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, 1999
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.
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
- -----------------------------------------------------
Preferred Stock (Cumulative; $100 Par Value)
Preferred Stock (Cumulative; $25 Par Value)
8.231% Capital Securities
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes/X/ No/ /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. / /
The aggregate market value of the voting stock held by non-affiliates of
the registrant at December 31, 1999, was approximately $1,645,000,000
The number of shares of the registrant's common stock outstanding at March
1, 2000 was 85,225,296.
Documents Incorporated by Reference
The Company's definitive proxy statement for its 2000 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
ESA Endangered Species Act
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
3
INDEX
Item Page
Part I
1. Business 5
General 5
Industry Overview 6
Regulation and Rates 6
Electric Utility Operations 6
Electric Utility Operating Statistics 11
Gas Utility Operations 13
Gas Utility Operating Statistics 16
Environment 17
Executive Officers 19
2. Properties 20
3. Legal Proceedings 20
4. Submission of Matters to a Vote of Security Holders 20
Part II
5. Market for Registrant's Common Equity and Related
Shareholder Matters 20
6. Selected Financial Data 22
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 23
7a. Quantitative and Qualitative Disclosures about
Market Risk 32
8. Financial Statements and Supplementary Data 33
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 33
Part III (Incorporated by reference from the Company's
definitive proxy statement issued in connection
with the 2000 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 33
Signatures 35
Exhibit Index 74
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, 1999, the Company had approximately 907,000 electric
customers; consisting of 803,700 residential, 97,600 commercial, 4,200
industrial and 1,500 other customers and approximately 569,900 gas customers;
consisting of 521,800 residential, 45,000 commercial, 3,000 industrial and 100
other customers. In 1999, approximately 290,000 customers purchased both forms
of energy from the Company. For the year 1999, the Company added approximately
16,300 electric customers and approximately 26,000 gas customers, representing
annualized growth rates of 1.8% and 4.8%, respectively. During 1999, the
Company's billed retail revenues from electric utility operations were derived
46% from residential customers, 37% from commercial customers, 14% from
industrial customers and 3% from other customers. The Company's retail revenues
from gas utility operations were derived 61% from residential customers, 28%
from commercial customers, 6% from industrial customers, 3% from transportation
customers and 2% from other customers. During this period, the largest customer
accounted for 1.8% 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 wholesale customers also vary by quarters and years depending principally
upon streamflow conditions for the generation of surplus hydro-electric power,
customer usage and the market demand by wholesale customers. Earnings from
electric operations therefore, can be significantly influenced by surplus sales
and variations in weather, hydro conditions and regional electric energy prices.
Earnings from gas operations can be significantly influenced by variations in
weather. The Company has a Purchased Gas Adjustment mechanism ("PGA") in retail
rates to recover variations in gas supply and transportation costs. (See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Rate Matters.")
During the period from January 1, 1995 through December 31, 1999, the
Company made gross electric utility plant additions of $845 million and
retirements of $146 million. In the five-year period ended December 31, 1999,
the Company made gross gas utility plant additions of $479 million and
retirements of $58 million. In the same five-year period, the Company made
gross common utility plant additions of $131 million and retirements of $10
million. Gross electric utility plant at December 31, 1999, was approximately
$4.0 billion which consisted of 46% distribution, 28% generation, 15%
transmission and 11% general plant and other. Gross gas utility plant at
December 31, 1999, was approximately $1.4 billion which consisted of 83%
distribution, 5% transmission and 12% general plant and other.
At year-end the Company had 2,869 aggregate full-time equivalent utility
employees.
On June 23, 1999, Company shareholders approved the formation of a
holding company structure for the Company and its subsidiaries. The proposed
holding company structure has been approved by the Federal Energy Regulatory
Commission and the Federal Trade Commission, but is still subject to regulatory
approval by the Washington Commission. The primary purpose for the holding
company formation is to allow the Company to separate its regulated utility
business from its other businesses, which will enhance the holding company's
ability to respond to the changing industry environment and will permit greater
financing flexibility. The Company's utility business is expected to constitute
the principal part of the holding company's earnings for the foreseeable future
after the restructuring.
5
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 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.
On December 20, 1999 FERC issued Order 2000 to advance the formation of
Regional Transmission Organizations (RTOs). This regulation requires each public
utility that owns, operates or controls facilities for the transmission of
electric energy in interstate commerce to file with FERC by October 15, 2000
their plans for forming and participating in an RTO. FERC's goal is to promote
efficiency in wholesale electricity markets and to ensure that electricity
consumers pay the lowest price possible for reliable service.
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 1999, 103 commercial and
industrial customers, on average, chose to use such service. The shifting of
customers from sales to transportation does not materially impact utility
margin, as the Company earns similar margins on transportation service as it
does on large volume, interruptible gas sales.
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, 1999, the Company's peak electric power resources were
approximately 5,101,647 KW. The Company's historical peak load of approximately
4,847,000 KW occurred on December 21, 1998.
During 1999, the Company's total electric energy production was supplied
23% by its own resources, 23% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydro-electric projects on
the Columbia River, 22% from other firm purchases and 32% from non-firm
purchases.
6
The following table shows the Company's electric energy supply resources
at December 31, 1999, and energy production during the year:
PEAK POWER RESOURCES
AT DECEMBER 31, 1999 1999 ENERGY PRODUCTION
---------------------------- -----------------------------
KILOWATTS % KILOWATT-HOURS %
(THOUSANDS)
---------------------------- -----------------------------
Purchased Resources:
Columbia River
PUD Contracts (Hydro) 1,414,000 27.7% 8,058,572 23.2%
Other Hydro1 547,322 10.7% 3,440,026 9.9%
Other Producers (1) 1,244,675 24.4% 15,237,380 44.0%
- ------------------------------ --------------- ----------- ---------------- -----------
Total Purchased 3,205,997 62.8% 26,735,978 77.1%
- ------------------------------ --------------- ----------- ---------------- -----------
Company-owned Resources:
Hydro 310,700 6.1% 1,648,200 4.8%
Coal 771,900 15.1% 5,630,670 16.2%
Natural gas/oil 813,050 16.0% 662,762 1.9%
- ------------------------------ --------------- ----------- ---------------- -----------
Total Company-owned 1,895,650 37.2% 7,941,632 22.9%
- ------------------------------ --------------- ----------- ---------------- -----------
Total 5,101,647 100.0% 34,677,610 100.0%
- ------------------------------ --------------- ----------- ---------------- -----------
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"), under the terms of long-term coal supply agreements.
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. (See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Other" for a discussion of the sale.)
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 May 1999, the Company and the other owners
announced that they had signed an agreement to sell all their ownership shares
in the plant to TransAlta Corporation of Calgary, Canada. (See "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Other" for a discussion of the sale.)
The Company owns a 160 megawatt natural-gas fired cogeneration facility
located near Bellingham, Washington which was purchased from Encogen Northwest
L.P. ("Encogen") on November 1, 1999. (See Electric Energy Supply Contracts and
Agreements with Non-Utilities.)
The Company also has the following plants with an aggregate net
generating capability of 963,750 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;
Snoqualmie Falls hydro plant (45,500 KW), half the capability of which was
installed during the period 1898 to 1910 and half in 1957; and one smaller hydro
plant, Electron (27,400 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 (113,200 KW each) installed during 1984. All of these
generating facilities are located in the Company's service territory.
_________________________________
(1) 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.
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 wholesale customers,
either directly or through tolling arrangements.
On December 19, 1997, the Company was issued a 50 year license by FERC for
its existing and operating White River project which includes authorization to
install an additional 14,000 KW generating unit. The Company has filed for a
rehearing with FERC on conditions of the license related to measures designed to
enhance salmon runs on the White River, because those conditions may make the
plant uneconomic to operate. On June 30, 1999, FERC issued a two year stay in
the license proceeding. This additional time allows the Company, state agencies,
local governments and public interest groups to resolve common issues relating
to the plant's continued operation and economics. 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.
COLUMBIA RIVER ELECTRIC ENERGY SUPPLY CONTRACTS
During 1999, approximately 23.2% of the Company's energy output was
obtained at an average cost of approximately 9.4 mills per KWH through long-term
contracts with several of the Washington PUDs owning 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 50% as of 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, 1999, the Company's aggregate annual capacity from all
units of the Rock Island Project was 478,000 KW. The Company has contracted to
purchase from Chelan 38.9% (505,000 KW as of December 31, 1999) 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, 1999) 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, 1999) of the annual output of the Priest Rapids
project and 10.8% (98,000 KW as of December 31, 1999) 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.)
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.
8
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. This contract expires on December 31, 2002.
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. This contract expires on October 31, 2003.
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.
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.
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.
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 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 four 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 four contracts are $181 million for 2000, $204
million for 2001, $206 million for 2002, $207 million for 2003, $213 million for
2004 and in the aggregate, $1.5 billion thereafter through 2012. These payments
reflect the Tenaska and Encogen contract restructurings described below. The
Company continues to seek restructuring of the other 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.
9
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
the Equilon 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 Equilon refinery in Anacortes, Washington. A dispute,
currently being litigated, exists between the Company and March Point over the
PURPA status of and the Company's obligations to buy the output of Phase II.
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 owned
and operated a natural-gas fired cogeneration facility located at the Georgia
Pacific mill near Bellingham, Washington. The contract had obligated the Company
to pay Encogen fixed and escalating fees well above current and projected future
market prices through mid-2008 for the output of the plant. On November 1, 1999,
the Company purchased the 160 megawatt plant from Encogen. The Company paid $55
million in cash and assumed $109 million in debt to acquire the partnership,
which owned no significant assets other than the plant. Pursuant to an October
27, 1999 order from the Washington Commission approving the purchase, the
Company will depreciate the original owner's net book value of the plant over
the remaining 23 year useful life of the project. The difference between the
purchase price and the net book value of the plant (approximately $72.5 million)
will be amortized over 9 years (the remaining term of the power purchase
contract). The purchase is expected to reduce the net cost of power from the
co-generation project by approximately 17% annually.
In December 1999, the Company bought out the remaining 8.5 years of one
of the natural gas supply contracts serving Encogen from Cabot Oil & Gas
Corporation which provided approximately 60% of the plant's natural gas
requirements. The Company will become the replacement gas supplier to the
project for 60% of the supply under the terms of the Cabot Agreement and expects
the agreement will reduce this portion of gas costs by 5% to 15% annually. The
Washington Commission has issued an order creating a regulatory asset relating
to the $12 million payment that requires the Company to accrue carrying costs on
the unamortized balance over the first 3 years.
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
an average of between 15 and 20 percent over the 14 year period from 1998
through 2011, net of the costs of the restructuring payment.
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 annually between 1.0% to 1.5% depending
on rate class on January 1 of 1998 through 2000. Electric tariff rates for
certain customers will increase by 1.5% in 2001.
10
ELECTRIC UTILITY OPERATING STATISTICS
YEAR ENDED ON DECEMBER 31 1999 1998 1997
- ----------------------------------------------------------------------------
Operating revenues by classes:
(thousands)
- ----------------------------------------------------------------------------
Residential $586,416 $540,549 $529,990
Commercial 457,339 431,752 414,480
Industrial 169,508 180,959 166,473
Other consumers 37,562 42,952 32,453
- ----------------------------------------------------------------------------
Operating revenues
billed to consumers (1) 1,250,825 1,196,212 1,143,396
Unbilled revenues -
net increase (decrease) (9,541) 4,024 (4,921)
PRAM accrual -- -- (40,777)
- -----------------------------------------------------------------------------
Total operating revenues
from consumers 1,241,284 1,200,236 1,097,698
Wholesale customers 316,728 274,972 133,726
- ----------------------------------------------------------------------------
Total operating revenues $1,558,012 $1,475,208 $1,231,424
- ----------------------------------------------------------------------------
Number of customers (average):
Residential 797,421 782,095 767,476
Commercial 96,769 94,118 91,517
Industrial 4,224 4,193 4,090
Other 1,497 1,437 1,389
- ----------------------------------------------------------------------------
Total customers (average) 899,911 881,843 864,472
- ----------------------------------------------------------------------------
KWH generated, purchased and
interchanged (thousands):
Company generated 7,941,632 7,934,730 6,641,118
Purchased power 26,716,328 24,231,978 22,611,963
Interchanged power (net) 19,650 91,230 103,959
- ----------------------------------------------------------------------------
Total energy output 34,677,610 32,257,938 29,357,040
Losses and company use (1,512,571) (1,413,331) (1,414,101)
- ----------------------------------------------------------------------------
Total energy sales 33,165,039 30,844,607 27,942,939
- ----------------------------------------------------------------------------
_____________________________
(2) Operating revenues in 1999, 1998 and 1997 were reduced by $43.8
million, $46.7 million and $40.5 million, respectively, as a result of the
Company's sale of $237.7 million of its investment in customer-owned
conservation measures. (See "Operating revenues" in Management's Discussion
and Analysis and Note 1 to the Consolidated Financial Statements.)
11
(continued from previous page)
YEAR ENDED ON DECEMBER 31 1999 1998 1997
- --------------------------------------------------------------------------------
Electric energy sales, KWH:
(thousands)
- --------------------------------------------------------------------------------
Residential 9,861,791 9,313,652 9,319,508
Commercial 7,482,280 7,191,164 7,022,092
Industrial 3,980,246 4,072,722 3,994,748
Other consumers 262,238 284,312 206,330
- --------------------------------------------------------------------------------
Total energy billed to consumers 21,586,555 20,861,850 20,542,678
Unbilled energy sales -
net increase (decrease) (155,023) 43,027 (45,556)
- --------------------------------------------------------------------------------
Total energy sales to consumers 21,431,532 20,904,877 20,497,122
Sales to wholesale customers 11,733,507 9,939,730 7,445,817
- --------------------------------------------------------------------------------
Total energy sales 33,165,039 30,844,607 27,942,939
- --------------------------------------------------------------------------------
Per residential customer:
Annual use (KWH) 12,367 11,909 12,143
Annual billed revenue $762.78 $721.09 $716.88
Billed revenue per KWH $.0617 $.0606 $.0590
Company-owned generation
capability - KW:
Hydro 310,700 308,200 309,950
Steam 771,900 771,900 771,900
Natural gas/oil 813,050 673,850 702,350
- --------------------------------------------------------------------------------
Total 1,895,650 1,753,950 1,784,200
- --------------------------------------------------------------------------------
Heating degree days 4,956 4,498 4,599
Percent of normal of 30 year
average 101.0% 91.6% 93.7%
Load factor 62.6% 52.6% 58.7%
12
Gas Utility Operations
Gas Supply
The Company currently purchases a blended portfolio of long-term firm,
short-term firm, and non-firm 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, 1999 DTH PER DAY %
- -----------------------------------------------------------------
Purchased Gas Supply
British Columbia 153,700 19.3
Alberta 77,100 9.7
United States 75,000 9.4
- -----------------------------------------------------------------
Total Purchased Gas Supply 305,800 38.4
- -----------------------------------------------------------------
Purchased Storage Capacity
Clay Basin 76,200 9.6
Jackson Prairie 48,000 6.0
LNG 69,900 8.8
- -----------------------------------------------------------------
Total Purchased Storage Capacity 194,100 24.4
- -----------------------------------------------------------------
Owned Storage Capacity
Jackson Prairie 267,400 33.5
Propane-Air Injection 30,000 3.7
- -----------------------------------------------------------------
Total Owned Storage Capacity 297,400 37.2
- -----------------------------------------------------------------
Total Peak Firm Gas Supply 797,300 100.0
- -----------------------------------------------------------------
All peak firm gas 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 Dth per day of gas supply away from the Tenaska Cogeneration Facility
and toward the core gas load by causing Tenaska to operate its facility on
distillate fuel and paying any additional costs of such operation.
The Company expects to meet its firm peak-day requirements for
residential, commercial and industrial markets through its firm gas purchase
contracts, firm transportation capacity, firm storage capacity and other firm
peaking resources. The Company believes that it will be able to acquire
incremental firm gas supply resources which are reliable and reasonably priced,
to meet anticipated growth in the requirements of its firm customers for the
foreseeable future.
13
Gas Supply Portfolio
For the 1999-2000 winter heating season, the Company has contracted for
approximately 19% 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 19% 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 39%, 9% and 4%, respectively, of expected peak-day requirements.
During 1999, approximately 48% of gas supplies purchased by the Company
originated from British Columbia while 26% originated in Alberta and 26%
originated in the U.S.
The current firm, long-term gas supply portfolio consists of arrangements
with 18 producers and gas marketers, with no single supplier representing more
than 12% of expected peak-day requirements. Contracts have remaining terms
ranging from less than one year to 12 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 ("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, or 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 5
to 16 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, totaling 90,392 Dth per day, has a remaining term of 24
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 340,000 Dth per day and total firm storage capacity exceeding 7,500,000
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. On
November 1, 1999, a facility expansion was placed in service. The Company's
share of the expanded service provides additional firm delivery capacity of over
100,000 Dth per day and additional firm storage capacity in excess of 1,000,000
Dth. The Company secured rights to additional firm seasonal pipeline capacity to
be utilized in conjunction with the expanded service.
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
14 and 20 years.
14
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 temporarily relinquish 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
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. Capacity release benefits are passed on to
customers through the PGA.
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
approximately $2 million annually.
On October 27, 1999, the Washington Commission approved the Company's PGA
and deferral amortization (true-up) filings effective November 1, 1999. The PGA
filing allows the Company to recover an expected increase in annual gas costs
and the deferral amortization filing allows the Company to recover prior period
gas cost undercollections. The filings replaced the PGA and deferral
amortization refund that had been effective since April 1, 1998. As a result,
gas rates to all sales customers increased by an average of 16.3%, while rates
for gas transportation service as well as gas margins remained unchanged.
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 1999 and 1998 were approximately $7.2 million and $1.1 million, respectively
while customers received approximately $11.3 million and $2.0 million,
respectively.
15
GAS UTILITY OPERATING STATISTICS
Twelve Months Ended December 31 1999 1998 1997
- --------------------------------------------------------------------------------
Operating revenues by classes (thousands):
Regulated utility sales:
Residential sales $296,032 $253,169 $246,747
Commercial firm sales 113,058 96,116 97,233
Industrial firm sales 21,724 18,557 19,524
Interruptible sales 30,404 22,190 19,832
Transportation services 13,117 14,211 14,631
Other 11,153 12,308 11,480
- --------------------------------------------------------------------------------
Total gas operating revenues $485,488 $416,551 $409,447
- --------------------------------------------------------------------------------
Customers, average number served
Residential 509,384 486,553 465,185
Commercial firm 43,567 42,273 41,158
Industrial firm 2,879 2,850 2,839
Interruptible 873 940 962
Transportation 103 123 128
- --------------------------------------------------------------------------------
Total customers (average) 556,806 532,739 510,272
- --------------------------------------------------------------------------------
Gas volumes (thousands of therms):
Residential sales 507,978 444,611 434,179
Commercial firm sales 221,804 193,765 195,087
Industrial firm sales 48,422 42,737 44,563
Interruptible sales 93,791 72,115 60,244
Transportation volumes 236,704 254,368 277,092
- --------------------------------------------------------------------------------
Total gas volumes 1,108,699 1,007,596 1,011,165
- --------------------------------------------------------------------------------
Working-gas volumes in storage at year end
(thousands of therms)
Jackson Prairie 60,673 37,683 52,429
Clay Basin 37,281 58,827 64,934
Average use per customer (therms):
Residential 997 914 933
Commercial firm 5,091 4,584 4,740
Industrial firm 16,819 14,995 15,697
Interruptible 107,435 76,718 62,624
Transportation 2,298,097 2,068,033 2,164,781
16
(continued from prior page)
TWELVE MONTHS ENDED DECEMBER 31 1999 1998 1997
- --------------------------------------------------------------------------------
Average revenue per customer:
Residential $ 581 $ 520 $ 530
Commercial firm 2,595 2,274 2,362
Industrial firm 7,546 6,511 6,877
Interruptible 34,827 23,606 20,615
Transportation 127,350 115,537 114,305
Average revenue per therm (cents):
Residential 58.3 56.9 56.8
Commercial firm 51.0 49.6 49.8
Industrial firm 44.9 43.4 43.8
Interruptible 32.4 30.8 32.9
Total sales to customers 52.9 51.8 52.2
Transportation 5.5 5.6 5.3
Weather - degree days 4,956 4,498 4,599
Percent of normal (30-year average) 101.0% 91.6% 93.7%
ENERGY CONSERVATION
The Company offers programs designed to help new and existing customers
use energy efficiently. The primary emphasis is to provide information and
technical services to enable customers to make energy-efficient choices with
respect to building design, equipment and building systems, appliance purchases
and operating practices.
Since May 1997, the Company has recovered electric energy conservation
expenditures through a tariff rider mechanism. The rider mechanism allows the
Company to defer the conservation expenditures and amortize them to expense as
the Company concurrently collects the conservation expenditures in rates over a
one year period. As a result of the rider, there is no effect on earnings per
share.
Since 1995, the Company has been authorized by the Washington Commission
to defer gas energy conservation expenditures and recover them through a tariff
tracker mechanism. The tracker mechanism allows the Company to defer
conservation expenditures and recover them in rates over the subsequent year.
The tracker mechanism also allows the Company to recover an Allowance for Funds
Used to Conserve Energy (AFUCE) on any outstanding balance that is not being
recovered in rates.
ENVIRONMENT
The Company's operations are subject to environmental regulation by
federal, state and local authorities. Due to the inherent uncertainties
surrounding the development of federal and state environmental and energy laws
and regulations, the Company cannot determine the impact such laws may have on
its existing and future facilities. (See Note 17 to the Consolidated Financial
Statements for further discussion of environmental sites.)
FEDERAL CLEAN AIR ACT AMENDMENTS OF 1990
The Company has an ownership interest in coal-fired, steam-electric
generating plants at Centralia, Washington and Colstrip, Montana, which are
subject to the federal Clean Air Act Amendments of 1990 ("CAAA") and other
regulatory requirements.
17
The Centralia Project and the Colstrip Projects met the sulfur dioxide
limits of the CAAA in Phase I (1995). All four units at the Colstrip Project,
operated by Montana Power, meet Phase II emission limits. In accordance with the
purchase agreement with TransAlta, the Centralia Owners are installing flue gas
scrubbers and low NOx burners on both units of the Centralia generating station
to meet state and federal emissions standards. The current cost estimate for the
Company's share of these additions is $14 million, of which approximately $4.2
million will have been committed by the anticipated closing date of the sale of
Centralia to TransAlta. In accordance with the agreements with TransAlta, these
expenditures will be reimbursed by TransAlta.
The Company owns combustion turbine units, most of which are capable of
being fueled by natural gas or oil. The nature of these units provides
operational flexibility in meeting air emission standards.
There is no assurance that in the future environmental regulations
affecting sulfur dioxide or nitrogen oxide emissions may not be further
restricted, or that restrictions on emissions of carbon dioxide or other
combustion by-products may not be imposed.
FEDERAL ENDANGERED SPECIES ACT
In November 1991, the National Marine Fisheries Service ("NMFS") listed
the Snake River Sockeye as an endangered species pursuant to the federal
Endangered Species Act ("ESA"). Since the Sockeye listing, the Snake River fall
and spring/summer Chinook have also been listed as threatened. In response to
the listings, a team of experts was formed to develop a plan for the recovery
needs of these species. In 1995, the NMFS issued a biological opinion which has
significantly changed the operation of the Federal Columbia River Power System.
The plans developed by NMFS affect the Mid-Columbia projects from which
the Company purchases power on a long-term basis, and will further reduce the
flexibility of the regional hydro-electric system. Although the full impacts are
unknown at this time, the plan developed by NMFS shifts an amount of the
Company's generation from the Mid-Columbia projects from winter periods into the
spring when it is not needed for system loads, and will increase the potential
for spill and loss of generation at the Mid-Columbia projects.
Since the 1991 listings, one more species of salmon has been listed and
two more have been proposed which may further influence operations. Upper
Columbia River Steelhead were listed by NMFS in August 1997. Anticipating the
Steelhead listing, the Mid-Columbia PUDs initiated consultation with the federal
and state agencies, Native American tribes and non-governmental organizations to
secure operational protection through a long-term settlement and habitat
conservation plan which includes fish protection and enhancement measurement for
the next 50 years. The negotiations have concluded among the Chelan and Douglas
County PUDs and various fishery agencies, and final agreement is subject to a
National Environmental Policy Act review and power purchaser approval.
Generally, the agreement obligates the PUDs to achieve certain levels of passage
efficiency for downstream migrants at their hydro-electric facilities and to
fund certain habitat conservation measures. Grant County PUD has yet to reach
agreement on these issues.
The proposed listings of Puget Sound Chinook salmon and spring Chinook
for the upper Columbia were approved in March 1999. The listing of spring
Chinook for the upper Columbia should not result in markedly differing
conditions for operations from previous listings in the area. However, Puget
Sound has not experienced ESA listing to date and listing of Puget Sound Chinook
could cause a number of changes to operations of government agencies and private
entities in the region including the Company. These may adversely affect hydro
plant operations, permit issuance for facilities construction and increased
costs for process and facilities. Because the Company relies substantially less
on hydro-electric energy from the Puget Sound area than from the Mid-Columbia
and because the impact on Company operations in the Puget Sound area is not
likely to impair significant generating resources, the impact of listing for
Puget Sound Chinook salmon should be proportionately less than the Columbia
River listings.
18
EXECUTIVE OFFICERS AT MARCH 1, 2000
NAME AGE OFFICES
- --------------------------------------------------------------------------------
W. S. Weaver 56 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.
J. W. Eldredge 49 Chief Accounting Officer since 1994; Corporate
Secretary and Controller since 1993; Controller since
1988.
D. E. Gaines 43 Treasurer since 1994; Director Strategic Planning 1992-
1994; Manager Financial Planning 1986 - 1992.
W. A. Gaines 44 Vice President Energy Supply since February 1997;
Manager Power Management 1996-1997; Manager Operations
Planning 1986-1996.
D. A. Graham 59 Vice President Human Resources since April 1998;
Director Human Resources 1989-1998.
R. L. Hawley 50 Vice President and Chief Financial Officer since March
1998. For more than five years prior to that time, he
was a partner with the accounting firm of
PricewaterhouseCoopers LLP.
T. J. Hogan 48 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 54 Vice President and General Counsel since June 1997. For
more than five years prior to that time he was a
partner with the law firm of Perkins Coie LLP.
S. McLain 43 Vice President Operations - Delivery since June 1999;
Vice President Corporate Performance 1997-1999;
Director Planning and Work Practices 1997; various
positions in Human Resources, Operations, Customer
Service and Strategic Planning 1988-1997.
G. B. Swofford 58 Vice President and Chief Operating Officer - Delivery
since June 1999; Vice President Customer Operations
1997-1999; 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.
19
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 (symbol PSD) is traded on the New York Stock
Exchange. The number of shareholders of record of the Company's common stock at
December 31, 1999, was 53,434.
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 $202
million at December 31, 1999. (See Note 7 to the Consolidated Financial
Statements.)
20
Dividends paid and high and low stock prices for each quarter over the
last two years were:
1999 1998
- -------------------------------------------------------------------------------
PRICE RANGE DIVIDENDS PRICE RANGE DIVIDENDS
QUARTER ENDED HIGH LOW PAID HIGH LOW PAID
- -------------------------------------------------------------------------------
March 31 28-3/8 22-15/16 $.46 30-1/4 26-5/8 $.46
June 30 26-3/8 23-1/8 $.46 28-5/8 25 $.46
September 30 24-1/2 21-3/4 $.46 28 24-1/16 $.46
December 31 23-1/4 18-3/4 $.46 29 25-7/8 $.46
21
ITEM 6. SELECTED FINANCIAL DATA (1)
(Dollars in thousands except per share data)
YEAR ENDED DECEMBER 31 1999 1998 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------
Operating revenue $2,066,630 $1,923,856 $1,681,528 $1,652,265 $1,631,118
Operating income 310,132 295,098 210,638 282,876 270,344
Income from continuing
operations 185,567 169,612 125,698 167,351 128,381
Income for common stock from
continuing operations 174,502 156,609 108,363 145,170 105,727
Basic and diluted earnings
per common share from
continuing operations (Note 1 to the 2.06 1.85 1.28 1.72 1.26
financial statements)
Dividends per common share 1.84 1.84 1.78 1.67 1.67
Book value per common share 16.24 16.00 16.06 16.31 16.27
- -----------------------------------------------------------------------------------------------------------
Total assets at year-end $5,145,606 $4,709,687 $4,493,306 $4,230,855 $4,244,568
Long-term obligations 1,783,139 1,475,106 1,412,153 1,166,601 1,230,499
Redeemable preferred stock 65,662 73,162 78,134 87,839 89,039
Corporation obligated,
mandatorily redeemable
preferred securities of
subsidiary trust holding
solely junior subordinated
debentures of the
corporation 100,000 100,000 100,000 -- --
- -----------------------------------------------------------------------------------------------------------
(1) Amounts for 1996 and 1995 have been retroactively restated to include
the results of operations, financial position and cash flows of WECo and WNG.
22
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 uncertainties. 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
Net income in 1999 was $185.6 million on operating revenues of $2.067
billion, compared to $169.6 million on operating revenues of $1.924 billion in
1998 and $123.1 million on operating revenues of $1.682 billion in 1997. Income
for common stock was $174.5 million in 1999, compared to $156.6 million in 1998
and $105.7 million in 1997.
Basic and diluted earnings per share in 1999 were $2.06 on 84.6 million
weighted average common shares outstanding compared to $1.85 on 84.6 million
weighted average common shares outstanding in 1998 and $1.25 on 84.6 million
weighted average common shares outstanding in 1997 including a $0.03 loss per
share from discontinued operations.
Net income in 1999 was positively impacted by net gains of approximately
$7.8 million or $0.09 per share from non-utility operations. The $0.09 per share
included gains from the sale of Homeguard Security Services, Inc., a wholly
owned subsidiary, and the Company's common stock investment in Cabot Oil & Gas
Corporation. These gains were offset in part by losses related to sales of
non-core assets and gas transportation contracts, establishing reserves for two
proposed small hydroelectric projects and costs of a subsidiary exiting certain
product lines. 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 1999 were 21.4
billion, compared with 20.9 billion in 1998 and 20.5 billion in 1997.
Kilowatt-hour sales to wholesale customers were 11.7 billion in 1999, 9.9
billion in 1998 and 7.4 billion in 1997.
Total gas volumes, including gas sales service and transportation, were
1,109 million therms in 1999, 1,008 million therms in 1998 and 1,011 million
therms in 1997.
23
INCREASE (DECREASE) OVER PRECEDING YEAR
years ended December 31 (dollars in millions)
1999 1998
- ---------------------------------------------------------------------
Operating revenues:
General rate increases $17.3 $18.5
PRAM electric revenue surcharges/refunds -- 44.8
BPA Residential Purchase and
Sale Agreement (4.8) (1.2)
Electric sales to wholesale customers 41.8 141.2
Electric revenue sold to conservation trust 2.9 (6.3)
Electric load and other changes 25.7 46.7
Gas revenue change 68.9 7.1
Other revenues (9.0) (8.6)
- ---------------------------------------------------------------------
Total operating revenue changes 142.8 242.2
- ---------------------------------------------------------------------
Operating expenses:
Energy costs:
Purchased electricity 28.0 137.2
Residential exchange 16.6 16.4
Purchased gas 44.2 (3.5)
Electric generation fuel 2.9 15.1
Utility operations and maintenance 9.0 (12.5)
Other operations and maintenance (7.7) (3.8)
Depreciation and amortization 10.1 3.7
Conservation amortization 1.6 (1.1)
Merger and related costs -- (55.8)
Taxes other than federal income taxes 19.7 1.2
Federal income taxes 3.3 60.9
- ---------------------------------------------------------------------
Total operating expense changes 127.7 157.8
- ---------------------------------------------------------------------
Other income 12.6 (20.2)
Interest charges 11.7 20.3
Discontinued operations -- 2.6
- ---------------------------------------------------------------------
Net income changes $ 16.0 $ 46.5
- ---------------------------------------------------------------------
The following information pertains to the changes outlined in the table
above:
Operating Revenues - Electric
Electric operating revenues increased $17.3 million and $18.5 million in
1999 and 1998, respectively, when compared to the prior years due to overall
average 1.2% general rate increases effective January 1, 1998 and January 1,
1999.
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. A decrease in
federal, state and local taxes as well as a decrease in interest expense and
recognition of interest income offset the $48.6 million reduction in revenues in
1997.
24
Electric revenues in 1999, 1998 and 1997 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. On January 29, 1997, the Company and the
BPA signed a Residential Exchange Termination Agreement. The Termination
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. These payments are recorded as a reduction of
purchased electricity expenses. Under the rate plan approved by the Washington
Commission in its merger order, the Company will continue to reflect, in
customers' bills, the level of Residential Exchange benefits in place at the
time of the merger. Over the remainder of the Residential Exchange Termination
Agreement from January 2000 through June 2001, it is projected that the Company
will credit customers approximately $106.8 million more than it will receive
from BPA during the following periods:
Credit to Received from BPA Excess Credits
Customers
Period (in Millions)
--------------------------------------------------------------------------
January - December 2000 $111.2 $41.0 $70.2
January - June 2001 63.6 27.0 36.6
--------------------------------------------------
$174.8 $68.0 $106.8
The allocation of future benefits of low-cost federal power, for the
five-year BPA rate plan period 2002 to 2006 will be decided as part of a current
BPA rate case process. As part of its rate case, the BPA has a "subscription
plan" that outlines how the agency proposes to allocate the low-cost federal
power, or in some cases, the power's equivalent monetary benefits. Following a
public rate-hearing process, the BPA is expected to publish a record of decision
on final power rates and allocations in the latter part of 2000.
Electric revenues in 1999 and 1998 were reduced by $43.8 million and
$46.7 million, respectively, when compared to prior years as a result of the
Company's sale of revenues associated with $237.7 million of its investment in
conservation assets to grantor trusts. The revenue decrease represents the
portion of rate revenues that were sold and forwarded to the trusts. 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 to wholesale customers. In addition, the Company has
increased its wholesale surplus power business in order to manage its core
energy portfolio through short and intermediate-term purchases, sales, arbitrage
and other risk management techniques. The Company has a Risk Management
Committee which oversees energy price risk matters. Sales to wholesale customers
increased $41.8 million and $141.2 million in 1999 and 1998, respectively,
compared to the prior years due primarily to favorable hydroelectric conditions
and 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.
OPERATING REVENUES - GAS
Regulated gas utility revenue in 1999 increased by $68.9 million from the
prior year on a 15.8% increase in gas volumes sold. Total gas volumes, including
transported gas, increased 10.0% in 1999 from 1998. The increase in sales
revenue was primarily the result of a 4.5% increase in gas customers during
1999, the impact of temperatures that averaged near normal as compared to warmer
than normal in the prior year and a Purchased Gas Adjustment that became
effective November 1, 1999. The Purchased Gas Adjustment ("PGA") and deferral
amortization (true-up) filings effective November 1, 1999 accounted for $17.3
million of this increase. (See "Rate Matters - Gas"). A larger percentage of
firm gas sales with higher prices and less transportation volumes in 1999 when
compared to last year also contributed to increased revenues. Utility gas margin
(the difference between gas revenues and gas purchases) increased by $19.4
million, or 9.8 %, in 1999 over 1998.
Regulated gas utility sales revenue in 1998 increased by $7.1 million, or
1.7%, 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.
25
OTHER REVENUES
Other revenues decreased $9.0 million in 1999 compared to 1998 due
primarily to decreased revenues at the Company's ConneXt subsidiary. Other
revenues decreased $8.6 million in 1998 compared to 1997 due primarily to the
sale of an unregulated subsidiary (Washington Energy Services Company) in
October 1997.
OPERATING EXPENSES
Purchased electricity expenses increased $28.0 million in 1999 when
compared to 1998 and $137.2 million in 1998 when compared to 1997. The increase
in 1999 was due primarily to an increase in secondary power purchases from other
utilities and marketers to support wholesale sales as a part of the Company's
energy price risk management policies and the increased load due to temperatures
that averaged near normal as compared to warmer than normal in 1998 and the
increase in electric customers in 1999 compared to 1998. 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.
Residential exchange credits associated with the Residential Purchase and
Sale Agreement with BPA decreased $16.6 million in 1999 when compared to 1998,
primarily as a result of the 1997 Residential Exchange Termination Agreement
discussed in "Operating Revenues - Electric." Residential exchange credits also
decreased $16.4 million in 1998 compared to 1997 as a result of the
aforementioned Termination Agreement. Residential exchange credits received in
1999 were $39.0 million and are estimated to be $41.0 million and $27.0 million
in the years 2000 and 2001, respectively. (See discussion of the Residential
Purchase and Sale Agreement under Operating Revenues.)
Purchased gas expenses increased $44.2 million in 1999 compared to 1998
due to both the increased volumes of purchases as a result of higher heating
load and the increase in gas service customers. Purchased gas expenses also
increased by $17.3 million in 1999 compared to 1998 due to approval of the
Company's PGA filing effective November 1, 1999. Changes in gas costs are passed
through to customers with the PGA mechanism. Purchased gas expenses decreased
$3.5 million in 1998 compared to 1997 despite the 2.6% increase in gas volumes
sold in 1998. 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.
Electric generation fuel expense increased $2.9 million in 1999 compared
to 1998 as a result of a $6.7 million Encogen fuel expense in the fourth quarter
of 1999 which was partially offset by the Company generating less electricity at
other Company-owned combustion turbines. The Company's acquisition of the 160
megawatt Encogen natural gas-fired cogeneration facility was completed on
November 1, 1999. (See "Other"). Electric generation fuel expense increased
$15.1 million in 1998 compared to 1997 primarily due to the Company generating
more electricity at Company-owned gas-fired combustion turbine plants. This
increase was 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.
Utility operations and maintenance expenses increased $9.0 million in
1999 compared to 1998. The primary reasons for the increase were increased
storm-repair costs of $8.3 million and increased expenditures for Year 2000
remediation efforts of $4.3 million (total expended in 1999 approximated $7.1
million for Year 2000 remediation). Utility operations and maintenance expenses
decreased $12.5 million in 1998 compared to 1997. The decrease was primarily the
result of the reduction in operating expenses resulting from consolidation of
the joint operations of two formerly separate electric and gas utilities with
overlapping service territories, the elimination of duplicate administrative
functions and the consolidation of Company facilities.
Other operations and maintenance expenses decreased $7.7 million in 1999
compared to 1998 primarily as a result of a wholly owned subsidiary's exiting
certain product lines. Other operations and maintenance expenses decreased $3.8
million in 1998 compared to 1997. The decrease resulted primarily from the sale
of the Company's unregulated subsidiary, Washington Energy Services Company, in
October 1997. The decreases were partially offset by increased operating
expenses at another subsidiary.
26
Depreciation and amortization expense increased $10.1 million in 1999
compared to 1998 due primarily to the effects of new plant placed into service
during the past year. 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 this increase in 1998 was a decrease in
depreciation and amortization expense resulting from an August 1997 Washington
Commission Order which authorized the Company to record in 1997 interest income
of $8.3 million related to a conservation tax refund, but required the Company
to expense in 1997 deferred storm damage costs in the amount of $7.4 million and
to establish a $1.0 million reserve to cover the costs of a Company retail pilot
program.
Taxes other than federal income taxes increased $19.7 million in 1999
compared to 1998 and $1.2 million in 1998 compared to 1997 due primarily to
increases in municipal taxes, state excise taxes and state property taxes.
Federal income taxes increased by $3.3 million in 1999 over 1998 primarily due
to higher pre-tax operating income for the period. Federal income taxes in 1997
were $60.9 million less than in 1998 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 for
1997 by $26.5 million, a decrease in PRAM revenues of $48.6 million in 1997
reduced federal income taxes by $17.0 million and merger costs expensed in the
first quarter of 1997 further reduced federal income taxes by $19.3 million.
OTHER INCOME
Other income, net of federal income tax, increased $12.6 million in 1999
compared to 1998 due primarily to net gains of approximately $7.8 million from
non-utility operations in 1999 and an increase of $2.8 million in AFUDC income.
The $7.8 million of net gains included gains from the sale of Homeguard Security
Services, Inc., a wholly owned subsidiary, and the Company's common stock
investment in Cabot Oil & Gas Corporation. These gains were offset in part by
losses related to sales of non-core assets and gas transportation contracts,
establishing reserves for two proposed small hydroelectric projects and expenses
of a subsidiary exiting certain product lines.
Other income, net of federal income tax, decreased $20.2 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.
INTEREST CHARGES
Interest charges, which consist of interest and amortization on long-term
debt and other interest, increased $11.7 million in 1999 compared to 1998 as a
result of the issuance of $200 million 6.74% Senior Medium-Term Notes, Series A,
in June 1998 and $250 million Senior Medium-Term Notes, Series B, in March 1999.
These increases were partially offset by the maturity or redemption of $188
million in Secured Medium-Term Notes since February 1998. Other interest expense
decreased $1.7 million compared to 1998 as a result of lower weighted average
interest rates.
Interest charges 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.
CONSTRUCTION, CAPITAL RESOURCES AND LIQUIDITY
Current construction expenditures, primarily transmission and
distribution-related, are designed to meet continuing customer growth and to
improve efficiencies of the Company's energy delivery systems. Construction
expenditures in 1999 and 2000 also include costs of developing a new customer
information system. Construction expenditures, which include energy conservation
expenditures and exclude AFUDC, were $330.8 million in 1999. The Company expects
construction expenditures for the period 2000 through 2002 will be approximately
$269 million, $250 million and $250 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 2000 through 2002 will, on average, be approximately 95% of
average estimated construction expenditures (excluding AFUDC) during the same
period.
On November 1, 1999, the Company assumed approximately $109 million of
project debt under the agreement to purchase the 160-megawatt natural gas-fired
cogeneration plant from Encogen Northwest L.P. Interest rates on the project
debt ranged from 8.64% to 13.03%. In February 2000, the Company used a portion
of the proceeds from the issuance of $225 million principal amount of Senior
Medium-Term notes to pay off the project debt.
27
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%.
On February 22, 2000, the Company issued $225 million principal amount of 7.96%
Senior Medium-Term Notes, Series B. The Notes are due February 22, 2010 and
proceeds were used to redeem the Encogen project debt and pay down a portion of
the Company's short-term debt.
In February 1999, the Company redeemed the remaining 203,006 outstanding
shares of Series B, Adjustable Rate Preferred Stock. In September 1999, the
Company redeemed $30 million 8.50% Series III Preferred Stock.
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 financing, 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, 1999, the Company could
issue either (i) approximately $867 million of additional first mortgage bonds,
(ii) approximately $712 million of additional preferred stock at an assumed
dividend rate of 7.3%, 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,
1999, the Company had available $375 million in lines of credit with various
banks, which provide credit support for outstanding commercial paper of $105.7
million, effectively reducing the available borrowing capacity under these lines
of credit to $269.3 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
$202 million at December 31, 1999.
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 annually between 1.0% to 1.5% depending on rate class on
January 1 of 1998 through 2000. Electric tariff rates for certain customers will
increase by 1.5% in 2001.
In September 1996, pursuant to a negotiated settlement with the
Washington Commission, the Company's PRAM was discontinued. PRAM accrued
revenues of $40.5 million, recorded at December 31, 1996, were recovered in the
first quarter of 1997. Overcollections 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.
On October 13, 1999, the Company received from the Washington Commission
an order regarding the accounting and ratemaking treatment of a proposed
Silicone Injection Program, which extends the life of treated underground cable
providing benefits to future periods. The order authorizes the Company to
capitalize the cost of the program and to depreciate the cost over the life of
the underground conductor. Therefore, this ratemaking treatment will more
closely match the cost of the program with the extended life of the treated
cables. The Company expects to spend between $20 and $30 million over the next
five years on the program.
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
approximately $2 million annually.
28
On October 27, 1999, the Washington Commission approved the Company's PGA
and deferral amortization (true-up) filings effective November 1, 1999. The PGA
filing allows the Company to recover an expected increase in annual gas costs
and the deferral amortization filing allows the Company to recover prior period
gas cost undercollections. The filings replaced the PGA and deferral
amortization refund that had been effective since April 1, 1998. As a result gas
rates to all sales customers increased by an average of 16.3% while rates for
gas transportation service as well as gas margins remained unchanged. (See Note
1 to the Consolidated Financial Statements for a description of the Company's
PGA mechanism.)
YEAR 2000 CONVERSION
Over the previous three years, the Company conducted an extensive program
to ensure the Company was ready for the Year 2000. The Company established a
central project team to coordinate all Year 2000 activities and identified
exposure in three categories: information technology; embedded chip technology;
and external noncompliance by customers and suppliers. The project team took a
phased approach in conducting the Year 2000 project for its internal systems. In
addition, a specialized embedded systems team was formed by the Company to
inventory, assess and remediate microprocessor technology in its generation,
transmission and distribution systems for both gas and electric operations.
Through December 31, 1999, the Company's total Year 2000 project costs
were approximately $13 million, exclusive of internal labor costs. Approximately
$3 million of these costs were capital costs. The Company does not anticipate
incurring any further costs related to the Year 2000 project. During the
rollover to the Year 2000 and to date, the Company has not experienced any
significant problems or interruptions to normal operations related to the Year
2000 issue.
Other
A power supply operating alliance between the Company and Duke Energy
Trading and Marketing ("DETM"), whereby the Company participated in the Western
market activities of DETM, was terminated effective May 31, 1999. Going forward
the Company will perform the functions of minimizing the cost of, and optimizing
the value inherent in, its core power supply portfolio. The Company augmented
its traditional supply management activities with an energy risk management and
hedging program.
In the second quarter of 1999, the Company sold its investment in the
common stock of Cabot Oil and Gas Corporation. The after-tax gain of $12.3
million was offset in part by the cost of ConneXt, a wholly-owned subsidiary,
exiting certain product lines.
In the third quarter of 1999, the Company sold the assets, liabilities
and trade name of its wholly-owned subsidiary, Homeguard Security Services, Inc.
The Company also sold in the third quarter of 1999 the majority of the gas
pipeline capacity rights and gas storage rights of Washington Energy Gas
Marketing ("WEGM", a wholly-owned subsidiary), in the United States and the
Province of Alberta, Canada.
In March 1998, the Company entered into an agreement with CellNet Data
Services Inc. ("CellNet") under which the Company would lend CellNet up to $35
million in the form of multiple draws so that CellNet can finance an Automated
Meter Reading (AMR) network system to be deployed in the Company's service
territory. The Company's promissory note with CellNet calls for the network
system to serve as collateral for the loan. The term of the loan is five years
after the first loan under the agreement is made to CellNet. The loan agreement
provides for interest only payments during the five year term, with the
principal due at the end of the five year term. In September 1999, the Company
announced it was expanding its AMR network system from 800,000 meters to
1,325,000 meters and as a result increased the authorized loan amount to $72
million. On June 30, 1999, the Company made the first loan under the loan
agreement and as of December 31, 1999, there were loans outstanding of $31.1
million. In February 2000, CellNet announced it would be acquired by a unit of
energy services firm Schlumberger Ltd. The acquisition will be handled through a
bankruptcy court filing and requires bankruptcy court approval. The Company does
not anticipate a change in its AMR project due to the reorganization of CellNet.
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
29
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
an average of between 15% and 20% over the 14 year period from 1998 through
2011, net of the costs of the restructuring payment.
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 owned
and operated a natural-gas fired cogeneration facility located at the Georgia
Pacific mill near Bellingham, Washington. The contract had obligated the Company
to pay fixed and escalating fees well above current and projected future market
prices through mid-2008 for the output of the plant. On November 1, 1999, the
Company purchased the 160 megawatt plant from Encogen. The Company paid $55
million in cash and assumed $109 million in debt to acquire the partnership,
which owned no significant assets other than the plant. Pursuant to an October
27, 1999 order from the Washington Commission approving the purchase, the
Company will depreciate the original owner's net book value of the plant over
the remaining 23 year useful life of the project. The difference between the
purchase price and the net book value of the plant (approximately $72.5 million)
will be amortized over 9 years (the remaining term of the power purchase
contract). The purchase is expected to reduce the net cost of power from the
co-generation project by approximately 17% annually.
In December 1999, the Company bought out the remaining 8.5 years of one
of the natural gas supply contracts serving Encogen from Cabot Oil & Gas
Corporation which provided approximately 60% of the plant's natural gas
requirements. The Company will become the replacement gas supplier to the
project for 60% of the supply under terms of the Cabot agreement and expects the
agreement will reduce this portion of gas costs by 5% to 15% annually. The
Washington Commission has issued an order creating a regulatory asset relating
to the $12 million payment that requires the Company to accrue carrying costs on
the unamortized balance over the first 3 years.
On November 2, 1998, the Company announced that 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. Completion of the
sale is contingent on acceptable regulatory treatment from the Washington
Commission. On September 30, 1999, the Washington Commission conditionally
approved the Colstrip sale, which at that time was fixed at $556 million. The
net book value of these assets and related regulatory assets is approximately
$464 million. After taxes and other costs, the Company expected to realize a
gain of approximately $37.6 million. However, the terms and conditions of the
Washington Commission order made the sale economically unattractive to the
Company. The Company appealed the Washington Commission's decision in December
1999. Pending the outcome of the appeal, the Company is working with various
parties to obtain other terms and conditions so the sale can proceed.
In May 1999, the eight partners, including the Company, in the Centralia
coal fired generating plant project announced the sale of the plant to TransAlta
Corporation of Calgary, Canada. The purchase price of the plant and the adjacent
mine (owned and operated by PacifiCorp) is $554 million. The Company owns a 7%
interest in the plant. The transaction is currently under review by the
Washington Commission.
SAFE HARBOR
The Company is including the following cautionary statement in this Form
10-K to make applicable and to take advantage of the safe harbor provisions of
the Private Securities Litigation Reform Act of 1995 for any forward-looking
statements made by, or on behalf of, the Company.
30
Any statements that express, or involve discussions as to expectations,
beliefs, plans, objectives, assumptions or future events or performance (often,
but not always, through the use of words or phrases such as "anticipates",
"believes", "estimates", "expects", "intends", "plans", "predicts", "projects",
"will likely result", "will continue", or similar expressions) are not
statements of historical facts and may be forward-looking.
Forward-looking statements involve risks and uncertainties which could
cause actual results or outcomes to differ materially from those expressed. The
Company's expectations, beliefs and projections are expressed in good faith and
are believed by the Company to have a reasonable basis, including without
limitation management's examination of historical operating trends, data
contained in the Company's records and other data available from third parties,
but there can be no assurance that the Company's expectations, beliefs or
projections will be achieved or accomplished.
In addition to other factors and matters discussed elsewhere herein, some
important factors that could cause actual results or outcomes for the Company to
differ materially from those discussed in forward-looking statements include:
- prevailing legislative developments, governmental policies and
regulatory actions with respect to allowed rates of return,
financings, or industry and rate structures
- weather and hydroelectric conditions
- effect of competition
- changes in and compliance with environmental and endangered species
laws and policies
- population growth rates and demographic patterns
- capital market conditions
- legal and regulatory proceedings
Any forward-looking statement speaks only as of the date on which such
statement is made, and the Company undertakes no obligation to update any
forward-looking statement to reflect events or circumstances after the date on
which such statement is made or to reflect the occurrence of unanticipated
events. New factors emerge from time to time and it is not possible for
management to predict all such factors, nor can it assess the impact of any such
factor on the business or the extent to which any factor, or combination of
factors, may cause results to differ materially from those contained in any
forward-looking statement.
31
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company is exposed to market risks, including changes in commodity
prices and interest rates.
Commodity Price Risk
The Company manages its energy supply portfolio to achieve three primary
objectives:
(i) Ensure that physical energy supplies are available to serve
retail customer requirements;
(ii) Manage portfolio risks to limit undesired impacts on Company
financial results; and
(iii) Optimize the value of the Company's energy supply assets.
The portfolio is subject to major sources of variability (e.g., hydro
generation, temperature-sensitive retail sales, and market prices for gas and
power supplies). At certain times, these sources of variability can mitigate
portfolio imbalances; at other times they can exacerbate portfolio imbalances.
Hedging strategies for the Company's energy supply portfolio interact
with portfolio optimization activities. Some hedges can be implemented in ways
that retain the Company's ability to use its energy supply portfolio to produce
additional value, other hedges can only be achieved by forgoing optimization
opportunities.
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, swaps
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.
Market risk is managed subject to parameters established by the Board of
Directors. A Risk Management Committee separate from the units that manage 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 risk of the Company primarily relates
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
three interest rate swaps were outstanding as of December 31, 1999. The carrying
amounts and fair values of the Company's fixed rate debt instruments are
described in Note 10 to the Consolidated Financial Statements.
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See index on page 38.
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 2000 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 38.
2) Exhibits - see index on page 74.
(b) Reports on Form 8-K:
The Company did not file any reports on Form 8-K during the
quarter ended December 31, 1999.
33
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PUGET SOUND ENERGY, INC.
William S. Weaver
------------------------
William S. Weaver
President and Chief Executive Officer
Date: March 3, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
- ------------------------------------------------------------------------------
William S. Weaver President, Chief Executive March 3, 2000
- -------------------------
(William S. Weaver) Officer and Director
Richard L. Hawley Vice President
- -------------------------
(Richard L. Hawley) and Chief Financial Officer
James W. Eldredge Corporate Secretary
- -------------------------
(James W. Eldredge) and Controller and
Chief Accounting Officer
Douglas P. Beighle Director
- -------------------------
(Douglas P. Beighle)
Charles W. Bingham Director
- -------------------------
(Charles W. Bingham)
Phyllis J. Campbell Director
- -------------------------
(Phyllis J. Campbell)
Craig W. Cole
- -------------------------
(Craig W. Cole) Director
34
SIGNATURE TITLE DATE
- ------------------------------------------------------------------------------
Donald J. Covey Director March 3, 2000
- -------------------------
(Donald J. Covey)
Robert L. Dryden Director
- -------------------------
(Robert L. Dryden)
Director
- -------------------------
(John D. Durbin)
John W. Ellis Director
- -------------------------
(John W. Ellis)
Daniel J. Evans Director
- -------------------------
(Daniel J. Evans)
Tomio Moriguchi Director
- -------------------------
(Tomio Moriguchi)
Sally G. Narodick Director
- -------------------------
(Sally G. Narodick)
35
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 accountants,
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.
William S. Weaver Richard L. Hawley 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)
36
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of Puget Sound Energy, Inc.:
In our opinion, the consolidated financial statements listed on page 38
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, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999, in conformity with accounting principles generally accepted in the
United States. In addition, in our opinion, the financial statement schedule
listed on page 38 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. We conducted our audits of
these financial statements in accordance with auditing standards generally
accepted in the United States 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 provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Seattle, Washington
February 10, 2000
37
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, 1999, 1998 and 1997 39
Consolidated Balance Sheets, December 31, 1999 and 1998 40-41
Consolidated Statements of Capitalization, December 31, 1999 and 1998 42
Consolidated Statements of Earnings Reinvested in the Business
for the years ended December 31, 1999, 1998 and 1997 43
Consolidated Statements of Comprehensive Income for the years
ended December 31, 1999, 1998 and 1997 43
Consolidated Statements of Cash Flows for the years
ended December 31, 1999, 1998 and 1997 44
Notes to Consolidated Financial Statements 45
Schedule:
II. Valuation and Qualifying Accounts and Reserves for the
years ended December 31, 1999, 1998 and 1997 73
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 74
38
Consolidated Statements of
INCOME
(for years ended December 31;
dollars in thousands,
except per share amounts) 1999 1998 1997
- --------------------------------------------------------------------------------------
Operating Revenues:
Electric $1,558,012 $1,475,208 $1,231,424
Gas 485,488 416,551 409,447
Other 23,130 32,097 40,657
- ---------------------------------------------------------------------------------------
Total operating revenues 2,066,630 1,923,856 1,681,528
- ---------------------------------------------------------------------------------------
Operating Expenses:
Energy costs:
Purchased electricity 780,162 752,148 614,929
Residential Exchange (39,000) (55,562) (71,970)
Purchased gas 220,009 175,805 179,287
Fuel 59,439 56,557 41,455
Utility operations and maintenance 240,645 231,636 244,072
Other operations and maintenance 22,387 30,102 33,919
Depreciation, depletion and amortization 175,710 165,587 161,865
Conservation amortization 7,841 6,199 7,318
Merger and related costs -- -- 55,789
Taxes other than federal income taxes 180,141 160,472 159,310
Federal income taxes 109,164 105,814 44,916
- ---------------------------------------------------------------------------------------
Total operating expenses 1,756,498 1,628,758 1,470,890
- ---------------------------------------------------------------------------------------
Operating Income 310,132 295,098 210,638
- ---------------------------------------------------------------------------------------
Other Income 25,819 13,182 33,398
- ---------------------------------------------------------------------------------------
Income Before Interest Charges 335,951 308,280 244,036
- ---------------------------------------------------------------------------------------
Interest Charges:
AFUDC (10,582) (7,580) (5,205)
Interest expense 160,966 146,248 123,543
- ---------------------------------------------------------------------------------------
Total interest charges 150,384 138,668 118,338
- ---------------------------------------------------------------------------------------
Income from Continuing Operations 185,567 169,612 125,698
Discontinued Operations:
Loss on disposal, net of tax -- -- (2,622)
- ---------------------------------------------------------------------------------------
Net Income 185,567 169,612 123,076
- ---------------------------------------------------------------------------------------
Less Preferred Stock Dividends Accrual 11,065 13,003 17,806
Preferred Stock Redemptions -- -- 471
- ---------------------------------------------------------------------------------------
Income for Common Stock $174,502 $156,609 $105,741
- ---------------------------------------------------------------------------------------
Common Shares Outstanding Weighted Average 84,613 84,561 84,560
- ---------------------------------------------------------------------------------------
Basic and Diluted Earnings (Loss)
Per Common Share:
From continuing operations $2.06 $1.85 $1.28
From discontinued operations -- -- (0.03)
- ---------------------------------------------------------------------------------------
Basic and diluted earnings per common share $2.06 $1.85 $1.25
- ---------------------------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
39
Consolidated Balance Sheets
ASSETS
(at December 31; dollars in thousands) 1999 1998
- --------------------------------------------------------------------------------
Utility Plant:
Electric plant $3,966,220 $3,640,647
Gas plant 1,371,589 1,278,275
Common plant 314,770 233,086
Less: Accumulated depreciation and amortization 1,901,658 1,721,096
- --------------------------------------------------------------------------------
Net utility plant 3,750,921 3,430,912
- --------------------------------------------------------------------------------
Other Property and Investments:
Investment in Bonneville Exchange Power Contract 61,716 70,537
Other 202,488 189,550
- --------------------------------------------------------------------------------
Total other property and investments 264,204 260,087
- --------------------------------------------------------------------------------
Current Assets:
Cash 65,707 28,216
- --------------------------------------------------------------------------------
Accounts receivable 214,523 190,658
Less: Allowance for doubtful accounts (1,503) (1,020)
- --------------------------------------------------------------------------------
Total accounts receivable 213,020 189,638
- --------------------------------------------------------------------------------
Unbilled revenues 121,303 126,740
Purchased gas receivable 33,700 5,492
Materials and supplies, at average cost 69,241 58,534
Prepayments and other 9,822 7,990
- --------------------------------------------------------------------------------
Total current assets 512,793 416,610
- --------------------------------------------------------------------------------
Long-Term Assets:
Regulatory asset for deferred income taxes 228,454 241,406
PURPA buyout costs 238,734 221,802
Other 150,500 138,870
- --------------------------------------------------------------------------------
Total long-term assets 617,688 602,078
- --------------------------------------------------------------------------------
Total Assets $5,145,606 $4,709,687
================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
40
Consolidated Balance Sheets
CAPITALIZATION AND LIABILITIES
(AT DECEMBER 31; DOLLARS IN THOUSANDS) 1999 1998
- --------------------------------------------------------------------------------
Capitalization:
(See "Consolidated Statements of Capitalization"):
Common equity $1,379,073 $1,352,680
Preferred stock not subject to mandatory
redemption 60,000 95,075
Preferred stock subject to mandatory redemption 65,662 73,162
Corporation obligated, mandatorily redeemable
preferred securities of subsidiary trust
holding solely junior subordinated debentures
of the corporation 100,000 100,000
Long-term debt 1,783,139 1,475,106
- --------------------------------------------------------------------------------
Total capitalization 3,387,874 3,096,023
- --------------------------------------------------------------------------------
Current Liabilities:
Accounts payable 178,218 163,141
Short-term debt 604,712 450,905
Current maturities of long-term debt 47,620 107,000
Accrued expenses:
Taxes 72,688 59,764
Salaries and wages 18,023 18,650
Interest 43,955 39,062
Other 24,129 23,150
- --------------------------------------------------------------------------------
Total current liabilities 989,345 861,672
- --------------------------------------------------------------------------------
Deferred Income Taxes 636,735 628,554
- --------------------------------------------------------------------------------
Other Deferred Credits 131,652 123,438
- --------------------------------------------------------------------------------
Commitments and Contingencies -- --
- --------------------------------------------------------------------------------
Total Capitalization and Liabilities $5,145,606 $4,709,687
================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
41
Consolidated Statements of
CAPITALIZATION
(at December 31; dollars in thousands) 1999 1998
- -----------------------------------------------------------------------------------------------
Common Equity:
Common stock ($10 stated value) - 150,000,000 shares
authorized, 84,922,405 and 84,560,561 shares outstanding $849,224 $845,606
Additional paid-in capital 454,982 450,724
Earnings reinvested in the business 66,019 47,548
Accumulated other comprehensive income - net 8,848 8,802
- -----------------------------------------------------------------------------------------------
Total common equity 1,379,073 1,352,680
- -----------------------------------------------------------------------------------------------
Preferred Stock Not Subject to Mandatory Redemption -
cumulative - $25 par value:* Adjustable Rate,
Series B - 2,000,000 shares
authorized, 0 and 203,006 shares outstanding -- 5,075
7.45% series II - 2,400,000 shares authorized and outstanding 60,000 60,000
8.50% series III - 1,200,000 shares authorized, 0
and 1,200,000 shares outstanding -- 30,000
- -----------------------------------------------------------------------------------------------
Total preferred stock not subject to mandatory redemption 60,000 95,075
- -----------------------------------------------------------------------------------------------
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
7.75% series - 750,000 shares authorized, 637,500 and
712,500 shares outstanding 63,750 71,250
- -----------------------------------------------------------------------------------------------
Total preferred stock subject to mandatory redemption 65,662 73,162
- -----------------------------------------------------------------------------------------------
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 1,563,000 1,420,000
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 105,980 370
Unamortized discount - net of premium (81) (124)
Long-term debt due within one year (47,620) (107,000)
- -----------------------------------------------------------------------------------------------
Total long-term debt excluding current maturities 1,783,139 1,475,106
- -----------------------------------------------------------------------------------------------
Total Capitalization $3,387,874 $3,096,023
- -----------------------------------------------------------------------------------------------
* 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.
42
Consolidated Statements of
EARNINGS REINVESTED
(for years ended December 31;
dollars in thousands,
except per share amounts) 1999 1998 1997
- ----------------------------------------------------------------------------------------
Balance at Beginning of Year $ 47,548 $ 46,672 $ 86,355
Net Income 185,567 169,612 123,076
Adjustment to conform fiscal year of WECo -- -- 10,835
- ----------------------------------------------------------------------------------------
Total 233,115 216,284 220,266
- ----------------------------------------------------------------------------------------
Deductions:
Dividends declared:
Preferred stock:
Adjustable Rate Series B 38 272 2,010
$1.86 per share on 7.45% series II 4,470 4,470 4,470
$2.13 per share on 8.50% series III 1,700 2,550 2,550
$4.84 per share on 4.84% series 72 72 192
$4.70 per share on 4.70% series 20 20 203
$8.00 per share on 8% series -- 25 122
$7.75 per share on 7.75% series 5,086 5,667 5,813
$1.97 per share on 7.875% series -- -- 3,940
Common Stock 155,591 155,591 150,591
Preferred stock redemptions 119 69 3,703
- ----------------------------------------------------------------------------------------
Total deductions 167,096 168,736 173,594
- ----------------------------------------------------------------------------------------
Balance at End of Year $ 66,019 $ 47,548 $46,672
- ----------------------------------------------------------------------------------------
Dividends Declared Per Common Share $1.84 $1.84 $1.78
- ----------------------------------------------------------------------------------------
Consolidated Statements of
COMPREHENSIVE INCOME
(for years ended December 31;
dollars in thousands) 1999 1998 1997
- ---------------------------------------------------------------------------------------
Net Income $185,567 $169,612 $123,076
Other comprehensive income, net of tax:
Unrealized holding gains (losses) on
available for sale securities 12,330 (6,152) 14,954
Reclassification adjustment for gains
included in net income (12,284) -- --
- ---------------------------------------------------------------------------------------
Other comprehensive income 46 (6,152) 14,954
- ---------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------
Comprehensive Income $185,613 $163,460 $138,030
- ---------------------------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
43
Consolidated Statements of
CASH FLOW
(for years ended December 31;
dollars in thousands) 1999 1998 1997
- --------------------------------------------------------------------------------------------------
Operating Activities:
Income from continuing operations $185,567 $169,612 $125,698
Adjustments to reconcile income from continuing
operations to net cash provided by operating activities
Depreciation and amortization 175,710 165,587 161,865
Deferred income taxes and tax credits - net 21,133 16,560 27,422
Gain from sale of investment in Cabot common stock (18,899) -- --
Gain from sale of investment in HomeGuard Security S (11,659) -- --
PRAM accrued revenues - net -- -- 40,777
Pretax write-down and equity in undistributed losses
unconsolidated affiliate -- -- 4,044
PURPA buyout costs (12,000) -- (215,000)
Other (including conservation amortization) (3,708) (14,321) 49,278
Change in certain current assets and liabilities (25,446) (23,106) (61,364)
- ---------------------------------------------------------------------------------------------------
Net cash provided by operating activities 310,698 314,332 132,720
- ---------------------------------------------------------------------------------------------------
Investing Activities:
Construction expenditures - excluding equity AFUDC (330,976) (335,471) (257,900)
Energy conservation expenditures (5,583) (6,745) (4,864)
Proceeds from sale of investment in Cabot common stock 37,353 -- --
Proceeds from sale of HomeGuard Security Services 13,399 -- --
Purchase of Encogen (55,000) -- --
Loans to CellNet Data Services (31,075) -- --
Cash received from sale of conservation assets - net -- -- 34,372
Other 9,001 8,844 24,716
- ---------------------------------------------------------------------------------------------------
Net cash used by investing activities (362,881) (333,372) (203,676)
- ---------------------------------------------------------------------------------------------------
Financing Activities:
Increase in short-term debt - net 153,807 78,367 85,975
Dividends paid (160,067) (168,667) (169,892)
Issuance of common stock 1,136 -- 65
Issuance of company obligated, mandatorily redeemable
preferred securities -- -- 100,000
Redemption of preferred stock (42,575) (5,454) (128,747)
Issuance of bonds 250,000 200,000 300,000
Redemption of bonds and notes (110,370) (81,093) (103,415)
Other (2,257) 13,374 (4,572)
- ---------------------------------------------------------------------------------------------------
Net cash provided by financing activities 89,674 36,527 79,414
- ------------------------------------------------------------------------ ------------ -------------
Increase in cash from continuing operations 37,491 17,487 8,458
Decrease in cash from discontinued operations:
Investing activities -- -- (2,622)
- ---------------------------------------------------------------------------------------------------
Net Increase in Cash 37,491 17,487 5,836
Cash at Beginning of Year 28,216 10,729 4,854
Adjustment to conform fiscal year of WECo -- -- 39
- ---------------------------------------------------------------------------------------------------
Cash at End of Year $65,707 $28,216 $10,729
- ---------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
44
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 was
structured as a tax-free exchange of shares, and is accounted for as a pooling
of interests for financial statement purposes
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. Certain reclassifications have
been made to the prior year financial statements to conform to the current
year's presentation with no material effect on consolidated net income, total
assets or common equity.
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.
45
Net regulatory assets and liabilities at December 31, 1999 and 1998,
included the following:
(DOLLARS IN MILLIONS) 1999 1998
- ----------------------------------------------------------------------------
Deferred income taxes $228.5 $241.4
PURPA electric energy supply contract buyout costs 238.7 221.8
Investment in BEP Exchange Contract 61.7 70.5
Unamortized energy conservation charges 4.6 7.1
Storm damage costs - electric 31.2 34.6
Purchased gas receivable 33.7 5.5
Deferred AFUDC 25.0 21.6
Various other costs 50.3 49.2
Deferred gains on property sales (17.1) (17.2)
- ----------------------------------------------------------------------------
Total $656.6 $634.5
- ----------------------------------------------------------------------------
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") has issued its Consensus 97-4 which addresses 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. The EITF states that Statement No. 71 shall 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.
Although discussions with regulatory authorities regarding retail
competition have occurred and are expected to continue, no transition to
competition plans for the Company's regulated operations have been proposed. The
Company's financial statements continue to apply Statement No. 71 for regulated
operations.
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 was recovered in rates over
the ten years ended December 31, 1999, 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 regulatory assets of approximately $239 million related
to the buyout of purchased power and gas sales contracts of two non-utility
generation projects. Washington Commission accounting orders have approved the
payments for deferral and collection in rates over the remaining life of the
energy supply contracts. Under terms of the orders, the Company is allowed to
accrue as an additional regulatory asset certain carrying costs of the deferred
balances.
46
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.
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 1999, 1998 and 1997 and
for depreciable gas utility plant was 3.4% in 1999,1998 and 1997.
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 1999, 1998 and 1997. 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:
$4,262,000 for 1999, $3,409,000 for 1998 and $2,704,000 for 1997. The deferred
asset is being amortized over the average useful life of the Company's
non-project utility plant.
47
PERIODIC RATE ADJUSTMENT MECHANISM
In April 1991, the Washington Commission issued an order establishing a
Periodic Rate Adjustment Mechanism ("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.
In September 1996, pursuant to a negotiated settlement with the
Washington Commission, the PRAM was discontinued. 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 an
electric 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 gas
transportation contracts 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 1999 and 1998 were approximately $7.2 million and $1.1 million, respectively,
while customers received approximately $11.3 and $2.0 million, respectively.
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 proceeds, net of transactional costs, 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.
48
ENERGY RISK MANAGEMENT
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 wholesale customers 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 risk management function manages the
Company's core electric and gas supply portfolios.
The Company manages its energy supply portfolio to achieve three primary
objectives:
(i) Ensure that physical energy supplies are available to serve
retail customer requirements;
(ii) Manage portfolio risks to limit undesired impacts on Company
financial results; and
(iii) Optimize the value of the Company's energy supply assets.
The Company enters into futures and options for the purpose of hedging
commodity price risk. 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.
During the first quarter of 1999, the Company adopted Issue 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk management
Activities" ("EITF 98-10") issued by the Emerging Issues Task Force of the
Financial Accounting Standards Board ("FASB"). EITF 98-10 addresses accounting
for the purchase and sale of energy trading contracts and is effective for
fiscal years beginning after December 15, 1998. The conclusion reached by the
EITF was that such contracts should be recorded at fair value when entered into
for trading activities with the mark-to-market gains or losses recorded in
current earnings. The Company does not consider its current operations to meet
the definition of trading activities as described by EITF 98-10. Accordingly,
the adoption of EITF 98-10 did not have an impact on the Company's 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"). In July 1999, the FASB issued Statement of Financial
Accounting Standards No. 137 which delayed the effective date of Statement No.
133 for one year, to fiscal years beginning after June 15, 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.
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 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 was adopted by the Company in the first quarter of 1999.
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. Adoption of SOP 98-5 did not have a material
impact on the Company's financial position or results of operations.
EARNINGS PER COMMON SHARE
Basic earnings per common share have been computed based on weighted
average common shares outstanding of 84,613,000, 84,561,000 and 84,560,000 for
1999, 1998 and 1997, respectively. Diluted earnings per common share have been
computed based on weighted average common shares outstanding of 84,847,000,
84,768,000 and 84,628,000 for 1999, 1998 and 1997, respectively, which include
the dilutive effect of securities related to employee compensation plans.
49
NOTE 2.
UTILITY PLANT
Utility plant at December 31, 1999 and 1998 included the following:
December 31 (dollars in thousands) 1999 1998
- ------------------------------------------------------------------------------
Electric, gas and common utility plant
classified by prescribed accounts at
original cost:
Distribution plant $2,970,643 $2,794,906
Production plant 1,116,351 943,808
Transmission plant 666,318 641,526
General plant 383,075 375,612
Construction work in progress 311,317 266,242
Plant acquisition adjustment 72,495 --
Intangible plant 103,276 99,776
Underground storage 14,801 16,307
Plant held for future use 9,755 9,016
Other 4,548 4,815
Less accumulated provision for depreciation 1,901,658 1,721,096
- ------------------------------------------------------------------------------
Net utility plant $3,750,921 $3,430,912
- ------------------------------------------------------------------------------
On November 1, 1999, the Company purchased a 160 megawatt natural
gas-fired cogeneration plant from Encogen Northwest L.P. for $164 million.
Pursuant to an October 27, 1999 order from the Washington Commission approving
the purchase, the Company will depreciate the original owner's net book value of
the plant over the remaining 23 year useful life of the project. The difference
between the purchase price and the net book value of the plant (approximately
$72.5 million) will be amortized over 9 years.
In December 1999, the Company bought out the remaining 8.5 years of one
of the natural gas supply contracts serving Encogen from Cabot Oil & Gas
Corporation which provided approximately 60% of the plant's natural gas
requirements. The Company will become the replacement gas supplier to the
project for 60% of the supply under terms of the Cabot Agreement. The Washington
Commission has issued an order creating a regulatory asset relating to the $12
million payment that requires the Company to accrue carrying costs on the
unamortized balance over the first 3 years.
50
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, 1997 8,600,000 878,395 84,511,245
- --------------------------------------------------- -------------------- ----------------- --------------------
Issued to Shareholders Under the Stock Purchase
and Dividend Reinvestment Plan:
1997 -- -- 33,930
1999 -- -- 361,944
- --------------------------------------------------- -------------------- ----------------- --------------------
Issued Pursuant to Employee Compensation Plans:
1997 -- -- 17,063
- --------------------------------------------------- -------------------- ----------------- --------------------
Acquired for Sinking Fund:
1997 -- (12,050) --
1998 -- (49,500) --
1999 -- (75,000) --
- --------------------------------------------------- -------------------- --------------------------------------
Called for Redemption and Canceled:
1997 (4,780,494) (85,002) --
1998 (16,500) (224) --
1999 (1,403,006) -- --
- --------------------------------------------------- --------------------- ---------------- --------------------
Fractional Share Redemptions in Connection with
Merger Exchange:
1997 -- -- (1,593)
1998 -- -- (84)
1999 -- -- (100)
- --------------------------------------------------- -------------------- ----------------- --------------------
Shares outstanding December 31, 1999 2,400,000 656,619 84,922,405
- --------------------------------------------------- -------------------- ----------------- --------------------
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.
51
The weighted average dividend rate for the Adjustable Rate Cumulative
Preferred Stock ("ARPS"), Series B ($25 par value) was 4.23% for 1999, 4.83% for
1998 and 5.61% for 1997. 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% Series Preferred was redeemed at par plus accrued dividends on September
1, 1999. The 7.45% Series Preferred may be redeemed at par on or after November
1, 2003.
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, 1999, there were 33,192 shares
of the 4.84% Series and 49,689 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 $104.13 per share
plus accrued dividends through February 15, 2000, and at per share amounts which
decline annually to a price of $100 after February 15, 2007.
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.
52
NOTE 6.
ADDITIONAL PAID-IN CAPITAL
The changes in Additional Paid-in Capital are as follows:
(dollars in thousands) 1999 1998 1997
- -------------------------------------------------------------------------------
Balance at beginning of year $450,724 $450,845 $446,910
Excess of proceeds over stated values of
common stock issued 4,198 -- 428
Par value over cost of reacquired
preferred stock -- -- 471
Retained earnings adjustment for
preferred redemption 150 -- 3,036
Issue costs and other expenses (90) (121) --
- -------------------------------------------------------------------------------
Balance at end of year $454,982 $450,724 $450,845
- -------------------------------------------------------------------------------
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 $202 million at December 31, 1999.
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.)
53
NOTE 8.
LONG-TERM DEBT
FIRST MORTGAGE BONDS AND SENIOR NOTES
(at December 31; dollars in thousands):
SERIES DUE 1999 1998
- -----------------------------------------------------------------------
6.50% 1999 -- $ 16,500
6.65% 1999 -- 10,000
6.41% 1999 -- 20,500
7.08% 1999 -- 10,000
7.25% 1999 -- 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
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
6.46% 2009 150,000 --
7.12% 2010 7,000 7,000
8.59% 2012 5,000 5,000
8.20% 2012 30,000 30,000
54
SERIES DUE 1999 1998
- -----------------------------------------------------------------------
6.83% & 6.90% 2013 13,000 13,000
7.35 & 7.36% 2015 12,000 12,000
6.74% 2018 200,000 200,000
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
7.00% 2029 100,000 --
- ---------------------------- --------------------- --------------------
Total $1,563,000 $1,420,000
- ---------------------------- --------------------- --------------------
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%.
On February 22, 2000, the Company issued $225 million principal amount of 7.96%
Senior Medium-Term Notes, Series B. The Notes are due February 22, 2010 and
proceeds were used to redeem the Encogen project debt and pay down a portion of
the Company's short-term debt.
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%.
PROJECT DEBT
On November 1, 1999, the Company assumed approximately $109 million of
project debt under the agreement to purchase the 160-megawatt natural gas-fired
cogeneration plant from Encogen Northwest L.P. Interest rates on the project
debt ranged from 8.64% to 13.03%. In February 2000, the Company used a portion
of the proceeds from the issuance of $225 million principal amount of Senior
Medium-Term notes to pay off the project debt. At December 31, 1999, the project
debt was included in Other notes.
LONG-TERM DEBT MATURITIES
The principal amounts of long-term debt maturities for the next five
years are as follows:
(DOLLARS IN THOUSANDS) 2000 2001 2002 2003 2004
-------------------------------------------------------------------------------
Maturities of:
Long-term debt $ 35,000 $ 19,000 $117,000 $ 72,000 $ 98,500
55
NOTE 9.
SHORT-TERM DEBT AND OTHER FINANCING ARRANGEMENTS
At December 31, 1999, 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) 1999 1998 1997
----------------------------------------------------------------------------
Short-term borrowings outstanding:
Commercial paper notes $105,712 $142,105 $124,538
Bank line of credit borrowing -- $25,000 $215,000
Uncommitted bank borrowings $499,000 $283,800 $33,000
Weighted average interest rate 6.59% 5.90% 6.88%
Credit availability (1) $375,000 $375,000 $375,000
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 debt. One agreement outstanding at December 31, 1999, 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. Two other
agreements outstanding at December 31, 1999, effectively change the Company's
interest rate on outstanding commercial paper to 7.39% on a notional principal
amount of $53.0 million expiring June 29, 2007.
___________________________
(1) Provides liquidity support for outstanding commercial paper and
borrowing from credit line banks in the amount of $105.7 million, $167.1 million
and $339.5 million for 1999, 1998 and 1997 respectively, effectively reducing
the available borrowing capacity under these credit lines to $269.3 million,
$207.9 million and $35.5 million, respectively.
56
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, 1999 and 1998:
1999 1999 1998 1998
CARRYING FAIR CARRYING FAIR
(DOLLARS IN MILLIONS) AMOUNT VALUE AMOUNT VALUE
- --------------------------------------------- ------------- ------------ ------------ -----------
Financial Assets:
Cash $ 65.7 $ 65.7 $ 28.2 $ 28.2
Cabot preferred stock $ 51.6 $ 51.6 $ 51.6 $ 51.6
Equity securities (1) $ 13.7 $ 13.7 $40.0 $40.0
Notes receivable $ 31.1 $ 31.1 -- --
Financial Liabilities:
Short-term debt $604.7 $604.7 $450.9 $450.9
Preferred stock subject to
mandatory redemption $ 65.7 $ 65.2 $ 73.2 $ 75.8
Corporation obligated, mandatorily
redeemable preferred securities of
subsidiary trust holding solely
junior subordinated debentures of
the corporation $100.0 $ 91.8 $100.0 $109.3
Long-term debt $1,724.8 $1,618.3 $1,582.1 $1,686.4
Project debt $106.0 $109.4 -- --
Unrecognized Financial Instruments:
Interest rate swaps -- $ (0.6) -- $(1.3)
- --------------------------------------------- ------------- ------------ ------------ -----------
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.
_______________________________
(1) 1999 carrying amount includes an adjustment of $13.5 million to report
the available-for-sale securities at market value. This amount has been included
as a component of other comprehensive income net of deferred taxes of $4.7
million.
57
NOTE 11.
SUPPLEMENTARY INCOME STATEMENT INFORMATION
(dollars in thousands) 1999 1998 1997
- --------------------------------------------------------------------------------
Taxes:
Real estate and personal property $ 48,036 $ 40,422 $ 46,252
State business 70,047 62,855 58,466
Municipal, occupational and other 52,739 48,090 45,252
Other 19,445 20,010 21,242
- --------------------------------------------------------------------------------
Total taxes $190,267 $171,377 $171,212
- --------------------------------------------------------------------------------
Charged to:
Operating expense $180,141 $160,472 $159,310
Other accounts, including
construction work in progress 10,126 10,905 11,902
- --------------------------------------------------------------------------------
Total taxes $190,267 $171,377 $171,212
- --------------------------------------------------------------------------------
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, 1999,
1998 and 1997, were approximately $19,179,000, $ 17,798,000 and $19,428,000,
respectively. Payments due for the years ended December 31, 1999, 1998 and 1997,
for the sublease of properties were approximately $2,321,000, $1,242,000, and
$962,000, respectively.
Future minimum lease payments for noncancelable leases are approximately
$16,459,000 for 2000, $14,621,000 for 2001, $14,210,000 for 2002, $12,019,000
for 2003, $7,854,000 for 2004 and in the aggregate, $9,252,000 thereafter.
Future minimum sublease receipts for noncancelable subleases are $2,025,000 for
2000, $2,025,000 for 2001, $2,025,000 for 2002, $2,025,000 for 2003, $3,000 for
2004 and in the aggregate, $3,000 thereafter.
58
NOTE 13.
FEDERAL INCOME TAXES
The details of federal income taxes ("FIT") are as follows:
(dollars in thousands) 1999 1998 1997
- --------------------------------------------------------------------------------
Charged to Operating Expense:
Current $94,516 $88,606 $ 28,863
Deferred - net 15,373 17,948 16,677
Deferred investment tax credits (725) (740) (624)
- --------------------------------------------------------------------------------
Total FIT charged to operations 109,164 105,814 44,916
- --------------------------------------------------------------------------------
Charged to Miscellaneous Income:
Current (1,665) 4,634 16,709
Deferred - net 4,574 (648) (1,902)
- --------------------------------------------------------------------------------
Total FIT charged to miscellaneous income 2,909 3,986 14,807
- --------------------------------------------------------------------------------
Credited to discontinued operations -- -- (1,412)
- --------------------------------------------------------------------------------
Total FIT $112,073 $109,800 $ 58,311
- --------------------------------------------------------------------------------
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) 1999 1998 1997
- --------------------------------------------------------------------------------
FIT at the statutory rate $104,174 $97,794 $63,485
- --------------------------------------------------------------------------------
Increase (Decrease):
Depreciation expense deducted in the
financial statements in excess of tax
depreciation, net of depreciation
treated as a temporary difference 8,678 7,756 7,019
AFUDC included in income in the financial
statements but excluded from taxable income (4,345) (3,953) (2,774)
Accelerated benefit on early retirement
of depreciable assets (812) (1,241) (805)
Investment tax credit amortization (725) (740) (624)
Energy conservation expenditures - net 13,434 12,754 11,028
Conservation Settlement -- -- (26,197)
Prior period adjustment/Audit adjustment -- -- (37)
Other - net (8,331) (2,570) 7,216
- --------------------------------------------------------------------------------
Total FIT $112,073 $109,800 $58,311
- --------------------------------------------------------------------------------
Effective tax rate 37.7% 39.3% 32.1%
- --------------------------------------------------------------------------------
59
The following are the principal components of FIT as reported:
(dollars in thousands) 1999 1998 1997
- --------------------------------------------------------------------------------
Current FIT $92,851 $93,240 $45,572
- --------------------------------------------------------------------------------
Deferred FIT - other:
Conservation tax settlement 2,927 3,257 14,404
Periodic rate adjustment mechanism (PRAM) -- 107 (14,272)
Deferred taxes related to insurance reserves (1,225) (1,224) (2,768)
Reversal of Statement No. 90 present
value adjustments 92 255 408
Residential Purchase and Sale Agreement - net -- 3,441 (6,047)
Normalized tax benefits of the
accelerated cost recovery system 14,452 20,118 22,575
Energy conservation program (983) (2,437) 5,101
Environmental remediation 947 (2,946) (3,092)
WNP 3 tax settlement (826) (826) 21,360
Merger costs 409 42 (7,322)
Demand charges 14 3,273 (3,558)
Other 4,140 (5,760) (12,014)
- ---------------------------------------------------------------------------------
Total deferred FIT - other 19,947 17,300 14,775
- --------------------------------------------------------------------------------
Deferred investment tax credits -
net of amortization (725) (740) (624)
Credited to discontinued operations -- (1,412)
- --------------------------------------------------------------------------------
Total FIT $112,073 $109,800 $58,311
- --------------------------------------------------------------------------------
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 rate making 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, 1999, the balance of this asset is $228.5
million.
60
The deferred tax liability at December 31, 1999 and 1998, is comprised of
amounts related to the following types of temporary differences
(dollars in thousands) 1999 1998
- ----------------------------------------------------------------------
Utility plant $574,064 $567,642
Investment in Cabot stock 10,635 13,435
Energy conservation charges 41,833 57,919
Contributions in aid of construction (33,927) (31,874)
Bonneville Exchange Power 22,618 26,513
Cabot Gas Contract Purchase 4,200 --
Other 17,312 (5,081)
- ----------------------------------------------------------------------
Total $636,735 $628,554
- ----------------------------------------------------------------------
The totals of $636.7 million and $628.6 million for 1999 and 1998 consist
of deferred tax liabilities of $719.7 million and $712.2 million net of deferred
tax assets of $83.0 million and $83.6 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.
PENSION BENEFITS OTHER BENEFITS
(dollars in thousands) 1999 1998 1999 1998
------------------------ -----------------------
Change in benefit obligation:
Benefit obligation at beginning of year $352,422 $325,063 $29,438 $27,433
Service cost 9,259 8,550 245 229
Interest cost 24,181 22,862 1,868 1,985
Amendments 500 2,540 -- --
Actuarial (gain)/loss (14,548) 15,272 (3,600) 1,896
Benefits paid (22,654) (21,865) (1,948) (2,105)
- ----------------------------------------------------------------------------- -----------------------
Benefit obligation at end of year $349,160 $352,422 $26,003 $29,438
- ----------------------------------------------------------------------------- -----------------------
Change in plan assets:
Fair value of plan assets at beginning of year $464,195 $415,270 $14,132 $14,445
Actual return on plan assets 82,300 67,544 740 570
Employer contribution 986 3,246 1,814 1,222
Benefits paid (22,654) (21,865) (1,948) (2,105)
- ----------------------------------------------------------------------------- -----------------------
Fair value of plan assets at end of year $524,827 $464,195 $14,738 $14,132
- ----------------------------------------------------------------------------- -----------------------
61
(continued from previous page)
PENSION BENEFITS OTHER BENEFITS
(dollars in thousands) 1999 1998 1999 1998
------------------------ ----------------------
Funded status $175,667 $111,773 $(11,265) $(15,306)
Unrecognized actuarial gain (189,609) (133,189) (4,870) (1,532)
Unrecognized prior service cost 22,218 25,510 (429) (463)
Unrecognized net initial (asset)/obligation (6,333) (7,563) 8,148 8,775
- ------------------------------------------------------------------------------ -----------------------
Net amount recognized $1,943 $(3,469) $(8,416) $(8,526)
- ------------------------------------------------------------------------------ -----------------------
Amounts recognized on statement of
financial position consist of:
Prepaid benefit cost $17,698 $8,900 $(8,416) $(8,526)
Accrued benefit liability (23,670) (22,988) -- --
Intangible asset 7,915 10,619 -- --
- ------------------------------------------------------------------------------ -----------------------
Net amount recognized $1,943 $(3,469) $(8,416) $(8,526)
- ------------------------------------------------------------------------------ -----------------------
In accounting for pension and other benefits costs under the plans, the
following weighted average actuarial assumptions were used:
PENSION BENEFITS OTHER BENEFITS
1999 1998 1997 1999 1998 1997
------------ ---------- ----------- --------- ------------ ------------
Discount rate 7.5% 7% 7.25-7.5% 7.5% 7% 7.25%
Return on plan assets 9.75% 9.75% 9% 6-8.5% 6-8.5% 6-8.5%
Rate of compensation increase 5% 5% 5% -- -- --
Medical trend rate -- -- -- 7% 7.5% 7.5%
- ---------------------------------------- ------------ ---------- ----------- --------- ------------ ------------
PENSION BENEFITS OTHER BENEFITS
1999 1998 1997 1999 1998 1997
------------ ----------- ---------- --------- ------------ ---------
Components of net periodic
benefit cost:
(dollars in thousands)
Service cost $9,259 $8,550 $8,268 $245 $229 $216
Interest cost 24,180 22,862 21,412 1,868 1,985 1,895
Expected return on plan assets (37,310) (33,744) (27,997) (857) (867) (821)
Amortization of prior service cost 3,330 3,330 2,247 (34) (34) (34)
Recognized net actuarial gain (3,117) (3,180) (1,144) (145) (97) (204)
Amortization of transition (1,230) (1,230) (1,095) 627 627 627
(asset)/obligation
Special recognition of prior service 462 -- -- -- -- --
costs
Plan curtailments, mergers -- -- 5,138 -- -- 4,712
- ---------------------------------------- ------------ ------------- ---------- --------- ------------ ---------
Net pension benefit cost (4,426) (3,412) 6,829 1,704 1,843 6,391
Regulatory adjustment 932 1,263 1,263 -- -- --
- ---------------------------------------- ------------- ------------ -------- --------- ------------ ---------
Net periodic benefit cost $(3,494) $(2,149) $8,092 $1,704 $1,843 $6,391
- ---------------------------------------- ------------- ------------ -------- --------- ------------ ---------
62
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 $29 million, $23.7 million, and $0,
respectively, as of December 31, 1999.
The assumed medical inflation rate is 7% in 1999 decreasing to 6% in
2003. A 1% change in the assumed medical inflation rate would have the following
effects:
1999 1998
1% 1% 1% 1%
(DOLLARS IN THOUSANDS) INCREASE DECREASE INCREASE DECREASE
------------------------------- -----------------------------
Effect on service and interest cost $596 $(579) $690 $(671)
components
Effect on postretirement benefit obligation $ 40 $ (39) $ 45 $(44)
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 loss under Statement No. 106 for 1997 of $4.7 million. 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
$7,123,400, $6,532,400 and $5,000,200 for the years 1999, 1998 and 1997,
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, 1999. 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 during 1999 was 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.
Effective with the beginning of the next offering period on January 1, 2000, the
option price will be 85% 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 $88,900, $98,200 and $97,600 for
1999, 1998 and 1997, respectively.
On February 1, 1998, the Company granted 50 performance shares to 2,800
eligible employees in recognition of their efforts to implement the Company's
strategies. On February 1, 2000, those performance shares and dividend
equivalents were converted to common stock. Total cost of the performance share
grant program was $4,053,400.
63
NOTE 16.
OTHER INVESTMENTS
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. For 1998, the
investment in Cabot common stock was classified as an available-for-sale
security and was reported at its fair value of $31,995,000. The unrealized gain
of $8,802,000 (net of deferred taxes of $4,739,000) was included as a separate
component of common equity. In May 1999, the Company sold the 2,133,000 shares
of common stock and recorded an after-tax gain of $12.3 million. At the time of
the sale, the fair value of the stock was $37,350,000, resulting in an increase
of $3,483,000 in the unrealized gain. This amount has been included as a
component of other comprehensive income, net of deferred taxes of $1,875,000.
The $12.3 million realized gain on the sale has been reclassified out of
accumulated other comprehensive income. 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, 1999. The Company has an agreement that Cabot, subject to certain
conditions, will repurchase all shares of the preferred stock by November 1,
2000. 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 from Cabot was
$948,000 for 1997. 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.
In March 1998, the Company entered into an agreement with CellNet Data
Services Inc. ("CellNet") under which the Company would lend CellNet up to $35
million in the form of multiple draws so that CellNet can finance an Automated
Meter Reading (AMR) network system to be deployed in the Company's service
territory. In September 1999, the Company announced it was expanding its AMR
network system from 800,000 meters to 1,325,000 meters and as a result increased
the authorized loan amount to $72 million. On June 30, 1999, the Company made
the first loan under the loan agreement and as of December 31, 1999, there were
loans outstanding of $31.1 million.
NOTE 17.
COMMITMENTS AND CONTINGENCIES
COMMITMENTS - ELECTRIC
For the twelve months ended December 31, 1999, approximately 23.2% of the
Company's energy output was obtained at an average cost of approximately 9.4
mills per KWH through long-term contracts with several of the Washington public
utility districts ("PUDs") owning 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, 1999, the Company was entitled to purchase portions of
the power output of the PUDs' projects as set forth in the following tabulation:
64
BONDS COMPANY'S ANNUAL AMOUNT
OUTSTANDING PURCHASABLE (APPROXIMATE)
-------------------------------------------------
CONTRACT LICENSE (1) 12/31/99 (2) % OF MEGAWATT COSTS (3)
PROJECT EXP. DATE EXP. DATE (MILLIONS) OUTPUT CAPACITY (MILLIONS)
- ------------------------- --------------- ------------- ----------------- ---------------- ----------------- --------------
Rock Island
Original units 2012 2029 83.5 52.4 478 $40.7
Additional units 2012 2029 331.7 100.0 -- --
Rocky Reach 2011 2006 265.6 38.9 505 22.6
Wells 2018 2012 182.9 31.3 261 9.6
Priest Rapids 2005 2005 169.1 8.0 72 2.0
Wanapum 2009 2005 186.3 10.8 98 3.4
----------------- --------------
Total 1,414 $78.3
The Company's estimated payments for power purchases from the Columbia
River projects are $81 million for 2000, $80 million for 2001, $80 million for
2002, $78 million for 2003, $76 million for 2004 and in the aggregate, $605
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 $155 million for 2000, $150 million for 2001, $141
million for 2002, $130 million for 2003, $77 million for 2004 and in the
aggregate, $707 million 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
four 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 four contracts are $181 million for 2000, $204 million for 2001, $206
million for 2002, $207 million for 2003, $213 million for 2004 and in the
aggregate, $1.5 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.
____________________________
(1) 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.
(2) 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: 40.8% at Rock Island; 45.7% at Rocky Reach; 81.3% at Priest
Rapids; and 49.7% at Wanapum; and 5.1% at Wells.
(3) The components of 1999 costs associated with the interest portion of
debt service are: Rock Island, $23.2 million for all units; Rocky Reach, $5.3
million; Wells, $2.7 million; Priest Rapids, $0.8 million; and Wanapum, $1.1
million.
65
The following table summarizes the Company's obligations for future power
purchases.
2005 &
THERE-
(In Millions) 2000 2001 2002 2003 2004 AFTER TOTAL
- ------------------------------ --------- ----------- ------------ ------------ ------------ ---------- ----------
Columbia River Projects $81 $80 $80 $78 $76 $605 $1,000
Other utilities 155 150 141 130 77 707 1,360
Non-Utility Generators 181 204 206 207 213 1,494 2,505
- ------------------------------ --------- ----------- ------------ ------------ ------------ ---------- ----------
Total $417 $434 $427 $415 $366 $2,806 $4,865
- ------------------------------ --------- ----------- ------------ ------------ ------------ ---------- ----------
Total purchased power contracts provided the Company with approximately
16.1 million, 15.8 million and 15.6 million MWH of firm energy at a cost of
approximately $487.4 million, $481.6 million and $464.5 million for the years
1999, 1998 and 1997, 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.
As part of its electric operations and in connection with the 1999
buy-out of the Cabot gas supply contract, the Company is obligated to deliver to
Encogen up to 21,800 MMBtu per day of natural gas for operation of the Encogen
cogeneration facility. This obligation continues for the remaining term of the
original Cabot agreement. The price paid by Encogen for this gas is reflective
of the price paid under the Cabot agreement. The difference between the price
paid by Encogen and the replacement cost of gas at current market prices will
reduce the Company's cost of power. The Company entered into two financial
arrangements to hedge future gas supply costs associated with this obligation,
hedging 20,000 MMBtu per day for 2000, and 10,000 MMBtu per day for the
remaining term of the agreement. Encogen has two remaining gas supply agreements
that comprise 40% of the plant's requirements with remaining terms of 8.5 years.
Not included in the table above are Encogen's obligations under these contracts
of $11,821,000 in 2000, $12,414,000 in 2001, $13,047,000 in 2002, $13,690,000 in
2003, $14,375,000 in 2004 and $65,098,000 in the aggregate thereafter.
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, 1999:
COMPANY'S SHARE
------------------------------------------------
ENERGY COMPANY'S PLANT IN SERVICE ACCUMULATED
PROJECT SOURCE (FUEL) OWNERSHIP SHARE (%) AT COST (MILLIONS) DEPRECIATION (MILLIONS)
- --------------------- ------------------ ------------------------ --------------------- --------------------------
Centralia Coal 7% $ 27.3 $ 19.2
Colstrip 1 & 2 Coal 50% 188.7 112.0
Colstrip 3 & 4 Coal 25% 451.2 191.5
Financing for a participant's ownership share in the projects is provided
for by such participant. The Company's share of related operating and
maintenance expenses is included in corresponding accounts in the Consolidated
Statements of Income.
66
On November 2, 1998, the Company announced that 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. Completion of the
sale is contingent on acceptable regulatory treatment from the Washington
Commission. On September 30, 1999, the Washington Commission conditionally
approved the Colstrip sale, which at that time was fixed at $556 million. The
net book value of these assets and related regulatory assets is approximately
$464 million. After taxes and other costs, the Company expected to realize a
gain of approximately $37.6 million. However, the terms and conditions of the
Washington Commission order made the sale economically unattractive to the
Company. The Company appealed the Washington Commission's decision in December
1999. Pending the outcome of the appeal, the Company is working with various
parties to obtain other terms and conditions so the sale can proceed.
In May 1999, the eight partners, including the Company, in the Centralia
coal fired generating plant project announced the sale of the plant to TransAlta
Corporation of Calgary, Canada. The purchase price of the plant and the adjacent
mine (owned and operated by PacifiCorp) is $554 million. The Company owns a 7%
interest in the plant. The transaction is currently under review by the
Washington Commission.
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 24 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 1999 for firm
gas supply, firm transportation service and firm storage and peaking service of
$31,012,000, $52,190,000 and $8,799,000, respectively.
The following tables summarize the Company's obligations for future
demand charges through the primary terms of its existing contracts and the
minimum annual take requirements under the gas supply agreements. The quantified
obligations are based on current contract prices and FERC authorized rates,
which are subject to change.
DEMAND CHARGE OBLIGATIONS
2005 &
THERE-
(In Thousands) 2000 2001 2002 2003 2004 AFTER TOTAL
- ------------------------------- ----------- ------------ ----------- ----------- ------------ ------------- --------------
Firm gas supply $28,114 $28,114 $27,358 $21,863 $11,482 $ 5,291 $122,222
Firm transportation service 51,248 51,196 51,196 51,196 45,020 91,209 341,065
Firm storage service 8,885 8,885 8,885 8,885 8,680 78,851 123,071
- ------------------------------- ----------- ------------ ----------- ----------- ------------ ------------- --------------
Total $88,247 $88,195 $87,439 $81,944 $65,182 $175,351 $586,358
- ------------------------------- ----------- ------------ ----------- ----------- ------------ ------------- --------------
MINIMUM ANNUAL TAKE OBLIGATIONS
2005 &
THERE-
(In thousands of therms) 2000 2001 2002 2003 2004 AFTER TOTAL
- -------------------------------------- ----------- ------------ ----------- ----------- ----------- ---------- --------------
Firm gas supply 588,967 444,726 403,026 318,515 144,849 685 1,900,768
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.
67
The Company does not anticipate any difficulty in achieving the minimum
annual take obligations shown, as such volumes represent less than 65% of
expected annual sales for 2000 and less than 49% 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
2005 &
THERE-
(In thousands of therms) 2000 2001 2002 2003 2004 AFTER TOTAL
- -------------------------- ----------- ------------ ----------- ----------- ------------ ---------- -------------
Firm gas supply 745,201 600,960 556,860 456,524 246,199 42,734 2,648,478
Washington Energy Gas Marketing Company ("WEGM"), a wholly-owned
subsidiary, holds firm rights to transport natural gas on the Nova Corporation
of Alberta ("Nova"), and Alberta Natural Gas Company ("ANG"), pipelines from
Alberta, Canada, to the northern border of Idaho, 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 Washington Energy Resources but were excluded from
the merger of Resources and Cabot completed in May 1994. Following the merger,
WEGM entered into a five-year contract with IGI Resources ("IGI"), Boise, Idaho,
to manage these rights. The management contract terminated on September 30,
1999. WEGM's annual obligations for future demand charges through the primary
term of WEGM's gas transportation and storage contracts are as follows: 2000,
$778,200; 2001, $778,200; 2002, $778,200; 2003, $634,900; 2004, $553,000 and
thereafter, $1,924,000.
Through October of 1999, WEGM also held firm rights to transport natural
gas on the PG&E Gas Transmission - Northwest ("PGT") pipeline from the northern
Idaho border to the northern California border. Effective November 1, 1999, WEGM
sold its remaining interests in the PGT pipeline capacity.
As of December 31, 1999, WEGM has a reserve for future losses associated
with the remaining contractual obligations of $1,779,800. In the third quarter
of 1999, WEGM recorded a $4,888,400 ($3,177,500 after tax) charge based on the
sale of its interest in the PGT pipeline capacity and actual mitigation results
in 1999. In the fourth quarter of 1999, WEGM recorded a $709,000 ($461,000 after
tax) charge to adjust the remaining reserve for expected future losses. During
1999, 1998 and 1997, pre-tax losses totaling $8,429,000, $1,916,000 and
$2,235,000, 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 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 and this process is nearing completion. 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, 1999.
ELECTRIC SITES
The Company has expended approximately $15.1 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, 1999, approximately $2.6 million has been accrued as a liability
for future remediation costs for these and other remediation activities.
68
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 $51.8
million and currently estimated future remediation costs are approximately $6.9
million. Work at both the Chehalis and Tideflats sites is substantially
completed and the remediation construction activity at Everett is completed. To
date, the Company has recovered approximately $57.5 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, 1999. 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.
69
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)
- ------------------------------- ----------------- ------------------ ------------------- ----------------
1999 Quarter First Second Third Fourth
- ------------------------------- ----------------- ------------------ ------------------- ----------------
Operating revenues $575,332 $435,439 $411,035 $644,824
Operating income $101,930 $ 54,897 $ 51,448 $101,857
Other income $3,747 $ 13,102 $9,801 $ (831)
Net income $ 69,755 $ 31,065 $ 24,912 $ 59,835
Basic and diluted earnings
per common share $ 0.79 $ 0.33 $ 0.26 $ 0.68
- ------------------------------- ----------------- ------------------ ------------------- ----------------
(unaudited; dollars in thousands except per-share amounts)
- ------------------------------ ----------------- ------------------ ------------------- ----------------
1998 Quarter (1) First Second Third Fourth
- ------------------------------ ----------------- ------------------ ------------------- ----------------
Operating revenues $524,514 $370,227 $428,510 $600,605
Operating income $ 98,681 $ 49,689 $ 50,834 $ 95,894
Other income $1,764 $3,862 $ 4,184 $3,372
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
- ------------------------------ ----------------- ------------------ ------------------- ----------------
_____________________________________
(1) Results for 1998 include certain reclassifications to present financial
results on a consistent basis with 1999.
70
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, 1999 and 1998, book overdrafts of $22,245,000 and $15,710,000
were included in accounts payable. Non-cash transactions in 1999 included the
issuance of $6,682,000 of Company common stock for the Company's Dividend
Reinvestment Plan and the assumption of $109 million in long-term debt as part
of the purchase of the Encogen partnership.
The following provides additional information concerning cash flow
activities:
- --------------------------------------------------------------- ------------ ------------ ------------
(year ended December 31; dollars in thousands) 1999 1998 1997
- --------------------------------------------------------------- ------------ ------------ ------------
Changes in certain current assets and current liabilities:
Accounts receivable $(23,382) $(29,042) $ (4,488)
Unbilled revenue 5,437 (3,909) 4,591
Materials and supplies (10,707) (4,111) 3,316
Prepayments and other (1,832) (2,175) 5,670
Purchased gas liability (28,208) (6,368) (34,966)
Accounts payable 15,077 25,650 3,003
Accrued expenses and other 18,169 (3,151) (38,490)
-------------------------------------------------------------- ------------ ------------ ------------
Net change in certain current assets
and current liabilities $(25,446) $(23,106) $(61,364)
- --------------------------------------------------------------- ------------ ------------ ------------
Cash payments:
Interest (net of capitalized interest) $153,093 $131,567 $119,810
Income taxes $99,959 $119,664 $104,161
- --------------------------------------------------------------- ------------ ------------ ------------
NOTE 21.
MERGER OF PUGET POWER AND WECO
Included in consolidated results of operations for the month of January
1997 are the following results of the previously separate companies for that
period (Dollars in Thousands):
MONTH ENDED
JANUARY 31, 1997
PUGET POWER WECO
---------------- -------------
Revenues $123,051 $60,486
Net Income $19,671 $9,378
Common Dividends Declared $29,244 --
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.
71
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.
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 computer billing system
software, real estate investment and development and small hydro-electric
project development. Reconciling items between segments are not material.
In the third quarter of 1999, the Company sold the assets, liabilities
and trade name of Homeguard Security Services, Inc., its wholly-owned home
security services subsidiary and recorded a net gain of approximately $7.6
million.
Financial data for business segments are as follows:
(dollars in thousands)
Regulated
1999 Utility Other Total
- -----------------------------------------------------------------------------------------------
Revenues $2,043,500 $23,130 $2,066,630
Depreciation & Amortization 175,610 100 175,710
Federal Income Tax 110,026 (862) 109,164
Operating Income 309,005 1,127 310,132
Interest Charges, net of AFUDC 150,384 -- 150,384
Net Income 174,914 10,653 185,567
Total Assets 4,999,020 146,586 5,145,606
Regulated
1998 Utility Other Total
- -----------------------------------------------------------------------------------------------
Revenues $1,891,759 $32,097 $1,923,856
Depreciation & Amortization 165,491 96 165,587
Federal Income Tax 106,967 (1,153) 105,814
Operating Income 292,337 2,761 295,098
Interest Charges, net of AFUDC 138,561 107 138,668
Net Income 170,435 (823) 169,612
Total Assets 4,596,893 112,794 4,709,687
- -----------------------------------------------------------------------------------------------
72
Regulated
1997 Utility Other Total
- -----------------------------------------------------------------------------------------------
Revenues $1,640,871 $40,657 $1,681,528
Depreciation & Amortization 161,402 463 161,865
Federal Income Tax 34,230 10,686 44,916
Operating Income 215,126 (4,488) 210,638
Interest Charges, net of AFUDC 117,258 1,080 118,338
Net Income 123,872 (796) 123,076
Total Assets 4,396,832 96,474 4,493,306
- -----------------------------------------------------------------------------------------------
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, 1999
- ----------------------------------------------
Accounts deducted from assets on balance sheet:
Allowance for doubtful
accounts receivable $1,020 $6,885 $6,402 $1,503
Gas transportation contracts reserve $4,611 $5,598 $8,429 $1,780
- ---------------------------------------------- ------------------ ----------------- ----------------- ----------------
YEAR ENDED DECEMBER 31, 1998
- ----------------------------------------------
Accounts deducted from assets on balance sheet:
Allowance for doubtful
accounts receivable $ 971 $5,905 $5,856 $1,020
Gas transportation contracts reserve $6,527 -- $1,916 $4,611
- ---------------------------------------------- ------------------ ----------------- ----------------- ----------------
YEAR ENDED DECEMBER 31, 1997
- ----------------------------------------------
Accounts deducted from assets on balance sheet:
Allowance for doubtful
accounts receivable (1) $1,700 $5,080 $5,809 $ 971
Gas transportation contracts reserve $8,762 -- $2,235 $6,527
______________________________________
(1) Includes additions of $369 and deductions of $384 related to October
through December 1996 for WECo.
73
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 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)
4.8 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)
4.9 Pledge Agreement, dated as of March 1, 1992, by and between the Company
and Chemical Bank relating to a series of first mortgage bonds. (Exhibit 4.15 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1993,
Commission File No. 1-4393)
4.10 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)
4.11 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).
4.12 Indenture of First Mortgage dated as of April 1, 1957 (Exhibit 4-B,
Registration No. 2-14307).
4.13 First Supplemental Indenture dated as of October 1, 1959 (Exhibit 4-D
to Registration No. 2-17876).
4.14 Sixth Supplemental Indenture dated as of August 1, 1966 (Exhibit to
Form 8-K for month of August 1966, File No. 0-951).
4.15 Sixteenth Supplemental Indenture dated as of June 1, 1977 (Exhibit
6-05 to Registration No. 2-60352).
4.16 Seventeenth Supplemental Indenture dated as of August 9, 1978 (Exhibit
5-K.18 to Registration No. 2-64428).
4.17 Twenty-second Supplemental Indenture dated as of July 15, 1986
(Exhibit 4-B.20 to Form 10-K for the year ended September 30, 1986, File No.
0-951).
4.18 Twenty-sixth Supplemental Indenture dated as of September 1, 1990
(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
(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
(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 (Exhibit
4-A to 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)
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)
10.28 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)
10.29 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)
10.30 Letter Agreement dated March 31, 1980, between the Company and
Manufacturers Hanover Leasing Corporation. (Exhibit b-8 to Registration No.
2-68498)
10.31 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)
10.32 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)
10.33 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)
10.34 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)
10.35 Agreement executed as of April 17, 1984, between the United States of
America, Department of the Interior, acting through the Bonneville Power
Administration, and wholesale customers 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)
10.36 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)
10.37 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)
10.38 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)
10.39 Irrevocable Offer of Washington Public Power Supply System Nuclear
Project No. 3 Capability for Acquisition executed by the Company, dated
September 17, 1985. (Exhibit A of Exhibit (10)-50 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.40 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)
10.41 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)
10.42 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)
10.43 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)
10.44 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)
10.45 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)
10.46 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)
10.47 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)
10.48 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)
10.49 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)
10.50 Agreement for the Purchase of Power dated as of October 29, 1984,
between South Fork II, Inc. and the Company (Weeks Falls Hydro-electric
Project). (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.51 Agreement for the Purchase of Power dated as of October 29, 1984,
between South Fork Resources, Inc. and the Company (Twin Falls Hydro-electric
Project). (Exhibit (10)-61 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.52 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)
10.53 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
Hydro-electric Project). (Exhibit (10)-63 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.54 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)
10.55 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)
10.56 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)
10.57 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)
10.58 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)
10.59 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)
10.60 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)
10.61 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)
10.62 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)
10.63 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)
10.64 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)
10.65 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)
10.66 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)
10.67 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)
10.68 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)
10.69 Agreement for Sale and Exchange of Firm Power dated as of November
23, 1988, between the Bonneville Power Administration and the Company. (Exhibit
(10)-79 to Annual Report on Form 10-K for the fiscal year ended December 31,
1988, Commission File No.1-4393)
10.70 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)
10.71 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)
10.72 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)
10.73 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)
10.74 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)
10.75 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)
10.76 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)
10.77 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)
10.78 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)
10.79 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)
10.80 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)
10.81 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)
10.82 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)
10.83 Agreement for Firm Power Purchase dated July 23, 1990, between
Trans-Pacific Geothermal Corporation, a Nevada corporation, and the Company.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31,
1991, Commission File No. 1-4393)
10.84 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)
10.85 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)
10.86 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)
10.87 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)
10.88 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)
10.89 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)
10.90 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)
10.91 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)
10.92 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)
10.93 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)
10.94 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)
10.95 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)
10.96 Amendment to Agreement for Firm Power Purchase, dated as of September
30, 1991, between Sumas Energy, Inc. and the Company. (Exhibit (10)-112 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1991,
Commission File No. 1-4393)
10.97 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)
10.98 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)
10.99 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)
10.100 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)
10.101 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)
10.102 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)
10.103 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)
10.104 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)
10.105 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)
10.106 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)
10.107 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)
10.108 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)
10.109 Service Agreement dated September 1, 1987 between Northwest Pipeline
Corporation and Washington Natural Gas Company for SGS-1 firm storage service at
Jackson Prairie (Exhibit 10-A Form 10-K for the year ended September 30, 1994,
File No. 11271).
10.110 Service Agreement dated April 14, 1993 between Questar Pipeline
Corporation and Washington Natural Gas Company for FSS-1 firm storage service at
Clay Basin (Exhibit 10-B Form 10-K for the year ended September 30, 1994, File
No. 11271).
10.111 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.
10.112 Firm Transportation Service Agreement dated October 1, 1990, between
Northwest Pipeline Corporation and Washington Natural Gas Company (Exhibit 10-D
Form 10-K for the year ended September 30, 1994, File No. 11271).
10.113 Gas Transportation Service Contract dated June 29, 1990, between
Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 4-A
Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
10.114 Gas Transportation Service Contract dated July 31, 1991, between
Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 4-A
Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
10.115 Amendment to Gas Transportation Service Contract dated July 31,
1991, between Washington Natural Gas Company and Northwest Pipeline Corporation.
(Exhibit 10-E.2 Form 10-K for the year ended September 30, 1995, File No.
11271).
10.116 Gas Transportation Service Contract dated July 15, 1994, between
Washington Natural Gas Company and Northwest Pipeline Corporation. (Exhibit
10-E.3 Form 10-K for the year ended September 30, 1995, File No. 11271). 10.117
Amendment to Gas Transportation Service Contract dated August 15, 1994, between
Washington Natural Gas Company and Northwest Pipeline Corporation. (Exhibit
10-E.4 Form 10-K for the year ended September 30, 1995, File No. 11271). 10.118
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, (Exhibit 10-N, Form 10-K for the year ended September 30,
1994, File No. 1-11271).
10.119 Firm Transportation Service Agreement dated March 1, 1992 between
Northwest Pipeline Corporation and Washington Natural Gas Company (Exhibit 10-O,
Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.120 Firm Transportation Service Agreement dated January 12, 1994 between
Northwest Pipeline Corporation and Washington Natural Gas Company for firm
transportation service from Jackson Prairie (Exhibit 10-P, Form 10-K for the
year ended September 30, 1994, File No. 1-11271).
10.121 Firm Transportation Service Agreement dated January 12, 1994 between
Northwest Pipeline Corporation and Washington Natural Gas Company for firm
transportation service from Jackson Prairie (Exhibit 10-Q, Form 10-K for the
year ended September 30, 1994, File No. 1-11271).
10.122 Firm Transportation Service Agreement dated January 12, 1994 between
Northwest Pipeline Corporation and Washington Natural Gas Company for firm
transportation service from Plymouth, LNG (Exhibit 10-R, Form 10-K for the year
ended September 30, 1994, File No. 1-11271).
10.123 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 (Exhibit 10-S, Form 10-K for the year ended September 30,
1994, File No. 1-11271).
10.124 Firm Transportation Agreement dated October 27, 1993 between Pacific
Gas Transmission Company and Washington Natural Gas Company for firm
transportation service from Kingsgate (Exhibit 10-T, Form 10-K for the year
ended September 30, 1994, File No. 1-11271).
10.125 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.
10.126 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)
10.127 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)
10.128 Asset Purchase Agreement between PP&L Global, Inc. and the Company.
(Exhibit 2a to Current Report on Form 8-K dated November 13, 1998)
10.129 Employment agreement with S. A. McKeon, Vice President and General
Counsel, dated May 27, 1997. (Exhibit 10.152 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1998, Commission File No. 1-4393)
10.130 Employment agreement with R. L. Hawley, Vice President and Chief
Financial Officer, dated March 16, 1998. (Exhibit 10.153 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1998, Commission File No.
1-4393)
*10.131 Separation agreement with J. Quintana, Vice President External
Affairs, dated December 29, 1999.
*12-a Statement setting forth computation of ratios of earnings to fixed
charges (1995 through 1999).
*12-b Statement setting forth computation of ratios of earnings to combined
fixed charges and preferred stock dividends (1995 through 1999).
*21 Subsidiaries of the Registrant.
*23.1 Consent of PricewaterhouseCoopers LLP.
*27 Financial Data Schedules.
---------------------------------
*Filed herewith.