 1980 and related documents
pertaining to Whitehorn turbine construction trust financing. (Exhibit 10.52 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1980,
Commission File No. 1-4393)
10.34 Letter Agreement dated March 31, 1980, between the Company and
Manufacturers Hanover Leasing Corporation. (Exhibit b-8 to Registration No.
2-68498)
10.35 Coal Supply Agreement for Colstrip 3 and 4, dated as of July 2,
1980; Amendment No. 1 to Coal Supply Agreement, dated as of July 10, 1981, and
Coal Transportation Agreement dated as of July 10, 1981. (Exhibit 20-a to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1981,
Commission File No. 1-4393)
10.36 Residential Purchase and Sale Agreement between the Company and the
Bonneville Power Administration, effective as of October 1, 1981. (Exhibit 20-b
to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981,
Commission File No. 1-4393)
10.37 Letter of Agreement to Participate in Licensing of Creston
Generating Station, dated September 30, 1981. (Exhibit 20-c to Quarterly Report
on Form 10-Q for the quarter ended September 30, 1981, Commission File No.
1-4393)
10.38 Power sales contract dated August 27, 1982 between the Company and
Bonneville Power Administration. (Exhibit 10-a to Quarterly Report on Form 10-Q
for the quarter ended September 30, 1982, Commission File No. 1-4393)
10.39 Agreement executed as of April 17, 1984, between the United States
of America, Department of the Interior, acting through the Bonneville Power
Administration, and other utilities relating to extension energy from the
Hanford Atomic Power Plant No. 1. (Exhibit (10)-47 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1984, Commission File No. 1-4393)
10.40 Agreement for the Assignment of Output from the Centralia Thermal
Project, dated as of April 14, 1983, between the Company and Public Utility
District No. 1 of Grays Harbor. (Exhibit (10)-48 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1984, Commission File No. 1-4393)
10.41 Settlement Agreement and Covenant Not to Sue executed by the United
States Department of Energy acting by and through the Bonneville Power
Administration and the Company dated September 17, 1985. (Exhibit (10)-49 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1985,
Commission File No. 1-4393)
10.42 Agreement to Dismiss Claims and Covenant Not to Sue dated September
17, 1985 between Washington Public Power Supply System and the Company. (Exhibit
(10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No. 1-4393)
10.43 Irrevocable Offer of Washington Public Power Supply System Nuclear
Project No. 3 Capability for Acquisition executed by the Company, dated
September 17, 1985. (Exhibit A of Exhibit (10)-50 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
83
10.44 Settlement Exchange Agreement ("Bonneville Exchange Power
Contract") executed by the United States of America Department of Energy acting
by and through the Bonneville Power Administration and the Company, dated
September 17, 1985. (Exhibit B of Exhibit (10)-50 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.45 Settlement Agreement and Covenant Not to Sue between the Company
and Northern Wasco County People's Utility District, dated October 16, 1985.
(Exhibit (10)-53 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1985, Commission File No. 1-4393)
10.46 Settlement Agreement and Covenant Not to Sue between the Company
and Tillamook People's Utility District, dated October 16, 1985. (Exhibit
(10)-54 to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No. 1-4393)
10.47 Settlement Agreement and Covenent Not to Sue between the Company
and Clatskanie People's Utility District, dated September 30, 1985. (Exhibit
(10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No.
1-4393)
10.48 Stipulation and Settlement Agreement between the Company and
Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October 31, 1986.
(Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1986, Commission File No. 1-4393)
10.49 Transmission Agreement dated April 17, 1981, between the Bonneville
Power Administration and the Company (Colstrip Project). (Exhibit (10)-55 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.50 Transmission Agreement dated April 17, 1981, between the Bonneville
Power Administration and Montana Intertie Users (Colstrip Project). (Exhibit
(10)-56 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No.
1-4393)
10.51 Ownership and Operation Agreement dated as of May 6, 1981, between
the Company and other Owners of the Colstrip Project (Colstrip 3 and 4).
(Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No.
1-4393)
10.52 Colstrip Project Transmission Agreement dated as of May 6, 1981,
between the Company and Owners of the Colstrip Project. (Exhibit (10)-58 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.53 Common Facilities Agreement dated as of May 6, 1981, between the
Company and Owners of Colstrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File
No. 1-4393)
10.54 Agreement for the Purchase of Power dated as of October 29, 1984,
between South Fork II, Inc. and the Company (Weeks Falls Hydroelectric Project).
(Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
10.55 Agreement for the Purchase of Power dated as of October 29, 1984,
between South Fork Resources, Inc. and the Company (Twin Falls Hydroelectric
Project). (Exhibit (10)-61 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.56 Agreement for Firm Purchase Power dated as of January 4, 1988,
between the City of Spokane, Washington and the Company (Spokane Waste
Combustion Project). (Exhibit (10)-62 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.57 Agreement for Evaluating, Planning and Licensing dated as of
February 21, 1985 and Agreement for Purchase of Power dated as of February 21,
1985 between Pacific Hydropower Associates and the Company (Koma Kulshan
Hydroelectric Project). (Exhibit (10)-63 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.58 Power Sales Agreement dated as of August 1, 1986, between Pacific
Power & Light Company ("PacifiCorp")and the Company. (Exhibit (10)-64 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File
No. 1-4393)
10.59 Agreement for Purchase and Sale of Firm Capacity and Energy dated
as of August 1, 1986 between The Washington Water Power Company ("Avista") and
the Company. (Exhibit (10)-65 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
84
10.60 Amendment dated as of June 1, 1968, to Power Sales Contract between
Public Utility District No. 1 of Chelan County, Washington and the Company
(Rocky Reach Project). (Exhibit (10)-66 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.61 Coal Supply Agreement dated as of October 30, 1970, between the
Washington Irrigation & Development Company and the Company and other Owners of
the Centralia Thermal Project (Centralia Generating Plant). (Exhibit (10)-67 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.62 Interruptible Natural Gas Service Agreement dated as of May 14,
1980, between Cascade Natural Gas Corporation and the Company (Whitehorn
Combustion Turbine). (Exhibit (10)-68 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.63 Interruptible Natural Gas Service Agreement dated as of January 31,
1983, between Cascade Natural Gas Corporation and the Company (Fredonia
Generating Station). (Exhibit (10)-69 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.64 Interruptible Gas Service Agreement dated May 14, 1981, between
Washington Natural Gas Company and the Company (Fredrickson Generating Station).
(Exhibit (10)-70 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
10.65 Settlement Agreement dated April 24, 1987, between Public Utility
District No. 1 of Chelan County, the National Marine Fisheries Service, the
State of Washington, the State of Oregon, the Confederated Tribes and Bands of
the Yakima Indian Nation, Colville Indian Reservation, Umatilla Indian
Reservation, the National Wildlife Federation and the Company (Rock Island
Project). (Exhibit (10)-71 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.66 Amendment No. 2 dated as of September 1, 1981, and Amendment No. 3
dated September 14, 1987, to Coal Supply Agreement between Western Energy
Company and the Company and the other Owners of Colstrip 3 and 4. (Exhibit
(10)-72 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
10.67 Amendatory Agreement No. 1 dated August 27, 1982, and Amendatory
Agreement No. 2 dated August 27, 1982, to the Power Sales Contract between the
Company and the Bonneville Power Administration dated August 27, 1982. (Exhibit
(10)-73 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
10.68 Transmission Agreement dated as of December 30, 1987, between the
Bonneville Power Administration and the Company (Rock Island Project). (Exhibit
(10)-74 to Annual Report on Form 10-K for the fiscal year ended December 31,
1988, Commission File No.
1-4393)
10.69 Agreement for Purchase and Sale of Firm Capacity and Energy between
The Washington Water Power Company and the Company dated as of January 1, 1988.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31,
1988, Commission File No. 1-4393)
10.70 Amendment dated as of August 10, 1988, to Agreement for Firm
Purchase Power dated as of January 4, 1988, between the City of Spokane,
Washington and the Company (Spokane Waste Combustion Project).(Exhibit (10)-76
to Annual Report on Form 10-K for the fiscal year ended December 31, 1988,
Commission File No. 1-4393)
10.71 Agreement for Firm Power Purchase dated October 24, 1988, between
Northern Wasco People's Utility District and the Company (The Dalles Dam North
Fishway). (Exhibit (10)-77 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1988, Commission File No. 1-4393)
10.72 Agreement for the Purchase of Power dated as of October 27, 1988,
between Pacific Power & Light Company (PacifiCorp) and the Company. (Exhibit
(10)-78 to Annual Report on Form 10-K for the fiscal year ended December 31,
1988, Commission File No. 1-4393)
10.73 Agreement for Sale and Exchange of Firm Power dated as of November
23, 1988, between the Bonneville Power Administration and the Company. (Exhibit
(10)-79 to Annual Report on Form 10-K for the fiscal year ended December 31,
1988, Commission File No.
1-4393)
85
10.74 Agreement for Firm Power Purchase, dated as of February 24, 1989,
between Sumas Energy, Inc. and the Company. (Exhibit (10)-1 to Quarterly Report
on Form 10-Q for the quarter ended March 31, 1989, Commission File No. 1-4393)
10.75 Settlement Agreement, dated as of April 27, 1989, between Public
Utility District No. 1 of Douglas County, Washington, Portland General Electric
Company ("Enron"), PacifiCorp, The Washington Water Power Company ("Avista") and
the Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q quarter ended
September 30, 1989, Commission File No. 1-4393)
10.76 Agreement for Firm Power Purchase (Thermal Project), dated as of
June 29, 1989, between San Juan Energy Company and the Company. (Exhibit (10)-2
to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989,
Commission File No. 1-4393)
10.77 Agreement for Verification of Transfer, Assignment and Assumption,
dated as of September 15, 1989, between San Juan Energy Company, March Point
Cogeneration Company and the Company. (Exhibit (10)-3 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)
10.78 Power Sales Agreement between The Montana Power Company and the
Company, dated as of October 1, 1989. (Exhibit (10)-4 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)
10.79 Conservation Power Sales Agreement dated as of December 11, 1989,
between Public Utility District No. 1 of Snohomish County and the Company.
(Exhibit (10)-87 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1989, Commission File No. 1-4393)
10.80 Memorandum of Understanding dated as of January 24, 1990, between
the Bonneville Power Administration and The Washington Public Power Supply
System, Portland General Electric Company ("Enron"), Pacific Power & Light
Company ("PacifiCorp"), The Montana Power Company, and the Company. (Exhibit
(10)-88 to Annual Report on Form 10-K for the fiscal year ended December 31,
1989, Commission File No. 1-4393)
10.81 Amendment No. 1 to Agreement for the Assignment of Power from the
Centralia Thermal Project dated as of January 1, 1990, between Public Utility
District No. 1 of Grays Harbor County, Washington and the Company. (Exhibit
(10)-89 to Annual Report on Form 10-K for the fiscal year ended December 31,
1990, Commission File No. 1-4393)
10.82 Preliminary Materials and Equipment Acquisition Agreement dated as
of February 9, 1990, between Northwest Pipeline Corporation and the Company.
(Exhibit (10)-90 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1990, Commission File No. 1-4393)
10.83 Amendment No. 1 to the Colstrip Project Transmission Agreement
dated as of February 14, 1990, among the Montana Power Company, The Washington
Water Power Company ("Avista"), Portland General Electric Company ("Enron"),
PacifiCorp and the Company. (Exhibit (10)-91 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.84 Settlement Agreement dated as of February 27, 1990, among United
States of America Department of Energy acting by and through the Bonneville
Power Administration, the Washington Public Power Supply System, and the
Company. (Exhibit (10)-92 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1990, Commission File No. 1-4393)
10.85 Amendment No. 1 to the Fifteen-Year Power Sales Agreement dated as
of April 18, 1990, between Pacificorp and the Company. (Exhibit (10)-93 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1990,
Commission File No. 1-4393)
10.86 Settlement Agreement dated as of October 1, 1990, among Public
Utility District No. 1 of Douglas County, Washington, the Company, Pacific Power
and Light Company ("PacifiCorp"), The Washington Water Power Company ("Avista"),
Portland General Electric Company ("Enron"), the Washington Department of
Fisheries, the Washington Department of Wildlife, the Oregon Department of Fish
and Wildlife, the National Marine Fisheries Service, the U.S. Fish and Wildlife
Service, the Confederated Tribes and Bands of the Yakima Indian Nation, the
Confederated Tribes of the Umatilla Reservation, and the Confederated Tribes of
the Colville Reservation. (Exhibit (10)-95 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.87 Agreement for Firm Power Purchase dated July 23, 1990, between
Trans-Pacific Geothermal Corporation, a Nevada corporation, and the Company.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31,
1991, Commission File No. 1-4393)
86
10.88 Agreement for Firm Power Purchase dated July 18, 1990, between
Wheelabrator Pierce, Inc., a Delaware corporation, and the Company. (Exhibit
(10)-2 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991,
Commission File No. 1-4393)
10.89 Agreement for Firm Power Purchase dated September 26, 1990, between
Encogen Northwest, L.P., a Delaware corporation, and the Company. (Exhibit
(10)-3 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991,
Commission File No. 1-4393)
10.90 Agreement for Firm Power Purchase (Thermal Project) dated December
27, 1990, among March Point Cogeneration Company, a California general
partnership comprising San Juan Energy Company, a California corporation;
Texas-Anacortes Cogeneration Company, a Delaware corporation; and the Company.
(Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended March 31,
1991, Commission File No. 1-4393)
10.91 Agreement for Firm Power Purchase dated March 20, 1991, between
Tenaska Washington, Inc., a Delaware corporation, and the Company. (Exhibit
(10)-1 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991,
Commission File No. 1-4393)
10.92 Letter Agreement dated April 25, 1991, between Sumas Energy, Inc.
and the Company, to amend the Agreement for Firm Power Purchase dated as of
February 24, 1989. (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the
quarter ended June 30, 1991, Commission File No. 1-4393)
10.93 Amendment dated June 7, 1991, to Letter Agreement dated April 25,
1991, between Sumas Energy, Inc. and the Company. (Exhibit (10)-3 to Quarterly
Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No.
1-4393)
10.94 Amendatory Agreement No. 3, dated August 1, 1991, to the Pacific
Northwest Coordination Agreement, executed September 15, 1964, among the United
States of America, the Company and most of the other major electrical utilities
in the Pacific Northwest. (Exhibit (10)-4 to Quarterly Report on Form 10-Q for
the quarter ended June 30, 1991, Commission File No. 1-4393)
10.95 Amendment dated July 11, 1991, to the Agreement for Firm Power
Purchase dated September 26, 1990, between Encogen Northwest, L.P., a Delaware
limited partnership, and the Company. (Exhibit (10)-1 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1991, Commission File No. 1-4393)
10.96 Agreement between the 40 parties to the Western Systems Power Pool
(the Company being one party) dated July 27, 1991. (Exhibit (10)-2 to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1991, Commission File
No. 1-4393)
10.97 Memorandum of Understanding between the Company and the Bonneville
Power Administration dated September 18, 1991. (Exhibit (10)-3 to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1991, Commission File
No. 1-4393)
10.98 Amendment of Seasonal Exchange Agreement, dated December 4, 1991,
between Pacific Gas and Electric Company and the Company. (Exhibit (10)-107 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1991,
Commission File No. 1-4393)
10.99 Capacity and Energy Exchange Agreement, dated as of October 4,
1991, between Pacific Gas and Electric Company and the Company. (Exhibit
(10)-108 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.100 Intertie and Network Transmission Agreement, dated as of October
4, 1991, between Bonneville Power Administration and the Company. (Exhibit
(10)-109 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.101 Amendatory Agreement No. 4, executed June 17, 1991, to the Power
Sales Agreement dated August 27, 1982, between the Bonneville Power
Administration and the Company. (Exhibit (10)-110 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.102 Amendment to Agreement for Firm Power Purchase, dated as of
September 30, 1991, between Sumas Energy, Inc. and the Company. (Exhibit
(10)-112 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
87
10.103 Centralia Fuel Supply Agreement, dated as of January 1, 1991,
between Pacificorp Electric Operations and the Company and other Owners of the
Centralia Steam-Electric Power Plant. (Exhibit (10)-113 to Annual Report on Form
10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.104 Agreement for Firm Power Purchase dated August 10, 1992, between
Pyrowaste Corporation, Puget Sound Pyroenergy Corporation and the Company.
(Exhibit (10)-114 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, Commission File No. 1-4393)
10.105 Memorandum of Termination dated August 31, 1992, between Encogen
Northwest, L.P. and the Company. (Exhibit (10)-115 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.106 Agreement Regarding Security dated August 31, 1992, between
Encogen Northwest, L.P. and the Company. (Exhibit (10)-116 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
10.107 Consent and Agreement dated December 15, 1992, between the
Company, Encogen Northwest, L.P. and The First National Bank of Chicago, as
collateral agent. (Exhibit (10)-117 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1992, Commission File No. 1-4393)
10.108 Subordination Agreement dated December 17, 1992, between the
Company, Encogen Northwest, L.P., Rolls-Royce & Partners Finance Limited and The
First National Bank of Chicago. (Exhibit (10)-118 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.109 Letter Agreement dated December 18, 1992, between Encogen
Northwest, L.P. and the Company regarding arrangements for the application of
insurance proceeds. (Exhibit (10)-119 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.110 Guaranty of Ensearch Corporation in favor of the Company dated
December 15, 1992. (Exhibit (10)-120 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.111 Letter Agreement dated October 12, 1992, between Tenaska
Washington Partners, L.P. and the Company regarding clarification of issues
under the Agreement for Firm Power Purchase. (Exhibit (10)-121 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
10.112 Consent and Agreement dated October 12, 1992, between the Company
and The Chase Manhattan Bank, N.A., as agent. (Exhibit (10)-122 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
10.113 Settlement Agreement dated December 29, 1992, between the Company
and the Bonneville Power Administration (BPA) providing for power purchase by
BPA. (Exhibit (10)-123 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, Commission File No. 1-4393)
10.114 Contract with W. S. Weaver, Executive Vice President & Chief
Financial Officer, dated April 24, 1991. (Exhibit 10.114 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1993, Commission File No.
1-4393)
10.115 General Transmission Agreement dated as of December 1, 1994,
between the Bonneville Power Administration and the Company (BPA Contract No.
DE-MS79-94BP93947) (Exhibit 10.115 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1994, Commission File No. 1-4393)
10.116 PNW AC Intertie Capacity Ownership Agreement dated as of October
11, 1994 between the Bonneville Power Administration and the Company (BPA
Contract No. DE-MS79-94BP94521) (Exhibit 10.116 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, Commission File No. 1-4393)
10.117 Power Exchange Agreement dated as of September 27, 1995, between
British Columbia Power Exchange Corporation and the Company. (Exhibit 10.117 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1996,
Commission File No. 1-4393)
10.118 Contract with W. S. Weaver, Executive Vice President and Chief
Financial Officer, dated October 18, 1996. (Exhibit 10.118 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1996, Commission File No.
1-4393)
10.119 Contract with S. M. Vortman, Senior Vice President Corporate and
Regulatory Relations, dated October 18, 1996. (Exhibit 10.119 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1996, Commission File No.
1-4393)
88
10.120 Contract with G. B. Swofford, Senior Vice President Customer
Operations, dated October 18, 1996. (Exhibit 10.120 to Annual Report on Form
10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393)
10.121 Service Agreement dated September 1, 1987 between Northwest
Pipeline Corporation and Washington Natural Gas Company for SGS-1 firm storage
service at Jackson Prairie (incorporated herein by reference to Washington
Natural Gas Company Exhibit 10-A Form 10-K for the year ended September 30,
1994, File No. 11271).
10.122 Service Agreement dated April 14, 1993 between Questar Pipeline
Corporation and Washington Natural Gas Company for FSS-1 firm storage service at
Clay Basin (incorporated herein by reference to Washington Natural Gas Company
Exhibit 10-B Form 10-K for the year ended September 30, 1994, File No. 11271).
10.123 Service Agreement dated November 1, 1989, with Northwest Pipeline
Corporation covering liquefaction storage gas service filed under cover of Form
SE dated December 27, 1989.
10.124 Firm Transportation Service Agreement dated October 1, 1990,
between Northwest Pipeline Corporation and Washington Natural Gas Company
(incorporated herein by reference to Washington Natural Gas Company Exhibit 10-D
Form 10-K for the year ended September 30, 1994, File No. 11271).
10.125 Gas Transportation Service Contract dated June 29, 1990, between
Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated
herein by reference to Washington Natural Gas Company Exhibit 4-A Form 10-Q for
the quarter ended March 31, 1993, File No. 0-951).
10.126 Gas Transportation Service Contract dated July 31, 1991, between
Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated
herein by reference to Washington Natural Gas Company Exhibit 4-A Form 10-Q for
the quarter ended March 31, 1993, File No. 0-951).
10.127 Amendment to Gas Transportation Service Contract dated July 31,
1991, between Washington Natural Gas Company and Northwest Pipeline Corporation.
10.128 Gas Transportation Service Contract dated July 15, 1994, between
Washington Natural Gas Company and Northwest Pipeline Corporation
10.129 Amendment to Gas Transportation Service Contract dated August 15,
1994, between Washington Natural Gas Company and Northwest Pipeline Corporation.
10.130 Washington Natural Gas Company Deferred Compensation Plan effective
September 1, 1995.
10.131 Form of Washington Natural Gas Company - Executive Retirement
Compensation Agreement reflecting all amendments through August 16, 1995.
10.132 Second Washington Energy Company Performance Share Plan (amended
and restated effective October 1, 1991) (incorporated herein by reference to
Washington Energy Company Exhibit 10-L.1, Form 10-K for the year ended September
30, 1991, File No. 0-8745).
10.133 Washington Energy Company Interim Performance Share Plan effective
December 7, 1994.
10.134 Washington Energy Company Stock Option Plan (incorporated herein
by reference to Exhibit 10-C Washington Energy Company Form 10-Q for the quarter
ended March 31, 1984, File No. 0-8745).
10.135 Amendment to Washington Energy Company Stock Option Plan
(incorporated herein by reference to Washington Energy Company Exhibit 10-S,
Form 10-K for the year ended September 30, 1986, File No. 0-8745).
10.136 Amendment to Washington Energy Company Stock Option Plan dated as
of February 26, 1988 (incorporated herein by reference to Washington Energy
Company Form S-8, Registration No. 33-24221).
10.137 Washington Energy Company Stock Option Plan effective December 15,
1993 (incorporated herein by reference to Washington Energy Company Exhibit 99,
Registration No. 33-55381).
10.138 Washington Energy Company Directors Stock Bonus Plan (incorporated
herein by reference to Washington Energy Company Exhibit 10-O, Form 10-K for the
year ended September 30, 1990, File No. 0-8745).
10.139 Form of Conditional Executive Employment Contract, filed under
cover of Form SE dated December 27, 1988 (incorporated herein by reference to
Washington Natural Gas Company Exhibit 10-M.2, Form 10-K for the year ended
September 30, 1994, File No.
1-11271).
10.140 Amended and restated Washington Energy Company and subsidiaries
Annual Incentive Plan for Vice Presidents and above, dated October 1994.
89
10.141 Interest Rate Swap Agreement dated September 27, 1989 between
Thermal Resources, Inc. and the First National Bank of Chicago, filed under
cover of Form SE dated December 27, 1989, (incorporated herein by reference to
Washington Natural Gas Company Exhibit 10-N, Form 10-K for the year ended
September 30, 1994, File No. 1-11271).
10.142 Firm Transportation Service Agreement dated March 1, 1992 between
Northwest Pipeline Corporation and Washington Natural Gas Company (incorporated
herein by reference to Washington Natural Gas Company Exhibit 10-O, Form 10-K
for the year ended September 30, 1994, File No. 1-11271).
10.143 Firm Transportation Service Agreement dated January 12, 1994
between Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transportation service from Jackson Prairie (incorporated herein by
reference to Washington Natural Gas Company Exhibit 10-P, Form 10-K for the year
ended September 30, 1994, File No. 1-11271).
10.144 Firm Transportation Service Agreement dated January 12, 1994
between Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transportation service from Jackson Prairie (incorporated herein by
reference to Washington Natural Gas Company Exhibit 10-Q, Form 10-K for the year
ended September 30, 1994, File No. 1-11271).
10.145 Firm Transportation Service Agreement dated January 12, 1994
between Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transportation service from Plymouth, LNG (incorporated herein by reference
to Washington Natural Gas Company Exhibit 10-R, Form 10-K for the year ended
September 30, 1994, File No. 1-11271).
10.146 Service Agreement dated July 9, 1991 with Northwest Pipeline
Corporation for SGS-2F Storage Service filed under cover of Form SE dated
December 23, 1991 (incorporated herein by reference to Washington Natural Gas
Company Exhibit 10-S, Form 10-K for the year ended September 30, 1994, File No.
1-11271).
10.147 Firm Transportation Agreement dated October 27, 1993 between
Pacific Gas Transmission Company and Washington Natural Gas Company for firm
transportation service from Kingsgate (incorporated herein by reference to
Washington Natural Gas Company Exhibit 10-T, Form 10-K for the year ended
September 30, 1994, File No. 1-11271).
10.148 Firm Storage Service Agreement and Amendment dated April 30, 1991
between Questar Pipeline Company and Washington Natural Gas Company for firm
storage service at Clay Basin filed under cover of Form SE dated December 23,
1991.
10.149 Employment agreement with R. R. Sonstelie, Chairman of the Board,
dated January 13, 1998.(Exhibit 10.150 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1997, Commission File No. 1-4393)
10.150 Change in control agreement with T. J. Hogan, dated August 17, 1995.
(Exhibit 10.152 to Annual Report on Form 10-K for the fiscal year ended December
31, 1997, Commission File No. 1-4393)
10.151 Asset Purchase Agreement between PP&L Global, Inc. and the Company.
(Exhibit 2a to Current Report on Form 8-K dated November 13, 1998)
*10.152 Employment agreement with S. A. McKeon, Vice President and General
Counsel, dated May 27, 1997.
*10.153 Employment agreement with R. L. Hawley, Vice President and Chief
Financial Officer, dated March 16, 1998.
*10.154 Employment agreement with J. Quintana, Vice President External
Affairs, dated March 20, 1998.
*12-a Statement setting forth computation of ratios of earnings to fixed
charges (1994 through 1998).
*12-b Statement setting forth computation of ratios of earnings to combined
fixed charges and preferred stock dividends (1994 through 1998).
*21 Subsidiaries of the Registrant.
*23.1 Consent of independent accountants.
*23.2 Consent of independent accountants.
*27 Financial Data Schedules.
---------------------------------
*Filed herewith.
90