============================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 1996
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
-----------------------------
Commission File Number 1-4393
-----------------------------
PUGET SOUND ENERGY, INC.
(Exact name of registrant as specified in its charter)
Washington 91-0374630
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
411 - 108th Avenue N.E., Bellevue, Washington 98004-5515
(Address of principal executive offices)
(206) 454-6363
(Registrant's telephone number, including area code)
============================================================================
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.
7-7/8% Series Preferred Stock
(Cumulative $25 Par Value) N. Y. S. E.
Adjustable Rate Cumulative Preferred
Stock, Series B ($25 Par Value) N. Y. S. E.
7.45% Series II, Preferred Stock
(Cumulative, $25 Par Value) N. Y. S. E.
8.50% Series III, Preferred Stock
(Cumulative, $25 Par Value) N. Y. S. E.
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Preferred Stock (Cumulative; $100 Par Value)
Preferred Stock (Cumulative; $25 Par Value)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
The aggregate market value of the voting stock held by non-affiliates of the
registrant at December 31, 1996 was approximately $1,523,552,000.
The number of shares of the registrant's common stock outstanding at
February 28, 1997 was 84,562,238.
Documents Incorporated by Reference
The Company's definitive proxy statement for its annual meeting of
shareholders on May 19, 1997, is incorporated by reference in Part III
hereof.
INDEX
Item Page
No. No.
Part I
1. Business................................................ 1
The Company............................................. 1
Industry Evolution and Merger with Washington Energy
Company................................................. 2
Regulation and Rates.................................... 3
Power Resources......................................... 4
Construction Financing.................................. 10
Environment............................................. 10
Operating Statistics.................................... 13
Executive Officers...................................... 15
2. Properties.............................................. 16
3. Legal Proceedings....................................... 16
4. Submission of Matters to a Vote of Security Holders..... 16
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters..................................... 16
6. Selected Financial Data................................. 17
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations........... 18
8. Financial Statements and Supplementary Data............. 27
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.................. 27
Part III
(Incorporated by reference from the Company's
definitive proxy statement issued in connection
with the 1997 Annual Meeting of Shareholders)
10. Directors and Executive Officers of the Registrant
11. Executive Compensation
12. Security Ownership of Certain Beneficial
Owners and Management
13. Certain Relationships and Related Transactions
Part IV
14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K..................................... 27
Signatures.............................................. 28
Exhibit Index........................................... 63
DEFINITIONS
AFUCE Allowance for Funds Used to Conserve Energy
AFUDC Allowance for Funds Used During Construction
BPA Bonneville Power Administration
CAAA Clean Air Act Amendments
Chelan Public Utility District No. 1 of
Chelan County, Washington
EPA Environmental Protection Agency
FERC Federal Energy Regulatory Commission
KW Kilowatts
KWH Kilowatt Hours
MW Megawatts (one MW equals one thousand KW)
MWH Megawatt Hours
Montana Power The Montana Power Company
NMFS National Marine Fisheries Service
NWPPC Northwest Power Planning Council
PRAM Periodic Rate Adjustment Mechanism
PRP Potentially Responsible Party
PUDs Washington Public Utility Districts
Washington Commission Washington Utilities and Transportation
Commission
WECo Washington Energy Company
WNG Washington Natural Gas Company
WPPSS Washington Public Power Supply System
PART I
ITEM 1. BUSINESS
THE COMPANY
Puget Sound Energy, Inc., formerly Puget Sound Power & Light Company,
("the Company") is an investor-owned public utility incorporated in the
State of Washington furnishing electric, and since February 10, 1997, gas
service in a territory covering approximately 6,000 square miles,
principally in the Puget Sound region of Washington State. On February 10,
1997, the Company completed a merger ("the Merger") with the Washington
Energy Company ("WECo") and its principal subsidiary, Washington Natural Gas
Company ("WNG"). Seattle-based WNG provided natural gas distribution
service to more than 500,000 customers in an area east of Puget Sound that
included Seattle, Tacoma, Everett, Bellevue and Olympia. The earnings,
operations and statistical information contained in this report reflect the
results and information for the Company without giving effect to the Merger
unless the text indicates otherwise. (See Note 18 to the Consolidated
Financial Statements). The Company changed its name to Puget Sound Energy,
Inc. effective with the Merger. (See "Merger with Washington Energy Company
and Washington Natural Gas Company" below.)
In December 1996, the Company had approximately 857,300 electric
customers, consisting of 761,000 residential, 90,500 commercial, 4,100
industrial and 1,400 other customers. For the year 1996, the Company added
approximately 16,600 customers, an annual growth rate of 2.0%. Growth in
total kilowatt-hour sales increased 8.0% in 1996 over 1995, due to increased
sales to other utilities, continuing growth in the number of customers and
colder average temperatures in 1996 than experienced in 1995.
During 1996, the Company's billed revenues were derived 47% from
residential customers, 35% from commercial customers, 14% from industrial
customers and 4% from sales to other utilities and others. During this
period, the largest single customer accounted for 3.3% of the Company's
operating revenues. The average number of kilowatt-hours billed per
residential customer served by the Company in 1996 was 12,399 kilowatt-
hours. At December 31, 1996, the peak power resources of the Company were
approximately 5,203,000 KW. The Company's historical peak load of
approximately 4,615,000 KW occurred on December 21, 1990.
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 to other utilities also vary by quarters and years depending
principally upon streamflow conditions for the generation of surplus hydro-
electric power, customer usage and the energy requirements of other
neighboring utilities. With the implementation of the Periodic Rate
Adjustment Mechanism ("PRAM") by the Washington Utilities and Transportation
Commission (the "Washington Commission") in October 1991, earnings have not
been significantly influenced, up or down, by sales of surplus electricity
to other utilities or by variations in normal seasonal weather or hydro
conditions. The PRAM however, ended effective September 30, 1996, under a
stipulated negotiated settlement approved by the Washington Commission.
With the discontinuance of the PRAM, the annual regulatory adjustments for
variations in weather and hydro conditions provided for in the PRAM will
1
also be discontinued. (See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Rate Matters")
During the period from January 1, 1992 through December 31, 1996, the
Company made gross electric utility plant additions of $915 million and
retirements of $131 million. Gross electric utility plant at December 31,
1996, was approximately $3.5 billion which consisted of 47% distribution,
27% generation, 15% transmission and 11% general plant and other.
The Company and its subsidiaries had 2,075 full-time equivalent
employees on December 31, 1996, down from 2,775 at the end of 1992. This
represents a workforce reduction of 25% over the last four years.
INDUSTRY EVOLUTION
The U.S. electric utility industry is facing an increasingly competitive
environment, particularly in wholesale electric generation and industrial
customer markets. The National Energy Policy Act of 1992 ("EPACT")
intensified competition in the wholesale electric market by easing
restrictions on wholesale power producers and by allowing the Federal Energy
Regulatory Commission ("FERC") to order access for wholesale sellers to
deliver power to wholesale buyers over transmission systems owned by others.
In 1996 FERC issued its landmark Orders 888 and 889, which require
jurisdictional utilities, including the Company, to file wholesale
transmission tariffs providing pricing and terms for transmission access for
wholesale purposes.
The EPACT does not permit the FERC to order transmission access for
retail purposes, but Congress now has pending bills that would require
existing utilities to allow competitors to use utility property, including
transmission and distribution facilities, to provide electric service to
retail customers of the existing utilities. Several states, including
California, New Hampshire and Rhode Island have enacted legislation to allow
such use by competitors of utility property. Most other states, including
Washington, are considering legislative or regulatory proposals which would
also allow such use of utility property by competitors to serve the retail
customers of the existing utilities. In its February 5, 1997 Order approving
the Company's merger with Washington Energy Company described above, the
Washington Commission required the Company to conduct a retail access pilot
program. Any substantial change in utility regulation in Washington state,
such as requiring utilities to allow use of utility property by competitors
for retail purposes, would require legislative action and would be subject to
court review. The major credit rating agencies have expressed the general
view that increased competition is likely to increase business risks in the
electric utility industry, with resulting pressures on utility credit quality
and investor returns. As required by the Public Utility Regulatory Policies
Act of 1978, the Company has contracted to purchase the net electrical output
from a number of non-utility generators. (See "Power Resources - Contracts
and Agreements with Non-Utilities") Most of these agreements provide for
power purchases at prices that are now above market prices. These excess
contract prices could become stranded costs in a deregulated electric
industry environment.
In this environment, the Company seeks to build on the strengths of its
efficient electric distribution and transmission system to become a leading
provider of energy and related services to homes and businesses in the
Pacific Northwest, and to streamline its energy supply operations. To
prepare for a more competitive business environment, the Company has
committed itself to being a low cost supplier of electricity. The Company
2
has taken steps to reduce costs, including work force reductions, facility
consolidations and reductions in capital budgets. The Company intends to
pursue opportunities for improved operating efficiencies and productivity,
including possible restructuring of its power supply resources and
contracts. The Company is also actively pursuing opportunities to become a
provider of new high value services such as wireless automated meter-based
services and geographic information systems, to utility customers and other
utilities.
MERGER WITH WASHINGTON ENERGY COMPANY AND WASHINGTON NATURAL GAS COMPANY
As part of the Company's effort to become the leading provider of
energy and related services in the Northwest, the Company, on February 10,
1997, completed the Merger between the Company, WECo and WNG. This
announcement followed approval by the Washington Commission, on February 5,
1997, of a merger agreement between the Company, WECo, the Staff of the
Washington Commission and the Public Counsel Section of the State Attorney
General's Office. These events marked the culmination of a sixteen month
process that began in October 1995 with the unanimous approval of the
Agreement and Plan of Merger among the Company, WECo and WNG (the "Merger
Agreement") by the Boards of Directors of the Company, WECo and WNG. On
March 20, 1996, shareholders of the Company and WECo, voting as separate
groups, gave their approval to the Merger.
The Merger Agreement called for each share of WECo common stock to be
exchanged for 0.86 share of the Company's common stock. Based on the
capitalization of the Company and WECo on February 10, 1997, holders of the
Company's and WECo's common stock held approximately 75% and 25%
respectively, of the aggregate number of outstanding shares of the merged
company's common stock. In addition, the Agreement called for the preferred
stock of WNG to be converted into preferred shares of the Company. The
Merger has been structured as a tax-free exchange of shares and will be
accounted for as a pooling of interests.
The order approving the Merger, issued by the Washington Commission on
February 5, 1997, contains a rate plan that is designed to provide a five-
year period of rate certainty for customers and provide the Company with an
opportunity to achieve a reasonable return on investment. As required under
the Merger order, the Company filed tariffs, effective February 8, 1997,
that resulted in an average decrease of 5.6% related to the PRAM, and an
increase in general rates of between 1.0% and 2.5%, depending on rate class.
The net impact was an average decrease of 3.7%, including a decrease in
residential rates of 3.2%. General rates for residential and industrial
customers will increase by 1.5% on January 1 of each of the four following
years, while those for small commercial customers will increase by 1.0% in
each of the following three years.
REGULATION AND RATES
The Company is subject to the regulatory authority of (1) the
Washington Commission as to rates, accounting, the issuance of securities
and certain other matters, and (2) the FERC in the transmission of electric
energy in interstate commerce, the sale of electric energy at wholesale for
resale, accounting and certain other matters. The Washington Commission
consists of three Commissioners, each appointed for a six-year term by the
Governor of the State of Washington. (See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Rate Matters.")
3
POWER RESOURCES
During 1996, the Company's total energy production was supplied 21% by
its own resources, 32% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydroelectric projects
on the Columbia River, 34% from other firm purchases and 13% from non-firm
purchases.
The following table shows the Company's resources at December 31, 1996,
and energy production during the year:
Peak Power Resources
at December 31, 1996 1996 Energy Production
----------------------- ----------------------
Kilowatts % Kilowatt-Hours %
--------- ---- -------------- ----
(Thousands)
Purchased Resources:
Columbia River
PUD Contracts (Hydro) 1,356,000 26.5 8,488,933 32.3
Other Hydro(a) 570,000 11.2 4,303,931 16.4
Thermal(a) 1,399,000 27.4 7,881,061 30.0
- -------------------------------------------------------------------------
Total Purchased 3,325,000 65.1 20,673,925 78.7
- -------------------------------------------------------------------------
Company-owned Resources:
Hydro 309,950 6.1 1,346,434 5.1
Coal 771,900 15.1 4,217,543 16.1
Natural gas/oil 702,350 13.7 21,618 0.1
- -------------------------------------------------------------------------
Total Company-owned 1,784,200 34.9 5,585,595 21.3
- -------------------------------------------------------------------------
Total 5,109,200 100.0 26,259,520 100.0
=========================================================================
(a) Power received from other utilities is classified between hydro and
thermal based on the character of the utility system used to supply the
power or, if the power is supplied from a particular resource, the character
of that resource.
Company Owned Resources
- -----------------------
The Company and other utilities are joint owners of four mine-mouth,
coal-fired, steam-electric generating units at Colstrip, Montana,
approximately 100 miles east of Billings. The Company owns a 50% interest
(330,000 KW) in Units 1 and 2 and a 25% interest (350,000 KW) in Units 3 and
4. The owners of the Colstrip Units purchase coal for the units from
Western Energy Company ("Western Energy"), an affiliate of Montana Power -
one of the joint owners, under the terms of long-term coal supply
agreements.
A contract price reopener for both the base price and adjustment
provisions of the Colstrip 1 and 2 Coal Supply Agreement became effective
July 30, 1996. Pursuant to a settlement agreement between the Company,
4
Montana Power and Western Energy dated February 21, 1997, the coal price has
been reduced on an interim basis pending a restructuring of the Colstrip
Coal supply arrangements.
In 1996, under the Colstrip 3 and 4 Coal Supply Agreement, the owners,
other than Montana Power, gave Western Energy written notice of the
existence of an unusual circumstance and gross inequity concerning the coal
price in accordance with contract provisions. Pursuant to a settlement
agreement between the Company, Montana Power and Western Energy dated
February 21, 1997, the coal price has been reduced on an interim basis
pending a restructuring of the Colstrip coal supply arrangements. Pursuant
to its settlement agreement, the Company has withdrawn from participation in
and will forego any benefits from the negotiations and a potential
arbitration regarding the notice of an unusual condition and a gross
inequity.
The Company owns a 7% interest (91,900 KW) in a coal-fired, steam-
electric generating plant near Centralia, Washington, with a net capability
of 1,313,000 KW. In 1991, the Company and other owners of the Centralia
Project renegotiated a long-term coal supply agreement with Pacific Power &
Light Company. The Company and other owners of the Centralia project are
reviewing emissions compliance options that will need to be adopted to meet
the Federal and State emission requirements by the year 2001. Legislation
is pending in the Washington State Legislature which would provide certain
tax relief to the owners of the Centralia Plant in order to help defray
costs associated with emissions compliance.
The Company also has the following plants with an aggregate net
generating capability of 1,012,300 KW: Upper Baker River hydro project
(103,000 KW) constructed in 1959; Lower Baker River hydro project (71,400
KW) reconstructed in 1968; White River hydro plant (63,400 KW) constructed
in 1911 with installation of the last unit in 1924; Snoqualmie Falls hydro
plant (44,000 KW), half the capability of which was installed during the
period 1898 to 1910 and half in 1957; two smaller hydro plants, Electron
(26,400 KW) and Nooksack Falls (1,750 KW), constructed during the period
1904 to 1929; a standby internal combustion unit (2,750 KW) installed in
1969; two oil-fired combustion turbine units (28,500 KW and 67,500 KW)
installed in 1972 and 1974, respectively; four dual-fuel combustion turbine
units (89,100 KW each) installed during 1981; and two dual-fuel combustion
turbine units (123,600 KW each) installed during 1984.
The Company's combustion turbines installed in 1981 and 1984 may be
fueled with either natural gas or distillate oil. Short-term supplies of
distillate fuel are stored on-site. These plants are operated from time to
time for peaking purposes and to produce energy for sales to other
utilities, either directly or through 'tolling' arrangements.
The Company has applied to the FERC for an initial license for its
existing and operating White River project which includes authorization to
install an additional 14,000 KW generating unit. The initial license for
the existing and operating Snoqualmie Falls project expired in December
1993. The Company is continuing the FERC application process to relicense
this project and expects a license to be issued in 1997. The Company has
also applied for a license to expand its existing 1,750 KW Nooksack Falls
project which is currently unlicensed and not operating because of an
electrical fire.
5
Columbia River Projects
- -----------------------
For the twelve months ended December 31, 1996, approximately 32% of the
Company's energy output was obtained at an average cost of approximately 8.7
mills per KWH through long-term contracts with several of the Washington
public utility districts ("PUDs") owning hydroelectric projects on the
Columbia River.
The 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 a share
of the output of the original units of the Rock Island Project which equals
57.1% through June 30, 1997. This share decreases gradually to 50% of the
output until 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, to a minimum 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. The
Company has contracted to purchase from Chelan County PUD a share of the
output of the Rocky Reach Project that remains unchanged for the remainder
of the contract. Under terms of a settlement agreement concerning
withdrawal of power, the Company's share of the output of the Wells Project
purchased from Douglas County PUD is currently 32.3% and is expected to
decrease to 31.5% by September 1, 1997. However, the Company's share of the
output can be ultimately reduced to 31.3% upon the additional exercise of
withdrawal rights by Douglas County PUD. The Company has contracted to
purchase from Grant County PUD a share of the output of the Priest Rapids
and Wanapum projects that remains unchanged for the remainder of the
contracts.
As of December 31, 1996, the Company was entitled to purchase portions
of the power output of the PUDs' projects as set forth in Note 15 to the
Consolidated Financial Statements.
In 1964, the Company and fifteen other utilities and agencies in the
Pacific Northwest entered into a long-term coordination agreement extending
until June 30, 2003 (the "Coordination Agreement"). This agreement provides
for the coordinated operation of substantially all of the hydroelectric
power plants and reservoirs in the Pacific Northwest. Negotiations are
being conducted regarding a possible replacement of the expiring
Coordination Agreement. Various fishery enhancement measures, including
most recently the 1995 "biological opinion" from the National Marine
Fisheries Service ("NMFS"), have reduced the flexibility provided by the
Coordination Agreement.
Certain utilities in the northwest United States and Canada are
obtaining the benefits of additional firm power as a result of the
6
ratification of a 1961 treaty between the United States and Canada under
which Canada is providing approximately 15,500,000 acre-feet of reservoir
storage on the upper Columbia River. As a result of this storage,
streamflow which would otherwise not be usable to serve firm regional load
is stored and later released during periods when it is usable. Pursuant to
the treaty, one-half of the firm power benefits produced by the additional
storage accrue to Canada. The Company's benefits from this storage are
based upon its percentage participation in the Columbia River projects and
one half of those benefits must be returned to Canada. In turn, the Company
has contracted to purchase 17.5% of Canada's share of the power to be
returned resulting from such storage until the beginning of a phased
expiration of the contract in 1998). The Company has also contracted to
purchase from the Bonneville Power Administration ("BPA") supplemental
capacity in amounts that decrease gradually until the beginning of a phased
expiration of the contract in 1998. Negotiations are being conducted
regarding replacement of the existing contracts.
See "ENVIRONMENT - Federal Endangered Species Act" for discussion of the
fishery enhancement plan related to these projects.
Contracts and Agreements with Other Utilities
- ---------------------------------------------
On September 17, 1985, the Company and BPA entered into a settlement
agreement settling the Company's claims against BPA resulting from BPA's
action in halting construction on Washington Public Power Supply System
("WPPSS") Nuclear Project No. 3 in which the Company has a 5% interest.
Under the settlement agreement, the Company is receiving from BPA for
approximately 30.5 years, beginning January 1, 1987, a certain amount of
electric power during the months of November through April. Under the
contract, the Company is guaranteed to receive not less than 191,667 MWH in
each contract year until the Company has received total deliveries of
5,833,333 MWH.
On April 4, 1988, the Company executed a 15-year contract, with
provisions for early termination by the company, for the purchase of firm
energy supply from Washington Water Power Company. This agreement calls for
the delivery of 100 MW of capacity and 657,000 MWH of energy from the
Washington Water Power system annually (75 annual average MW). Minimum and
maximum delivery rates are prescribed. Under this agreement, the energy is
to be priced at Washington Water Power's average generation and transmission
cost, subject to certain price ceilings.
On October 27, 1988, the Company executed a 15-year contract for the
purchase of firm power and energy from Pacific Power & Light Company. Under
the terms of the agreement, the Company receives 120 average MW of energy
and 200 MW of peak capacity.
On November 23, 1988, the Company executed an agreement to purchase
surplus firm power from BPA. Under the agreement, the Company receives 150
average MW of energy and 300 MW of peak capacity from BPA between October 1
and March 31 of each contract year. The contract extends for 20 years,
ending in 2008. The sale will convert to a power-for-power exchange on June
30, 2001.
On October 1, 1989, the Company signed a contract with Montana Power
under which Montana Power provides, from its share of Colstrip Unit 4, to
the Company 71 average MW of energy (94 MW of peak capacity) over a 21-year
7
period. On February 27, 1995, the Company delivered to Montana Power notice
of termination of the contract based on Montana Power's failure to arrange
for firm contractual transmission rights for such energy as required by the
contract. On February 21, 1997, the Company and Montana Power settled the
dispute as more fully described in the Company's 8-K statement filed on
February 27, 1997. Pursuant to the settlement, the contract remains in
effect and the price of power purchased by the Company is reduced. On
February 21, 1997, the Company and Montana Power also agreed to settle their
coal supply disputes in return for certain price reductions and
restructuring activities in connection with the Colstrip coal supply
arrangements. Montana has estimated that these agreements will result in an
annual reduction in Montana Power's revenues between $11 and $13 million,
before anticipated efficiency gains, commencing January 1, 1997. The
Company will see a reduction in its power supply costs of approximately the
same amount. In addition, the Company expects reductions in coal taxes and
royalties and anticipates efficiency gains through restructuring.
On December 11, 1989, the Company executed a conservation transfer
agreement with Snohomish County PUD. Snohomish County PUD, together with
Mason and Lewis County PUDs, will install conservation measures in their
service areas. The agreement calls for the Company to receive the power
saved over the expected 20-year life of the measures. The agreement calls
for BPA to deliver the conservation power to the Company from March 1, 1990
through June 30, 2001, and for Snohomish County PUD to deliver the
conservation power for the remaining term of the agreement. Power
deliveries gradually increased over the first five years of the agreement
and will remain at six average MW of energy throughout the remaining term of
the agreement.
The Company executed an exchange agreement with Pacific Gas & Electric
Company which became effective on January 1, 1992. Under the agreement, 300
MW of capacity together with 413,000 MWH of energy are exchanged seasonally
every year on a unit for unit basis. No payments are made under this
agreement. Pacific Gas & Electric Company is a summer peaking utility and
will provide power during the months of November through February. The
Company is a winter peaking utility and will provide power during the months
of June through September. By giving proper notice, either party may
terminate the contract for various reasons.
Contracts and Agreements with Non-Utilities
- -------------------------------------------
As required by federal law, Public Utility Regulatory Policies Act of
1978, P.L. 95-617 ("PURPA"), the Company has contracted to purchase the net
electrical output from a number of non-utility generators, of which the most
significant are described below. Payments by the Company to owners of these
non-utility generating resources are subject to the delivery of power. (See
Note 15 to the Consolidated Financial Statements) A number of these
agreements have escalation provisions providing for periodic increases in
the cost of power.
On February 21, 1985, the Company executed a 50-year contract to
purchase 6 average MW of energy and 14 MW of capacity, beginning in December
1990, from Koma Kulshan Associates, which owns and operates a small
hydroelectric project located near the Company's Upper Baker Dam.
On January 4, 1988, the Company executed a 21-year contract to purchase
15 average MW of energy and 23 MW of capacity, beginning November 1991, from
8
the City of Spokane, which owns and operates a regional solid waste
incineration project located near Spokane, Washington.
On June 29, 1989, the Company executed a 20-year contract to purchase
70 average MW of energy and 80 MW of capacity, beginning October 11, 1991,
from the March Point Cogeneration Company ("March Point"), which owns and
operates a natural gas-fired cogeneration facility known as March Point
Phase I, located at a Texaco refinery in Anacortes, Washington. On December
27, 1990, the Company executed a second contract (having a term coextensive
with the first contract) to purchase an additional 53 average MW of energy
and 60 MW of capacity, beginning January 1993, from March Point which owns
and operates another natural gas-fired cogeneration facility known as March
Point Phase II, also located at the Texaco refinery in Anacortes,
Washington. In November 1995, March 1996 and November 1996, the Company
delivered notices of breach to March Point based on, among other things,
March Point's failure to maintain generation at agreed-upon limits, to
displace generation pursuant to the parties' power purchase agreements, and
to provide information essential to the parties' agreed-upon displacement
arrangements. On November 29, 1995, March Point commenced litigation
against the Company in federal court for the Western District of Washington
in which March Point requests a declaration of certain obligations of March
Point and the Company under the contracts, injunctive relief preventing the
Company from terminating its contracts with March Point and damages based on
breach of contract. The Company has answered and counterclaimed in the
action, contending that March Point has breached the contracts. The Company
seeks declaratory relief regarding the parties' obligations and rights under
the contracts, damages based on the breach and rescission.
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 July
1993, from Encogen Northwest L.P. ("Encogen") (a limited partnership having
a general partner that is a subsidiary of Enserch Development Corp.), which
owns and operates a natural-gas fired cogeneration facility located at the
Georgia Pacific mill near Bellingham, Washington. In June 1995, the Company
delivered notice of breach to Encogen based on, among other things,
Encogen's failure to provide information essential to the parties' agreed-
upon displacement arrangements. On September 20, 1995, Encogen commenced
litigation against the Company in Whatcom County Superior Court requesting a
declaration of certain obligations of Encogen under the contract, and
seeking further relief. The Company has answered and counterclaimed in the
action, contending that Encogen has breached the contract and seeking
declaratory relief regarding Encogen's duty to provide certain information.
On March 20, 1991, the Company executed a 20-year contract to purchase
216 average MW of energy and 245 MW of capacity, beginning April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas
fired cogeneration project located near Ferndale, Washington.
Energy Conservation
- -------------------
The Company offers programs designed to help new and existing customers
use electric energy efficiently. The primary emphasis is to provide
9
information and technical services to enable customers to make energy-
efficient choices with respect to building design, equipment and building
systems, appliance purchases and O&M practices.
The Company's energy conservation expenditures have historically been
accumulated, included in rate base and amortized to expense over a ten year
period at the direction of the Washington Commission. In June 1995 the
Company sold approximately $202.5 million of its investment in customer-
owned energy conservation measures to a grantor trust, which, in turn,
issued securities backed by a Washington state statute enacted in 1994.
(See Note 1 to the Consolidated Financial Statements)
Construction Financing
- ----------------------
The Company estimates its combined electric and gas construction
expenditures, excluding Allowance for Funds Used During Construction
("AFUDC"), for 1997 through 1999 will be $247 million, $252 million and $226
million, respectively. The Company expects cash from operations (net of
dividends and AFUDC) during the period 1997 through 1999 will, on average,
be approximately 73% of average estimated construction expenditures
(excluding AFUDC) during the same period. (See "Management's Discussion and
Analysis of Financial Condition and Results of Operations" for a discussion
of the Company's construction program.) The Company's ability to finance
its future construction program is dependent upon market conditions and
maintaining a level of earnings sufficient to permit the sale of additional
securities. In determining the type and amount of future financings, the
Company may be limited by restrictions contained in its Mortgage Indenture,
Articles of Incorporation and certain loan agreements.
Under the most restrictive tests, at December 31, 1996, the Company
could issue (i) approximately $1.019 billion of additional first mortgage
bonds or (ii) approximately $571 million of additional preferred stock at an
assumed dividend rate of 6.80% or (iii) a combination thereof.
Environment
- -----------
The Company's operations are subject to environmental regulation by
federal, state and local authorities. Capital expenditures for
environmental controls for Company electric facilities are estimated at $2.3
million for 1997. Due to the inherent uncertainties surrounding the
development of federal and state environmental and energy laws and
regulations, the Company cannot determine the impact such laws may have on
its existing and future facilities.
Federal Comprehensive Environmental Response, Compensation and
Liability Act, and the Washington State Model Toxics Control Act
- ----------------------------------------------------------------
The federal Comprehensive Environmental Response, Compensation and
Liability Act (commonly referred to as the "Superfund Act") subjects certain
parties to liability for remedial action at contaminated disposal sites.
The Company has been named by the Environmental Protection Agency
("EPA") as a Potentially Responsible Party ("PRP") at four sites in
Washington State. The Company has reached settlements with the EPA on all
four sites under which the Company has paid approximately $7.7 million.
Estimated future remediation costs at these four sites are expected to be
10
$0.4 million. To date, the Company has recovered $4.0 million from its
insurance companies in connection with remediation and legal costs and
expects to recover an additional $1.9 million. These sites represent all
significant superfund sites at which the Company believes it has liability.
There is, however, no assurance that all contaminated sites and contaminants
for which the Company may have a responsibility have been identified or that
remedial actions planned to date at current sites, including actions
pursuant to consent decrees, will be adequate.
The Company has also commenced a program to test, replace and remediate
certain underground storage tanks as required by federal and state laws.
Remediation and testing of Company vehicle service facilities and storage
yards have also been commenced. To date, the Company has spent $3.2 million
to remediate underground tank sites and has recovered $1.2 million in
insurance proceeds. Future expenditures are anticipated to be $1.1 million
and future insurance proceeds are anticipated to be $1.6 million. Estimated
future remediation costs at other Company-owned sites were $0.7 million at
December 31, 1996. (See Note 15 to the Consolidated Financial Statements
for further discussion of environmental obligations and the related
regulatory treatment.) Estimates of future obligations in this section
relate to the Company's electric operations.
Federal Clean Air Act Amendments of 1990
- ----------------------------------------
The Company has an ownership interest in coal-fired, steam-electric
generating plants at Centralia, Washington and Colstrip, Montana which are
subject to the federal Clean Air Act Amendments of 1990 ("CAAA") and other
regulatory requirements.
The Centralia Project and the Colstrip Projects meet the sulfur dioxide
limits of the CAAA in Phase I (1995). The Company and other owners of the
Centralia Project, including Pacific Power & Light Company, which operates
the Centralia Project, are reviewing emission compliance options which will
need to be adopted to meet the Phase II limits in the year 2000.
Montana Power, which operates the Colstrip 3 and 4 Project, is working
to meet the Phase II limits in the year 2000. Under the CAAA, allowances
may be used to achieve compliance. It is believed that Units 1 and 2 may
have an excess of allowances above what is currently set for Phase II
requirements and that Units 3 and 4 have sufficient allowances for Phase II
requirements.
The Company owns combustion turbine units, most of which are capable of
being fueled by natural gas or oil. The nature of these units provides
operational flexibility in meeting air emission standards.
There is no assurance that in the future environmental regulations
affecting sulfur dioxide or nitrogen oxide emissions may not be further
restricted, and there is no assurance that restrictions on emissions of
carbon dioxide or other combustion by-products may not be imposed.
Federal Endangered Species Act
- ------------------------------
In November 1991, the National Marine Fisheries Service ("NMFS") listed
the Snake River Sockeye as an endangered species pursuant to the federal
Endangered Species Act. Since the Sockeye listing, the Snake River fall and
spring/summer Chinook have also been listed as threatened. In response to
the listings, a team of experts was formed to develop a plan for the
11
recovery needs of these species. In 1995 the NMFS issued a biological
opinion which has significantly changed the operation of the Federal
Columbia River Power System.
The plans developed by NMFS affect the Mid-Columbia projects from which
the Company purchases power on a long-term basis, and will further reduce
the flexibility of the regional hydroelectric system. Although the full
impacts are unknown at this time, the plan developed by NMFS shifts an
amount of the Company's generation from the Mid-Columbia projects from
winter periods into the spring when it is not needed for system loads, and
will increase the potential for spill and loss of generation at the Mid-
Columbia projects.
Other species are also proposed for listing as endangered species and
could further restrict regional hydro system flexibility and energy
production.
12
Puget Sound Energy, Inc.
ELECTRIC OPERATING STATISTICS
<TABLE>
<CAPTION>
Year Ended on December 31 1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------------
Operating revenues by classes
(thousands):
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Residential $ 554,318 $ 524,749 $ 532,124 $ 502,037 $ 443,490
Commercial 423,139 397,212 375,751 356,586 323,764
Industrial 170,596 168,501 163,574 150,063 138,416
Other consumers 44,125 38,730 38,759 28,189 35,779
- -------------------------------------------------------------------------------------------
Operating revenues billed
to consumers (a) 1,192,178 1,129,192 1,110,208 1,036,875 941,449
Unbilled revenues -
net increase (decrease) 13,201 (6,382) (2,522) 14,409 15,080
PRAM accrual (74,326) 3,953 25,835 42,100 42,119
- -------------------------------------------------------------------------------------------
Total operating revenues
from consumers 1,131,053 1,126,763 1,133,521 1,093,384 998,648
Other utilities 67,716 52,567 60,537 19,494 26,322
- -------------------------------------------------------------------------------------------
Total operating revenues $1,198,769 $1,179,330 $1,194,058 $1,112,878 $1,024,970
- -------------------------------------------------------------------------------------------
Number of customers (average):
Residential 754,097 739,173 723,566 708,123 692,100
Commercial 89,613 87,404 85,203 82,875 80,963
Industrial 3,993 3,908 3,851 3,715 3,659
Other 1,371 1,346 1,325 1,289 1,254
- -------------------------------------------------------------------------------------------
Total customers (average) 849,074 831,831 813,945 796,002 777,976
- -------------------------------------------------------------------------------------------
KWH generated, purchased
and interchanged (thousands):
Total Company generated 5,585,595 6,371,416 7,011,932 6,414,311 7,420,058
Purchased power 20,573,983 17,897,922 16,268,042 14,608,899 13,408,522
Interchanged power (net) 99,942 48,485 (87,771) 174,478 (118,346)
- -------------------------------------------------------------------------------------------
Total energy output 26,259,520 24,317,823 23,192,203 21,197,688 20,710,234
Losses and Company use (1,322,262) (1,235,457) (1,291,322) (1,096,599) (1,202,194)
- -------------------------------------------------------------------------------------------
Total energy sales 24,937,258 23,082,366 21,900,881 20,101,089 19,508,040
- -------------------------------------------------------------------------------------------
</TABLE>
(a) Operating revenues in 1996 and 1995 were reduced by $41.0 million and
$25.1 million, respectfully, as a result of the Company's sale of $202.5
million of its investment in customer-owned energy conservation measures.
(See "Operating revenues" in Management's Discussion and Analysis and Note 1
to the Consolidated Financial Statements.)
13
<TABLE>
<CAPTION>
(Continued from prior page 1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------------
Electric energy sales, KWH
(thousands):
<S> <C> <C> <C> <C> <C>
Residential 9,350,292 8,972,498 8,913,903 8,974,787 8,297,293
Commercial 6,807,465 6,538,533 6,301,568 6,175,911 5,945,284
Industrial 3,793,966 3,720,641 3,724,931 3,690,473 3,704,450
Other consumers 205,066 205,232 200,622 196,246 193,563
- --------------------------------------------------------------------------------------------
Total energy billed
to consumers 20,156,789 19,436,904 19,141,024 19,037,417 18,140,590
Unbilled energy sales -
net increase (decrease) 224,412 (158,920) (72,352) 139,329 209,565
- --------------------------------------------------------------------------------------------
Total energy sales
to consumers 20,381,201 19,277,984 19,068,672 19,176,746 18,350,155
Sales to other
electric utilities 4,556,057 3,804,382 2,832,209 924,343 1,157,885
- --------------------------------------------------------------------------------------------
Total energy sales 24,937,258 23,082,366 21,900,881 20,101,089 19,508,040
- --------------------------------------------------------------------------------------------
Per residential customer:
Annual use (KWH) 12,399 12,139 12,319 12,674 11,989
Annual billed revenue $762.35 $726.95 $735.42 $708.97 $640.79
Billed revenue per KWH $.0615 $.0599 $.0597 $.0559 $.0534
Company-owned generation
capability - kilowatts:
Hydro 309,950 309,950 309,950 309,950 309,950
Steam 771,900 771,900 771,900 857,700 857,700
Natural gas/oil 702,350 702,350 702,350 702,350 702,350
- --------------------------------------------------------------------------------------------
Total 1,784,200 1,784,200 1,784,200 1,870,000 1,870,000
- --------------------------------------------------------------------------------------------
Heating degree days 4,953 3,994 4,341 4,691 4,090
% of normal of 30 year
average (4,908) 100.9% 81.4% 88.4% 95.6% 83.3%
Load factor 55.5% 56.7% 54.7% 52.5% 57.0%
</TABLE>
14
EXECUTIVE OFFICERS AT DECEMBER 31, 1996:
Name Age Offices
- ---------------- --- ---------------------------------------------------
R. R. Sonstelie 51 President and Chief Executive Officer since 1992;
President and Chief Operating Officer 1991-1992;
President and Chief Financial Officer 1987-1991;
Executive Vice President 1985-1987;
Senior Vice President Finance 1983-1985;
Vice President Engineering and Operations 1980-1983;
Director since 1987.
W. S. Weaver 52 Executive Vice President and Chief Financial Officer
and Director since 1991. For more than five years
prior to that time, a Partner in the law firm Perkins
Coie.
G. B. Swofford 55 Senior Vice President Customer Operations since
1994; Vice President Divisions and Customer
Services 1991-1994; Vice President Rates and Customer
Programs 1986-1991; Director Conservation and
Division Services 1980-1986.
S. M. Vortman 51 Senior Vice President Corporate & Regulatory
Relations since 1994; Vice President
Strategic Planning and Regulatory Affairs
February 10, 1994 - May 9, 1994; Vice President
Corporate Services 1992-1994; Director Real Estate
1990-1992;
R. G. Bailey 57 Vice President Power Systems since 1980.
J. W. Eldredge 46 Chief Accounting Officer since 1994;
Corporate Secretary and Controller since 1993;
Controller since 1988; Manager Budgets and
Performance 1987-1988; Manager General Accounting
1984-1987.
G. N. Ferencz 50 Vice President Divisions since 1994; Director
Division Services 1992-1994; General Manager Thurston
Division 1990-1992; Division Administrator Southern
Division 1982-1990.
D. E. Gaines 39 Treasurer since 1994; Director Strategic
Planning 1992-1994; Manager Financial Planning 1986 -
1992.
J. L. Henry 51 Vice President Engineering and Operating Services
since 1994; Vice President Operations
Services 1991-1994; Director South Central Division
1990-1991; Director Division Operations 1984-1990.
Officers are elected for one-year terms.
15
ITEM 2. PROPERTIES
The principal generating plants owned by the Company are described
under Item 1 - "Business - Power Resources." The Company owns its
transmission and distribution facilities, and various other properties.
Substantially all properties of the Company are subject to the lien of the
Company's Mortgage Indenture.
ITEM 3. LEGAL PROCEEDINGS
See Note 15 to the Consolidated Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - NONE
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Company's common stock is traded on the New York Stock Exchange
(symbol PSD). The number of stockholders of record of the Company's common
stock at December 31, 1996, was 56,898.
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.
Certain provisions relating to the Company's senior securities limit
funds available for payment of dividends to net income available for
dividends on common stock (as defined in the Company's Mortgage Indenture)
accumulated after December 31, 1957, plus the sum of $7.5 million. As of
December 31, 1996, the balance of earnings reinvested in the business that
was not restricted as to dividends on common stock was approximately $254
million. (See Note 6 to the Consolidated Financial Statements.)
Dividends paid and high and low stock prices for each quarter over the
last two years were:
1996 1995
--------------------------- ---------------------------
Price Range Price Range
--------------- Dividends --------------- Dividends
Quarter Ended High Low Paid High Low Paid
- ------------- ------ ------ --------- ------ ------ ---------
March 31 25-7/8 23-5/8 $.46 21-1/2 20-1/8 $.46
June 30 25-1/2 23-1/2 $.46 23-3/8 20-3/4 $.46
September 30 24-3/8 22-1/2 $.46 23-3/8 21-1/4 $.46
December 31 24 23-1/8 $.46 24 22-1/4 $.46
16
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
Year Ended December 31
(Thousands of Dollars except per share data)
<CAPTION>
1996 1995 1994 1993 1992
- ---------------------------- --------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Operating Revenue $1,198,769 $1,179,330 $1,194,058 $1,112,878 $1,024,970
Operating Income $ 200,576 $ 214,588 $ 193,498 $ 210,980 $ 214,670
Net Income $ 135,371 $ 135,720 $ 120,059 $ 138,327 $ 135,720
Income for Common Stock $ 120,210 $ 120,192 $ 104,328 $ 121,885 $ 121,836
Common Shares Outstanding -
Weighted Average 63,640,861 63,640,861 63,632,057 60,930,859 56,283,949
Earnings Per Common Share
(Note 1 to the
Financial Statements) $1.89 $1.89 $1.64 $2.00 $2.16
Dividends Per Common Share $1.84 $1.84 $1.84 $1.83 $1.79
Book Value Per Common Share $18.53 $18.48 $18.43 $18.65 $17.76
Total Assets at Year End* $3,187,252 $3,268,995 $3,463,770 $3,341,130 $2,997,721
Long-term Obligations $ 820,664 $ 920,439 $ 963,298 $1,036,079 $1,044,992
Redeemable Preferred Stock $ 87,839 $ 89,039 $ 91,242 $ 93,176 $ 93,822
</TABLE>
* The Company adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes," effective January 1, 1993, providing deferred
taxes for items which previously had tax benefits flowed through to
ratepayers. A corresponding regulatory asset was recorded under long-term
assets. For years prior to 1993, the Company has reclassified as
liabilities deferred taxes previously netted with plant and other property
and investments.
17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Financial Condition and Results Of Operations
Net income in 1996 was $135.4 million on operating revenues of $1.199
billion, compared to $135.7 million on operating revenues of $1.179
billion in 1995 and $120.1 million on operating revenues of $1.194
billion in 1994. Income for common stock was $120.2 million for both
1996 and 1995 and $104.3 million for 1994.
Earnings per share in both 1996 and 1995 were $1.89 on 63.6 million
weighted average common shares outstanding and $1.64 on 63.6 million
weighted average common shares outstanding in 1994.
Return on the average book value of the Company's common equity was
10.3% in 1996 and 1995 and 8.9% in 1994. The dividend payout ratio was
97.4% in 1996 and 1995 and 112.2% in 1994.
Total kilowatt-hour sales to ultimate consumers in 1996 were 20.4
billion, compared with 19.3 billion in 1995 and 19.1 billion in 1994.
Kilowatt-hour sales to other utilities were 4.6 billion in 1996, 3.8
billion in 1995 and 2.8 billion in 1994.
The preferred stock dividend accrual decreased $0.4 million in 1996
compared to 1995 due to lower dividend rates on the Adjustable Rate
Cumulative Preferred Stock ("ARPS"), Series B ($100 par value). The
preferred stock dividend accrual decreased $0.2 million in 1995
compared to 1994 due to the redemption of the $40 million Adjustable
Rate Cumulative Preferred Stock ("ARPS"), Series A ($100 par value) in
February 1994. The preferred stock dividend accrual decreased $0.7
million in 1994 compared to 1993. This decrease was due to the
redemptions of the $50 million Flexible Dutch Auction Rate Transferable
Securities $100 Par Value Preferred Stock ("FLEX DARTS"), Series B in
July 1993 and the $40 million ARPS, Series A in February 1994. These
decreases were partially offset by the issuance in February 1994 of the
$50 million ARPS, Series B ($25 par value).
18
Increase (Decrease) Over Preceding Year
Years Ended December 31
(Dollars in Millions)
1996 1995 1994
- ------------------------------------------------------------------------
Operating revenues
General rate increase $ -- $ -- $ 27.0
PRAM surcharge billed 41.2 53.5 29.6
Accrual of revenue under
the PRAM - Net (78.3) (21.9) (16.3)
BPA Residential Purchase and
Sale Agreement (15.8) (25.3) 2.3
Sales to other utilities 15.1 (8.0) 41.0
Revenue sold to conservation trust (15.9) (25.1) --
Load and other changes 73.1 12.1 (2.4)
- ------------------------------------------------------------------------
Total operating revenue changes 19.4 (14.7) 81.2
- ------------------------------------------------------------------------
Operating expenses
Purchased and interchanged power 18.6 14.8 77.1
Fuel 5.0 (11.5) (5.5)
Other operation expenses 2.5 (38.7) 26.0
Maintenance (2.7) 1.8 (2.5)
Depreciation and amortization 1.2 (8.2) 0.1
Taxes other than federal income taxes 7.1 1.7 7.2
Federal income taxes 1.7 4.3 (3.7)
- ------------------------------------------------------------------------
Total operating expense changes 33.4 (35.8) 98.7
- ------------------------------------------------------------------------
Allowance for funds used during
construction ("AFUDC") (0.9) 0.8 (0.8)
Other income 4.7 (5.3) 1.0
Interest charges (9.9) 0.9 1.0
- ------------------------------------------------------------------------
Net income changes $ (0.3) $15.7 $(18.3)
========================================================================
The following information pertains to the changes outlined in the table
above:
Operating Revenues
Revenues since October 1, 1995, increased as a result of rates authorized by
the Washington Utilities and Transportation Commission (the "Washington
Commission") under the fifth Periodic Rate Adjustment Mechanism ("PRAM")
filing. Revenues since October 1, 1994, increased as a result of rates
authorized by the Washington Commission under the fourth PRAM filing.
Revenues since October 1, 1993, increased as a result of rates authorized by
the Washington Commission in its general rate order issued on September 21,
1993. The PRAM was terminated effective September 30, 1996. (See "Rate
Matters.")
Revenues have been reduced by virtue of the credit that the Company received
through the Residential Purchase and Sale Agreement with the Bonneville
Power Administration ("BPA"). This agreement enables the Company's
residential and small farm customers to receive the benefits of lower-cost
federal power. A corresponding reduction is included in purchased and
19
interchanged power expenses. On January 29, 1997, the Company and the BPA
signed a Residential Exchange Termination Agreement. The Agreement
effectively ends the Company's participation in the Residential Purchase and
Sale Agreement in exchange for settlement payments by the BPA of
approximately $237 million over five years. (See "Other" for a discussion of
the Residential Exchange Termination Agreement.)
Revenues in 1996 and 1995 have been reduced by $41.0 million and $25.1
million as a result of the CompanyOs sale of revenues associated with $202.5
million of its investment in conservation assets to a grantor trust. The
revenue decrease represents the portion of rate revenues that were sold and
forwarded to the trust. The impact of this revenue decrease, however, was
offset by related reductions in other operation and interest expenses. (See
OOtherO for a discussion of the sale of conservation assets.)
To meet customer demand, the Company's power supply portfolio includes net
purchases of power under long-term supply contracts. However, depending
principally upon streamflow available for hydroelectric generation and
weather effects on customer demand, from time to time the Company may have
surplus power available for sale at wholesale to other utilities. In
addition, the Company intends to increase its wholesale surplus power
business through short and intermediate term purchase, sale, arbitrage and
other trading and marketing techniques.
Operating Expenses
Purchased and interchanged power expenses increased $18.6 million in 1996
when compared to 1995. Higher payments for firm power purchases from non-
utility generators and secondary power purchases from other utilities
contributed an increase of $34.5 million. This increase was partially
offset by increased credits associated with the Residential Purchase and
Sale Agreement with BPA of $15.2 million. (See discussion of the
Residential Purchase and Sale Agreement under "Operating revenues.")
Purchased and interchanged power expenses increased $14.8 million in 1995
when compared to 1994. Higher payments for firm power purchases from non-
utility generators and secondary power purchases from other utilities
contributed an increase of $35.4 million. This increase was partially
offset by increased credits associated with the Residential Purchase and
Sale Agreement with BPA of $24.1 million.
Purchased and interchanged power expenses increased $77.1 million in 1994
when compared to 1993. Higher payments related to new firm power purchase
contracts from non-utility generators contributed an increase of $89.3
million. Also contributing to the increase was a reduction in credits
associated with the Residential Purchase and Sale Agreement with BPA of $2.2
million. Partially offsetting these increases were lower secondary power
purchases from other utilities of $15.6 million.
Fuel expense increased $5.0 million in 1996. The increase was due in part
to an Arbitration PanelOs decision in 1995 of a dispute involving the coal
supply agreement at the CompanyOs fifty percent-owned Colstrip 1 and 2
plants that resulted in a $4.6 million decrease to fuel expense recorded in
the first quarter of 1995. In addition, the Company recorded a one-time
charge of $1.8 million in the second quarter of 1996 relating to a loss on
the sale of oil stocks at a combustion turbine site.
Fuel expense decreased $11.5 million in 1995 compared to 1994 as the Company
generated less electricity at company-owned coal plants while purchasing
20
more power on the secondary market. Additionally, an Arbitration PanelOs
decision of a dispute involving the coal supply agreement at the CompanyOs
fifty percent-owned Colstrip 1 and 2 plants resulted in a $4.6 million
decrease to fuel expense in the first quarter of 1995 pertaining to coal
deliveries from August 1, 1991, through March 31, 1995. Fuel expense
decreased $5.5 million in 1994 as the Company purchased additional power
from cogeneration facilities rather than run Company-owned gas turbines.
Other operation expenses increased $2.5 million in 1996 when compared to
1995. The increase was due primarily to $7.8 million increase in
transmission and distribution expenses, caused in part by a severe wind
storm in November 1996. In addition, the Company expensed certain merger
integration costs of approximately $4.8 million. These increases were
partially offset by an $11.6 million decrease in amortization expense
associated with the Company's conservation program. In June 1995 the
Company sold, to a grantor trust, approximately $202.5 million of its
investment in customer-owned energy conservation measures. (See discussion
of the conservation asset transaction in "Other.")
Other operation expenses decreased $38.7 million in 1995 when compared to
1994. The decrease was due in part to charges in 1994 totaling $20.9
million associated with the Company's two voluntary early retirement and
separation programs and related business office and service facility
consolidations. (See Note 10 to the Consolidated Financial Statements.)
Also contributing to the decrease was lower amortization expense of $14.3
million associated with the CompanyOs sale, in June 1995, of $202.5 million
of its investment in customer-owned energy conservation measures.
Other operation expenses increased $26.0 million in 1994 when compared to
1993. Included in the increase were charges totaling $20.9 million
reflecting costs associated with the Company's two voluntary early
retirement and separation programs and related business office and service
facility consolidations. Also included was an increase of $4.0 million in
amortization expense associated with the Company's energy conservation
program and an increase of $1.8 million in transmission and distribution
expenses.
Maintenance expense decreased $2.7 million in 1996 as compared to 1995. The
decrease was primarily the result of lower maintenance expense at the
CompanyOs Colstrip and Centralia coal-fired generation projects.
Maintenance expense increased $1.8 million in 1995 over 1994 due primarily
to higher distribution maintenance expenses in the first and fourth quarters
of 1995 resulting from storm damage to Company transmission and distribution
facilities. Maintenance expense in 1994 was lower by $2.5 million due
primarily to a $4.4 million decrease in distribution maintenance expense.
This decrease was partially offset by a $1.3 million increase in
administration and general maintenance expense.
Depreciation and amortization expense increased $1.2 million in 1996 from
1995 levels due primarily to the effects of new electric plant placed into
service during 1996.
Depreciation and amortization expense decreased $8.2 million in 1995 from
1994 levels. A decrease of $12.9 million was attributable to the completion
in September 1994, of the 10 year amortization period related to two
terminated generating projects. This decrease was partially offset by the
effects of new plant placed into service.
21
Depreciation and amortization expense increased $0.1 million in 1994
compared to the prior year. Increased depreciation expense related to
additional plant placed into service was offset by the completion of the 10
year amortization period related to two terminated generating projects.
Taxes other than federal income taxes increased $7.1 million in 1996
compared to 1995. The increase was due primarily to higher Washington state
property tax payments of $2.9 million and higher revenue-based municipal and
state excise tax payments of $3.0 million.
Taxes other than federal income taxes increased $1.7 million in 1995
compared to 1994. Municipal and state excise tax payments increased $3.5
million and were partially offset by lower property tax payments of $0.8
million and other federal and state taxes of $1.0 million. Taxes other than
federal income taxes increased $7.2 million in 1994 compared to the prior
year. Municipal and state excise taxes, which are revenue-based, were
higher by $4.5 million. Also contributing to the increase were higher
Washington and Montana state property tax payments of $1.4 million.
Federal income taxes on operations increased $1.7 million in 1996 over 1995.
The increase was due primarily to a decrease in energy conservation
expenditures in 1996 which are deducted for federal income taxes. Federal
income taxes on operations increased $4.3 million in 1995 compared to the
prior year due primarily to higher pre-tax operating income during 1995.
Federal income taxes on operations decreased $3.7 million in 1994 due
primarily to lower pre-tax operating income during 1994.
AFUDC
(See Note 1 to the Consolidated Financial Statements.)
Other Income
Total other income increased $4.7 million in 1996. The increase was due
primarily to increased earnings of subsidiaries of $6.4 million offset by
lower interest income of $1.0 million. The increased earnings from
subsidiaries were due to increased profits from property sales of the
Company's real estate subsidiary. Cash received from these sales, which
totaled $39.0 million, has been paid to the Company and is recorded on the
Statement of Cash Flows as "Cash received from subsidiaries."
Other income decreased $5.3 million in 1995. The decrease was due in part
to lower energy conservation expenditures resulting in a $2.2 million
decline in Allowance for Funds Used to Conserve Energy ("AFUCE") and a $1.4
million decrease in excess AFUDC over the Federal Energy Regulatory
Commission ("FERC") maximum allowed by the Washington Commission. Also
contributing to the decrease were higher non-utility expenses of $0.9
million when compared to 1994.
Other income increased $1.0 million in 1994 over 1993. Included was an
increase in subsidiary earnings of $2.2 million due primarily to an after-
tax gain of $1.9 million resulting from the sale of a small hydroelectric
generating project by the Company's Hydro Energy Development Corporation
subsidiary. Cash received from the sale, which totaled $30.1 million, is
recorded on the Statement of Cash Flows as "Cash received from subsidiary."
22
Interest Charges
Interest charges, which consist of interest and amortization on long-term
debt and other interest, decreased $9.9 million in 1996 compared to 1995.
Interest and amortization on long-term debt decreased $8.0 million.
Contributing $7.5 million in reduced interest expense were five First
Mortgage Bond retirements or redemptions totaling $151 million over the
previous 17 months.
Other interest expense decreased $1.9 million in 1996 over 1995. The
decrease was the result of lower weighted average interest rates and lower
average daily short-term borrowings in 1996 as compared to 1995.
Interest charges increased $0.9 million in 1995 compared to 1994. Interest
and amortization on long-term debt decreased $3.0 million. Contributing
$4.3 million in reduced interest expense were five First Mortgage Bond
retirements or redemptions totaling $181 million over the previous 23
months. Partially offsetting this was $1.3 million in new interest expense
associated with two issues of Secured Medium-Term Notes totaling $85 million
that were issued during the same period. Other interest expense increased
$3.9 million in 1995 over 1994. The increase was the result of higher
weighted average interest rates and higher average daily short-term
borrowings in 1995 as compared to 1994.
Interest charges increased $1.0 million in 1994. Interest and amortization
on long-term debt decreased $1.9 million. Contributing $8.1 million in
reduced interest expense were eight First Mortgage Bond and Secured Medium-
Term Note retirements or redemptions totaling $191 million over the previous
22 months. Partially offsetting this was $6.4 million in new interest
expense associated with nine issues of Secured Medium-Term Notes totaling
$169 million issued over the previous 23 months. Other interest expense
increased $2.9 million in 1994 due to higher average daily short-term
borrowings and higher weighted average interest rates in 1994 as compared to
1993.
Construction and Financing Program
Current construction expenditures are primarily transmission and
distribution-related, designed to meet continuing customer growth.
Construction expenditures, which include energy conservation expenditures
and exclude AFUDC and AFUCE, were $115.8 million in 1996. The Company
expects combined electric and gas construction expenditures for the period
1997 through 1999 will be approximately $247 million, $252 million and $226
million, respectively. The ratio of cash from operations (net of dividends,
AFUDC and AFUCE) to construction expenditures (excluding AFUDC and AFUCE)
was 144.4% in 1996. The Company expects cash from operations (net of
dividends and AFUDC) during the period 1997 through 1999 will, on average,
be approximately 73% of average estimated construction expenditures
(excluding AFUDC) during the same period.
In October 1992, 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 $450 million principal amount of First Mortgage
Bonds. The First Mortgage Bonds can be issued as Secured Medium-Term Notes,
through underwritten offerings, pursuant to delayed delivery contracts or
any combination thereof. These Secured Medium-Term Notes were designated
Series B. As of February 10, 1997, the Company has issued $364 million in
Series B Notes having an average coupon rate of 6.90%.
23
Short-term borrowings from banks and the sale of commercial paper are used
to provide working capital for the construction program. At December 31,
1996, the Company had in place $176.5 million in lines of credit with
several banks, which provided liquidity support for outstanding commercial
paper of $88.7 million, effectively reducing the available borrowing
capacity under these lines of credit to $87.8 million. (See Note 8 to the
Consolidated Financial Statements.)
Rate Matters
In the Washington Commission's September 21, 1993, general rate case order,
the Company was allowed a 10.5% return on common equity and 8.94% return on
rate base, based on a capital structure of 47% debt, 8% preferred stock and
45% common equity.
On September 22, 1995, the Washington Commission issued a rate order
relating to the Company's fifth annual rate adjustment under the PRAM. In
addition to approval of the rate adjustment, the Commission also agreed,
pursuant to a negotiated settlement, to discontinue the PRAM on September
30, 1996. PRAM accrued revenues of $40.5 million, recorded at December 31,
1996, were recovered in the first quarter of 1997. Over-collection of PRAM
revenues, if any, are expected to be refunded to customers in the second
quarter of 1997.
With the discontinuance of the PRAM, the annual regulatory adjustments for
variations in weather and hydro conditions provided for in the PRAM were
also discontinued.
On September 30, 1996, the Washington Commission issued an order granting a
joint motion by the Company and the Washington Commission Staff to transfer
annual revenues of $165.5 million which were being collected in PRAM rates
to the Company's permanent rate schedules. As a result of the order, the
Company also wrote off $4.5 million in previously accrued revenues related
to special industrial customer service contracts.
The Merger
On February 7, 1997, the Boards of the Company and Washington Energy Company
(WECo) approved the merger of their respective companies effective
February 10, 1997. The merged company is called Puget Sound Energy, Inc.
This announcement followed the approval by the Washington Commission, on
February 5, 1997, of a merger agreement between the Company, WECo, the Staff
of the Washington Commission and the Public Counsel Section of the State
Attorney General's Office. Shareholders of the Company and WECo, voting as
separate groups had, on March 20, 1996, already given their approval to an
Agreement and Plan of Merger ("Merger Agreement") between the two companies.
The order approving the merger contains a rate plan that is designed to
provide a five-year period of rate certainty for customers and provide the
Company with an opportunity to achieve a reasonable return on investment.
As required under the merger order, the Company filed tariffs, effective
February 8, 1997, that resulted in an average electric rate decrease of 5.6%
related to the PRAM, and an increase in general rates of between 1.0% and
2.5%, depending on rate class. The net impact was an average rate decrease
of 3.7%, including a decrease in residential rates of 3.24%. General
electric rates for residential and industrial customers will increase by
1.5% on January 1 of each of the four following years, while those for small
commercial customers will increase by 1.0% in each of the following three
years. General rates for all classes of natural gas customers will remain
24
unchanged until January 1, 1999, when they will decrease sufficiently to
reduce utility margin by 1 percent. (See Note 18 to the Consolidated
Financial Statements.)
Other
The U.S. electric utility industry is facing an increasingly competitive
environment, particularly in wholesale generation and industrial customer
markets. The National Energy Policy Act of 1992 ("EPACT") intensified
competition in the wholesale electric market by easing restrictions on
wholesale power producers and by allowing the Federal Energy Regulatory
Commission ("FERC") to order access for wholesale sellers to deliver power to
wholesale buyers over transmission systems owned by others. In 1996 FERC
issued its landmark Orders 888 and 889, which require jurisdictional
utilities, including the Company, to file wholesale transmission tariffs
providing pricing and terms for transmission access for wholesale purposes.
The EPACT does not permit the FERC to order transmission access for retail
purposes, but Congress now has pending bills that would require existing
utilities to allow competitors to use utility property, including
transmission and distribution facilities, to provide electric service to
retail customers of the existing utilities. Several states, including
California, New Hampshire and Rhode Island have enacted legislation to allow
such use by competitors of utility property. Most other states, including
Washington, are considering legislative or regulatory proposals which would
also allow such use of utility property by competitors to serve the retail
customers of the existing utilities. In its February 5, 1997 Order approving
the Company's merger with Washington Energy Company described above, the
Washington Commission required the Company to conduct a retail access pilot
program. Any substantial change in utility regulation in Washington state,
such as requiring utilities to allow use of utility property by competitors
for retail purposes, would require legislative action and would be subject to
court review. The major credit rating agencies have expressed the general
view that increased competition is likely to increase business risks in the
electric utility industry, with resulting pressures on utility credit quality
and investor returns.
In this environment, the Company seeks to build on the strengths of its
efficient electric distribution and transmission system to become a leading
provider of energy and related services to homes and businesses in the
Pacific Northwest, and to streamline its energy supply operations. To
prepare for a more competitive business environment, the Company has
committed itself to being a low cost supplier of electricity. The Company
has taken steps to reduce costs, including work force reductions, facility
consolidations and reductions in capital budgets. The Company intends to
pursue opportunities for improved operating efficiencies and productivity,
including possible restructuring of its power supply resources and
contracts. The Company is also actively pursuing opportunities to become a
provider of new high value services such as wireless automated meter-based
services and geographic information systems, to utility customers and other
utilities.
The Company and BPA have entered into a letter of intent, subject to various
conditions, regarding pursuit of construction of a joint transmission
project in Whatcom and Skagit counties in northern Washington state, the
northernmost portion of the Company's service territory. The joint project
is intended to provide the Company and BPA with certain transfer capacity
with Canadian utilities and is intended to relieve certain transmission
constraints on the respective systems of BPA and the Company. The joint
25
project, which is expected to be completed in late 1997, will involve a
combination of existing facility upgrades and new construction.
On May 24, 1996, the Company filed a proposal with the Washington Commission
to create an Optional Large Power Sales Rate for its largest customers.
Under the Company's proposal, customers who elect the Optional Large Power
Sales Rate would no longer be considered "core" customers. Instead, they
would form a new class of "non-core" customers, and the Company would no
longer have an obligation to plan for future resources to serve their needs.
The non-core customers will receive access to electric energy that is priced
at current market cost and will pay a charge for energy delivery (including
a charge for conservation programs) and a transition charge (representing
the difference between the Company's present cost and the current market
cost of electric energy and capacity). The transition charge will be phased
out before the end of the year 2000. Non-core customers also would take on
the risk that market costs could become volatile and that electricity could
be unavailable on the open market. On October 9, 1996, the Washington
Commission approved the Company's proposal and ordered the new optional
large power sales tariff into effect November 1, 1996.
On January 29, 1997, the Company and BPA signed a Residential Exchange
Termination Agreement. The Agreement ends the Company's participation in
the Residential Purchase and Sale Agreement with BPA. The Residential
Purchase and Sale Agreement enabled the Company's residential and small farm
customers to receive the benefits of lower-cost federal power. As part of
the Termination Agreement, the Company will receive payments by the BPA of
approximately $237 million over five years. Under the rate plan approved by
the Washington Commission in its merger order, the Company will continue to
reflect, in customers' bills, the current level of Residential Exchange
benefits. Over the five year period, it is projected that the Company will
credit customers approximately $250 million more than it will receive from
BPA. The Company expects the difference will be made up through the general
rate increases approved in the merger order and additional reductions in
operating expenses.
On July 12, 1996, the Company and several other Northwest electric companies
signed a memorandum of understanding to study the creation of an independent
transmission grid operator called "IndeGO." Participation in IndeGO would
be open to all transmission owners in the Northwest and would include both
investor-owned utilities and certain government-owned power agencies.
The Company's energy conservation expenditures have historically been
accumulated, included in rate base and amortized to expense over a ten year
period at the direction of the Washington Commission. In June 1995 the
Company sold approximately $202.5 million of its investment in customer-
owned energy conservation measures to a grantor trust, which, in turn,
issued securities backed by a Washington state statute enacted in 1994. The
statute provides that if certain conditions are met, securities could be
issued, backed by a statutory requirement that a portion of rate revenues be
forwarded to the trust to repay those securities. The proceeds of the sale
were used to pay down short-term debt. The Company recognized no gain or
loss on the sale.
The Company is in the process of selectively replacing the High Molecular
Weight ("HMW") underground distribution cable installed during the 1960s and
1970s. The Company installed about 4,800 miles of standard HMW cable
between 1964 and 1979, but the Company and other utilities have experienced
increasing cable failures in recent years. The Company is continuing to
analyze cable failure trends to find ways to mitigate the effect of cable
26
failures on customer service. To minimize the impact on customers of
increasing cable failures, the Company replaces a certain amount of HMW
cable each year and is beginning to use silicone injection to lengthen the
life of potentially problem cables. The Company so far has replaced 780
miles and injected 20 miles of HMW cable. The Company expects to spend $49
million on additional cable replacement during the period 1997-2000. In
1997 the Company is planning either to replace or use silicone injection on
150 miles of HMW cable.
For a discussion of environmental obligations, see Note 15 to the
Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See index on page 32.
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 1995 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 32.
2) Exhibits - see index on page 63.
(b) Reports on Form 8-K:
1) Form 8-k dated December 12, 1996, Item 5 - Other Events,
related to stipulated settlement agreement filed with the
Washington Utilities and Transportation Commission.
27
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
PUGET SOUND ENERGY, INC.
By s/s R. R. Sonstelie
____________________________________
R. R. Sonstelie
Chairman and Chief Executive Officer
Date: March 13, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
___________________________ ____________________________ _____________
s/s R. R. Sonstelie Chairman,
___________________________ Chief Executive Officer
(R. R. Sonstelie) and Director
s/s William S. Weaver Vice Chairman,
___________________________ Chairman of Unregulated
(William S. Weaver) Subsidiaries and Director
s/s James P. Torgerson Vice President and
___________________________ Chief Financial Officer March 13, 1997
(James P. Torgerson)
s/s James W. Eldredge Corporate Secretary
___________________________ and Controller and
(James W. Eldredge) Chief Accounting Officer
s/s Douglas P. Beighle Director
___________________________
(Douglas P. Beighle)
s/s Charles W. Bingham Director
___________________________
(Charles W. Bingham)
28
Signatures, continued
s/s Phyllis J. Campbell Director
___________________________
(Phyllis J. Campbell)
s/s Donald J. Covey Director
___________________________
(Donald J. Covey)
s/s Robert L. Dryden Director
___________________________
(Robert L. Dryden)
s/s John D. Durbin Director
___________________________
(John D. Durbin)
s/s John W. Ellis Director
___________________________
(John W. Ellis)
s/s Daniel J. Evans Director
___________________________
(Daniel J. Evans)
Director
___________________________
(Nancy L. Jacob)
s/s Tomio Moriguchi Director
___________________________
(Tomio Moriguchi)
s/s Sally G. Narodick Director
___________________________
(Sally G. Narodick)
s/s R. Kirk Wilson Director
___________________________
(R. Kirk Wilson)
29
Puget Sound Energy, Inc.
Report of Management:
The accompanying consolidated financial statements of Puget Sound Energy,
Inc. have been prepared under the direction of management, which is
responsible for their integrity and objectivity. The statements have been
prepared in accordance with generally accepted accounting principles and
include amounts based on judgments and estimates by management where
necessary. Management also prepared the other information in the Annual
Report on Form 10-K and is responsible for its accuracy and consistency with
the financial statements.
The Company maintains a system of internal control which, in management's
opinion, provides reasonable assurance that assets are properly safeguarded
and transactions are executed in accordance with management's authorization
and properly recorded to produce reliable financial records and reports. The
system of internal control provides for appropriate division of
responsibility and is documented by written policy and updated as necessary.
The Company's internal audit staff assesses the effectiveness and adequacy of
the internal controls on a regular basis and recommends improvements when
appropriate. Management considers the internal auditor's and independent
auditor's recommendations concerning the Company's internal controls and
takes steps to implement those that they believe are appropriate in the
circumstances.
In addition, Coopers & Lybrand L.L.P., the independent auditors, have
performed audit procedures deemed appropriate to obtain reasonable assurance
about whether the financial statements are free of material misstatement.
The Board of Directors pursues its oversight role for the financial
statements through the audit committee, which is composed solely of outside
Directors. The audit committee meets regularly with management, the internal
auditors and the independent auditors, jointly and separately, to review
management's process of implementation and maintenance of internal accounting
controls and auditing and financial reporting matters. The internal and
independent auditors have unrestricted access to the audit committee.
s/s R. R. Sonstelie s/s William S. Weaver s/s James W. Eldredge
____________________ _______________________ _______________________
R. R. Sonstelie William S. Weaver James W. Eldredge
Chairman and Vice Chairman and Corporate Secretary
Chief Executive Officer Chairman of Unregulated and Controller
Subsidiaries (Chief Accounting Officer)
30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of
Puget Sound Energy, Inc.
We have audited the consolidated financial statements and the financial
statement schedule of Puget Sound Energy, Inc. (formerly Puget Sound Power &
Light Company) listed on page 32 of this Annual Report on Form 10-K. These
financial statements and financial statement schedule are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements and financial statement schedule based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Puget Sound
Energy, Inc. as of December 31, 1996 and 1995, and the consolidated results
of its operations and its cash flows for each of the three years in the
period ended December 31, 1996 in conformity with generally accepted
accounting principles. In addition, in our opinion, the financial statement
schedule referred to above, when considered in relation to the basic
financial statements taken as a whole, presents fairly, in all material
respects, the information required to be included therein.
Coopers & Lybrand L.L.P.
Seattle, Washington
February 12, 1997
31
PUGET SOUND ENERGY, INC.
CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
COVERED BY THE FOREGOING REPORT OF INDEPENDENT ACCOUNTANTS
CONSOLIDATED FINANCIAL STATEMENTS: Page
Consolidated Balance Sheets, December 31, 1996 and 1995.................33
Consolidated Statements of Capitalization, December 31, 1996 and 1995...35
Consolidated Statements of Income for the years ended
December 31, 1996, 1995 and 1994......................................36
Consolidated Statements of Earnings Reinvested in the Business
for the years ended December 31, 1996, 1995 and 1994..................37
Consolidated Statements of Cash Flows for the years
ended December 31, 1996, 1995 and 1994................................38
Notes to Consolidated Financial Statements..............................39
SCHEDULE:
II. Valuation and Qualifying Accounts and Reserves for the
years ended December 31, 1996, 1995 and 1994......................62
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.
32
<TABLE>
Consolidated Balance Sheets
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------------------
<CAPTION>
Assets
December 31
(Dollars in Thousands) 1996 1995
- ----------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant:
Electric plant, at original cost (Notes 2, 7 and 15) $3,479,652 $3,400,723
Less: Accumulated depreciation 1,188,576 1,118,678
- ----------------------------------------------------------------------------------------
Net utility plant 2,291,076 2,282,045
- ----------------------------------------------------------------------------------------
Other Property and Investments:
Investment in Bonneville Exchange Power Contract 86,772 94,241
Investment in and advances to subsidiaries 73,957 95,459
Energy conservation loans to customers 415 783
Other investments, at cost 16,988 11,328
- ----------------------------------------------------------------------------------------
Total other property and investments 178,132 201,811
- ----------------------------------------------------------------------------------------
Current Assets:
Cash (Note 9) 3,736 12,498
- ----------------------------------------------------------------------------------------
Accounts receivable:
Customers 96,435 90,345
Other 41,149 34,627
Less allowance for doubtful accounts 770 886
- ----------------------------------------------------------------------------------------
Total accounts receivable 136,814 124,086
- ----------------------------------------------------------------------------------------
Estimated unbilled revenue 93,563 80,363
PRAM accrued revenues 40,470 59,123
Materials and supplies, at average cost 36,683 46,407
Prepayments and Other 3,911 4,352
- ----------------------------------------------------------------------------------------
Total current assets 315,177 326,829
- ----------------------------------------------------------------------------------------
Long-Term Assets:
Regulatory asset for deferred income taxes (Note 12) 234,095 249,731
PRAM accrued revenues (net of current portion) -- 55,673
Unamortized debt expense 9,062 10,264
Unamortized energy conservation charges 41,734 37,889
Other 117,976 104,753
- ----------------------------------------------------------------------------------------
Total long-term assets 402,867 458,310
- ----------------------------------------------------------------------------------------
Total Assets $3,187,252 $3,268,995
========================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
- ----------------------------------
33
<TABLE>
<CAPTION>
Capitalization and Liabilities
December 31
(Dollars in Thousands) 1996 1995
- ----------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization
(See "Consolidated Statements of Capitalization"):
Common equity $1,179,026 $1,175,904
Preferred stock not subject to mandatory redemption 125,000 125,000
Preferred stock subject to mandatory redemption 87,839 89,039
Long-term debt 820,664 920,439
- ----------------------------------------------------------------------------------------
Total capitalization 2,212,529 2,310,382
- ----------------------------------------------------------------------------------------
Current Liabilities:
Accounts payable 71,690 50,269
Short-term debt (Notes 8 and 9) 120,413 167,049
Current maturities of long-term debt (Note 7) 99,922 43,000
Accrued expenses:
Taxes 38,335 36,321
Salaries and wages 24,013 22,011
Interest 21,878 22,921
Other 28,685 27,356
- ----------------------------------------------------------------------------------------
Total current liabilities 404,936 368,927
- ----------------------------------------------------------------------------------------
Deferred Income Taxes:
Deferred income taxes (Note 12) 500,638 528,400
Investment tax credits -- 311
- ----------------------------------------------------------------------------------------
Total deferred income taxes 500,638 528,711
- ----------------------------------------------------------------------------------------
Other Deferred Credits:
Customer advances for construction 20,405 19,972
Other 48,744 41,003
- ----------------------------------------------------------------------------------------
Total other deferred credits 69,149 60,975
- ----------------------------------------------------------------------------------------
Commitments and Contingencies
(Notes 1, 11, 12, 13, 14, 15 and 18) -- --
- ----------------------------------------------------------------------------------------
Total Capitalization and Liabilities $3,187,252 $3,268,995
========================================================================================
34
</TABLE>
The accompanying notes are an integral part of the financial statements.
<TABLE>
<CAPTION>
Consolidated Statements of Capitalization
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------------------
December 31
(Dollars in Thousands) 1996 1995
- ----------------------------------------------------------------------------------------
<S> <C> <C>
Common Equity:
Common stock - ($10 stated value) - 80,000,000 shares
authorized, 63,640,861 shares
outstanding (Notes 3 and 14) $ 636,409 $ 636,409
Additional paid-in capital (Notes 5 and 14) 328,963 328,963
Earnings reinvested in the business (Note 6) 213,654 210,532
- ----------------------------------------------------------------------------------------
Total common equity 1,179,026 1,175,904
- ----------------------------------------------------------------------------------------
Preferred Stock Not Subject to Mandatory
Redemption - cumulative (Note 3):
$25 par value:*
7.875% series - 3,000,000 shares authorized and outstanding 75,000 75,000
Adjustable Rate, Series B - 2,000,000 shares authorized
and outstanding 50,000 50,000
- ----------------------------------------------------------------------------------------
Total preferred stock not subject to mandatory redemption 125,000 125,000
- ----------------------------------------------------------------------------------------
Preferred Stock Subject To Mandatory Redemption - cumulative
(Notes 4 and 9):
$100 par value:*
4.84% series - 150,000 shares authorized,
47,956 shares outstanding 4,796 4,796
4.70% series - 150,000 shares authorized,
56,215 shares outstanding 5,621 5,621
8% series - 150,000 shares authorized,
24,224 and 36,224 shares outstanding 2,422 3,622
7.75% series - 750,000 shares authorized and outstanding 75,000 75,000
- ----------------------------------------------------------------------------------------
Total preferred stock subject to mandatory redemption 87,839 89,039
- ----------------------------------------------------------------------------------------
Long-Term Debt (Notes 7 and 9):
First mortgage bonds 759,000 794,000
Guaranteed collateralized bonds -- 8,000
Pollution control revenue bonds:
Revenue refunding 1991 series, due 2021 50,900 50,900
Revenue refunding 1992 series, due 2022 87,500 87,500
Revenue refunding 1993 series, due 2020 23,460 23,460
Other notes 19 21
Unamortized discount - net of premium (293) (442)
Long-term debt due within one year (99,922) (43,000)
- ----------------------------------------------------------------------------------------
Total long-term debt excluding current maturities 820,664 920,439
- ----------------------------------------------------------------------------------------
Total Capitalization $2,212,529 $2,310,382
========================================================================================
</TABLE>
* 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 financial statements.
35
<TABLE>
<CAPTION>
Consolidated Statements of Income
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands except per share amounts) 1996 1995 1994
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues $1,198,769 $1,179,330 $1,194,058
- ----------------------------------------------------------------------------------------
Operating Expenses:
Operation (Note 15):
Purchased and interchanged power 428,172 409,541 394,758
Fuel 40,645 35,658 47,166
Other (Notes 10 and 11) 167,265 164,735 203,476
Maintenance 50,456 53,148 51,342
Depreciation and amortization 108,752 107,582 115,738
Taxes other than federal income taxes (Note 10) 116,661 109,533 107,821
Federal income taxes (Note 12) 86,242 84,545 80,259
- ----------------------------------------------------------------------------------------
Total operating expenses 998,193 964,742 1,000,560
- ----------------------------------------------------------------------------------------
Operating Income 200,576 214,588 193,498
- ----------------------------------------------------------------------------------------
Other Income:
Allowance for funds used during
construction - equity portion 231 719 530
Miscellaneous - net of taxes (Notes 10 and 12) 11,629 6,957 12,290
- ----------------------------------------------------------------------------------------
Total other income - net 11,860 7,676 12,820
- ----------------------------------------------------------------------------------------
Income Before Interest Charges 212,436 222,264 206,318
- ----------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 69,757 77,224 80,213
Allowance for funds used during
construction - debt portion (3,919) (4,292) (3,667)
Other interest 7,850 9,722 5,782
Amortization of debt expense,
net of premium (Note 7) 3,377 3,890 3,931
- ----------------------------------------------------------------------------------------
Total interest charges 77,065 86,544 86,259
- ----------------------------------------------------------------------------------------
Net Income 135,371 135,720 120,059
- ----------------------------------------------------------------------------------------
Less Preferred Stock Dividend Accruals 15,161 15,528 15,731
- ----------------------------------------------------------------------------------------
Income for Common Stock $ 120,210 $ 120,192 $ 104,328
- ----------------------------------------------------------------------------------------
Common shares outstanding weighted average 63,640,861 63,640,861 63,632,057
Earnings per common share $ 1.89 $ 1.89 $ 1.64
========================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
36
<TABLE>
<CAPTION>
Consolidated Statements of Earnings Reinvested in the Business
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands except per share amounts) 1996 1995 1994
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at Beginning of Year $210,532 $207,567 $220,259
Net Income 135,371 135,720 120,059
- ----------------------------------------------------------------------------------------
Total 345,903 343,287 340,318
- ----------------------------------------------------------------------------------------
Deductions:
Dividends Declared:
Preferred stock:
$4.84 per share on 4.84% series 232 232 242
$4.70 per share on 4.70% series 265 276 319
$8.00 per share on 8% series 218 314 410
$7.75 per share on 7.75% series 5,813 5,813 5,813
$1.97 per share on 7.875% series 5,906 5,906 5,906
Adjustable Rate, Series A -- -- 700
Adjustable Rate, Series B 2,716 3,115 2,277
Common stock 117,099 117,099 117,084
- ----------------------------------------------------------------------------------------
Total deductions 132,249 132,755 132,751
- ----------------------------------------------------------------------------------------
Balance at End of Year (Note 6) $213,654 $210,532 $207,567
- ----------------------------------------------------------------------------------------
Dividends declared per common share $ 1.84 $ 1.84 $ 1.84
========================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
37
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
Puget Sound Energy, Inc.
- ----------------------------------------------------------------------------------------
Year Ended December 31 1996 1995 1994
(Dollars in Thousands)
- ----------------------------------------------------------------------------------------
Operating Activities:
<S> <C> <C> <C>
Net income $135,371 $135,720 $120,059
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 108,752 107,582 115,738
Deferred income taxes and tax credits - net (12,437) 12,049 17,762
PRAM accrued revenues - net 74,326 (3,955) (25,835)
Other (11,915) 17,878 37,283
Change in certain current assets and
liabilities (Note 17) 9,961 (17,564) (5,979)
- ----------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 304,058 251,710 259,028
- ----------------------------------------------------------------------------------------
Investing Activities:
Construction expenditures - excluding equity AFUDC (114,037) (119,294) (213,982)
Additions to energy conservation program (6,683) (15,156) (36,648)
Cash received from subsidiaries 39,000 -- 30,136
Cash received from sale of conservation assets - net -- 199,452 --
Other (including advances to subsidiaries) (7,985) 702 (7,241)
- ----------------------------------------------------------------------------------------
Net Cash Provided (Used) by Investing Activities (89,705) 65,704 (227,735)
- ----------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in short-term debt (46,636) (67,405) 85,148
Dividends paid (net of newly issued shares
totaling $239,000 in 1994) (132,249) (132,755) (132,513)
Issuance of common and preferrred stock
(Notes 3, 4 and 5) -- -- 50,000
Issuance of bonds (Note 7) -- -- 85,000
Redemption of bonds and notes (43,002) (108,004) (73,014)
Redemption of preferred stock (1,200) (1,993) (41,865)
Other (28) (43) (2,210)
- ----------------------------------------------------------------------------------------
Net Cash Used by Financing Activities (223,115) (310,200) (29,454)
- ----------------------------------------------------------------------------------------
Increase (decrease) in Cash (8,762) 7,214 1,839
Cash at Beginning of Year 12,498 5,284 3,445
- ----------------------------------------------------------------------------------------
Cash at End of Year $ 3,736 $ 12,498 $ 5,284
========================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
38
Puget Sound Energy, Inc.
Notes To Consolidated Financial Statements
- ----------------------------------------------------------------------------
1) Summary of Significant Accounting Policies
Significant accounting policies are described below.
Basis of Presentation:
Puget Sound Energy, Inc., formerly Puget Sound Power & Light Company, ("the
Company"), is an investor-owned public utility incorporated in the State of
Washington furnishing electric service in a territory covering approximately
4,500 square miles, principally in the Puget Sound region of Washignton
state. The earnings, operations and statistical information contained in
this report reflect the results for the Company without giving effect to its
merger in 1997 with Washington Energy Company ("WECo") (See Note 18). The
change of its name to Puget Sound Energy, Inc. was effective with the
merger.
The consolidated financial statements include the accounts of the Company
and a wholly-owned subsidiary which had issued Guaranteed Collateralized
Bonds, the proceeds of which were advanced to the Company (See Note 7). The
subsidiary has no independent operations.
Investments in all other subsidiaries are stated on an equity basis inasmuch
as the assets, liabilities, revenues and operating expenses of the
subsidiaries are not material in relation to those of the Company.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Utility Plant:
The costs of additions to utility plant, including renewals and betterments,
are capitalized at original cost. Costs include indirect costs such as
engineering, supervision, certain taxes and pension and other benefits, and
an allowance for funds used during construction. Replacements of minor
items of property are included in maintenance expense. The original cost of
operating property together with removal cost, less salvage, is charged to
accumulated depreciation when the property is retired and removed from
service.
Accounting for Regulatory Assets:
The Company prepares its financial statements in accordance with Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" ("Statement No. 71"). Statement No. 71
requires the Company to defer certain costs that would otherwise be charged
to expense, if it is probable that future rates will permit recovery of such
costs. Accounting under Statement No. 71 is appropriate as long as: rates
are established by or subject to approval by independent, third-party
regulators; rates are designed to recover the specific enterprise's cost-of-
service; and in view of demand for service, it is reasonable to assume that
rates set at levels that will recover costs can be charged to and collected
39
from customers. In applying Statement No. 71, the Company must give
consideration to changes in the level of demand or competition during the
cost recovery period. In accordance with Statement No. 71, the Company
capitalizes certain costs in accordance with regulatory authority whereby
those costs will be expensed and recovered in future periods.
Net regulatory assets at December 31, 1996 and 1995 included the following:
- ----------------------------------------------------------------
(Dollars in Millions) 1996 1995
- ----------------------------------------- ------ ------
Deferred income taxes $234.1 $249.7
Investment in BEP Exchange Contract 86.8 94.2
Unamortized energy conservation charges 41.7 37.9
PRAM accrued revenues 40.5 114.8
Storm damage costs 39.3 27.3
Various other costs 66.3 69.5
- ----------------------------------------- ------ -----
Total $508.7 $593.4
================================================================
If the Company, at some point in the future, determines that all or a
portion of the utility operations no longer meets the criteria for continued
application of Statement No. 71, the Company would be required to adopt the
provisions of Statement of Financial Accounting Standards No. 101,
"Regulated Enterprises - Accounting for the Discontinuation of Application
of FASB Statement No. 71." Adoption of Statement No. 101 would require the
Company to write off the regulatory assets and liabilities related to those
operations not meeting Statement No. 71 requirements.
The Company, in prior years, incurred costs associated with its 5% interest
in a now terminated nuclear generating project (identified herein as
"Investment in Bonneville Exchange Power ("BEP")"). Under terms of a
settlement agreement with the Bonneville Power Administration ("BPA"), which
settled claims of the Company relating to construction delays associated
with that project, the Company is receiving, over 30.5 years, power from the
federal power system resources marketed by BPA. Approximately two-thirds of
the Company's Investment in BEP is included in rate base and amortized on a
straight-line basis over the life of the contract (amortization is included
in "Purchased and interchanged power"). The remainder of the Company's
investment is being recovered in rates over ten years, without a return
during the recovery period (the related amortization is included in
"Depreciation and amortization", pursuant to a FERC accounting order).
Operating Revenues:
Operating revenues are recorded on the basis of service rendered, which
include estimated unbilled revenue and revenue accrued under the Periodic
Rate Adjustment Mechanism ("PRAM").
Energy Conservation:
The Company accumulates energy conservation expenditures which are included
in rate base and amortized to expense over a ten-year period when authorized
by the Washington Utilities and Transportation Commission ("Washington
Commission").
In June 1995, the Company sold approximately $202.5 million of its
investment in customer-owned energy conservation measures to a grantor trust
which, in turn, issued securities backed by a Washington state statute
40
enacted in 1994. The proceeds of the sale were used to pay down short-term
debt. The Company recognized no gain or loss on the sale. The Company's
total unamortized conservation balance at December 31, 1996 was $41.7
million.
Self-Insurance:
Prior to October 1, 1993, provision was made for uninsured storm damage,
comprehensive liability, industrial accidents and catastrophic property
losses, with the approval of the Washington Commission, on the basis of the
amount of outside insurance in effect and historical losses. To the extent
actual costs varied from the provision, the difference was deferred for
incorporation into future rates.
In its September 21, 1993 order, the Washington Commission terminated,
prospectively, the provision for deferral of uninsured storm damage except
for certain losses associated with major storms. At December 31, 1996, the
Company had no insurance coverage for storm damage and is self-insured for a
portion of the risk associated with comprehensive liability, industrial
accidents and catastrophic property losses. The amount of uninsured storm
damage costs deferred under the regulatory treatment approved by the
Washington Commission at December 31, 1996 was $39.3 million, which includes
$14.7 million of costs deferred as a result of a severe snowstorm in late
December 1996.
Depreciation and Amortization:
For financial statement purposes, the Company provides for depreciation on a
straight-line basis. The depreciation of automobiles, trucks, power
operated equipment and tools is allocated to asset and expense accounts
based on usage. The annual depreciation provision stated as a percent of
average original cost of depreciable utility plant was 3.0% in 1996, 1995
and 1994.
The Company's investments in terminated generating projects were amortized
on a straight-line basis over the ten year period ending in 1994 (included
in operating expenses under "Depreciation and amortization").
Amounts recoverable through rates related to investments in terminated
generating projects and the Bonneville Exchange Power Contract were adjusted
to their present value in prior years in accordance with Statement of
Financial Accounting Standards No. 90 ("Statement No. 90"). These
adjustments result in reduced net amortization expense over the recovery
periods, the effect of which is included in miscellaneous income in the
amount, net of federal income tax expense, of $1.1 million, $1.3 million and
$1.8 million for 1996, 1995 and 1994, respectively.
Federal Income Taxes:
The Company normalizes, with the approval of the Washington Commission,
certain items. Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 109. (See Note 12.)
Allowance for Funds Used During Construction:
The Allowance for Funds Used During Construction ("AFUDC") represents the
cost of both the debt and equity funds used to finance utility plant
additions during the construction period. The amount of AFUDC recorded in
each accounting period varies depending principally upon the level of
41
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 is the Company's
authorized rate of return, which was 8.94% effective October 1, 1993. To
the extent amounts calculated using this rate exceed the AFUDC calculated
using the Federal Energy Regulatory Commission ("FERC") formula, the Company
capitalizes the excess as a deferred asset, crediting miscellaneous income.
The amounts included in income were: $2,112,000 for 1996; $1,614,000 for
1995; and $3,016,000 for 1994. The deferred asset is being amortized over
the average useful life of the Company's non-project utility plant.
Allowance For Funds Used to Conserve Energy:
The Washington Commission has authorized the Company to capitalize, as part
of energy conservation costs, related carrying costs calculated at a rate
established by the Washington Commission. This Allowance for Funds Used to
Conserve Energy ("AFUCE") has been credited as a non-cash item to
miscellaneous income in the amount of $661,000 in 1996, $1,463,000 in 1995,
and $3,317,000 in 1994. Cash inflow related to AFUCE occurs when these
charges are reflected in rates, or when the underlying asset is sold to a
third party. AFUCE was discontinued with the PRAM on September 30, 1996.
Periodic Rate Adjustment Mechanism:
In April 1991, the Washington Commission issued an order establishing a PRAM
designed to operate as an interim rate adjustment mechanism between general
rate cases. Under the PRAM, the Company was allowed to request annual rate
adjustments, on a prospective basis, to reflect changes in certain costs as
set forth in the PRAM order. Also, under terms of the order, recovery of
certain costs was decoupled from levels of electricity sales.
Rates established for the PRAM period were subject to future adjustment
based on actual customer growth and variations in certain costs, principally
those affected by hydro and weather conditions. To the extent revenue
billed to customers varied from amounts allowed under the methodology
established in the PRAM order, the difference was accumulated, without
interest, for rate recovery which was then established in the next PRAM
hearing. In its September 22, 1995 order, the Washington Commission
approved the Company's last PRAM filing and the recovery of $71.2 million
over the period October 1, 1995 through September 30, 1996. In addition to
approval of the rate adjustment, the Commission also agreed, pursuant to a
negotiated settlement, to discontinue the PRAM on September 30, 1996, the
end of the last PRAM period. PRAM accrued revenues of $40.5 million,
recorded at December 31, 1996, were recovered in the first quarter of 1997.
Over-collection of PRAM revenues, if any, are expected to be refunded to
customers in the second quarter of 1997.
Other:
Debt premium, discount and expenses are amortized over the life of the
related debt.
In March 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
("Statement No. 121"). Statement No. 121 requires that long-lived assets and
42
certain intangibles be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of the asset may not be
recoverable. If impairment has occurred, an impairment loss must be
recognized. Statement No. 121 was implemented in 1996. Adoption of this
standard has not had a material impact on the financial position, results of
operations, or liquidity of the Company.
In October 1995, the FASB issued Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation" ("Statement No. 123").
Statement No. 123 establishes a fair value based method of accounting for
stock-based compensation plans and encourages entities to adopt that method
in place of the provisions of Accounting Principles Board Opinion No. 25
("APB 25"). The Company intends to continue to apply the provisions of APB
25 in recognizing compensation expense related to its stock-based
compensation plans. The difference in expense between Statement No. 123 and
APB 25 is not material.
Earnings Per Common Share:
Earnings per common share have been computed based on the weighted average
number of common shares outstanding.
2) Property Plant and Equipment
- ---------------------------------------------------------------------------
December 31 (Dollars in Thousands) 1996 1995
- ---------------------------------------------------------------------------
Electric utility plant classified by prescribed
accounts at original cost:
Intangible plant $ 50,714 $ 38,786
Production plant 926,706 905,047
Transmission plant 535,661 521,810
Distribution plant 1,634,463 1,571,037
General plant 236,972 241,533
Construction work in progress 83,085 105,617
Plant held for future use 10,802 15,644
Acquisition adjustments 1,249 1,249
- ---------------------------------------------------------------------------
Total electric utility plant $3,479,652 $3,400,723
===========================================================================
43
3) Capital Stock
Preferred Stock
--------------------------------
Not Subject Subject to
to Mandatory Common
Mandatory Redemption Redemption Stock
- -------------------------- -------------------- ---------- -----------
Without
$100 $100 Par Value
$25 Par Par ($10 Stated
Par Value Value Value Value)
- -------------------------- --------- -------- ---------- -----------
Shares outstanding
January 1, 1994 3,000,000 400,000 931,763 63,629,416
Sold to Public:
1994 2,000,000 -- -- --
Issued to shareholders under
the stock purchase and
dividend reinvestment plan:
1994 -- -- -- 11,445
Acquired for sinking fund:
1994 -- -- (19,339) --
1995 -- -- (22,029) --
1996 -- -- (12,000) --
Called for redemption
and canceled:
1994 -- (400,000) -- --
- ---------------------------------------------------------------------------
Shares outstanding
December 31, 1996 5,000,000 -- 878,395 63,640,861
============================================================================
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. On October 18, 1995, the Company's
Board of Directors approved an amendment to the Rights Agreement which
precludes the merger with WECo from triggering any rights under the Rights
Agreement.
44
On February 3, 1994, the Company issued $50 million, Adjustable Rate
Cumulative Preferred Stock ("ARPS"), Series B ($25 par value). The proceeds
were used to retire the $40 million principal amount of its ARPS Series A
($100 par value). The weighted average dividend rate for the ARPS Series B
was 5.49% for 1996, 6.05% for 1995 and 5.93% for 1994. The weighted average
dividend rate for the ARPS Series A was 7.00% in the first two months of
1994.
For each quarterly period, dividends on the ARPS Series B, determined in
advance of such period, will be set at 83% of the highest of three interest
rates as defined in the Statement of Relative Rights and Preferences for
ARPS Series B. The dividend rate for any dividend period will in no event
be less than 4% per annum or greater than 10% per annum. The Company may
redeem the ARPS Series B at any time on not less than 30 days notice at
$27.50 per share on or prior to February 1, 1999, and at $25 per share
thereafter, plus in each case accrued dividends to the date of redemption;
provided however, that no shares shall be redeemed prior to February 1,
1999, if such redemption is for the purpose or in anticipation of refunding
such share at an effective interest or dividend cost to the Company of less
than 5.37% per annum.
4) Preferred Stock Subject to Mandatory Redemption
The Company is required to deposit funds annually in a sinking fund
sufficient to redeem the following number of shares of each series of
preferred stock at $100 per share plus accrued dividends: 4.84% Series and
4.70% Series, 3,000 shares each; 8% Series, 6,000 and 1,000 shares through
2003 and 2004, respectively; and 7.75% Series, 37,500 shares on each
February 15, commencing on February 15, 1998. Previous requirements have
been satisfied by delivery of reacquired shares. At December 31, 1996,
there were 9,044 shares of the 4.84% Series, 6,785 shares of the 4.70%
Series and 776 shares of the 8% Series acquired by the Company and available
for future sinking fund requirements. Upon involuntary liquidation, all
preferred shares are entitled to their par value plus accrued dividends.
The preferred stock subject to mandatory redemption may also be redeemed by
the Company at the following redemption prices per share plus accrued
dividends: 4.84% Series, $102; 4.70% Series, $101; and 8% Series, $101.
The 7.75% Series may be redeemed by the Company, subject to certain
restrictions, at $105.17 per share plus accrued dividends through February
15, 1997 and at per share amounts which decline annually to a price of $100
after February 15, 2007.
45
5) Additional Paid-in Capital
(Dollars in Thousands) 1996 1995 1994
- ----------------------------------------------------------------------------
Balance at beginning of year $328,963 $328,753 $329,922
Excess of proceeds over stated values of:
Common stock issued under the
stock purchase and
dividend reinvestment plan -- -- 124
Par value over cost of reacquired
preferred stock -- 210 68
Issue costs of preferred stock -- -- (1,361)
- ---------------------------------------------------------------------------
Balance at end of year $328,963 $328,963 $328,753
===========================================================================
6) Earnings Reinvested in the Business
Earnings reinvested in the business unrestricted as to payment of cash
dividends on common stock approximated $254 million at December 31, 1996,
under the provisions of the most restrictive covenants applicable to
preferred stock and long-term debt contained in the Company's Articles of
Incorporation and indentures. 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 and the disallowance of
certain terminated generating project costs by the Washington Commission do
not impact the amount of earnings reinvested in the business for purposes of
payment of dividends on common stock under the terms of the aforementioned
Articles and indentures. (See Note 1.)
46
7) Long-Term Debt
First Mortgage Bonds at December 31: (Dollars in Thousands)
Series Due 1996 1995 Series Due 1996 1995
- ----------------------------------------------------------------------
5.25% 1996 $ -- $ 20,000 7.15% 2002 $ 5,000 $ 5,000
4.85% 1996 -- 15,000 7.625% 2002 25,000 25,000
7.875% 1997 100,000 100,000 7.02% 2003 30,000 30,000
6.17% 1998 10,000 10,000 6.20% 2003 3,000 3,000
5.70% 1998 5,000 5,000 6.40% 2003 11,000 11,000
8.83% 1998 25,000 25,000 7.70% 2004 50,000 50,000
6.50% 1999 16,500 16,500 7.80% 2004 30,000 30,000
6.65% 1999 10,000 10,000 8.06% 2006 46,000 46,000
6.41% 1999 20,500 20,500 8.14% 2006 25,000 25,000
7.25% 1999 50,000 50,000 7.75% 2007 100,000 100,000
6.61% 2000 10,000 10,000 8.40% 2007 10,000 10,000
9.14% 2001 30,000 30,000 8.59% 2012 5,000 5,000
7.85% 2002 30,000 30,000 8.20% 2012 30,000 30,000
7.07% 2002 27,000 27,000 7.35% 2024 55,000 55,000
- ----------------------------------------------------------------------
Total First Mortgage Bonds $759,000 $794,000
======================================================================
Guaranteed Collateralized Bonds at December 31: (Dollars in Thousands)
Series Due 1996 1995
- ----------------------------------------------------------------------
8.45% 1996 $ -- $ 8,000
- ----------------------------------------------------------------------
Total Guaranteed Collateralized Bonds $ -- $ 8,000
======================================================================
The Company unconditionally guaranteed all payments of principal, premium
and interest on each series of the Guaranteed Collateralized Bonds issued in
1986 by its wholly-owned subsidiary.
Substantially all electric utility properties owned by the Company are
subject to the lien of the First Mortgage Bonds.
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%.
47
Long-Term Debt Maturities
- -------------------------
The principal amounts of long-term debt maturities for the next five years
are as follows:
(Dollars in Thousands) 1997 1998 1999 2000 2001
- --------------------- -------- ------- ------- ------- -------
Maturities of
long-term debt $100,000 $ 40,000 $ 97,000 $ 10,000 $ 30,000
========================================================================
8) Short-Term Debt
At December 31, 1996, the Company had short-term borrowing arrangements
which included a $100 million line of credit with four major banks, a $75
million line of credit with five banks and a $1.5 million line with another
two banks. In February 1997, the Company replaced the $100 million and $75
million credit lines with a new $400 million line of credit with 15 banks.
The agreements provide the Company with the ability to borrow at different
interest rate options. For the new $400 million line of credit, the options
are: (1) the higher of the prime rate or the Federal Funds rate plus 1/2 of
1 percent or (2) the Eurodollar rate plus .30 percent. The new areement
requires an availability fee of .09 percent per annum on the unused loan
commitment. Borrowings on the $1.5 million credit line are at the prime
rate and compensating balances of 2-1/2% are required.
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) 1996 1995 1994
- ---------------------------------------- ------- ------- -------
Short-term borrowings outstanding:
Bank notes $ 31,700 $ 44,000 $ 94,900
Commercial paper notes $ 88,713 $123,049 $139,554
Weighted average interest rate 5.69% 6.00% 6.24%
Unused lines of credit (a) $176,500 $176,500 $176,500
- ---------------------------------------------------------------------------
(a) Provides liquidity support for outstanding commercial paper in the
amount of $88.7 million, $123.0 million and $139.6 million for 1996,
1995 and 1994, respectively, effectively reducing the available
borrowing capacity under these credit lines to $87.8 million, $53.5
million, and $36.9 million, respectively.
48
9) Estimated Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 1996 and 1995.
1996 1995
------------------- --------------------
Carrying Fair Carrying Fair
(Dollars in Millions) Amount Value Amount Value
- ---------------------------- -------- ------- -------- -------
Financial Assets:
Cash $ 3.7 $ 3.7 $ 12.5 $ 12.5
Financial Liabilities:
Short-term debt $ 120.4 $ 120.4 $ 167.0 $ 167.0
Preferred stock subject to
mandatory redemption $ 87.8 $ 88.5 $ 89.0 $ 91.2
Long-term debt $ 920.6 $ 952.9 $ 963.4 $1,012.8
- ---------------------------------------------------------------------------
The fair value of outstanding bonds including current maturities is
estimated based on quoted market prices.
The preferred stock subject to mandatory redemption is estimated based on
dealer quotes.
The carrying value of short-term debt is considered to be a reasonable
estimate of fair value. The carrying amount of cash, which includes
temporary investments with maturities of 3 months or less, is also
considered to be a reasonable estimate of fair value.
10) Supplementary Income Statement Information
(Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Taxes:
Real estate and personal property $ 35,181 $ 32,208 $ 33,050
State business 44,422 43,541 42,241
Municipal, occupational and other 29,337 27,280 25,132
Payroll 8,650 8,638 9,514
Other 4,061 3,512 4,194
- ---------------------------------------------------------------------------
Total taxes $121,651 $115,179 $114,131
- ---------------------------------------------------------------------------
Charged to:
Operating expense $116,661 $109,533 $107,821
Other accounts, including
construction work in progress 4,990 5,646 6,310
- ---------------------------------------------------------------------------
Total taxes $121,651 $115,179 $114,131
===========================================================================
See "Consolidated Statements of Income" for maintenance and depreciation
expense.
Other operation expenses in 1994 include charges totaling $20.9 million
related to two early separation and retirement programs and associated
facilities consolidations. Severance packages accepted by employees totaled
49
$18.3 million, including retirement benefits and pension expenses of $6.9
million. Facility consolidation expenses were $2.6 million.
Advertising, research and development expenses and amortization of
intangibles are not significant. The Company pays no royalties.
11) Leases
The Company treats all leases as operating leases for ratemaking purposes as
required by the Washington Commission. Certain leases contain purchase
options, renewal and escalation provisions. Capitalized leases are not
material.
Rental and operating lease expense for the years ended December 31, 1996,
1995 and 1994 were approximately $15,714,000, $15,119,000 and $13,874,000,
respectively. Payments due for the years ended December 31, 1996, 1995 and
1994 for the sublease of properties were approximately $1,584,000, $554,000
and $529,000, respectively.
At December 31, 1996, future minimum lease payments for noncancelable leases
are $10,111,000 for 1997, $10,044,000 for 1998, $9,386,000 for 1999,
$8,544,000 for 2000, $8,483,000 for 2001, and in the aggregate $18,153,000
thereafter. Future minimum sublease receipts for noncancelable subleases
are $828,000 for 1997, $822,000 for 1998, $820,000 for 1999, $766,000 for
2000, $500,000 for 2001, and in the aggregate $791,000 thereafter.
12) Federal Income Taxes
The details of federal income taxes ("FIT") are as follows:
(Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Charged to Operating Expense:
Current $98,679 $72,020 $63,935
Deferred - net (12,126) 12,940 16,739
Deferred investment tax credits (311) (415) (415)
- ---------------------------------------------------------------------------
Total FIT charged to operations $86,242 $84,545 $80,259
===========================================================================
Charged to Miscellaneous Income:
Current $(2,037) $(1,125) $(1,253)
Deferred - net -- (476) 1,438
- ---------------------------------------------------------------------------
Total FIT charged to miscellaneous income $(2,037) $(1,601) $ 185
===========================================================================
Total FIT $84,205 $82,944 $80,444
===========================================================================
50
The following is a reconciliation of the difference between the amount of
FIT computed by multiplying pre-tax book income by the statutory tax rate,
and the amount of FIT in the Consolidated Statements of Income:
(Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
FIT at the statutory rate $76,852 $76,532 $70,177
- ---------------------------------------------------------------------------
Increase (Decrease):
Depreciation expense deducted in
the financial statements in
excess of tax depreciation, net
of depreciation treated as a
temporary difference 5,538 5,370 4,717
AFUDC included in income in the financial
statements but excluded from taxable income (2,191) (2,319) (2,525)
Investment tax credit amortization (311) (415) (415)
Energy conservation expenditures - net 3,380 806 5,607
Other 937 2,970 2,883
- ---------------------------------------------------------------------------
Total FIT $84,205 $82,944 $80,444
===========================================================================
Effective tax rate 38.3% 37.9% 40.1%
===========================================================================
The following are the principal components of FIT as reported:
(Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Current FIT $96,642 $70,895 $62,682
===========================================================================
Deferred FIT - other:
Conservation tax settlement (759) (7) 341
Periodic rate adjustment mechanism (PRAM) (26,014) 1,384 9,287
Deferred taxes related to insurance
reserves (938) (938) (938)
Terminated generating projects -- -- (3,345)
Reversal of Statement No. 90 present
value adjustments 552 688 926
Residential Purchase and Sale
Agreement - net (2,178) (4,010) (624)
Normalized tax benefits of the
accelerated cost recovery system 18,071 19,435 19,042
Energy conservation program (1,255) (1,969) (2,253)
Other 395 (2,119) (4,259)
- ---------------------------------------------------------------------------
Total deferred FIT - other $(12,126) $12,464 $18,177
===========================================================================
Deferred investment tax credits -
net of amortization (311) (415) (415)
- ---------------------------------------------------------------------------
Total FIT $84,205 $82,944 $80,444
===========================================================================
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
51
financial statement purposes because they are not allowed for ratemaking
purposes.
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("Statement No.
109"). Statement No. 109 requires recording deferred tax balances, at the
currently enacted tax rate, for all temporary differences between the book
and tax bases of assets and liabilities, including temporary differences for
which no deferred taxes had been previously provided because of use of flow-
through tax accounting for rate-making purposes. Because of prior, and
expected future ratemaking treatment for temporary differences for which
flow-through tax accounting has been utilized, a regulatory asset for income
taxes recoverable through future rates related to those differences has also
been established. At December 31, 1996, the balance of this asset is $234
million.
The deferred tax liability at December 31, 1996 and 1995 is comprised of
amounts related to the following types of temporary differences:
(Dollars in Thousands) 1996 1995
- --------------------------------------------------------------
Utility plant $449,031 $442,425
PRAM 14,167 40,181
Energy conservation charges 25,636 32,441
Contributions in aid of construction (27,355) (25,425)
Bonneville Exchange Power 11,622 14,217
Other 27,537 24,561
- --------------------------------------------------------------
Total $500,638 $528,400
==============================================================
The totals of $501 million and $528 million for 1996 and 1995 consist of
deferred tax liabilities of $540 million and $564 million net of deferred
tax assets of $39 million and $36 million, respectively.
13) Retirement Benefits
The Company has a noncontributory defined benefit pension plan covering
substantially all of its employees. Benefits are a function of both years
of service and the average of the five highest consecutive years of basic
earnings within the last ten years of employment. The Company funds pension
cost using the "frozen entry-age" actuarial cost method.
52
Net pension costs for 1996, 1995 and 1994, including $1,564,000 for 1996,
$1,966,000 for 1995 and $2,752,000 for 1994 which were charged to
construction and other asset accounts, were comprised of the following
components:
(Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Service cost (benefits earned
during the period) $ 6,792 $ 6,129 $ 7,244
Interest cost on projected
benefit obligation 16,365 15,656 14,895
Actual return on plan assets (38,474) (53,810) 4,392
Net amortization and deferral 18,064 35,335 (21,539)
- ---------------------------------------------------------------------------
Net pension costs under
FASB Statement No. 87 2,747 3,310 4,992
- ---------------------------------------------------------------------------
Regulatory adjustment 1,263 1,263 1,263
- ---------------------------------------------------------------------------
Net pension costs $ 4,010 $ 4,573 $ 6,255
===========================================================================
Funded Status of Plan
At December 31 (Dollars in Thousands) 1996 1995
- ---------------------------------------------------------------------------
Actuarial present value of benefit obligations:
Vested $(182,805) $(181,367)
Non-vested (3,274) (1,387)
- ----------------------------------------------------------------------------
Accumulated benefit obligation (186,079) (182,754)
Effect of future compensation levels (46,411) (41,566)
- ----------------------------------------------------------------------------
Total projected benefit obligation (232,490) (224,320)
Plan assets at market value 282,886 254,844
- ----------------------------------------------------------------------------
Plan assets in excess of projected benefit
obligation 50,396 30,524
Unrecognized net gain due to variance
between assumptions and experience (52,250) (34,584)
Prior service cost 7,819 9,606
Transition asset as of January 1, 1986,
being amortized on a straight-line
basis over 18 years (2,934) (3,354)
Regulatory adjustment, cumulative 3,664 4,927
- ---------------------------------------------------------------------------
Prepaid pension cost recognized
in long-term assets on balance sheet $ 6,695 $ 7,119
===========================================================================
In December 1995, in connection with the proposed merger with WECo, the
Company offered to its employees a Voluntary Separation Plan. A total of
204 employees elected to participate in the Voluntary Separation Plan
resulting in a curtailment gain for 1996 of $1.6 million under Statement of
Financial Accounting Standards No. 88.
Assumptions used for the above calculations are as follows: settlement
(discount) rate for 1996 and 1995 - 7.5% and for 1994 - 8.25%; rate of
annual compensation increase for 1996 and 1995 - 5.0% and for 1994 - 5.5%;
53
and long-term rate of return on assets for 1996 and 1995 - 9.0% and for 1994
- - 8.5%.
Plan assets consist primarily of U.S. Government securities, corporate debt
and equity securities.
The Company has supplemental retirement plans for officer and director level
employees. Expenses for these plans for 1996, 1995 and 1994 were $817,000,
$916,000, and $1,043,000, respectively.
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.
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" ("Statement No. 106") which requires the costs
associated with postretirement benefits to be accrued over the period of
employment. The Company is recognizing the impact of Statement No. 106 by
amortizing its transition obligation of $24.9 million to expense over 20
years. The resulting 1996, 1995 and 1994 annual costs under Statement No.
106 were approximately $2.8 million, $3.6 million, and $3.8 million,
respectively. In addition, a curtailment loss under Statement No. 106 for
1996 of $1.4 million resulted from the 1995 Voluntary Separation Plan
discussed above.
In the rate order issued by the Washington Commission on September 21, 1993,
the Washington Commission approved adoption of accrual accounting for
postretirement benefits. For rate purposes, the difference between accrual
and pay-as-you-go accounting will be phased in over five years. The
Washington Commission's calculation of Statement No. 106 costs for rate
purposes differs from the Company's cost by an insignificant amount. In
1996, 1995 and 1994, the expenses recognized for postretirement benefits
were $3.8 million, $2.5 million and $2.4 million, respectively.
14) Employee Investment Plan
The Company has a qualified employee Investment Plan 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 55% of the basic contribution of each participating employee. The
basic contribution is limited to 6% of the employee's eligible earnings.
All Company contributions are used to purchase Company common stock on the
open market or directly from the Company.
The Company contributions to the plan were $3,057,000, $3,103,000 and
$3,321,000 for the years 1996, 1995 and 1994, respectively. The
shareholders have authorized the issuance of up to 2,000,000 shares of
common stock under the plan, of which 959,142 were issued through December
31, 1996. The employee Investment Plan eligibility requirements are set
forth in the plan documents.
54
15) Commitments and Contingencies
Commitments
For the twelve months ended December 31, 1996, approximately 32% of the
Company's energy output was obtained at an average cost of approximately 8.7
mills per KWH through long-term contracts with several of the Washington
public utility districts ("PUDs") owning hydroelectric projects on the
Columbia River.
The purchase of power from the Columbia River projects is generally on a
"cost-of-service" basis under which the Company pays a proportionate share
of the annual cost of each project in direct proportion to the amount of
power annually purchased by the Company from such project. Such payments
are not contingent upon the projects being operable. These projects are
financed through substantially level debt service payments, and their annual
costs should not vary significantly over the term of the contracts unless
additional financing is required to meet the costs of major maintenance,
repairs or replacements or license requirements. The Company's share of the
costs and the output of the projects is subject to reduction due to various
withdrawal rights of the PUDs and others over the lives of the contracts.
As of December 31, 1996, the Company was entitled to purchase portions of
the power output of the PUDs' projects as set forth in the following
tabulation:
Company's Annual Amount
Bonds Purchasable (Approximate)
Contract License Outstanding ---------------------------
Exp. Exp. 12/31/96(a) % of Kilowatt Costs(b)
Project Date Date (Millions) Output Capacity (Millions)
- --------------------------------------------------------------------------
Rock Island
Original units 2012 2029 $ 84.5 57.1 )
)423,000 $ 45.4
Additional units 2012 2029 320.9 100.0 )
Rocky Reach 2011 2006(c) 200.0 38.9 482,750 19.3
Wells 2018 2012(c) 183.9 32.3 271,320 9.9
Priest Rapids 2005 2005(c) 186.8 8.0 72,320 2.2
Wanapum 2009 2005(c) 209.1 10.8 106,380 2.8
- ------------------------------------------------------------------------
Total 1,355,770 $79.6
==========================================================================
(a) The contracts for purchases initially were generally coextensive
with the term of the PUD bonds associated with the project. Under the terms
of some financings and refinancings, however, long-term bonds were sold to
finance certain assets whose estimated useful lives extend beyond the
expiration date of the power sales contracts. Of the total outstanding
bonds sold for each project, the percentage of principal amount of bonds
which mature beyond the contract expiration dates are: 70.7% at Rock Island;
31.8% at Rocky Reach; 71.3% at Priest Rapids; and 46.3% at Wanapum.
(b) The components of 1997 costs associated with the interest portion
of debt service are: Rock Island, $24.2 million for all units; Rocky Reach,
$5.3 million; Wells, $2.9 million; Priest Rapids, $0.9 million; and Wanapum,
$1.2 million.
55
(c) The Company is unable to predict whether the licenses under the
Federal Power Act will be renewed to the current licensees. In the past
twelve months, the FERC has issued orders for Rocky Reach, Wells and Priest
Rapids/Wanapum projects under Section 22 of the Federal Power Act, which
affirm the Company's contractual rights to receive power under existing
terms and conditions even if a new licensee is granted a license prior to
expiration of the contract term.
- -----------------------------
The Company's estimated payments for power purchases from the Columbia River
projects are $80 million for 1997, $79 million for 1998, $81 million for
1999, $83 million for 2000, $84 million for 2001 and in the aggregate $1.05
billion thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with
other utilities and non-utility generators in the region. The Company is
generally not obligated to make payments under these contracts unless power
is delivered. The Company's estimated payments for firm power purchases
from other utilities and non-utility generators, excluding the Columbia
River projects, are $422 million for 1997, $441 million for 1998, $464
million for 1999, $481 million for 2000, $509 million for 2001 and in the
aggregate $5 billion thereafter through 2024. These contracts have varying
terms and may include escalation and termination provisions.
Total purchased power contracts provided the Company with approximately 17.1
million, 16.4 million and 16.0 million MWH of firm energy at a cost of
approximately $485.6 million, $478.7 million and $450.7 million for the
years 1996, 1995 and 1994, respectively.
The following table indicates the Company's percentage ownership and the
extent of the Company's investment in jointly-owned generating plants in
service at December 31, 1996:
Company's Share
------------------------------
Energy Company's Plant in Accumulated
Source Ownership Service at cost Depreciation
Project (Fuel) Share (%) (Millions) (Millions)
- -------------- ------ --------- -------------- ------------
Centralia Coal 7 $ 27.4 $ 17.3
Colstrip 1 & 2 Coal 50 184.7 96.4
Colstrip 3 & 4 Coal 25 450.3 154.6
- ------------------------------------------------------------------------
Financing for a participant's ownership share in the projects is provided
for by such participant. The Company's share of related operating and
maintenance expenses is included in corresponding accounts in the
Consolidated Statements of Income.
Certain purchase commitments have been made in connection with the Company's
construction program.
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 four sites. The
Company has also instituted an ongoing program to test, replace and
remediate certain underground storage tanks as required by federal and state
56
laws. Remediation and testing of Company vehicle service facilities and
storage yards is also continuing.
On April 1, 1992, the Washington Commission issued an order regarding the
treatment of costs incurred by the Company for certain sites under its
environmental remediation program. The order authorizes 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 Company has expended approximately $14.3 million related to the
remediation activities covered by the Washington Commission's order, of
which approximately $5.7 million has been recovered from insurance carriers.
At December 31, 1996, approximately $2.1 million has been accrued as a
liability for future remediation costs for these and other remediation
activities. At December 31, 1996, an asset of approximately $10.0 million
has been recorded related to expected future recoveries.
Other contingencies, arising out of the normal course of the Company's
business, exist at December 31, 1996. The ultimate resolution of these
issues is not expected to have a material adverse impact on the financial
condition, results of operations or liquidity of the Company.
16) 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.
1996 Quarter Ended March 31 June 30 Sept. 30 Dec. 31
- --------------------------------------------------------------------------
(Dollars in thousands except per share amounts)
Operating revenues $331,009 $257,317 $252,882 $357,561
Operating income $ 64,688 $ 39,899 $ 33,004 $ 62,985
Other income $ 1,119 $ 860 $ 6,040 $ 3,841
Net income $ 46,419 $ 21,632 $ 20,121 $ 47,199
Earnings per common share $ 0.67 $ 0.28 $ 0.26 $ 0.68
- --------------------------------------------------------------------------
1995 Quarter Ended March 31 June 30 Sept. 30 Dec. 31
- --------------------------------------------------------------------------
(Dollars in thousands except per share amounts)
Operating revenues $338,345 $261,592 $248,584 $330,809
Operating income $ 70,359 $ 42,938 $ 37,001 $ 64,290
Other income $ 1,682 $ 2,587 $ 2,258 $ 1,149
Net income $ 48,746 $ 22,863 $ 19,019 $ 45,091
Earnings per common share $ 0.70 $ 0.30 $ 0.24 $ 0.65
- --------------------------------------------------------------------------
57
17) Consolidated Statement of Cash Flows
For purposes of the Statement of Cash Flows, the Company considers all
temporary investments to be cash equivalents. These temporary cash
investments are securities held for cash management purposes, having
maturities of three months or less. The net change in current assets and
current liabilities for purposes of the Statement of Cash Flows excludes
short-term debt, current maturities of long-term debt and the current
portion of PRAM accrued revenues.
The following provides additional information concerning cash flow
activities:
Year Ended December 31: (Dollars in Thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Changes in certain current
assets and current liabilities:
Accounts receivable $(12,727) $(16,498) $(16,725)
Unbilled revenues (13,201) 6,382 2,521
Materials and supplies 9,724 3,136 2,840
Prepayments and Other 442 908 (75)
Accounts payable 21,422 (7,756) 4,576
Accrued expenses and Other 4,301 (3,736) 884
- ---------------------------------------------------------------------------
Net change in certain current assets
and current liabilities $ 9,961 $(17,564) $ (5,979)
===========================================================================
Cash payments:
Interest (net of capitalized interest) $ 78,624 $ 90,015 $ 83,959
Income taxes $ 98,609 $ 74,273 $ 63,477
- ---------------------------------------------------------------------------
18) Merger with Washington Energy Company
On February 7, 1997, the Boards of the Company and WECo approved the merger
of their respective companies effective February 10, 1997. The merged
company is called Puget Sound Energy, Inc. This announcement followed the
approval by the Washington Commission, on February 5, 1997, of a merger
agreement between the Company, WECo, the Staff of the Washington Commission
and the Public Counsel Section of the State Attorney General's Office.
Shareholders of the Company and WECo, voting as separate groups had, on
March 20, 1996, already given their approval to an Agreement and Plan of
Merger ("Merger Agreement") between the two companies.
The Merger Agreement called for each share of WECo common stock to be
exchanged for 0.86 share of the Company's common stock (approximately
20,921,000 shares of Company stock are expected to be issued). On February
10, 1997, the Company increased the number of authorized shares to
150,000,000. Based on the capitalization of the Company and WECo on
February 10, 1997, holders of the Company's and WECo's common stock held
approximately 75% and 25% respectively, of the aggregate number of
outstanding shares of the merged company's common stock. In addition, the
Agreement called for the preferred stock of Washington Natural Gas Company,
a wholly-owned subsidiary of WECo, to be converted into preferred shares of
the merged company. The merger has been structured as a tax-free exchange
of shares, and is expected to be accounted for as a pooling of interests for
financial statement purposes.
58
The order approving the merger, issued by the
Washington Commission, contains a rate plan that is designed to provide a
five-year period of rate certainty for customers and provide the Company
with an opportunity to achieve a reasonable return on investment. As
required under the stipulated settlementmerger order, the Company filed
tariffs, effective February 8, 1997, that resulted in an average electric
rate decrease of 5.6% related to the PRAM, and an increase in general rates
of between 1.0% and 2.5%, depending on rate class. The net impact was an
average rate decrease of 3.7%, including a decrease in residential rates of
3.24%. General electric rates for residential and industrial customers will
increase by 1.5% on January 1 of each of the four following years, while
those for small commercial customers will increase by 1.0% in each of the
following three years. General rates for all classes of natural gas
customers will remain unchanged until January 1, 1999, when they will
decrease sufficiently to reduce utility margin by 1 percent.
In connection with the merger, through December 31, 1996, the Company has
incurred direct merger related costs and indirect costs related to
integration of the operations of the Company and WECo, (including costs
related to a voluntary early separation plan accepted by 204 employees of
the Company - under terms of the plan, certain employees were terminated in
1996 and termination of others was subject to completion of the merger).
Indirect costs of $4.8 million were expensed in the fourth quarter of 1996.
Direct costs of $6.0 million have been deferred and will be expensed in the
first quarter of 1997, as of the merger consummation date.
The Company currently estimates that additional direct and indirect merger
costs of $33 million, including approximately $8 million deferred by WECo
and $25 million of additional costs will be incurred and charged to expense
in 1997. These estimates are subject to revision as the integration process
proceeds.
Unaudited pro forma information (assuming the merger had been completed as
of December 31, 1996) as of December 31, 1996 and for the three years in the
period ended December 31, 1996, follows. Information for WECo is as of
September 30, 1996, and for three years in the period ended September 30,
1996 (the fiscal year-end of WECo).
59
Pro Forma Balance Sheet Information
Pro Forma
(Thousands except per share amounts) Puget WECo Total
- ------------------------------------ --------- --------- ---------
Total Assets: $3,187,252 $1,034,436 $4,221,688
========= ========= =========
Capitalization:
Common Equity $1,179,026 $ 199,351 $1,378,377
Preferred Stock 212,839 90,000 302,839
Long-term debt 820,664 344,920 1,165,584
Other Liabilities 974,723 400,165 1,374,888
--------- --------- ---------
Total capitalization and
liabilities $3,187,252 $1,034,436 $4,221,688
===========================================================================
Pro Forma Income Statement Information
Pro Forma
Year ended December 31, 1996 Puget WECo Total
- --------------------------------- --------- --------- ---------
Revenues $1,198,769 $ 425,711 $1,624,480
Net Income $ 135,371 $ 23,128 $ 165,519(a)
Income available for common stock $ 120,210 $ 23,128 $ 143,338
Earnings per common share $ 1.89 $ .96(b) $ 1.70(a)(b)
Weighted average common
shares outstanding 63,641 24,159 84,418(a)
- ----------------------------------------------------------------------
Pro Forma
Year ended December 31, 1995 Puget WECo Total
- --------------------------------- --------- --------- ---------
Revenues $1,179,330 $ 443,611 $1,622,941
Net Income $ 135,720 $ (41,062) $ 101,784(a)
Income available for common stock $ 120,192 $ (41,062) $ 79,130
Earnings per common share $ 1.89 $ (1.72)(b) $ 0.94(a)(b)
Weighted average common
shares outstanding 63,641 23,893 84,189(a)
- ----------------------------------------------------------------------
60
Pro Forma
Year ended December 31, 1994 Puget WECo Total
- --------------------------------- --------- --------- ---------
Revenues $1,194,058 $ 432,025 $1,626,083
Net Income $ 120,059 $ (45,646) $ 78,383(a)
Income available for common stock $ 104,328 $ (46,328) $ 58,000
Earnings per common share $ 1.64 $ (1.97)(b) $ 0.69(a)(b)
Weighted average common
shares outstanding 63,632 23,486 83,830(a)
======================================================================
(a) Pro Forma totals do not add across as a result of adjustments giving
effect to the merger exchange ratio and the effects of the exchange of
Company preferred stock for preferred stock of WECo's wholly-owned
subsidiary.
(b) WECo and Pro Forma earnings per share include amounts related to
discontinued operations as follows: 1996, $.07 and $.02, respectively;
1995, $1.11 and $.32, respectively; and 1994, $.04 and $.01, respectively.
In connection with the merger, the Company paid, subsequent to year end, a
dividend on the shares issued to WECo shareholders of $.02 per share,
representing a dividend for the period February 11, 1997 through February
15, 1997, the date of payment for the latest Company dividend.
61
<TABLE>
<CAPTION>
Puget Sound Energy, Inc.
Schedule II. Valuation and Qualifying Accounts and Reserves
- -----------------------------------------------------------------------------------
(Dollars in Thousands)
- -----------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
- -----------------------------------------------------------------------------------
Additions
Balance at Charged to Balance
Beginning Costs and at End
of Period Expenses Deductions of Period
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Year Ended December 31, 1996
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 886 $4,073 $4,189 $ 770
===================================================================================
Year Ended December 31, 1995
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 610 $4,527 $4,251 $ 886
===================================================================================
Year Ended December 31, 1994
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 523 $3,537 $3,450 $ 610
===================================================================================
</TABLE>
62
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)
2.2 Puget Sound Power & Light Company Stock Option Agreement dated as
of October 18, 1995, between Puget Sound Power & Light Company and Washington
Energy Company. (Exhibit 2.2 to Registration No. 333-617)
2.3 Washington Energy Company Stock Option Agreement dated as of
October 18, 1995, between Washington Energy Company and Puget Sound Power &
Light Company. (Exhibit 2.3 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)
3-b Restated Bylaws of the Company. (Exhibit 4-b to Registration
No. 33-18506)
4.1 Fortieth through Seventy-fifth Supplemental Indentures defining
the rights of the holders of the Company's First Mortgage Bonds. (Exhibit 2-
d to Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347;
Exhibits 2-e through and including 2-k to Registration No. 2-60200; Exhibit 4-
h to Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No.
2-60200; Exhibits 2-m to Registration No. 2-37645; Exhibit 2-o through and
including 2-s to Registration No. 2-60200; Exhibit 5-b to Registration No. 2-
62883; Exhibit 2-h to Registration No. 2-65831; Exhibit (4)-j-1 to
Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit
(4)-b to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No. 1-4393; Exhibits (4)(a) and (4)(b) to Company's
Current Report on Form 8-K, dated April 22, 1986; Exhibit (4)a to Company's
Current Report on Form 8-K, dated September 5, 1986; Exhibit (4)-b to
Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
1986, Commission File No. 1-4393; Exhibit (4)-c to Registration No. 33-18506;
Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended
December 31, 1989, Commission File No. 1-4393; Exhibit (4)-b to Annual Report
on Form 10-K for the fiscal year ended December 31, 1990, Commission File No.
1-4393; Exhibits (4)-b and (4)-c to Registration No. 33-45916; Exhibit (4)-c
to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; and
Exhibit 4.3 to Registration No. 33-63278.)
4.2 Credit Agreement dated as of December 1, 1991, among the Company
and various banks named therein, Seattle-First National Bank as Agent.
(Exhibit (4)-d to Registration No. 33-45916)
4.3 Credit Agreement dated as of December 1, 1991, among the Company
and various banks named therein, Bank of New York as Agent. (Exhibit (4)-e
to Registration No. 33-45916)
4.4 Final form of Indenture dated as of November 1, 1986, among
Puget Energy, the Company, and The First National Bank of Boston, as Trustee.
(Exhibit 4-a to Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1986, Commission File No. 1-4393)
4.5 Final form of Pledge Agreement dated November 1, 1986, between
the Company and The First National Bank of Boston, as Trustee. (Exhibit 4-c
to Company's Quarterly Report on Form 10-Q for the quarter ended September
30, 1986, Commission File No. 1-4393)
4.6 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)
4.7 Amendment No. 1 dated as of August 30, 1991, to the Rights
Agreement dated as of January 15, 1991, between the Registrant and the Bank
of New York (as successor to The Chase Manhatten Bank, N.A.), as Rights
Agent. (Exhibit 2.1 to Registration Statement on Form 8 filed on August 30,
1991)
4.8 Amendment No. 2 dated as of October 18, 1995, to the Rights
Agreement dated as of January 15, 1991, between the Registrant and The Bank
of New York (as successor to The Chase Manhatten Bank, N.A.), as Rights
Agent. (Exhibit 1 to Registration Statement on Form 8-A/A filed on October
27, 1995)
4.9 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)
4.10 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)
4.11 Statement of Relative Rights and Preferences for the Adjustable
Rate Cumulative Preferred Stock, Series B ($25 Par Value). (Exhibit 1.1 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)
4.12 Statement of Relative Rights and Preferences for the Series A
Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred
Stock. (Exhibit 1.3 to Registration Statement on Form 8-A filed February 14,
1994, Commission File No. 1-4393)
4.13 Statement of Relative Rights and Preferences for the Series B
Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred
Stock. (Exhibit 1.4 to Registration Statement on Form 8-A filed February 14,
1994, Commission File No. 1-4393)
4.14 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)
4.15 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)
4.16 Statement of Relative Rights and Preferences for the 7 7/8%
Series Preferred Stock Cumulative, $25 Par Value. (Exhibit 1.7 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)
4.17 Pledge Agreement, dated as of March 1, 1992, by and between the
Company and 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)
4.18 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)
4.19 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).
4.20 Form of Statement of Relative Rights and Preferences for the
Series III Cumulative Preferred Stock, $25 Par Value (included as Annex F to
the Joint Proxy Statement/Prospectus filed February 1, 1996).
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 Administrator and Washington Public Power Supply System and the
Company, relating to the Hanford Project. (Exhibit 13-u to Registration 2-
21824)
10.20 Replacement Power Sales Contract dated April 12, 1963, between
the United States of America, Department of the Interior, acting through the
Bonneville Power Administrator and the Company, relating to the Hanford
Project. (Exhibit 13-v to Registration No. 2-21824)
10.21 Contract covering undivided interest in ownership and operation
of Centralia Thermal Plant, dated May 15, 1969. (Exhibit 5-b to
Registration No. 2-3765)
10.22 Construction and Ownership Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-b to
Registration No. 2-45702)
10.23 Operation and Maintenance Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-c to
Registration No. 2-45702)
10.24 Coal Supply Agreement, dated as of July 30, 1971, among The
Montana Power Company, the Company and Western Energy Company. (Exhibit 5-d
to Registration No. 2-45702)
10.25 Power Purchase Agreement with Washington Public Power Supply
System and the Bonneville Power Administration dated February 6, 1973.
(Exhibit 5-e to Registration No. 2-49029)
10.26 Ownership Agreement among the Company, Washington Public Power
Supply System and others dated September 17, 1973. (Exhibit 5-a-29 to
Registration No. 2-60200)
10.27 Contract dated June 19, 1974, between the Company and P.U.D.
No. 1 of Chelan County. (Exhibit D to Form 8-K dated July 5, 1974
10.28 Restated Financing Agreement among the Company, lessee,
Chrysler Financial Corporation, owner, Nevada National Bank and Bank of
Montreal (California), trustee, dated December 12, 1974 pertaining to a
combustion turbine generating unit trust. (Exhibit 5-a-35 to Registration
No. 2-60200)
10.29 Restated Lease Agreement between the Company, lessee, and the
Bank of California, and National Association, lessor, dated December 12,
1974 for one combustion generating unit. (Exhibit 5-a-36 to Registration
No. 2-60200)
10.30 Financing Agreement Supplement and Amendment among the Company,
lessee, Chrysler Financial Corporation, owner, The Bank of California,
National Association, trustee, Pacific Mutual Life Insurance Company,
Bankers Life Company, and The Franklin Life Insurance Company, lenders,
dated as of March 26, 1975, pertaining to a combustion turbine generating
unit trust. (Exhibit 5-a-37 to Registration No. 2-60200)
10.31 Lease Agreement Supplement and Amendment between the Company,
lessee, and The Bank of California, National Association, lessor, dated as
of March 26, 1975 for one combustion turbine generating unit. (Exhibit 5-a-
38 to Registration No. 2-60200)
10.32 Exchange Agreement executed August 13, 1964, between the United
States of America, Columbia Storage Power Exchange and the Company, relating
to Canadian Entitlement. (Exhibit 13-ff to Registration No. 2-24252)
10.33 Loan Agreement dated as of December 1, 1980 and related
documents pertaining to Whitehorn turbine construction trust financing.
(Exhibit 10.52 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1980, Commission File No. 1-4393)
10.34 Letter Agreement dated March 31, 1980, between the Company and
Manufacturers Hanover Leasing Corporation. (Exhibit b-8 to Registration No.
2-68498)
10.35 Coal Supply Agreement for Colstrip 3 and 4, dated as of July 2,
1980; Amendment No. 1 to Coal Supply Agreement, dated as of July 10, 1981;
and Coal Transportation Agreement dated as of July 10, 1981. (Exhibit 20-a
to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981,
Commission File No. 1-4393)
10.36 Residential Purchase and Sale Agreement between the Company and
the Bonneville Power Administration, effective as of October 1, 1981.
(Exhibit 20-b to Quarterly Report on Form 10-Q for the quarter ended
September 30, 1981, Commission File No. 1-4393)
10.37 Letter of Agreement to Participate in Licensing of Creston
Generating Station, dated September 30, 1981. (Exhibit 20-c to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1981, Commission
File No. 1-4393)
10.38 Power sales contract dated August 27, 1982 between the Company
and Bonneville Power Administration. (Exhibit 10-a to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1982, Commission File No. 1-
4393)
10.39 Agreement executed as of April 17, 1984, between the United
States of America, Department of the Interior, acting through the Bonneville
Power Administration, and other utilities relating to extension energy from
the Hanford Atomic Power Plant No. 1. (Exhibit (10)-47 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1984, Commission File No. 1-
4393)
10.40 Agreement for the Assignment of Output from the Centralia
Thermal Project, dated as of April 14, 1983, between the Company and Public
Utility District No. 1 of Grays Harbor. (Exhibit (10)-48 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1984, Commission File
No. 1-4393)
10.41 Settlement Agreement and Covenant Not to Sue executed by the
United States Department of Energy acting by and through the Bonneville
Power Administration and the Company dated September 17, 1985. (Exhibit
(10)-49 to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No. 1-4393)
10.42 Agreement to Dismiss Claims and Covenant Not to Sue dated
September 17, 1985 between Washington Public Power Supply System and the
Company. (Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1985, Commission File No. 1-4393)
10.43 Irrevocable Offer of Washington Public Power Supply System
Nuclear Project No. 3 Capability for Acquisition executed by the Company,
dated September 17, 1985. (Exhibit A of Exhibit (10)-50 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-
4393)
10.44 Settlement Exchange Agreement ("Bonneville Exchange Power
Contract") executed by the United States of America Department of Energy
acting by and through the Bonneville Power Administration and the Company,
dated September 17, 1985. (Exhibit B of Exhibit (10)-50 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-
4393)
10.45 Settlement Agreement and Covenant Not to Sue between the
Company and Northern Wasco County People's Utility District, dated
October 16, 1985. (Exhibit (10)-53 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.46 Settlement Agreement and Covenant Not to Sue between the
Company and Tillamook People's Utility District, dated October 16, 1985.
(Exhibit (10)-54 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1985, Commission File No. 1-4393)
10.47 Settlement Agreement and Covenent Not to Sue between the
Company and Clatskanie People's Utility District, dated September 30,
1985. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1985, Commission File No. 1-4393)
10.48 Stipulation and Settlement Agreement between the Company and
Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October
31, 1986. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1986, Commission File No. 1-4393)
10.49 Transmission Agreement dated April 17, 1981, between the
Bonneville Power Administration and the Company (Colstrip Project). (Exhibit
(10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
10.50 Transmission Agreement dated April 17, 1981, between the
Bonneville Power Administration and Montana Intertie Users (Colstrip
Project). (Exhibit (10)-56 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.51 Ownership and Operation Agreement dated as of May 6, 1981,
between the Company and other Owners of the Colstrip Project (Colstrip 3 and
4). (Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
10.52 Colstrip Project Transmission Agreement dated as of May 6, 1981,
between the Company and Owners of the Colstrip Project. (Exhibit (10)-58 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.53 Common Facilities Agreement dated as of May 6, 1981, between the
Company and Owners of Colstrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.54 Agreement for the Purchase of Power dated as of October 29,
1984, between South Fork II, Inc. and the Company (Weeks Falls Hydroelectric
Project). (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.55 Agreement for the Purchase of Power dated as of October 29,
1984, between South Fork Resources, Inc. and the Company (Twin Falls
Hydroelectric Project). (Exhibit (10)-61 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.56 Agreement for Firm Purchase Power dated as of January 4, 1988,
between the City of Spokane, Washington, and the Company (Spokane Waste
Combustion Project). (Exhibit (10)-62 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.57 Agreement for Evaluating, Planning and Licensing dated as of
February 21, 1985 and Agreement for Purchase of Power dated as of February
21, 1985 between Pacific Hydropower Associates and the Company (Koma Kulshan
Hydroelectric Project). (Exhibit (10)-63 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.58 Power Sales Agreement dated as of August 1, 1986, between
Pacific Power & Light Company and the Company. (Exhibit (10)-64 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987, Commission
File No. 1-4393)
10.59 Agreement for Purchase and Sale of Firm Capacity and Energy
dated as of August 1, 1986 between The Washington Water Power Company and the
Company. (Exhibit (10)-65 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.60 Amendment dated as of June 1, 1968, to Power Sales Contract
between Public Utility District No. 1 of Chelan County, Washington and the
Company (Rocky Reach Project). (Exhibit (10)-66 to Annual Report on Form 10-
K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.61 Coal Supply Agreement dated as of October 30, 1970, between the
Washington Irrigation & Development Company and the Company and other Owners
of the Centralia Thermal Project (Centralia Generating Plant). (Exhibit (10)-
67 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.62 Interruptible Natural Gas Service Agreement dated as of May 14,
1980, between Cascade Natural Gas Corporation and the Company (Whitehorn
Combustion Turbine). (Exhibit (10)-68 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.63 Interruptible Natural Gas Service Agreement dated as of January
31, 1983, between Cascade Natural Gas Corporation and the Company (Fredonia
Generating Station). (Exhibit (10)-69 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.64 Interruptible Gas Service Agreement dated May 14, 1981, between
Washington Natural Gas Company and the Company (Fredrickson Generating
Station). (Exhibit (10)-70 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.65 Settlement Agreement dated April 24, 1987, between Public
Utility District No. 1 of Chelan County, the National Marine Fisheries
Service, the State of Washington, the State of Oregon, the Confederated
Tribes and Bands of the Yakima Indian Nation, Colville Indian Reservation,
Umatilla Indian Reservation, the National Wildlife Federation and the Company
(Rock Island Project). (Exhibit (10)-71 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.66 Amendment No. 2 dated as of September 1, 1981, and Amendment No.
3 dated September 14, 1987, to Coal Supply Agreement between Western Energy
Company and the Company and the other Owners of Colstrip 3 and 4. (Exhibit
(10)-72 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
10.67 Amendatory Agreement No. 1 dated August 27, 1982, and Amendatory
Agreement No. 2 dated August 27, 1982, to the Power Sales Contract between
the Company and the Bonneville Power Administration dated August 27, 1982.
(Exhibit (10)-73 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
10.68 Transmission Agreement dated as of December 30, 1987, between
the Bonneville Power Administration and the Company (Rock Island Project).
(Exhibit (10)-74 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1988, Commission File No. 1-4393)
10.69 Agreement for Purchase and Sale of Firm Capacity and Energy
between The Washington Water Power Company and the Company dated as of
January 1, 1988. (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the
quarter ended March 31, 1988, Commission File No. 1-4393)
10.70 Amendment dated as of August 10, 1988, to Agreement for Firm
Purchase Power dated as of January 4, 1988, between the City of Spokane,
Washington, and the Company (Spokane Waste Combustion Project).(Exhibit (10)-
76 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988,
Commission File No. 1-4393)
10.71 Agreement for Firm Power Purchase dated October 24, 1988,
between Northern Wasco People's Utility District and the Company (The Dalles
Dam North Fishway). (Exhibit (10)-77 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1988, Commission File No. 1-4393)
10.72 Agreement for the Purchase of Power dated as of October 27,
1988, between Pacific Power & Light Company (PacifiCorp) and the Company.
(Exhibit (10)-78 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1988, Commission File No. 1-4393)
10.73 Agreement for Sale and Exchange of Firm Power dated as of
November 23, 1988, between the Bonneville Power Administration and the
Company. (Exhibit (10)-79 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1988, Commission File No. 1-4393)
10.74 Agreement for Firm Power Purchase, dated as of February 24,
1989, between Sumas Energy, Inc. and the Company. (Exhibit (10)-1 to
Quarterly Report on Form 10-Q for the quarter ended March 31, 1989,
Commission File No. 1-4393)
10.75 Settlement Agreement, dated as of April 27, 1989, between Public
Utility District No. 1 of Douglas County, Washington, Portland General
Electric Company, PacifiCorp, The Washington Water Power Company and the
Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q the for quarter
ended September 30, 1989, Commission File No. 1-4393)
10.76 Agreement for Firm Power Purchase (Thermal Project), dated as of
June 29, 1989, between San Juan Energy Company and the Company. (Exhibit
(10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30,
1989, Commission File No. 1-4393)
10.77 Agreement for Verification of Transfer, Assignment and
Assumption, dated as of September 15, 1989, between San Juan Energy Company,
March Point Cogeneration Company and the Company. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1989,
Commission File No. 1-4393)
10.78 Power Sales Agreement between The Montana Power Company and the
Company, dated as of October 1, 1989. (Exhibit (10)-4 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-
4393)
10.79 Conservation Power Sales Agreement dated as of December 11,
1989, between Public Utility District No. 1 of Snohomish County and the
Company. (Exhibit (10)-87 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1989, Commission File No. 1-4393)
10.80 Memorandum of Understanding dated as of January 24, 1990,
between the Bonneville Power Administrator and The Washington Public Power
Supply System, Portland General Electric Company, Pacific Power & Light
Company, The Montana Power Company, and the Company. (Exhibit (10)-88 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1989,
Commission File No. 1-4393)
10.81 Amendment No. 1 to Agreement for the Assignment of Power from
the Centralia Thermal Project dated as of January 1, 1990, between Public
Utility District No. 1 of Grays Harbor County, Washington, and the Company.
(Exhibit (10)-89 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1990, Commission File No. 1-4393)
10.82 Preliminary Materials and Equipment Acquisition Agreement dated
as of February 9, 1990, between Northwest Pipeline Corporation and the
Company. (Exhibit (10)-90 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1990, Commission File No. 1-4393)
10.83 Amendment No. 1 to the Colstrip Project Transmission Agreement
dated as of February 14, 1990, among the Montana Power Company, The
Washington Water Power Company, Portland General Electric Company, PacifiCorp
and the Company. (Exhibit (10)-91 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.84 Settlement Agreement dated as of February 27, 1990, among United
States of America Department of Energy acting by and through the Bonneville
Power Administrator, the Washington Public Power Supply System, and the
Company. (Exhibit (10)-92 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1990, Commission File No. 1-4393)
10.85 Amendment No. 1 to the Fifteen-Year Power Sales Agreement dated
as of April 18, 1990, between Pacificorp and the Company. (Exhibit (10)-93
to Annual Report on Form 10-K for the fiscal year ended December 31, 1990,
Commission File No. 1-4393)
10.86 Settlement Agreement dated as of October 1, 1990, among Public
Utility District No. 1 of Douglas County, Washington, the Company, Pacific
Power and Light Company, The Washington Water Power Company, Portland General
Electric Company, the Washington Department of Fisheries, the Washington
Department of Wildlife, the Oregon Department of Fish and Wildlife, the
National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the
Confederated Tribes and Bands of the Yakima Indian Nation, the Confederated
Tribes of the Umatilla Reservation, and the Confederated Tribes of the
Colville Reservation. (Exhibit (10)-95 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.87 Agreement for Firm Power Purchase dated July 23, 1990, between
Trans-Pacific Geothermal Corporation, a Nevada corporation, and the Company.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March
31, 1991, Commission File No. 1-4393)
10.88 Agreement for Firm Power Purchase dated July 18, 1990, between
Wheelabrator Pierce, Inc., a Delaware corporation, and the Company. (Exhibit
(10)-2 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991,
Commission File No. 1-4393)
10.89 Agreement for Firm Power Purchase dated September 26, 1990,
between Encogen Northwest, L.P., A Delaware Corporation and the Company.
(Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended March
31, 1991, Commission File No. 1-4393)
10.90 Agreement for Firm Power Purchase (Thermal Project) dated
December 27, 1990, among March Point Cogeneration Company, a California
general partnership comprising San Juan Energy Company, a California
corporation; Texas-Anacortes Cogeneration Company, a Delaware corporation;
and the Company. (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the
quarter ended March 31, 1991, Commission File No. 1-4393)
10.91 Agreement for Firm Power Purchase dated March 20, 1991, between
Tenaska Washington, Inc. a Delaware corporation, and the Company. (Exhibit
(10)-1 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991,
Commission File No. 1-4393)
10.92 Letter Agreement dated April 25, 1991, between Sumas Energy,
Inc., and the Company, to amend the Agreement for Firm Power Purchase dated
as of February 24, 1989. (Exhibit (10)-2 to Quarterly Report on Form 10-Q
for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.93 Amendment dated June 7, 1991, to Letter Agreement dated April
25, 1991, between Sumas Energy, Inc., and the Company. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission
File No. 1-4393)
10.94 Amendatory Agreement No. 3, dated August 1, 1991, to the Pacific
Northwest Coordination Agreement, executed September 15, 1964, among the
United States of America, the Company and most of the other major electrical
utilities in the Pacific Northwest. (Exhibit (10)-4 to Quarterly Report on
Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.95 Amendment dated July 11, 1991, to the Agreement for Firm Power
Purchase dated September 26, 1990, between Encogen Northwest, L.P., a
Delaware limited partnership and the Company. (Exhibit (10)-1 to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1991, Commission File
No. 1-4393)
10.96 Agreement between the 40 parties to the Western Systems Power
Pool (the Company being one party) dated July 27, 1991. (Exhibit (10)-2 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1991,
Commission File No. 1-4393)
10.97 Memorandum of Understanding between the Company and the
Bonneville Power Administration dated September 18, 1991. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1991,
Commission File No. 1-4393)
10.98 Amendment of Seasonal Exchange Agreement, dated December 4,
1991, between Pacific Gas and Electric Company and the Company. (Exhibit
(10)-107 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.99 Capacity and Energy Exchange Agreement, dated as of October 4,
1991, between Pacific Gas and Electric Company and the Company. (Exhibit
(10)-108 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.100 Intertie and Network Transmission Agreement, dated as of October
4, 1991, between Bonneville Power Administration and the Company. (Exhibit
(10)-109 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.101 Amendatory Agreement No. 4, executed June 17, 1991, to the Power
Sales Agreement dated August 27, 1982, between the Bonneville Power
Administration and the Company. (Exhibit (10)-110 to Annual Report on Form
10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.102 Amendment to Agreement for Firm Power Purchase, dated as of
September 30, 1991, between Sumas Energy, Inc. and the Company. (Exhibit
(10)-112 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.103 Centralia Fuel Supply Agreement, dated as of January 1, 1991,
between Pacificorp Electric Operations and the Company and other Owners of
the Centralia Steam-Electric Power Plant. (Exhibit (10)-113 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1991, Commission File No.
1-4393)
10.104 Agreement for Firm Power Purchase dated August 10, 1992, between
Pyrowaste Corporation, Puget Sound Pyroenergy Corporation and the Company.
(Exhibit (10)-114 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, Commission File No. 1-4393)
10.105 Memorandum of Termination dated August 31, 1992, between Encogen
Northwest, L.P. and the Company. (Exhibit (10)-115 to Annual Report on Form
10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.106 Agreement Regarding Security dated August 31, 1992, between
Encogen Northwest, L.P. and the Company. (Exhibit (10)-116 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
10.107 Consent and Agreement dated December 15, 1992, between the
Company, Encogen Northwest, L.P. and The First National Bank of Chicago, as
collateral agent. (Exhibit (10)-117 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.108 Subordination Agreement dated December 17, 1992, between the
Company, Encogen Northwest, L.P., Rolls-Royce & Partners Finance Limited and
The First National Bank of Chicago. (Exhibit (10)-118 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-
4393)
10.109 Letter Agreement dated December 18, 1992, between Encogen
Northwest, L.P. and the Company regarding arrangements for the application of
insurance proceeds. (Exhibit (10)-119 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.110 Guaranty of Ensearch Corporation in favor of the Company dated
December 15, 1992. (Exhibit (10)-120 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.111 Letter Agreement dated October 12, 1992, between Tenaska
Washington Partners, L.P. and the Company regarding clarification of issues
under the Agreement for Firm Power Purchase. (Exhibit (10)-121 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1992, Commission
File No. 1-4393)
10.112 Consent and Agreement dated October 12, 1992, between the
Company, and The Chase Manhattan Bank, N.A., as agent. (Exhibit (10)-122 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1992,
Commission File No. 1-4393)
10.113 Settlement Agreement dated December 29, 1992, between the
Company and the Bonneville Power Administration (BPA) providing for power
purchase by BPA. (Exhibit (10)-123 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.114 Contract with W. S. Weaver, Executive Vice President & Chief
Financial Officer, dated April 24, 1991. (Exhibit 10.114 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1993, Commission File No. 1-
4393)
10.115 General Transmission Agreement dated as of December 1, 1994,
between the Bonneville Power Administration and the Company (BPA Contract No.
DE-MS79-94BP93947) (Exhibit 10.115 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1994, Commission File No. 1-4393)
10.116 PNW AC Intertie Capacity Ownership Agreement dated as of October
11, 1994 between the Bonneville Power Administration and the Company (BPA
Contract No. DE-MS79-94BP94521) (Exhibit 10.116 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, Commission File No. 1-4393)
*10.117 Power Exchange Agreement dated as of September 27, 1995, between
British Columbia Power Exchange Corporation and the Company.
*10.118 Contract with W. S. Weaver, Executive Vice President and Chief
Financial Officer, dated October 18, 1996.
*10.119 Contract with S. M. Vortman, Senior Vice President Corporate and
Regulatory Relations, dated October 18, 1996.
*10.120 Contract with G. B. Swofford, Senior Vice President Customer
Operations, dated October 18, 1996.
*12-a Statement setting forth computation of ratios of earnings to
fixed charges (1992 through 1996).
*12-b Statement setting forth computation of ratios of earnings to
combined fixed charges and preferred stock dividends (1992 through 1996).
*21 List of subsidiaries.
*23 Consent of accountants.
*27 Financial Data Schedule
*99 Pro Forma Statements of Puget Sound Energy, Inc.
_________________________________
*Filed herewith.
POWER EXCHANGE AGREEMENT EXHIBIT 10.117
This POWER EXCHANGE AGREEMENT (this "Agreement"), dated as of September 27,
1995, is made by and between Puget Sound Power & Light Company ("Puget") and
British Columbia Power Exchange Corporation ("Powerex"). Each of Puget and
Powerex is sometimes referred to in this Agreement as "Party"; both of Puget
and Powerex are sometimes referred to in this Agreement as "Parties."
RECITALS
A. Puget is engaged in negotiations with the Bonneville Power
Administration ("BPA") concerning the acquisition by Puget of rights,
acceptable to Puget, to a share of the transfer capability of BPA's Westside
Northern Intertie (as defined below). The acquisition of such rights would
enable Puget to transfer power and energy generated in Canada to points in
the United States.
B. Contemporaneously with or following Puget's acquisition of a share
of the transfer capability of the Westside Northern Intertie, each of Puget
and Powerex desires to exchange power and energy with the other subject to
the terms and provisions of this Agreement.
AGREEMENTS
The Parties, therefore, agree as follows:
1. Definitions
The following terms used in this Agreement have the respective meanings
set forth below:
(a) "Agreement," "Puget," "Powerex," "Party," "Parties" and "BPA" have
the meanings set forth above.
(b) "Annual Shortage" means, with respect to each Year, the amount
(expressed in megawatt-hours) by which the Delivery Amount for such Year
exceeds the amount of power and energy made available by Powerex to Puget
pursuant to paragraph 3(a) at the Powerex Point of Delivery during such Year.
(c) "B.C. Hydro" means British Columbia Hydro and Power Authority or
its successors.
(d) "Delivery Amount" means (i) for any Year that is an entire
calendar year, 1,200,000 megawatt-hours of power and energy; (ii) for any
Year that is less than an entire calendar year, "Delivery Amount" means
1,200,000 megawatt-hours of power and energy prorated on a daily basis at a
rate of delivery of 3,288 megawatt-hours per day; (iii) if prior to the
midpoint of any Year Puget's share of the rated transfer capability of the
Westside Northern Intertie is, pursuant to the Westside Northern Intertie
Agreement, less than 300 megawatts in a north-to-south direction, "Delivery
Amount" means 1,200,000 megawatt-hours of power and energy (prorated as
provided in clause (ii) of this paragraph 1(d)) multiplied by a fraction, the
numerator of which is an amount (expressed in megawatts) equal to Puget's
then-current share of the rated transfer capability of the Westside Northern
Intertie and the denominator of which is an amount equal to 300 megawatts;
and (iv) for any Year in which notice has been delivered pursuant to
paragraph 3(h), "Delivery Amount" means 1,200,000 megawatt-hours of power and
energy prorated on a daily basis at a rate of delivery of 3,288
megawatt-hours per day and calculated on the basis of the number of days
elapsed prior to the delivery of such notice.
(e) "Effective Date" means the date by which the term of this
Agreement commences pursuant to paragraph 2(a).
(f) "Electric Disturbance" means any sudden, unexpected, changed or
abnormal electric condition, originating in or transmitted through B.C.
Hydro's electric system, Powerex's electric system (if any) or Puget's
electric system, which causes damage or interruption of service.
(g) "Event of Default" means either of the following:
(i) a material breach or material default in performance of
this Agreement by Powerex, which breach or default has continued for a
period in excess of thirty (30) days after Puget has notified Powerex in
writing that such breach or default will, unless corrected within such
thirty (30) day period, constitute an Event of Default entitling Puget
pursuant to Section 2(c) to terminate this Agreement; or
(ii) a material breach or material default in performance of
this Agreement by Puget, which breach or default has continued for a
period in excess of thirty (30) days after Powerex has notified Puget in
writing that such breach or default will, unless corrected within such
thirty (30) day period, constitute an Event of Default entitling Powerex
pursuant to Section 2(c) to terminate this Agreement.
(h) FERC" means the Federal Energy Regulatory Commission of the United
States or its regulatory successors.
(i) "Herein," "hereof" and "hereto," whenever used in this
Agreement, mean or refer to the whole of this Agreement and not to any
particular part or provision of this Agreement.
(j) "Powerex Point of Delivery" means a point on the United
States-Canada border at or near Blaine, Washington, at which the electric
facilities of B.C. Hydro and the Westside Northern Intertie are connected.
(k) "Prudent Utility Practice" means any of the practices, methods and
acts which:
(i) when engaged in, have previously been engaged in or
approved by a significant portion of the electric utility industry; or
(ii) in the exercise of reasonable judgment considering the
facts known when engaged in, could have been expected to accomplish the
desired result at a reasonable cost consistent with applicable law,
reliability, safety, efficiency and expedition.
Prudent Utility Practice is not limited to the optimum practice, method or
act, but rather is a spectrum of possible practices, methods or acts.
(l) "Puget Point of Delivery" means any point:
(i) on Puget's electric system (excluding any facilities and
capacity rights with respect to the Pacific Northwest AC Intertie)
requested in writing by Powerex at which:
(A) Puget has rights to deliver power to be exchanged
pursuant to this Agreement;
(B) Puget has, in Puget's determination, sufficient
capacity available on the facilities at such point to deliver
power to be exchanged pursuant to this Agreement; and
(C) Puget's transmission facilities are connected with
the transmission facilities of another scheduling utility that
has its own control area;
or
(ii) not on Puget's electric system, but designated by Puget as
a Puget Point of Delivery pursuant to paragraph 3(f).
Some or all of the Puget Points of Delivery as of the date of this Agreement
are identified in Exhibit A to this Agreement.
(m) "Term" means the period commencing on the Effective Date and
ending as contemplated in paragraph 2(b).
(n) "Westside Northern Intertie" means BPA's two 500 kilovolt
transmission lines between BPA's Custer Substation and the United
States-Canada border, BPA's Monroe-Custer #2 500 kilovolt transmission line
and the substation facilities related to each of such 500 kilovolt
transmission lines.
(o) "Westside Northern Intertie Agreement" has the meaning set forth
in paragraph 2(a).
(p) "Working Day" means any day which both Powerex and Puget observe
as a regular working day.
(q) "Year" means, as the context may require, (i) any entire calendar
year during the Term and (ii) the period commencing on the Effective Date and
ending at 2400 hours on December 31, 1995, and (iii) the period commencing at
0000 hours on January 1, 2005, and ending at 2400 hours on the tenth (10th)
anniversary of the Effective Date; PROVIDED, that if the Term is terminated
pursuant to this Agreement earlier than the tenth (10th) anniversary of the
Effective Date, then the last Year of the Term shall be the period commencing
at 0000 hours on January 1 of such Year and ending at 2400 hours on the date
on which the Term is so terminated.
2. Term and Termination
(a) The term of this Agreement shall commence at 2400 hours on the
latest of (i) the date of execution and delivery of this Agreement, (ii) the
date by which the agreement between Puget and BPA, pursuant to which Puget
acquires rights satisfactory to Puget to a share of the transfer capability
of the Westside Northern Intertie (the "Westside Northern Intertie
Agreement"), becomes effective in accordance with its terms, (iii) the date
by which this Agreement has been approved, accepted for filing, or otherwise
permitted to become effective by FERC; PROVIDED, that if FERC approves or
accepts for filing this Agreement or otherwise permits this Agreement to
become effective with any change or new condition, this Agreement shall not
be or become effective unless both of the Parties have agreed in writing, and
until the date by which both of the Parties have so agreed, to such change or
new condition, and (iv) the date by which Powerex's board of directors has
approved the provisions of this Agreement. Puget shall notify Powerex in
writing of the date referred to in clause (ii) of this paragraph promptly
following Puget's obtaining the rights described in such clause (ii).
Powerex shall notify Puget in writing of the date referred to in clause (iv)
of this paragraph promptly following Powerex's obtaining the approval
described in such clause (iv). If Powerex's board of directors does not
approve the provisions of this Agreement prior to October 20, 1995, then
either Puget or Powerex may deliver written notice to the other Party that
this Agreement is to be void ab initio, and upon receipt of such notice this
Agreement shall be void ab initio and of no force or effect.
(b) Unless earlier terminated pursuant to the terms hereof, the term
of this Agreement shall continue in effect until 2400 hours on the tenth
(10th) anniversary of the Effective Date.
(c) Upon the occurrence of an Event of Default, Puget or Powerex,
whichever is non-breaching or non-defaulting (as the case may be), may
terminate the Term by giving the other Party written notice of such
termination. Such termination shall be effective upon receipt of such notice
by such other Party. The Party terminating this Agreement pursuant to this
paragraph 2(c) shall incur no liability (whether for loss of profits, loss of
revenues or otherwise) to the other Party or to any other person or entity on
account of such termination.
(d) The termination of the Term pursuant to the terms hereof shall
serve automatically to terminate the Term and any tariff, rate and rate
schedule (i) comprised by or which incorporates this Agreement or (ii) which
is for service required to be offered as a result of this Agreement. If no
regulatory filing is required to effectuate termination of service under this
Agreement, no filing shall be required to be made for this purpose and each
Party hereby waives any right it may have to request or require that any
regulatory filing, beyond the initial filing of this Agreement with FERC,
shall be made to effectuate any termination of the Term or of this Agreement
(or any service pursuant to this Agreement). If a regulatory filing is
required to effectuate such termination, each Party hereby waives any right
it may have to request or to have any termination of the Term or of this
Agreement (or any service pursuant to this Agreement) denied, conditioned,
suspended or otherwise deferred.
(e) All rights and remedies of either Party under this Agreement and
at law and in equity shall be cumulative and not mutually exclusive and the
exercise of one right or remedy shall not be deemed a waiver of any other
right or remedy. Except as expressly otherwise provided in this Agreement,
nothing contained in any provision of this Agreement shall be construed to
limit or exclude any right or remedy of either Party (arising on account of
the breach or default by the other Party or otherwise) now or hereafter
existing under any other provision of this Agreement, at law or in equity.
The Parties agree that a Party not in breach or default under this Agreement
may seek specific performance from the other Party of any and all obligations
required or provided for under this Agreement.
3. Exchange of Power and Energy
(a) Subject only to paragraphs 3(c), 3(d), 3(h), 4 and 7(a), Powerex
shall, during each Year, make available to Puget at the Powerex Point of
Delivery an amount of power and energy up to the Delivery Amount.
(b) Subject to paragraphs 3(h) and 7(a), Puget shall, during each hour
of the Term, make available to Powerex at a Puget Point of Delivery an amount
of power and energy equal to the amount of power and energy requested by
Powerex (pursuant to paragraph 4) to be made available by Puget at such Puget
Point of Delivery during such hour; provided, that Puget shall not be
obligated pursuant to this paragraph 3(b) to make available at any and all
Puget Points of Delivery during any hour any amount of power and energy
(i) that exceeds the amount of power and energy actually made available to
Puget by Powerex, pursuant to this Agreement, at the Powerex Point of
Delivery during such hour or (ii) to the extent that doing so would be
contrary to Prudent Utility Practice.
(c) If Puget determines that for any hour Puget's available share of
the transfer capability (expressed in megawatts) of the Westside Northern
Intertie during such hour is less than the megawatt amount of power and
energy that Powerex would otherwise make available to Puget at the Powerex
Point of Delivery pursuant to paragraphs 3(a) and 4, then, without limiting
the provisions of paragraph 5, Powerex shall not be obligated pursuant to
paragraph 3(a) to, and Powerex shall not pursuant to paragraph 3(a), make
available to Puget during such hour the amount of power and energy that
exceeds such available Puget share of the transfer capability of the Westside
Northern Intertie (as determined by Puget) during such hour.
(d) If Puget determines that for any hour the available transfer
capability of any Puget Point of Delivery requested by Powerex (pursuant to
paragraph 4) for such hour (i) is less than the amount of power and energy
that Powerex has requested (pursuant to paragraph 4) Puget to make available
to Powerex at such Puget Point of Delivery or (ii) would be contrary to
Prudent Utility Practice, then, without limiting the provisions of paragraph
5, Powerex shall not be obligated pursuant to paragraph 3(a) to, and Powerex
shall not pursuant to paragraph 3(a), make available to Puget during such
hour the amount of power and energy that exceeds such available transfer
capability of such Puget Point of Delivery (as determined by Puget) during
such hour.
(e) Puget shall, at the written request of Powerex, notify Powerex of
the transfer capability anticipated by Puget to be available at any Puget
Point of Delivery during the period of time (up to one month) specified in
such request. Puget shall provide such notification to Powerex within one
month following receipt of such request therefor. Puget shall determine the
anticipated available transfer capability of such Puget Point of Delivery in
a reasonable manner.
(f) Powerex may request in writing that any point not on Puget's
electric system, but to which Puget has contractual or other rights to
deliver power and energy (e.g., BPA's John Day Substation), be designated by
Puget as a Puget Point of Delivery pursuant to this Agreement. Subject to
the other provisions of this Agreement, Puget shall use reasonable efforts to
accommodate such request and to designate such point as a Puget Point of
Delivery. Nothing in this paragraph is intended to limit any other provision
of this Agreement, including, without limitation, paragraph 4.
(g) By written agreement from time to time, the Parties may specify
amounts of power and energy that are to be exchanged pursuant to this
Agreement, but that are not to be included in the Delivery Amount for any
Year. The price to be paid for the exchange services to be provided by Puget
with respect to any such power and energy shall be as set forth in such
agreement. Any such agreement (and all of the terms and provisions thereof)
shall be subject to the rules, regulations, orders and other requirements,
now or hereafter in effect, of all regulatory authorities having jurisdiction
over such agreement, the Parties or either of them, including, without
limitation, FERC, the Canadian National Energy Board and the British Columbia
Ministry of Energy, Mines and Petroleum Resources.
(h) If at any time during the Term any of the payment amounts set
forth in paragraph 6 is changed by order of any governmental or regulatory
authority having jurisdiction over this Agreement, the Parties or either of
them, and such change is not also pursuant to an amendment of this Agreement
as set forth in paragraph 9(a), then either Party may, by written notice to
the other Party, reduce to zero (0) the amount of power and energy that each
Party would otherwise be obligated prospectively, pursuant to paragraph 3, to
make available to the other Party at the Powerex Point of Delivery or at any
Puget Point of Delivery, as the case may be. From and after the date of
receipt of such notice, neither Party shall be obligated prospectively to
make any power or energy available to the other Party pursuant to paragraph
3(a) or 3(b).
4. Scheduling
(a) Powerex shall have the right to preschedule (and otherwise to
schedule) power and energy pursuant to this Agreement from and after the date
on which Puget has the right to schedule power and energy on the Westside
Northern Intertie pursuant to the Westside Northern Intertie Agreement.
Powerex shall preschedule all deliveries of power and energy to be made
available at the Powerex Point of Delivery pursuant to paragraphs 3(a) and 5
in accordance with the procedures set forth in paragraphs 4(a)(i) and
4(a)(ii) (which procedures may be varied, by the mutual agreement of the
Parties' schedulers, in a manner not inconsistent with the other provisions
of this Agreement) and otherwise in a manner and at times that would enable
Puget to preschedule and schedule power and energy consistent with the
provisions relating to scheduling set forth in the Westside Northern Intertie
Agreement:
(i) Powerex shall, no later than 1100 hours of each Working Day
during the Term, (A) notify Puget in writing of the amounts of power and
energy (if any) that Powerex anticipates making available to Puget
during each hour of the next succeeding Working Day and non-Working Days
at the Powerex Point of Delivery and (B) specify in such written notice
(1) each Puget Point of Delivery at which Powerex requests all or part
of the power and energy made available by Powerex at the Powerex Point
of Delivery during such hour to be made available by Puget at such Puget
Point of Delivery during such hour, (2) the control area to receive such
power and energy at each such Puget Point of Delivery and (3) the party
to receive such power and energy at each such Puget Point of Delivery.
(ii) Puget shall, no later than 1200 hours of each Working Day,
notify Powerex as to whether, and by what amount (expressed in
megawatts):
(A) Puget has, pursuant to paragraph 3(c), determined
that, for any hour specified in Powerex's notice pursuant to
paragraph 4(a)(i) on such Working Day, Puget's available share of
the transfer capability of the Westside Northern Intertie during
such hour is less than the amount of power and energy that Powerex
anticipates making available to Puget during such hour at the
Powerex Point of Delivery pursuant to paragraph 3(a); and
(B) Puget has, pursuant to paragraph 3(d), determined
that, for any hour specified in Powerex's notice pursuant to
paragraph 4(a)(i) on such Working Day, the available transfer
capability of any Puget Point of Delivery requested by Powerex for
such hour is less than the amount of power and energy that Powerex
has requested Puget to make available to Powerex at such Puget
Point of Delivery during such hour;
PROVIDED, that Puget shall have no obligation to notify Powerex pursuant
to this paragraph 4(a)(ii) if Puget makes neither of the determinations
described in paragraphs 4(a)(ii)(A) and 4(a)(ii)(B).
(iii) If the available transfer capability of any Puget Point of
Delivery requested by Powerex for any hour is less than the amount of
power and energy that Powerex has requested Puget to make available to
Powerex at such Puget Point of Delivery during such hour (the "Requested
Amount"), Puget shall notify Powerex of an alternate Puget Point of
Delivery and of the hour (as each is determined by Puget) at which Puget
shall, following receipt of Powerex's request to do so, make the
Requested Amount available to Powerex; provided, that Puget shall not be
obligated pursuant to this paragraph to make power and energy available
to Powerex at any alternate Puget Point of Delivery to the extent that
the cumulative Requested Amount made available to Powerex at all
alternate Puget Points of Delivery pursuant to this paragraph would
exceed 180,000 megawatt-hours per month or 1,200,000 megawatt-hours per
Year.
(iv) If Puget does not, on any Working Day during the Term,
notify Powerex pursuant to paragraph 4(a)(ii) that Puget has made either
of the determinations described in paragraphs 4(a)(ii)(A) and
4(a)(ii)(B), then Powerex's preschedule on such Working Day shall be
deemed to be the amounts of power and energy set forth in the written
notice delivered by Powerex pursuant to paragraph 4(a)(i) on such
Working Day with respect to the Powerex Point of Delivery and each Puget
Point of Delivery specified in such notice. If Puget does, on any
Working Day during the Term, notify Powerex pursuant to paragraph
4(a)(ii) that Puget has made either of the determinations described in
paragraphs 4(a)(ii)(A) and 4(a)(ii)(B), then Powerex's preschedule on
such Working Day shall be deemed to be the amounts of power and energy
set forth in the written notice delivered by Powerex pursuant to
paragraph 4(a)(i) on such Working Day with respect to the Powerex Point
of Delivery and each Puget Point of Delivery specified in such notice,
adjusted downward to reflect any such determination by Puget.
(b) Powerex may request a change to any amount of power and energy
prescheduled, pursuant to paragraph 4(a), to be delivered at the Powerex
Point of Delivery or at any Puget Point of Delivery, provided that such
request is made by Powerex not later than one (1) hour prior to the hour in
which such amount of power and energy was so prescheduled to be delivered.
Puget shall endeavor (but shall in no event be obligated) to accept and make
deliveries of power and energy in accordance with such request by Powerex.
Notwithstanding the foregoing, the entire amount of power and energy
requested by Powerex, pursuant to this paragraph 4, to be made available by
Puget at all Puget Points of Delivery during any hour shall not exceed the
amount of power and energy scheduled, pursuant to this paragraph 4, to be
made available to Puget by Powerex at the Powerex Point of Delivery during
such hour.
5. Exchange Balancing
The Annual Shortage for any Year (if any) shall, pursuant to the
provisions of paragraphs 3 and 4, be made available by Powerex to Puget at
the Powerex Point of Delivery within two (2) Years following the end of such
Year. The power and energy scheduled (pursuant to paragraph 4) during any
Year shall be deemed to be power and energy constituting an Annual Shortage
for any previous Year until the entire amount of any Annual Shortage is made
available to Puget at the Powerex Point of Delivery. Notwithstanding
anything in this Agreement to the contrary, the entire amount of any Annual
Shortage shall be made available by Powerex to Puget at the Powerex Point of
Delivery (for exchange by Puget to Powerex at one or more Points of Delivery
pursuant to paragraph 3) within two (2) years following the expiration of the
Term.
6. Payments by Powerex; Return of Losses by Powerex
(a) As compensation to Puget for the exchange service provided by
Puget to Powerex pursuant to this Agreement, Powerex shall pay to Puget each
calendar month the following amounts:
(i) With respect to any amount of power and energy that does
not constitute all or part of an Annual Shortage,
(A) the product of (i) the amount of such power and
energy (expressed in megawatt-hours) scheduled and made available
by Powerex pursuant to this Agreement and made available by Puget
to Powerex at all Puget Points of Delivery during such month,
multiplied by (ii) three dollars and fifty cents (US$3.50);
plus
(B) the amount of all incremental costs and expenses
(if any) incurred, in Puget's determination, by Puget during such
month for transmission, on any transmission system other than
Puget's to any Puget Point of Delivery not on Puget's electric
system, of such power and energy delivered by Powerex to Puget at
the Powerex Point of Delivery during such month; and
(ii) With respect to any amount of power and energy that does
constitute all or part of an Annual Shortage,
(A) the product of (i) the amount of such power and
energy (expressed in megawatt-hours) made available by Puget to
Powerex at all Puget Points of Delivery during such month,
multiplied by (ii) three dollars and fifty cents (US$3.50),
together with interest thereon accruing at an annual rate equal
to Puget's annual weighted average cost of capital with respect
to investments by Puget in the Westside Northern Intertie (such
rate to be calculated on the basis of a 365- or 366-day year and
actual days elapsed and such interest to accrue from, and
including, the last day of the Year in which such Annual Shortage
was incurred to, but excluding, the date on which such power and
energy is delivered by Powerex to Puget at the Powerex Point of
Delivery);
plus
(B) the amount of all incremental costs and expenses
(if any) incurred by Puget, in Puget's determination, during such
month for transmission, on any transmission system other than
Puget's to any Puget Point of Delivery not on Puget's electric
system, of such power and energy delivered by Powerex to Puget at
the Powerex Point of Delivery during such month.
(b) Not later than thirty (30) days after the end of each calendar
month during the Term, Puget shall mail to Powerex a statement showing the
amount payable by Powerex pursuant to paragraph 6(a). Powerex shall pay the
entire amount of each such statement within twenty (20) days after receipt
thereof, such payment to be made in immediately available funds by electronic
wire transfer into the account designated from time to time by Puget to
Powerex for such purpose. Puget shall, within fifteen (15) days following a
written request from Powerex therefor, provide to Powerex such documentation
in connection with each such statement as Powerex may reasonably request.
(c) To compensate Puget for losses incurred in providing transmission
service pursuant to this Agreement, Powerex shall make available to Puget at
the Powerex Point of Delivery (unless otherwise mutually agreed upon by the
Parties) on the corresponding hour one hundred sixty-eight (168) hours later
or on another hour mutually agreed upon by the Parties, an amount of power
and energy equal to the product of (a) the amount of power and energy
(expressed in megawatt-hours) for which exchange service is provided to
Powerex by Puget during a given hour pursuant to this Agreement multiplied by
(b) a loss factor of three percent (3%). Puget may review the loss factor in
effect from time to time under this Agreement and, no more frequently than
once in any Year, determine a revised loss factor to reflect any change in
condition that does or would substantially affect losses on Puget's electric
system; PROVIDED, however, that any revision to the loss factor pursuant to
this Agreement (a) shall be prospective only, (b) shall be made in an
equitable manner so as to be consistent with such change in condition and
(c) shall reflect values that (i) represent the current operating conditions
on Puget's electric system or (ii) have changed due to a change in Puget's
methodology for calculating loss factors acceptable to FERC.
7. Limitation of Liability
(a) Neither Party shall be liable to the other for, or be considered
to be in breach or default under this Agreement because of, any delay or
failure in performance under this Agreement if such delay or failure is due
to any interruption, suspension, curtailment or fluctuation in transmission
resulting from any of the following:
(i) any cause or condition beyond such Party's reasonable
control, or which such Party is unable to overcome by the exercise of
reasonable diligence (including, but not limited to, failure or threat
of failure of facilities or equipment; fire, lightning, flood,
earthquake, volcanic activity, wind, storm and other acts of the
elements; court order and act, or failure to act, of civil, military or
governmental authority; strike, lockout and other labor dispute;
epidemic, riot, insurrection, sabotage, war, blockade and other civil
disturbance or disobedience; labor or material shortage; act or omission
of any person or entity (other than such Party and its contractors or
suppliers of any tier or anyone acting on behalf of such Party); and
Electric Disturbance originating in or transmitted through such Party's
electric system or any electric system with which such Party's system is
interconnected); or
(ii) any action taken by such Party which is, in the judgment of
such Party, necessary or prudent to protect the operation, performance,
integrity, reliability or stability of such Party's electric system or
of any electric system with which such Party's electric system is
interconnected, whether such action occurs automatically or manually.
Nothing contained in this Agreement shall be construed to require either
Party to settle any strike, lockout or other labor dispute in which it may be
involved.
However, if any of the foregoing causes, conditions, actions or events causes
either Party to receive an amount of power and energy less than the amount of
power and energy to which such Party would be otherwise entitled pursuant to
this Agreement, the other Party shall offer to make the difference between
such amounts of power and energy available to such Party at the appropriate
point of delivery pursuant to this Agreement at such times and in such
amounts as may be satisfactory to both of the Parties.
(b) Neither Puget nor Powerex (either, a "First Party") nor the
successors or permitted assigns of the First Party nor the respective
directors , officers, employees, agents or representatives of the First Party
or its successor or assigns shall be liable to the other Party ("Second
Party") for any cost, expense, loss, injury, harm, liability or damages
incurred by the Second Party caused by or arising out of any Electric
Disturbance that migrates, directly or indirectly, from or through the First
Party's electric system (or, in the case of Powerex, the electric system of
B.C. Hydro) to the Second Party's electric system (or, in the case of
Powerex, the electric system of B.C. Hydro). The Second Party hereby
releases the First Party, its successors and assigns, and the respective
directors, officers, employees, agents and representatives of the First Party
and its successors and assigns (each, a "First Party Beneficiary"), from any
such cost, expense, loss, injury, harm, liability or damages, whether or not
the same arises or results from or is caused by any negligence of such First
Party Beneficiary.
(c) Neither Party shall be liable to the other Party under this
Agreement for any loss of profit, revenues or expectancies or for any
incidental, indirect, special, exemplary, punitive or consequential damages.
This provision shall apply notwithstanding anything to the contrary set forth
in this Agreement.
(d) The provisions of this paragraph 7 shall apply to the fullest
extent permitted by applicable law and notwithstanding the provisions of any
other paragraph or section of this Agreement; provided, however, that the
benefits of this paragraph 7 shall not extend to either Party to the extent
that such Party is prevented by federal, state or local law from complying
with any of the provisions of this paragraph 7.
8. Notices
Any notice, request, authorization, direction or other communication
(except for any communication between the Parties' schedulers pursuant to
paragraph 4) under this Agreement shall be given in writing and shall be
delivered in person, by first-class U.S. mail (stamped with the required
postage) or by telecopy, properly addressed to the intended recipient as
follows:
If to Puget:
Puget Sound Power & Light Company
P.O. Box 97034
Bellevue, Washington 98009-9734
Attention: Vice President Power Planning
Telecopy: (206) 462-3175
If to Powerex:
British Columbia Power Exchange Corporation
Suite 2210
666 Burrard Street
Vancouver, B.C., Canada V6C 2X8
Attention: Vice President Development
Telecopy: (604) 891-5015
Any such notice, request, authorization, direction or other communication
delivered pursuant to this paragraph 8 in person or by mail shall be deemed
to be delivered to the recipient Party upon receipt, and any such notice,
request, authorization, direction or other communication delivered pursuant
to this paragraph 8 by telecopy shall be deemed delivered to the recipient
Party upon electronic confirmation of receipt. Either Party may change its
address specified above by giving the other Party notice of such change in
accordance with this section 8.
9. Miscellaneous
(a) Amendments. No amendment or modification of this Agreement shall
be valid unless set forth in a written agreement hereafter entered into by
Powerex and Puget.
(b) Nonwaiver. The failure of either Party to insist upon or enforce
strict performance by the other Party of any provision of this Agreement or
to exercise any right under this Agreement shall not be construed as a waiver
or relinquishment to any extent of such Party's right to assert or rely on
any such provision or right in that or any other instance; rather, the same
shall be and shall remain in full force and effect. Any waiver at any time
by either Party of any of its rights under this Agreement in a particular
circumstance or instance shall not constitute a waiver thereof in any other
circumstance or instance.
(c) Headings. The paragraph and section headings used in this
Agreement are for convenience of reference only and shall not be used or
construed to define, interpret, expand or limit any of the terms or
provisions of this Agreement.
(d) Transfer of Interests. Neither Party shall sell, assign,
encumber, dispose of or otherwise transfer (voluntarily, or by operation of
law or otherwise) this Agreement or any right, interest or benefit under this
Agreement without the prior written consent of the other, which consent shall
not be unreasonably denied, delayed or withheld; PROVIDED, however, that
(a) Powerex hereby consents to any such sale, assignment, encumbrance,
disposition or transfer by Puget to (i) a successor in operation of all or
substantially all of the electric utility properties of Puget or (ii) any
holder (or the trustee of any holder) of the debt of Puget pursuant to the
terms of a mortgage, trust, security agreement, indenture or other instrument
of indebtedness to which Puget and such holder (or such trustee) are parties,
as security for bonds or other indebtedness of Puget, past or future, and
(b) Puget hereby consents to the assignment by Powerex to any third party of
Powerex's right pursuant to this Agreement to receive and take delivery of
power and energy at any Puget Point of Delivery, provided that such third
party is a scheduling utility that operates its own control area at such
Puget Point of Delivery. Neither the pledge, mortgage or grant of any lien
for security by Puget of any of its rights in this Agreement or any right,
interest or benefit that Puget may have under this Agreement, nor the
execution of a pledge, mortgage, security agreement, indenture or trust deed
or a judicial or foreclosure sale made thereunder, shall be deemed a
voluntary transfer within the meaning of this paragraph 9(d). No assignment
by either Party shall relieve or release it to any extent of any of its
obligations hereunder. Subject to the foregoing restrictions, this Agreement
shall be fully binding upon, inure to the benefit of and be legally
enforceable by the Parties and their respective successors, assigns and legal
representatives.
(e) Severability. The invalidity or unenforceability of any provision
of this Agreement shall not affect the other provisions hereof, and this
Agreement shall be construed in all respects as if such invalid or
unenforceable provision were omitted.
(f) Implementation. Each Party shall take such action (including, but
not limited to, the execution, acknowledgment and delivery of documents) as
may reasonably be requested by the other Party for the implementation and
continuing performance of this Agreement.
(g) Relationship of Parties. Nothing contained in this Agreement
shall be construed to create an agency, association, joint venture, trust or
partnership, or impose an agency, trust or partnership covenant, obligation
or liability on or with regard to either of the Parties. Each Party shall be
individually responsible for its own covenants, obligations and liabilities
under this Agreement. All rights and obligations of the Parties are several,
not joint. No Party shall be deemed to control, to be under the control of,
or to be the agent of, the other Party.
(h) No Dedication of Facilities. No undertaking by one Party to the
other Party under any provision of this Agreement shall constitute the
dedication of the electric system or any portion thereof of the undertaking
Party to the public or to such other Party, and it is understood and agreed
that any such undertaking under any provision of this Agreement by a Party
shall cease upon the termination, cancellation or completion of such Party's
obligations under this Agreement.
(i) No Retail Services. Nothing contained in this Agreement shall
grant any rights to, or obligate either Party to provide, any services
hereunder directly to or for retail customers of the other Party.
(j) No Third-Party Beneficiaries. There are no third-party
beneficiaries of this Agreement. This Agreement shall not be construed to
create rights in, or to grant remedies to, any third party as a beneficiary
of this Agreement or of any duty, obligation or undertaking established
herein. No action may be commenced or prosecuted against either Party by any
third party claiming as a third-party beneficiary of this Agreement or the
transactions contemplated by this Agreement. This Agreement shall not
release or discharge any liability of any third party to either Party or give
any third party any right of subrogation or action over against either Party.
(k) Survival. Paragraphs 5, 6, 7 and all other provisions of this
Agreement that may reasonably be interpreted or construed as surviving the
termination, cancellation or expiration of this Agreement shall survive the
termination, cancellation or expiration of this Agreement.
(l) Governing Law. The rights and obligations of each Party under
this Agreement shall in all respects, including all matters of construction,
validity and performance, be governed by and construed in accordance with the
laws of the State of Washington (without reference to any rules governing
conflict of laws), except to the extent such laws may be preempted by the
laws of the United States of America.
(m) Judgments and Determinations. Whenever it is provided in this
Agreement that either Party shall determine or make a determination or
judgment, or that any action, determination or judgment shall be in such
Party's determination or judgment, the exercise of such determination or
judgment shall be made solely by such Party and shall be final and not
subject to challenge, so long as such Party exercises its determination or
judgment in good faith and not arbitrarily or capriciously.
(n) Regulatory Matters. This Agreement is subject to the rules,
regulations, orders and other requirements, now or hereafter in effect, of
all regulatory authorities having jurisdiction over this Agreement, the
Parties or either of them, including, without limitation, FERC, the Canadian
National Energy Board and the British Columbia Ministry of Energy, Mines and
Petroleum Resources. The rates for services specified herein shall remain in
effect during the Term and shall not be subject to change through application
by either party to FERC pursuant to the provisions of Section 205 of the
Federal Power Act absent the written agreement of both of the Parties. The
word "rates" as used in this paragraph 9(n) means a statement of services as
provided in this Agreement, rates and charges for or in connection with those
services, and all classifications, practices, rules, regulations or
contracts, including but not limited to this Agreement, which may in any
manner affect or relate to such services, rates and charges.
(o) Currency. All denominations of currency set forth in this
Agreement are in United States dollars.
(p) Interpretation of Ambiguities; Entire Agreement. Each provision
of this Agreement is the product of negotiation between the Parties. Any
rule of interpreting ambiguities against the interests of the drafting party
shall not be applied in resolving any dispute over the meaning of any
provision of this Agreement or the intent of the Parties with respect to such
provision. This Agreement constitutes, on and as of the date hereof, the
entire agreement of the Parties with respect to the subject matter hereof,
and all prior agreements, whether written or oral, between the Parties with
respect to the subject matter hereof are hereby superseded in their
entireties.
PUGET SOUND POWER & LIGHT COMPANY
By _____________________________
J. R. Lauckhart
Vice President Power Planning
Date Signed ______________________
BRITISH COLUMBIA POWER EXCHANGE CORPORATION
By _____________________________
Its _____________________________
Date Signed ______________________
EXHIBIT A
TO POWER EXCHANGE AGREEMENT
Puget Points of Delivery Potential Scheduling Utilities
Colstrip Project 500 kV Bus The Montana Power Company
The Washington Water Power Company
Portland General Electric Company
BPA Garrison Substation The Montana Power Company
The Washington Water Power Company
PacifiCorp
Portland General Electric Company
Bonneville Power Administration
Mid Columbia The Washington Water Power Company
Portland General Electric Company
PacifiCorp
Grant County PUD
Chelan County PUD
Douglas County PUD
Seattle City Light
Tacoma City Light
Bonneville Power Administration
Centralia PacifiCorp
Portland General Electric Company
The Washington Water Power Company
Bonneville Power Administration
Seattle City Light
Tacoma City Light
Puget Starwood Substation Tacoma City Light
Puget Maple Valley Substation Seattle City Light
Bonneville Power Administration
Seattle City Light Bothell Substation Seattle City Light
Rocky Reach Substation (230 kV) Bonneville Power Administration
BPA Vantage Substation (230 kV) Bonneville Power Administration
BPA Bellingham Substation (115 kV) Bonneville Power Administration
BPA Covington Substation (230 kV) Bonneville Power Administration
BPA Custer Substation (230 kV) Bonneville Power Administration
BPA C. W. Paul Substation (500 kV) Bonneville Power Administration
BPA Monroe Substation (230 kV) Bonneville Power Administration
Puget Sedro Woolley Substation (230kV) Bonneville Power Administration
Sedro Woolley Tap (230 kV) Bonneville Power Administration
Puget White River Substation (230 kV) Bonneville Power Administration
-5-
AGREEMENT EXHIBIT 10.118
THIS AGREEMENT ("Agreement") is made and entered into as of the __ day
of October, 1996 between PUGET SOUND POWER & LIGHT COMPANY, a Washington
corporation (the "Company"), and WILLIAM S. WEAVER ("Employee"). The term
"Parties" refers to the Company and the Employee.
RECITALS
A. Employee is currently serving as Executive Vice President and Chief
Financial Officer of the Company.
B. Pursuant to an Agreement and Plan of Merger, dated as of October
18, 1995 (the "Merger Agreement"), Washington Energy Company and Washington
Natural Gas Company have agreed to merge with and into the Company (the
"Merger").
C. Employee's position and job responsibilities within the Company
have changed and will continue to change as a result of the Merger Agreement
and the Merger. Consequently, Employee has advised the Company's President
and Chief Executive Officer that he wishes to tender his resignation.
D. The Company desires to retain the services of Employee and
accordingly hasagreed to provide incentives for Employee to remain employed
with the Company.
NOW, THEREFORE, in consideration of the mutual covenants and agreements
contained herein, and for other good and valuable consideration, the Parties
agree as follows:
1. Incentive Payments
The Company agrees to provide to Employee the following benefits if
Employee does not voluntarily terminate his employment with the Company
prior to the consummation of the Merger pursuant to the terms of the Merger
Agreement (the "Effective Date") and his employment thereafter terminates
for any reason other than retirement at the Normal Retirement Date, as
defined in the Company's Supplemental Retirement Plan for Officers as
amended to the date of this Agreement (the "SERP").
(a) Employee's full base salary earned through the termination
date, plus payment for all accrued vacation and any deferred compensation to
which Employee is entitled for the fiscal year most recently ended prior to
Employee's termination, and Employee's pro rata share of any compensation
under any Company plan which has accrued through the date of termination,
regardless of whether or not pursuant to the terms of the plan such amounts
are vested or are payable in the year of termination; plus
(b) An amount equal to three times the greater of (i) the sum of
Employee's annual base salary in 1996 plus the bonus paid to Employee in
1996 plus the phantom stock payment made to Employee in 1996 or (ii) the sum
of Employee's annual base salary at the rate in effect as of the date of
termination, plus the amount of any additional compensation awarded to
Employee, including any sums paid under phantom stock awards, for the
calendar year most recently ended. However, if Employee's Normal Retirement
Date is less than three years after the date of termination, the multiplier
in the preceding sentence shall be reduced from three to that fraction of
three representing the number of months remaining to the Normal Retirement
Date divided by 36 (e.g., if 18 months remain to the Normal Retirement Date,
the multiplier would be 18/36 x three = 1.5).
(c) The Company shall maintain in full force and effect for the
three years following the date of termination (or, if less, until the
Employee's Normal Retirement Date) all employee benefit plans, programs and
policies, including any life or health insurance plans, in which Employee
was entitled to participate immediately prior to termination, provided that
Employee is qualified to participate under the general terms and provisions
of such plans, programs and policies. In the event that Employee's
continued participation in any such plan, program or policy is not possible
under its terms and conditions, the Company shall at its option either
arrange for Employee to receive benefits substantially similar to those
which Employee would have been entitled to receive under each plan, program
or policy, or pay to employee an amount equal to the premiums that the
Company would pay on Employee's behalf for participation in such plan,
program or policy. At the end of the period of coverage, Employee will have
the option to receive an assignment at no cost, and with no apportionment of
prepaid premiums, of any assignable insurance policies owned by the Company
and relating to Employee, and to take advantage of any conversion privileges
pertinent to the benefits available under Company policies.
(d) In addition to the regular payment of benefits to which
Employee is entitled under the retirement plans or programs in effect on the
date of Employee's termination, which shall not be affected by such
termination, the Company shall pay to Employee in cash at the Normal
Retirement Date or at such earlier retirement date as Employee may elect
pursuant to the plans, an amount equal to the actuarial equivalent of the
additional retirement compensation to which Employee would have been
entitled under the terms of such retirement plans or programs (without
regard to vesting) had Employee continued in the employ of the Company for
an additional three years at Employee's base salary rate as of the date of
termination. If Employee's Normal Retirement Date would occur during that
three period, then the amount of such additional compensation shall be
calculated on the basis that Employee's employment continued to that date.
For purposes of this calculation, the actuarial equivalent shall be
determined by assuming survival to age 80.
(e) Employee shall waive all rights to receive shares of common
stock of the Company issuable upon exercise of options or similar rights, if
any, granted to Employee under the Company's stock option or similar equity
plans. In return for that waiver, Employee shall be entitled to receive,
within 30 days following the date of termination, a payment equal to the
difference between the exercise price of all options or similar rights held
by Employee, whether or not then fully exercisable, and the higher of (i)
the closing price of the common stock on the New York Stock Exchange on the
date of termination or (ii) the highest price per share actually paid in
connection with any change of control of the Company.
(f) Notwithstanding any other provisions of this Agreement, if any
payments or benefits under this Agreement, together with any other Parachute
Payments (as defined under Internal Revenue Code Section 280(G)(b)(2)) made
by the Company to Employee, if any, are characterized as Excess Parachute
Payments (as defined in Internal Revenue Code, Section 280(G)(b)(1)), then
the Company shall pay to Employee, in addition to the payments to be
received under this Section, an amount equal to the excise taxes imposed by
Section 4999 of the Code on Employee's Excess Parachute Payments, plus an
amount equal to the federal and, if applicable, state income taxes which
will be payable by Employee as a result of this additional payment.
(g) In addition, if Employee does not voluntarily terminate his
employment with the Company prior to the date which is six months after the
Effective Date of the Merger and his employment thereafter terminates for
any reason other than retirement at the Normal Retirement Date, the Company
agrees that the benefits payable to Employee under the SERP shall be based
upon Employee's average Compensation (as defined in the SERP, which
Compensation includes amounts paid in respect of phantom stock awards) for
his highest consecutive twenty-four months of service, rather the highest
sixty consecutive months of service as now provided in Section 3.1 of the
SERP. No amendment or termination of the SERP subsequent to the date of
this Agreement shall diminish such benefits.
Employee shall not be required to mitigate the amount of any payment due
hereunder by seeking other employment and, except as provided in the next
sentence, the payments due hereunder shall not be affected by any other
employment which Employee may obtain. If Employee accepts a position with
another employer during the period for payment of employee benefits under
Section 1c, then the Company's obligation to pay such employee benefits will
cease as of the date of Employee's new employment, provided, however, that
the Company will continue such benefits for the full period to the extent
that they exceed the comparable benefits from such other employment.
2. Termination for Cause
Notwithstanding Section 1 of this Agreement, if prior to the Effective
Date of the Merger the Board of Directors of the Company terminates
Employee's employment for "Cause," then the Company shall be obligated to
pay to Employee under this Agreement only his current base salary plus
accrued vacation and any other compensation actually accrued through the
date of termination. If the Company terminates Employee's employment at any
time without Cause, the Company shall be obligated to provide to Employee
the benefits set forth in Section 1 of this Agreement. For the purposes of
this Agreement, "Cause" shall mean (a) the willful and continued failure by
Employee to substantially perform his duties with the Company (other than
any such failure resulting from incapacity due to physical or mental
illness), for a period of 30 days after written notice of demand for
substantial performance has been delivered to Employee by the Board of
Directors which specifically identifies the manner in which the Board
believes that Employee has not substantially performed his duties, or (b)
the willful engaging by Employee in gross misconduct materially and
demonstrably injurious to the Company, as determined by the Board of
Directors after notice to Employee and an opportunity for a hearing. No
act, nor failure to act, on Employee's part shall be considered "willful"
unless he has acted or failed to act with an absence of good faith and
without a reasonable belief that his action or failure to act was in the
best interests of the Company.
3. Indemnification
The Company shall defend, indemnify and hold Employee harmless from any
and all liabilities, obligations, claims or expenses which arise in
connection with or as a result of Employee's service as an officer, employee
or director of the Company and/or any of its affiliates and subsidiaries to
the fullest extent allowed by law. The Company shall assure that Employee
remains covered by the Company's policies of directors' and officers'
liability insurance for six years following the date of termination.
4. Payments and Disputes
For purposes of this Agreement, the date of termination will be the
date written notice of termination is given by Employee or the Company. The
amounts specified in Sections 1(a) and 1(b) will be paid no more than ten
business days after the date of termination. In the event that any payments
due hereunder shall be delayed for any reason for more than ten business
days from the date due, the amounts due shall bear interest at the rate of
12% per annum until paid.
Any dispute between the Parties hereto with respect to any of the
matters set forth herein shall be submitted to binding arbitration in city
of Seattle, state of Washington. Either Party may commence the arbitration
by delivery of a written notice to the other, describing the issue in
dispute and its position with regard to the issue. If the Parties are
unable to agree on an arbitrator within 30 days following delivery of such
notice, the arbitrator shall be selected by a Judge of the Superior Court of
the State of Washington for King County upon three days' notice. Discovery
shall be allowed in connection with any such arbitration to the same extent
permitted by the Washington Rules of Civil Procedure but either Party may
petition the arbitrator to limit the scope of such discovery, in which event
the arbitrator shall determine the extent of discovery allowable in
connection with the dispute in question. Except as otherwise provided
herein, the arbitration shall be conducted in accordance with the rules of
the American Arbitration Association then in effect for expedited
proceedings. The award of the arbitrator shall be final and binding, and
judgment upon an award may be entered in any court of competent
jurisdiction. The arbitrator shall hold a hearing, at which the Parties may
present evidence and argument, within 30 days of his or her appointment, and
shall issue an award within 15 days of the close of the hearing. The
Company will pay all fees and expenses, including attorneys' fees and the
cost of the arbitrator, incurred by Employee in good faith in contesting or
disputing any termination for Cause or in seeking to obtain or enforce any
right or benefit provided by this Agreement.
5. Notices
All notices or other communications required or permitted by this
Agreement shall be in writing and shall be sufficiently given if personally
delivered or if sent by certified mail, postage prepaid, addressed as
follows:
If to Employee, to:
William S. Weaver
10 East Roanoke, #18
Seattle, WA 98102
If to the Company:
Puget Sound Power & Light Company
P.O. Box 97034
Bellevue, Washington 98009-9734
Attention: Chief Executive Officer
Facsimile: (206) 462-3300
Any such mailed notice or communication shall be deemed to have been
given three days after the date mailed. Any address may be changed by
giving written notice of such change in the manner provided herein for
giving notice.
6. Entire Agreement
This Agreement contains the entire understanding of the Parties with
regard to the subject matter of this Agreement and may only be changed by
written agreement signed by both Parties. Any and all prior discussions,
negotiations, commitments and understandings related thereto are merged
herein.
7. Binding Effect
This Agreement shall be binding upon and inure to the benefit of the
Parties, and their successors, legal representatives and heirs, including
any successor to the Company's business or assets by merger, consolidation,
sale of assets or otherwise.
8. Governing Law
This Agreement shall be governed by, construed and enforced in
accordance with the laws of the state of Washington, without giving effect
to principles and provisions thereof relating to conflict or choice of laws
and irrespective of the fact that any one of the Parties is now or may
become a resident of a different state.
9. Validity
In case any term of this Agreement shall be invalid, illegal or
unenforceable, in whole or in part, the validity of any of the other terms
of this Agreement shall not in any way be affected thereby.
10. Counterparts
This Agreement may be executed in counterparts, each of which shall be
deemed to be an original.
IN WITNESS WHEREOF, the Parties have executed this Agreement as of the
date first written above.
PUGET SOUND POWER & LIGHT COMPANY
By /s/ Richard R. Sonstelie
--------------------
/s/ William S. Weaver
-----------------
WILLIAM S. WEAVER
-6-
AGREEMENT EXHIBIT 10.119
THIS AGREEMENT ("Agreement") is made and entered into as of the 18th
day of October, 1996 between PUGET SOUND POWER & LIGHT COMPANY, a Washington
corporation (the "Company"), and SHEILA M. VORTMAN ("Employee"). The term
"Parties" refers to the Company and the Employee.
RECITALS
A. Employee is currently serving as Senior Vice President Corporate
and Regulatory Relations of the Company.
B. Pursuant to an Agreement and Plan of Merger, dated as of October
18, 1995 (the "Merger Agreement"), Washington Energy Company and Washington
Natural Gas Company have agreed to merge with and into the Company (the
"Merger").
C. The Company recognizes that the Merger Agreement and the Merger may
have an adverse effect upon its retention of key management personnel and
may create distractions which interfere with their ability to function most
effectively. In light of these concerns, the Company has determined that it
is appropriate to offer additional security to certain key senior management
personnel to induce them to remain in the employ of the Company and to
encourage a high level of effective management in the best interests of the
Company and its shareholders.
NOW, THEREFORE, in consideration of the mutual covenants and agreements
contained herein, and for other good and valuable consideration, the Parties
agree as follows:
1. Severance Benefits Payable in the Event of Termination of Employment
The Company agrees to provide to Employee the following benefits if
Employee does not voluntarily terminate her employment with the Company
prior to the consummation of the Merger pursuant to the terms of the Merger
Agreement (the "Effective Date") and Employee's employment is thereafter
terminated within three years following the Effective Date by Employee for
Good Reason (as hereafter defined) or by the Company other than for Cause
(as hereafter defined), death or disability.
(a) Employee's full base salary earned through the termination
date, plus payment for all accrued vacation and any deferred compensation to
which Employee is entitled for the fiscal year most recently ended prior to
Employee's termination, and Employee's pro rata share of any compensation
under any Company plan which has accrued through the date of termination,
regardless of whether or not pursuant to the terms of the plan such amounts
are vested or are payable in the year of termination; plus
(b) An amount equal to three times the greater of (i) the sum of
Employee's annual base salary in 1996 plus the bonus paid to Employee in
1996 or (ii) the sum of Employee's annual base salary at the rate in effect
as of the date of termination, plus the amount of any additional
compensation awarded to Employee for the calendar year most recently ended
(whether or not fully paid).
(c) The Company shall maintain in full force and effect for the
three years following the date of termination all employee benefit plans,
programs and policies, including any life or health insurance plans, in
which Employee was entitled to participate immediately prior to termination,
provided that Employee is qualified to participate under the general terms
and provisions of such plans, programs and policies. In the event that
Employee's continued participation in any such plan, program or policy is
not possible under its terms and conditions, the Company shall at its option
either arrange for Employee to receive benefits substantially similar to
those which Employee would have been entitled to receive under each plan,
program or policy, or pay to employee an amount equal to the premiums that
the Company would pay on Employee's behalf for participation in such plan,
program or policy. At the end of the period of coverage, Employee will have
the option to receive an assignment at no cost, and with no apportionment of
prepaid premiums, of any assignable insurance policies owned by the Company
and relating to Employee, and to take advantage of any conversion privileges
pertinent to the benefits available under Company policies.
(d) In addition to the regular payment of benefits to which
Employee is entitled under the retirement plans or programs in effect on the
date of Employee's termination, which shall not be affected by such
termination, the Company shall pay to Employee in cash at age 65 or at such
earlier retirement date as Employee may elect pursuant to the plans, an
amount equal to the actuarial equivalent of the additional retirement
compensation to which Employee would have been entitled under the terms of
such retirement plans or programs (without regard to vesting) had Employee
continued in the employ of the Company for an additional three years at
Employee's base salary rate as of the date of termination. For purposes of
this calculation, the actuarial equivalent shall be determined by assuming
survival to age 80.
(e) Employee shall waive all rights to receive shares of common
stock of the Company issuable upon exercise of options or similar rights, if
any, granted to Employee under the Company's stock option or similar equity
plans. In return for that waiver, Employee shall be entitled to receive,
within 30 days following the date of termination, a payment equal to the
difference between the exercise price of all options or similar rights held
by Employee, whether or not then fully exercisable, and the higher of (i)
the closing price of the common stock on the New York Stock Exchange on the
date of termination or (ii) the highest price per share actually paid in
connection with any change of control of the Company.
(f) Notwithstanding any other provisions of this Agreement, if any
payments or benefits under this Agreement, together with any other Parachute
Payments (as defined under Internal Revenue Code Section 280(G)(b)(2)) made
by the Company to Employee, if any, are characterized as Excess Parachute
Payments (as defined in Internal Revenue Code, Section 280(G)(b)(1)), then
the Company shall pay to Employee, in addition to the payments to be
received under this Section, an amount equal to the excise taxes imposed by
Section 4999 of the Code on Employee's Excess Parachute Payments, plus an
amount equal to the federal and, if applicable, state income taxes which
will be payable by Employee as a result of this additional payment.
Employee shall not be required to mitigate the amount of any payment due
hereunder by seeking other employment and, except as provided in the next
sentence, the payments due hereunder shall not be affected by any other
employment which Employee may obtain. If Employee accepts a position with
another employer during the period for payment of employee benefits under
Section 1(c), then the Company's obligation to pay such employee benefits
will cease as of the date of Employee's new employment, provided, however,
that the Company will continue such benefits for the full period to the
extent that they exceed the comparable benefits from such other employment.
2. Retention Incentive Benefit
To induce Employee to remain in the employ of the Company for an extended
period following the Effective Date of the Merger, the Company agrees to
accrue an Incentive Benefit based upon continued employment. One third of
the Incentive Benefit will become vested if Employee continues to be
employed by the Company for a period of one year subsequent to the Effective
Date, an additional one third of the Incentive Benefit will become vested if
Employee continues to be employed by the Company for a period of three years
subsequent to the Effective Date, and the final one third of the Incentive
Benefit will become vested if Employee continues to be employed by the
Company for a period of five years subsequent to the Effective Date. The
total Incentive Benefit will be an amount equal to three times the sum of
Employee's annual base salary in 1996 plus the bonus paid to Employee in
1996. The portion of the Incentive Benefit which has become vested will be
paid to Employee or her heirs in equal monthly installments (less any
required tax withholding) over a three-year period commencing on the date
that Employee's employment with the Company eventually terminates for any
reason, whether by normal retirement, early retirement, death, disability,
voluntary resignation, or involuntary termination. Payments of the vested
Incentive Benefit shall not reduce any amounts otherwise payable to
Employee, whether under the Company's Supplemental Retirement Plan for
Officers or otherwise.
3. Termination for Cause
If the Board of Directors of the Company terminates Employee's
employment for Cause, then the Company shall be obligated to pay to Employee
under Section 1 of this Agreement only her current base salary plus accrued
vacation and any other compensation actually accrued through the date of
termination. Incentive Benefits which have become vested pursuant to
Section 2 of this Agreement shall not be adversely affected by a subsequent
termination for Cause. For the purposes of this Agreement, "Cause" shall
mean (a) the willful and continued failure by Employee to substantially
perform her duties with the Company (other than any such failure resulting
from incapacity due to physical or mental illness), for a period of 30 days
after written notice of demand for substantial performance has been
delivered to Employee by the Board of Directors which specifically
identifies the manner in which the Board believes that Employee has not
substantially performed her duties, or (b) the willful engaging by Employee
in gross misconduct materially and demonstrably injurious to the Company, as
determined by the Board of Directors after notice to Employee and an
opportunity for a hearing. No act, nor failure to act, on Employee's part
shall be considered "willful" unless Employee has acted or failed to act
with an absence of good faith and without a reasonable belief that the
action or failure to act was in the best interests of the Company.
4. Good Reason
Employee may regard the happening of one or more of the following
events as a constructive termination which will constitute Good Reason
entitling Employee to terminate employment with the Company and receive the
benefits set forth in Section 1 of this Agreement:
(a) Without Employee's written consent, a significant reduction in
the scope of Employee's job responsibilities, the assignment to Employee of
duties not customarily performed by senior executives of the Company and
inconsistent with Employee's position as a senior executive as of the date
of this Agreement; or the failure of the Company to provide Employee with
the normal perquisites of a senior executive of the Company, including but
not limited to an office and appropriate support services.
(b) A reduction by the Company in Employee's base salary as in
effect as of the date of this Agreement unless such reduction is applied to
all officers of the Company, does not exceed the average percentage
reduction in base salary for all officers and is not greater than a
reduction of 25%, or the failure by the Company to increase such base salary
each year following the Effective Date of the Merger by an amount which
equals at least one-half, on a percentage basis, the average percentage
increase in base for all senior officers of the Company (excluding the Chief
Executive Officer) during the prior two calendar years.
(c) Failure by the Company to maintain any employee benefits to
which Employee is entitled prior to the date of this Agreement at a level
equal to or greater than those now in effect, through the continuation of
the same or substantially similar programs and policies, or the taking of
any action by the Company that would adversely affect Employee's
participation in or materially reduce Employee's benefits under any such
plans, programs or policies, or deprive Employee of any fringe benefits
enjoyed by Employee as of the date of this Agreement, unless in each case
such a reduction in benefits is nondiscriminatory as to Employee and is
applied generally to all officers of the Company.
(d) The failure by the Company to provide Employee with the number
of paid vacation days to which Employee would be entitled as a salaried
employee of the Company, its subsidiaries or affiliates or any parent or
successor of the Company on a nondiscriminatory basis.
(e) The requirement by the Company that Employee relocate her
residence or office anywhere outside of the Seattle/Bellevue metropolitan
area, except for required travel on the Company's business to the extent
consistent with Employee's duties.
(f) Any purported termination of employment by the Company other
than for Cause as defined in this Agreement, or death or disability.
The Company and Employee acknowledge and agree that the organizational and
management changes which the Company plans to implement following the
Effective Date of the Merger will entail a significant reduction in the
scope of Employee's current job responsibilities and will therefore
constitute Good Reason entitling Employee, if she so chooses, to voluntarily
terminate her employment and to receive the benefits set forth in Section 1
of this Agreement.
5. Payments and Disputes
For purposes of this Agreement, the date of termination will be the
date written notice of termination is given by Employee or the Company. If
termination is under circumstances entitling Employee to the benefits of
Section 1, then the amounts specified in Sections 1(a) and 1(b) will be paid
no more than ten business days after the date of termination. In the event
that any payments due hereunder shall be delayed for any reason for more
than ten business days from the date due, the amounts due shall bear
interest at the rate of 12% per annum until paid.
In the event the Company wishes to contest or dispute a termination for
Good Reason by Employee, it must give written notice of such dispute within
30days after the date of termination. If Employee wishes to contest or
dispute a termination for Cause by the Company, Employee must give written
notice of such dispute within 30 days of receiving a written notice of
termination or, if no notice is provided, within 30 days after the date of
actual termination by the Company.
Any dispute between the Parties hereto with respect to any of the
matters set forth herein shall be submitted to binding arbitration in city
of Seattle, state of Washington. Either Party may commence the arbitration
by delivery of a written notice to the other, describing the issue in
dispute and its position with regard to the issue. If the Parties are
unable to agree on an arbitrator within 30 days following delivery of such
notice, the arbitrator shall be selected by a Judge of the Superior Court of
the State of Washington for King County upon three days' notice. Discovery
shall be allowed in connection with any such arbitration to the same extent
permitted by the Washington Rules of Civil Procedure but either Party may
petition the arbitrator to limit the scope of such discovery, in which event
the arbitrator shall determine the extent of discovery allowable in
connection with the dispute in question. Except as otherwise provided
herein, the arbitration shall be conducted in accordance with the rules of
the American Arbitration Association then in effect for expedited
proceedings. The award of the arbitrator shall be final and binding, and
judgment upon an award may be entered in any court of competent
jurisdiction. The arbitrator shall hold a hearing, at which the Parties may
present evidence and argument, within 30 days of his or her appointment, and
shall issue an award within 15 days of the close of the hearing. The
Company will pay all fees and expenses, including attorneys' fees and the
cost of the arbitrator, incurred by Employee in good faith in contesting or
disputing any termination for Cause or in seeking to obtain or enforce any
right or benefit provided by this Agreement.
6. Notices
All notices or other communications required or permitted by this
Agreement shall be in writing and shall be sufficiently given if personally
delivered or if sent by certified mail, postage prepaid, addressed as
follows:
If to Employee, to:
Sheila M. Vortman
_________________
_________________
If to the Company:
Puget Sound Power & Light Company
P.O. Box 97034
Bellevue, Washington 98009-9734
Attention: Chief Executive Officer
Facsimile: (206) 462-3300
Any such mailed notice or communication shall be deemed to have been
given three days after the date mailed. Any address may be changed by
giving written notice of such change in the manner provided herein for
giving notice.
7. Entire Agreement
This Agreement contains the entire understanding of the Parties with
regard to the subject matter of this Agreement and may only be changed by
written agreement signed by both Parties. Any and all prior discussions,
negotiations, commitments and understandings related thereto are merged
herein.
8. Binding Effect
This Agreement shall be binding upon and inure to the benefit of the
Parties, and their successors, legal representatives and heirs, including
any successor to the Company's business or assets by merger, consolidation,
sale of assets or otherwise.
9. Governing Law
This Agreement shall be governed by, construed and enforced in
accordance with the laws of the state of Washington, without giving effect
to principles and provisions thereof relating to conflict or choice of laws
and irrespective of the fact that any one of the Parties is now or may
become a resident of a different state.
10. Validity
In case any term of this Agreement shall be invalid, illegal or
unenforceable, in whole or in part, the validity of any of the other terms
of this Agreement shall not in any way be affected thereby.
11. Counterparts
This Agreement may be executed in counterparts, each of which shall be
deemed to be an original.
IN WITNESS WHEREOF, the Parties have executed this Agreement as of the
date first written above.
PUGET SOUND POWER & LIGHT COMPANY
By s/s Richard R. Sonstelie
------------------------
Its President and Chief Executive Officer
/s/ Sheila M. Vortman
-----------------
SHEILA M. VORTMAN
-6-
AGREEMENT EXHIBIT 10.120
THIS AGREEMENT ("Agreement") is made and entered into as of the 18th
day of October, 1996 between PUGET SOUND POWER & LIGHT COMPANY, a Washington
corporation (the "Company"), and GARY B. SWOFFORD ("Employee"). The term
"Parties" refers to the Company and the Employee.
RECITALS
A. Employee is currently serving as Senior Vice President Customer
Operations of the Company.
B. Pursuant to an Agreement and Plan of Merger, dated as of October
18, 1995 (the "Merger Agreement"), Washington Energy Company and Washington
Natural Gas Company have agreed to merge with and into the Company (the
"Merger").
C. The Company recognizes that the Merger Agreement and the Merger may
have an adverse effect upon its retention of key management personnel and
may create distractions which interfere with their ability to function most
effectively. In light of these concerns, the Company has determined that it
is appropriate to offer additional security to certain key senior management
personnel to induce them to remain in the employ of the Company and to
encourage a high level of effective management in the best interests of the
Company and its shareholders.
NOW, THEREFORE, in consideration of the mutual covenants and agreements
contained herein, and for other good and valuable consideration, the Parties
agree as follows:
1. Severance Benefits Payable in the Event of Termination of Employment
The Company agrees to provide to Employee the following benefits if
Employee does not voluntarily terminate her employment with the Company
prior to the consummation of the Merger pursuant to the terms of the Merger
Agreement (the "Effective Date") and Employee's employment is thereafter
terminated within three years following the Effective Date by Employee for
Good Reason (as hereafter defined) or by the Company other than for Cause
(as hereafter defined), death or disability.
(a) Employee's full base salary earned through the termination
date, plus payment for all accrued vacation and any deferred compensation to
which Employee is entitled for the fiscal year most recently ended prior to
Employee's termination, and Employee's pro rata share of any compensation
under any Company plan which has accrued through the date of termination,
regardless of whether or not pursuant to the terms of the plan such amounts
are vested or are payable in the year of termination; plus
(b) An amount equal to three times the greater of (i) the sum of
Employee's annual base salary in 1996 plus the bonus paid to Employee in
1996 or (ii) the sum of Employee's annual base salary at the rate in effect
as of the date of termination, plus the amount of any additional
compensation awarded to Employee for the calendar year most recently ended
(whether or not fully paid).
(c) The Company shall maintain in full force and effect for the
three years following the date of termination all employee benefit plans,
programs and policies, including any life or health insurance plans, in
which Employee was entitled to participate immediately prior to termination,
provided that Employee is qualified to participate under the general terms
and provisions of such plans, programs and policies. In the event that
Employee's continued participation in any such plan, program or policy is
not possible under its terms and conditions, the Company shall at its option
either arrange for Employee to receive benefits substantially similar to
those which Employee would have been entitled to receive under each plan,
program or policy, or pay to employee an amount equal to the premiums that
the Company would pay on Employee's behalf for participation in such plan,
program or policy. At the end of the period of coverage, Employee will have
the option to receive an assignment at no cost, and with no apportionment of
prepaid premiums, of any assignable insurance policies owned by the Company
and relating to Employee, and to take advantage of any conversion privileges
pertinent to the benefits available under Company policies.
(d) In addition to the regular payment of benefits to which
Employee is entitled under the retirement plans or programs in effect on the
date of Employee's termination, which shall not be affected by such
termination, the Company shall pay to Employee in cash at age 65 or at such
earlier retirement date as Employee may elect pursuant to the plans, an
amount equal to the actuarial equivalent of the additional retirement
compensation to which Employee would have been entitled under the terms of
such retirement plans or programs (without regard to vesting) had Employee
continued in the employ of the Company for an additional three years at
Employee's base salary rate as of the date of termination. For purposes of
this calculation, the actuarial equivalent shall be determined by assuming
survival to age 80.
(e) Employee shall waive all rights to receive shares of common
stock of the Company issuable upon exercise of options or similar rights, if
any, granted to Employee under the Company's stock option or similar equity
plans. In return for that waiver, Employee shall be entitled to receive,
within 30 days following the date of termination, a payment equal to the
difference between the exercise price of all options or similar rights held
by Employee, whether or not then fully exercisable, and the higher of (i)
the closing price of the common stock on the New York Stock Exchange on the
date of termination or (ii) the highest price per share actually paid in
connection with any change of control of the Company.
(f) Notwithstanding any other provisions of this Agreement, if any
payments or benefits under this Agreement, together with any other Parachute
Payments (as defined under Internal Revenue Code Section 280(G)(b)(2)) made
by the Company to Employee, if any, are characterized as Excess Parachute
Payments (as defined in Internal Revenue Code, Section 280(G)(b)(1)), then
the Company shall pay to Employee, in addition to the payments to be
received under this Section, an amount equal to the excise taxes imposed by
Section 4999 of the Code on Employee's Excess Parachute Payments, plus an
amount equal to the federal and, if applicable, state income taxes which
will be payable by Employee as a result of this additional payment.
Employee shall not be required to mitigate the amount of any payment due
hereunder by seeking other employment and, except as provided in the next
sentence, the payments due hereunder shall not be affected by any other
employment which Employee may obtain. If Employee accepts a position with
another employer during the period for payment of employee benefits under
Section 1(c), then the Company's obligation to pay such employee benefits
will cease as of the date of Employee's new employment, provided, however,
that the Company will continue such benefits for the full period to the
extent that they exceed the comparable benefits from such other employment.
2. Retention Incentive Benefit
To induce Employee to remain in the employ of the Company for an
extended period following the Effective Date of the Merger, the Company
agrees to accrue an Incentive Benefit based upon continued employment. One
third of the Incentive Benefit will become vested if Employee continues to
be employed by the Company for a period of one year subsequent to the
Effective Date, an additional one third of the Incentive Benefit will become
vested if Employee continues to be employed by the Company for a period of
three years subsequent to the Effective Date, and the final one third of the
Incentive Benefit will become vested if Employee continues to be employed by
the Company for a period of five years subsequent to the Effective Date.
The total Incentive Benefit will be an amount equal to three times the sum
of Employee's annual base salary in 1996 plus the bonus paid to Employee in
1996. The portion of the Incentive Benefit which has become vested will be
paid to Employee or her heirs in equal monthly installments (less any
required tax withholding) over a three-year period commencing on the date
that Employee's employment with the Company eventually terminates for any
reason, whether by normal retirement, early retirement, death, disability,
voluntary resignation, or involuntary termination. Payments of the vested
Incentive Benefit shall not reduce any amounts otherwise payable to
Employee, whether under the Company's Supplemental Retirement Plan for
Officers or otherwise.
3. Termination for Cause
If the Board of Directors of the Company terminates Employee's
employment for Cause, then the Company shall be obligated to pay to Employee
under Section 1 of this Agreement only her current base salary plus accrued
vacation and any other compensation actually accrued through the date of
termination. Incentive Benefits which have become vested pursuant to
Section 2 of this Agreement shall not be adversely affected by a subsequent
termination for Cause. For the purposes of this Agreement, "Cause" shall
mean (a) the willful and continued failure by Employee to substantially
perform her duties with the Company (other than any such failure resulting
from incapacity due to physical or mental illness), for a period of 30 days
after written notice of demand for substantial performance has been
delivered to Employee by the Board of Directors which specifically
identifies the manner in which the Board believes that Employee has not
substantially performed her duties, or (b) the willful engaging by Employee
in gross misconduct materially and demonstrably injurious to the Company, as
determined by the Board of Directors after notice to Employee and an
opportunity for a hearing. No act, nor failure to act, on Employee's part
shall be considered "willful" unless Employee has acted or failed to act
with an absence of good faith and without a reasonable belief that the
action or failure to act was in the best interests of the Company.
4. Good Reason
Employee may regard the happening of one or more of the following
events as a constructive termination which will constitute Good Reason
entitling Employee to terminate employment with the Company and receive the
benefits set forth in Section 1 of this Agreement:
(a) Without Employee's written consent, a significant reduction in
the scope of Employee's job responsibilities, the assignment to Employee of
duties not customarily performed by senior executives of the Company and
inconsistent with Employee's position as a senior executive as of the date
of this Agreement; or the failure of the Company to provide Employee with
the normal perquisites of a senior executive of the Company, including but
not limited to an office and appropriate support services.
(b) A reduction by the Company in Employee's base salary as in
effect as of the date of this Agreement unless such reduction is applied to
all officers of the Company, does not exceed the average percentage
reduction in base salary for all officers and is not greater than a
reduction of 25%, or the failure by the Company to increase such base salary
each year following the Effective Date of the Merger by an amount which
equals at least one-half, on a percentage basis, the average percentage
increase in base for all senior officers of the Company (excluding the Chief
Executive Officer) during the prior two calendar years.
(c) Failure by the Company to maintain any employee benefits to
which Employee is entitled prior to the date of this Agreement at a level
equal to or greater than those now in effect, through the continuation of
the same or substantially similar programs and policies, or the taking of
any action by the Company that would adversely affect Employee's
participation in or materially reduce Employee's benefits under any such
plans, programs or policies, or deprive Employee of any fringe benefits
enjoyed by Employee as of the date of this Agreement, unless in each case
such a reduction in benefits is nondiscriminatory as to Employee and is
applied generally to all officers of the Company.
(d) The failure by the Company to provide Employee with the number
of paid vacation days to which Employee would be entitled as a salaried
employee of the Company, its subsidiaries or affiliates or any parent or
successor of the Company on a nondiscriminatory basis.
(e) The requirement by the Company that Employee relocate her
residence or office anywhere outside of the Seattle/Bellevue metropolitan
area, except for required travel on the Company's business to the extent
consistent with Employee's duties.
(f) Any purported termination of employment by the Company other
than for Cause as defined in this Agreement, or death or disability.
The Company and Employee acknowledge and agree that the organizational and
management changes which the Company plans to implement following the
Effective Date of the Merger will entail a significant reduction in the
scope of Employee's current job responsibilities and will therefore
constitute Good Reason entitling Employee, if she so chooses, to voluntarily
terminate her employment and to receive the benefits set forth in Section 1
of this Agreement.
5. Payments and Disputes
For purposes of this Agreement, the date of termination will be the
date written notice of termination is given by Employee or the Company. If
termination is under circumstances entitling Employee to the benefits of
Section 1, then the amounts specified in Sections 1(a) and 1(b) will be paid
no more than ten business days after the date of termination. In the event
that any payments due hereunder shall be delayed for any reason for more
than ten business days from the date due, the amounts due shall bear
interest at the rate of 12% per annum until paid.
In the event the Company wishes to contest or dispute a termination for
Good Reason by Employee, it must give written notice of such dispute within
30days after the date of termination. If Employee wishes to contest or
dispute a termination for Cause by the Company, Employee must give written
notice of such dispute within 30 days of receiving a written notice of
termination or, if no notice is provided, within 30 days after the date of
actual termination by the Company.
Any dispute between the Parties hereto with respect to any of the
matters set forth herein shall be submitted to binding arbitration in city
of Seattle, state of Washington. Either Party may commence the arbitration
by delivery of a written notice to the other, describing the issue in
dispute and its position with regard to the issue. If the Parties are
unable to agree on an arbitrator within 30 days following delivery of such
notice, the arbitrator shall be selected by a Judge of the Superior Court of
the State of Washington for King County upon three days' notice. Discovery
shall be allowed in connection with any such arbitration to the same extent
permitted by the Washington Rules of Civil Procedure but either Party may
petition the arbitrator to limit the scope of such discovery, in which event
the arbitrator shall determine the extent of discovery allowable in
connection with the dispute in question. Except as otherwise provided
herein, the arbitration shall be conducted in accordance with the rules of
the American Arbitration Association then in effect for expedited
proceedings. The award of the arbitrator shall be final and binding, and
judgment upon an award may be entered in any court of competent
jurisdiction. The arbitrator shall hold a hearing, at which the Parties may
present evidence and argument, within 30 days of his or her appointment, and
shall issue an award within 15 days of the close of the hearing. The
Company will pay all fees and expenses, including attorneys' fees and the
cost of the arbitrator, incurred by Employee in good faith in contesting or
disputing any termination for Cause or in seeking to obtain or enforce any
right or benefit provided by this Agreement.
6. Notices
All notices or other communications required or permitted by this
Agreement shall be in writing and shall be sufficiently given if personally
delivered or if sent by certified mail, postage prepaid, addressed as
follows:
If to Employee, to:
Gary B. Swofford
_________________
_________________
If to the Company:
Puget Sound Power & Light Company
P.O. Box 97034
Bellevue, Washington 98009-9734
Attention: Chief Executive Officer
Facsimile: (206) 462-3300
Any such mailed notice or communication shall be deemed to have been
given three days after the date mailed. Any address may be changed by
giving written notice of such change in the manner provided herein for
giving notice.
7. Entire Agreement
This Agreement contains the entire understanding of the Parties with
regard to the subject matter of this Agreement and may only be changed by
written agreement signed by both Parties. Any and all prior discussions,
negotiations, commitments and understandings related thereto are merged
herein.
8. Binding Effect
This Agreement shall be binding upon and inure to the benefit of the
Parties, and their successors, legal representatives and heirs, including
any successor to the Company's business or assets by merger, consolidation,
sale of assets or otherwise.
9. Governing Law
This Agreement shall be governed by, construed and enforced in
accordance with the laws of the state of Washington, without giving effect
to principles and provisions thereof relating to conflict or choice of laws
and irrespective of the fact that any one of the Parties is now or may
become a resident of a different state.
10. Validity
In case any term of this Agreement shall be invalid, illegal or
unenforceable, in whole or in part, the validity of any of the other terms
of this Agreement shall not in any way be affected thereby.
11. Counterparts
This Agreement may be executed in counterparts, each of which shall be
deemed to be an original.
IN WITNESS WHEREOF, the Parties have executed this Agreement as of the
date first written above.
PUGET SOUND POWER & LIGHT COMPANY
By /s/ Richard R. Sonstelie
--------------------
Its President and Chief Executive Officer
/s/ Gary B. Swofford
----------------
GARY B. SWOFFORD
Exhibit 12a
<TABLE>
PUGET SOUND POWER & LIGHT COMPANY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
<CAPTION>
Year Ended December 31
------------------------------------------------
1996 1995 1994 1993 1992
------------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR FIXED CHARGES
Pre-tax income:
Net income per statement of income $135,371 $135,720 $120,059 $138,327 $135,720
Federal income taxes 86,242 84,545 80,259 83,970 72,449
Federal income taxes charged to
other income - net 2,524 (488) 1,556 (382) (2,106)
Undistbuted (earnings) or losses
of less-than-fifty-percent-owned
entities -- -- -- -- (567)
------------------------------------------------
Total $224,137 $219,777 $201,874 $221,915 $205,496
Fixed charges:
Interest on long-term debt $ 73,134 $ 81,115 $ 84,144 $ 86,030 $ 89,509
Other interest 8,848 10,049 6,249 3,542 10,477
Portion of rentals representative
of the interest factor 3,236 3,798 4,218 3,937 4,474
------------------------------------------------
Total $ 85,218 $ 94,962 $ 94,611 $ 93,509 $104,460
Earnings available for
fixed charges $309,355 $314,739 $296,485 $315,424 $309,956
================================================
RATIO OF EARNINGS TO FIXED CHARGES 3.63x 3.31x 3.13x 3.37x 2.97x
</TABLE>
<TABLE>
Exhibit 12b
PUGET SOUND POWER & LIGHT COMPANY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
(Dollars in Thousands)
<CAPTION>
Year Ended December 31
------------------------------------------------
1996 1995 1994 1993 1992
------------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR COMBINED FIXED
CHARGES AND PREFERRED DIVIDEND REQUIREMENTS
Pretax Income:
Net Income per statement
of income $135,371 $135,720 $120,059 $138,327 $135,720
Federal income taxes 86,242 84,545 80,259 83,970 72,449
Federal income taxes charged to
other income - net 2,524 (488) 1,556 (382) (2,106)
------------------------------------------------
Subtotal 224,137 219,777 201,874 221,915 206,063
Undistributed (earnings) or losses
of less-than-fifty-percent-owned
entities -- -- -- -- (567)
------------------------------------------------
Total $224,137 $219,777 $201,874 $221,915 $205,496
Fixed charges:
Interest on long-term debt $ 73,134 $ 81,115 $ 84,144 $ 86,030 $ 89,509
Other interest 8,848 10,049 6,249 3,542 10,477
Portion of rentals representative
of the interest factor 3,236 3,798 4,218 3,937 4,474
-------------------------------------------------
Total $ 85,218 94,962 $ 94,611 $ 93,509 $104,460
Earnings available for combined
fixed charges and preferred
dividend requirements $309,355 $314,739 $296,485 $315,424 $309,956
================================================
DIVIDEND REQUIREMENT:
Fixed charges above $ 85,218 $ 94,962 $ 94,611 $ 93,509 $104,460
Preferred dividend requirements 25,102 25,144 26,451 26,377 21,080
------------------------------------------------
Total $110,320 $120,106 $121,062 $119,886 $125,540
================================================
RATIO OF EARNINGS TO COMBINED FIXED
CHARGES AND PREFERRED STOCK DIVIDENDS 2.80 2.62 2.45 2.63 2.47
COMPUTATION OF PREFERRED DIVIDEND
REQUIREMENTS:
(a) Pre-tax income $224,137 $219,777 $201,874 $221,915 $206,063
(b) Net income $135,371 $135,720 $120,059 $138,327 $135,720
(c) Ratio of (a) to (b) 1.6557 1.6193 1.6815 1.6043 1.5183
(d) Preferred dividends $ 15,161 $ 15,527 $ 15,731 $ 16,442 $ 13,884
Preferred dividend requirements
[(d) multiplied by (c)] $ 25,102 $ 25,144 $ 26,451 $ 26,377 $ 21,080
================================================
</TABLE>
EXHIBIT 21
SUBSIDIARIES
- --------------------
1. Puget Western, Inc.
19515 North Creek Parkway
Suite 310
Bothell, Washington 98011
2. Puget Sound Energy Company
P.O. Box 97034
Bellevue, Washington 98009-9734
3. ConnexT
1301 Fifth Avenue
Suite 1900
Seattle, WA 98101
4. Puget Energy, Inc.
411 108th Avenue N.E.
Bellevue, WA 98004-5515
5. Hydro Energy Development Corporation
19515 North Creek Parkway
Suite 310
Bothell, Washington 98011
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements
of Puget Sound Energy, Inc. (formerly Puget Sound Power & Light Company) on
Form S-3 (File Nos. 33-26818 and 33-53056) and Form S-8 (Nos. 33-27396 and
333-23393) of our report dated February 12, 1997, on our audits of the
consolidated financial statements and financial statement schedule of
Puget Sound Energy, Inc. as of December 31, 1996 and 1995, and
for the years ended December 31, 1996, 1995 and 1994, which report is
included in this Annual Report on Form 10-K.
Coopers & Lybrand
Seattle, Washington
March 21, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000081100
<NAME> PUGET SOUND ENERGY, INC.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,291,076
<OTHER-PROPERTY-AND-INVEST> 178,132
<TOTAL-CURRENT-ASSETS> 315,177
<TOTAL-DEFERRED-CHARGES> 0
<OTHER-ASSETS> 402,867
<TOTAL-ASSETS> 3,187,252
<COMMON> 636,409
<CAPITAL-SURPLUS-PAID-IN> 328,963
<RETAINED-EARNINGS> 213,654
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,179,026
87,839
125,000
<LONG-TERM-DEBT-NET> 820,664
<SHORT-TERM-NOTES> 31,700
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 88,713
<LONG-TERM-DEBT-CURRENT-PORT> 99,922
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 754,388
<TOT-CAPITALIZATION-AND-LIAB> 3,187,252
<GROSS-OPERATING-REVENUE> 1,198,769
<INCOME-TAX-EXPENSE> 86,242
<OTHER-OPERATING-EXPENSES> 911,951
<TOTAL-OPERATING-EXPENSES> 998,193
<OPERATING-INCOME-LOSS> 200,576
<OTHER-INCOME-NET> 11,860
<INCOME-BEFORE-INTEREST-EXPEN> 212,436
<TOTAL-INTEREST-EXPENSE> 77,065
<NET-INCOME> 135,371
15,161
<EARNINGS-AVAILABLE-FOR-COMM> 120,210
<COMMON-STOCK-DIVIDENDS> 117,099
<TOTAL-INTEREST-ON-BONDS> 69,757
<CASH-FLOW-OPERATIONS> 304,058
<EPS-PRIMARY> 1.89
<EPS-DILUTED> 1.89
</TABLE>
EXHIBIT 99
UNAUDITED PRO FORMA CONDENSED FINANCIAL INFORMATION
The following unaudited pro forma financial information combines the
historical consolidated balance sheets and statements of income of Puget
Sound Power and Light Company ("Puget") and Washington Energy Company
("WECo") after giving effect to the merger. The unaudited pro forma
condensed balance sheet gives effect to the merger as if it had occurred at
the balance sheet date. The unaudited pro forma condensed statement of
income for the twelve months ended December 31, 1996, gives effect to the
merger as if it had occurred on January 1, 1996. These statements are
prepared on the basis of accounting for the merger as a pooling-of-interests
and are based on the assumptions set forth in the notes thereto. The
following pro forma financial information has been prepared from, and should
be read in conjunction with, the historical consolidated financial statements
and related notes thereto of Puget, WECo and Washington Natural Gas Company
("WNG"), a wholly-owned subsidiary of WECo. The following information is not
necessarily indicative of the operating results or financial position that
would have occurred had the merger been consummated on the date, or at the
beginning of the periods, for which the merger is being given effect, nor is
it necessarily indicative of future operating results or financial position.
EXHIBIT 99
<TABLE>
PAGE 2
PUGET SOUND ENERGY
PRO FORMA CONDENSED BALANCE SHEET
AT DECEMBER 31, 1996
(Thousands of dollars)
(unaudited)
<CAPTION>
Pro Forma
Puget (1) WECo (1) Combined
---------- ---------- ----------
<S> <C> <C> <C>
ASSETS
Property, Plant and Equipment:
Utility plant $3,479,652 $1,129,849 $4,609,501
Accumulated provisions for depreciation
and amortization 1,188,576 293,979 1,482,555
--------- --------- ---------
Net property, plant and equipment 2,291,076 835,870 3,126,946
--------- --------- ---------
Other Property and Investments:
Investment in Bonneville Exchange Power Contract 86,772 -- 86,772
Investment in and advances to subsidiaries 73,957 -- 73,957
Investment in unconsolidated affiliate -- 69,352 69,352
Other 17,403 5,270 22,673
--------- --------- ---------
Total other property and investments 178,132 74,622 252,754
--------- --------- ---------
Current Assets:
Cash 3,736 599 4,335
Accounts receivable 136,814 11,714 148,528
Estimated unbilled revenue 93,563 12,199 105,762
PRAM accrued revenues 40,470 -- 40,470
Materials and supplies, at average cost 36,683 24,955 61,638
Prepayments and other 3,911 13,509 17,420
--------- --------- ---------
Total current assets 315,177 62,976 378,153
--------- --------- ---------
Long-Term Assets:
Regulatory asset for deferred income taxes 234,095 19,353 253,448
Unamortized energy conservation charges 50,796 -- 50,796
Other 117,976 41,615 159,591
--------- --------- ---------
Total long-term assets 402,867 60,968 463,835
--------- --------- ---------
TOTAL ASSETS $3,187,252 $1,034,436 $4,221,688
========= ========= =========
</TABLE>
See accompanying Notes to Unaudited Pro Forma Condensed Financial Statements
EXHIBIT 99
PAGE 3
<TABLE>
PUGET SOUND ENERGY
PROFORMA CONDENSED BALANCE SHEET
AT DECEMBER 31, 1996
(Thousands of dollars)
(unaudited)
<CAPTION>
Pro Forma
Puget (1) WECo (1) Combined
---------- ---------- ----------
<S> <C> <C> <C>
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock and additional paid-in capital (4) $ 965,372 $ 326,650 $1,292,022
Earnings reinvested (Accumulated deficit) 213,654 (127,299) 86,355
Preferred stock not subject to mandatory redemption 125,000 90,000 215,000
Preferred stock subject to mandatory redemption 87,839 -- 87,839
Long-term debt 820,664 344,920 1,165,584
--------- --------- ---------
Total capitalization 2,212,529 634,271 2,846,800
--------- --------- ---------
Current Liabilities:
Accounts payable 71,690 21,891 93,581
Short-term debt 120,413 177,709 298,122
Current maturities of long-term debt 99,922 140 100,062
Accrued taxes 38,335 14,202 52,537
Other 74,576 73,185 147,761
--------- --------- ---------
Total current liabilities 404,936 287,127 692,063
--------- --------- ---------
Deferred Taxes:
Deferred income taxes 500,638 75,119 575,757
Deferred investment credits -- 8,479 8,479
--------- --------- ---------
Total deferred taxes 500,638 83,598 584,236
--------- --------- ---------
Other Deferred Credits:
Customer advances for construction 20,405 5,334 25,739
Other 48,744 24,106 72,850
--------- --------- ---------
Total other deferred credits 69,149 29,440 98,589
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES $3,187,252 $1,034,436 $4,221,688
========= ========= =========
</TABLE>
See accompanying Notes to Unaudited Pro Forma Condensed Financial Statements
EXHIBIT 99
PAGE 4
<TABLE>
PUGET SOUND ENERGY
PRO FORMA CONDENSED STATEMENT OF INCOME
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1996
(Thousands, except per share amounts)
(unaudited)
<CAPTION>
Pro Forma
Puget (1) WECo (1) Combined(5)
---------- ---------- -----------
<S> <C> <C> <C>
OPERATING REVENUES $1,198,769 $425,711 $1,624,480
OPERATING EXPENSES:
Purchased and interchanged power and gas purchases 428,172 177,719 605,891
Other operating expenses and maintenance 258,366 85,689 344,055
Depreciation, and amortization 108,752 35,777 144,529
Taxes other than federal income taxes 116,661 39,308 155,969
Federal income taxes 86,242 15,232 101,474
------- ------- -------
Total operating expenses 998,193 353,725 1,351,918
------- ------- -------
OPERATING INCOME 200,576 71,986 272,562
------- ------- -------
OTHER INCOME (EXPENSE):
Preferred dividend requirement - WNG (6 ) -- (7,020) --
Other - net of taxes 11,860 1,150 13,010
------- ------- -------
Total other income (expense) 11,860 (5,870) 13,010
------- ------- -------
INCOME BEFORE INTEREST CHARGES 212,436 66,116 285,572
INTEREST CHARGES 77,065 41,156 118,221
------- ------- -------
INCOME FROM CONTINUING OPERATIONS BEFORE
PREFERRED DIVIDENDS 135,371 24,960 167,351
LESS: PREFERRED STOCK DIVIDEND ACCRUALS 15,161 -- 22,181
------- ------- -------
INCOME FOR COMMON STOCK (2) $120,210 $ 24,960 $145,170
======= ======= =======
COMMON SHARES OUTSTANDING WEIGHTED AVERAGE (3) 63,641 24,159 84,418
EARNINGS PER SHARE (2) $1.89 $1.03 $1.72
</TABLE>
See accompanying Notes to Unaudited Pro Forma Condensed Financial Statements
EXHIBIT 99
PAGE 5
NOTES TO UNAUDITED PROFORMA CONDENSED FINANCIAL STATEMENTS
(1) Puget's fiscal year ends on December 31. WECo's fiscal year ends on
September 30. The pro forma financial data for the twelve months ended
December 31, 1996 are the results of twelve months ended December 31,
1996 for Puget and twelve months ended September 30, 1996 for WECo.
(2) Income for Common Stock and Earnings Per Share are based on income from
continuing operations after preferred dividend requirements.
(3) The Pro Forma Condensed Financial Statements reflect the conversion of
each share of WECo common stock outstanding into .860 share of Puget
Sound Energy common stock and the issuance of Puget Sound Energy
preferred stock for WNG preferred stock. The Pro Forma Condensed
Financial Statements are presented as if the merger had been consummated
prior to the periods presented.
(4) The number of shares of common stock outstanding, by company, were as
follows:
Puget WECo Pro Forma
---------- ---------- ----------
at December 31, 1996 63,641,000 24,319,000 84,555,000
(5) The Pro Forma Financial Statements do not reflect the $370 million net
cost savings estimated to be achieved in the ten-year period following
consummation of the merger. The terms and conditions under which the
Washington Utilities and Transportation Commission may approve the
merger are unknown.
(6) Assumes WNG preferred stock has been exchanged for Puget Sound Energy
preferred stock. In the Pro Forma Condensed Statements of Income, these
dividend requirements are included in "Preferred Stock Dividend
Accruals."
