UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D. C. 20549



                                    FORM 10-K



                   /X/      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
                            THE SECURITIES EXCHANGE ACT OF 1934 


                   For the fiscal year ended December 31, 1998

                                       OR


                  / /      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                           THE SECURITIES EXCHANGE ACT OF 1934



                          Commission File Number 1-4393



                            PUGET SOUND ENERGY, INC.
             (Exact name of registrant as specified in its charter)


             Washington                                     91-0374630
             (State or other jurisdiction of          (I.R.S. Employer
             incorporation or organization)        Identification No.)



                       411 - 108th Avenue N.E., Bellevue,
                         Washington 98004-5515 (Address
                         of principal executive offices)


                                 (425) 454-6363
              (Registrant's telephone number, including area code)


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<PAGE>

Securities registered pursuant to Section 12(b) of the Act:

                                                           NAME OF EACH EXCHANGE
  TITLE OF EACH CLASS                                            ON WHICH LISTED
-------------------------------------------------------------------------------
  Common Stock, without par value,
  $10 stated value                                                   N. Y. S. E.

  Preference Share Purchase Rights                                   N. Y. S. E.

  7.45% Series II, Preferred Stock
  (Cumulative, $25 Par Value)                                        N. Y. S. E.

  8.50% Series III, Preferred Stock
  (Cumulative, $25 Par Value)                                        N. Y. S. E.

Securities registered pursuant to Section 12(g) of the Act:

  TITLE OF EACH CLASS                                             
----------------------------------------------------------------

  Preferred Stock (Cumulative; $100 Par Value)

  Preferred Stock (Cumulative; $25 Par Value)

  8.231% Capital Securities

       Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
         Yes/X/   No/ /
       Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
       The aggregate market value of the voting stock held by non-affiliates of
the registrant at December 31, 1998, was approximately $2,353,000,000.
       The number of shares of the registrant's common stock outstanding at
February 26, 1999, was 84,560,548.

                       Documents Incorporated by Reference

         The Company's definitive proxy statement for its 1999 Annual Meeting of
Shareholders is incorporated by reference in Part III hereof.

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         DEFINITIONS

AFUDC                 Allowance for Funds Used During Construction
BPA                   Bonneville Power Administration
CAAA                  Clean Air Act Amendments
Cabot                 Cabot Oil & Gas Corporation
Chelan                Public Utility District No. 1 of Chelan County, Washington
Dth                   Dekatherm (One Dth is equal to one MMBTu)
EPA                   Environmental Protection Agency
FERC                  Federal Energy Regulatory Commission
KW                    Kilowatts
KWH                   Kilowatt Hours
MMBTu                 One Million British Thermal Units
MW                    Megawatts (one MW equals one thousand KW)
MWH                   Megawatt Hours
Montana Power         The Montana Power Company
NERC                  North American Electric Reliability Council
NMFS                  National Marine Fisheries Service
PGA                   Purchased Gas Adjustment
PRAM                  Periodic Rate Adjustment Mechanism
PRP                   Potentially Responsible Party
PUDs                  Washington Public Utility Districts
PURPA                 Public Utility Regulatory Policies Act
WECo                  Washington Energy Company
WEGM                  Washington Energy Gas Marketing Company
Washington Commission Washington Utilities and Transportation Commission
WNG                   Washington Natural Gas Company
WSCC                  Western Systems Coordinating Council


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         INDEX
       Item       Page
       Part I
           1.     Business                                                    5
                         General                                              5
                         Industry Overview                                    5
                         Regulation and Rates                                 6
                         Electric Utility Operations                          6
                         Electric Utility Operating Statistics               13
                         Gas Utility Operations                              15
                         Gas Utility Operating Statistics                    18
                         Energy Conservation                                 19
                         Environment                                         20
                         Executive Officers                                  22
           2.     Properties                                                 23
           3.     Legal Proceedings                                          23
           4.     Submission of Matters to a Vote of Security Holders        23

       Part II
           5.     Market for Registrant's Common Equity and Related 
                  Stockholder Matters                                        23
           6.     Selected Financial Data                                    25
           7.     Management's Discussion and Analysis of
                  Financial Condition and Results of Operations              26
           8.     Financial Statements and Supplementary Data                38
           9.     Changes in and Disagreements with Accountants
                  on Accounting and Financial Disclosure                     38

       Part       III (Incorporated by reference from the Company's definitive
                  proxy statement issued in connection with the 1999 Annual
                  Meeting of Shareholders)
           10.    Directors and Executive Officers of the Registrant
           11.    Executive Compensation
           12.    Security Ownership of Certain Beneficial Owners and Management
           13.    Certain Relationships and Related Transactions

       Part IV    Exhibits, Financial Statement Schedules and
                  Reports on Form 8-K                                        38
                  Signatures                                                 39
                  Exhibit Index                                              80


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         PART I

         ITEM 1.  BUSINESS

GENERAL
       Puget Sound Energy, Inc. (the "Company"), is an investor-owned public
utility incorporated in the State of Washington furnishing electric and gas
service in a territory covering approximately 6,000 square miles, principally in
the Puget Sound region of Washington state.
       At December 31, 1998, the Company had approximately 890,800 electric
customers, consisting of 789,800 residential, 95,300 commercial, 4,200
industrial and 1,500 other customers and approximately 543,900 gas customers,
consisting of 497,200 residential, 43,600 commercial, 3,000 industrial and 100
other customers. For the year 1998, the Company added approximately 18,900
electric customers and approximately 22,600 gas customers, representing
annualized growth rates of 2.2% and 4.3%, respectively. During 1998, the
Company's billed retail revenues from electric utility operations were derived
45% from residential customers, 36% from commercial customers, 15% from
industrial customers and 4% from other customers, and the Company's retail
revenues from gas utility operations were derived 61% from residential
customers, 28% from commercial customers, 8% from industrial customers and 3%
from other customers. During this period, the largest customer accounted for
2.4% of the Company's utility operating revenues.
       The Company is affected by various seasonal weather patterns throughout
the year and, therefore, operating revenues and associated expenses are not
generated evenly during the year. Variations in energy usage by consumers occur
from season to season and from month to month within a season, primarily as a
result of weather conditions. The Company normally experiences its highest
energy sales in the first and fourth quarters of the year. Sales of electricity
to other utilities also vary by quarters and years depending principally upon
streamflow conditions for the generation of surplus hydro-electric power,
customer usage and the energy requirements of other neighboring utilities.
Earnings from electric operations therefore, since the discontinuance of the
PRAM in 1996, can be significantly influenced by surplus sales and variations in
weather, hydro conditions and non-firm regional electric energy prices. Earnings
from gas operations can be significantly influenced by variations in weather.
The Company has a purchased gas adjustment mechanism in retail rates to recover
variations in gas supply costs. (See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Rate Matters.")
       During the period from January 1, 1994 through December 31, 1998, the
Company made gross electric utility plant additions of $729 million and
retirements of $154 million. In the five-year period ended December 31, 1998,
the Company made gross gas utility plant additions of $481 million and
retirements of $52 million. Gross electric utility plant at December 31, 1998,
was approximately $3.8 billion which consisted of 47% distribution, 25%
generation, 16% transmission and 12% general plant and other. Gross gas utility
plant at December 31, 1998, was approximately $1.3 billion which consisted of
82% distribution, 5% transmission and 13% general plant and other.
       At year-end the Company had 2,996 aggregate full-time equivalent utility
employees.

INDUSTRY OVERVIEW
       The electric and gas industries in the United States are undergoing
significant changes. The focus of these changes is to promote competition among
suppliers of electricity and gas and associated services. In 1996 and 1997, the
Federal Energy Regulatory Commission ("FERC") issued orders that require
utilities, including the Company, to file open access transmission tariffs that
will make the utilities' electric transmission systems available to wholesale
sellers and buyers on a non-discriminatory basis. A number of states, including
California, have restructured their electric industries to separate or
"unbundle" power generation, transmission and distribution in order to permit
new competitors to enter the market place. In part because electric rates in the
Pacific Northwest have been among the lowest in the nation, certain of the
legislatures in this region, including Washington, have not yet enacted laws to
provide for competition at the retail level. The Washington Commission has
initiated a pilot program, in which the Company participates, that permits
consumers limited direct access to competitive energy suppliers. The Company is
actively monitoring developments in this area and has indicated its support for
the enactment of legislation that would provide increased choice for electric
service customers in the state of Washington.

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<PAGE>

       In order to position itself to respond effectively to future
restructuring of the utility industry, and in anticipation of a competitive
environment for electric energy sales, the Company in 1997 organized its utility
operations into separate business units: energy delivery; energy supply and
customer solutions. This reorganization accommodates, if it occurs,
legislatively mandated unbundling of power generation from transmission and
distribution which would allow customers to purchase these services and
commodities individually from different suppliers or, alternatively, as a
complete package.
       Since 1986, the Company has been offering gas transportation as a
separate service to industrial and commercial customers who choose to purchase
their gas supply directly from producers and gas marketers. The continued
evolution of the natural gas industry, resulting primarily from FERC Orders 436,
500 and 636, has served to increase the ability of large gas end-users to bypass
the Company in obtaining gas supply and transportation services. Although the
Company has not lost any substantial industrial or commercial load as a result
of such bypass, in certain years up to 160 customers annually have taken
advantage of unbundled transportation service; in 1998, 123 commercial and
industrial customers, on average, chose to use such service.

REGULATION AND RATES
       The Company is subject to the regulatory authority of (1) the Washington
Commission as to retail rates, accounting, the issuance of securities and
certain other matters and (2) the FERC with respect to the transmission of
electric energy, the resale of electric energy at wholesale, accounting and
certain other matters. (See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Rate Matters.")

ELECTRIC UTILITY OPERATIONS
       At December 31, 1998, the Company's peak electric power resources were
approximately 5,145,610 KW. The Company's historical peak load of approximately
4,847,000 KW occurred on December 21, 1998.
       During 1998, the Company's total electric energy production was supplied
25% by its own resources, 20% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydro-electric projects on
the Columbia River, 29% from other firm purchases and 26% from non-firm
purchases.


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<PAGE>


       The following table shows the Company's electric energy supply resources
at December 31, 1998, and energy production during the year:

                             PEAK POWER RESOURCES
                             AT DECEMBER 31, 1998         1998 ENERGY PRODUCTION
                           -----------------------------------------------------
                                KILOWATTS       %       KILOWATT-HOURS    %
                                                          (THOUSANDS)
                           -----------------------------------------------------
  Purchased Resources:
    Columbia River
      PUD Contracts (Hydro)      1,416,000    27.5%      6,471,295     20.1%
    Other Hydro  (a)               573,760    11.2%      3,015,835      9.3%
  Other  Producers  (a)          1,401,900    27.2%     14,836,079     46.0%
------------------------------------------- -------- -------------- ---------
  Total Purchased                3,391,660    65.9%     24,323,209     75.4%
------------------------------------------- -------- -------------- ---------
  Company-owned Resources:
    Hydro                          308,200     6.0%      1,231,496      3.8%
    Coal                           771,900    15.0%      5,746,536     17.8%
    Natural gas/oil                673,850    13.1%        956,698      3.0%
------------------------------------------- -------- -------------- ---------
  Total Company-owned            1,753,950    34.1%      7,934,730     24.6%
------------------------------------------- -------- -------------- ---------
  Total                          5,145,610   100.0%     32,257,939    100.0%
------------------------------------------- -------- -------------- ---------

       (a) Power received from other utilities is classified between hydro and
other producers based on the character of the utility system used to supply the
power or, if the power is supplied from a particular resource, the character of
that resource.

COMPANY-OWNED ELECTRIC GENERATION RESOURCES
       The Company and other utilities are joint owners of four mine-mouth,
coal-fired, steam-electric generating units at Colstrip, Montana, approximately
100 miles east of Billings, Montana. The Company owns a 50% interest (330,000
KW) in Units 1 and 2 and a 25% interest (350,000 KW) in Units 3 and 4. The
owners of the Colstrip Units purchase coal for the Units from Western Energy
Company ("Western Energy"), an affiliate of Montana Power Company ("Montana
Power") (one of the joint owners), under the terms of long-term coal supply
agreements. In February 1997, the Company, Montana Power and Western Energy
settled a dispute under a power sales agreement between Montana Power and the
Company and entered into an agreement to restructure the mines and plants. In
the third quarter of 1998, Western Energy, the Company and other joint owners of
Units 3 and 4 revised the coal supply contract which reduced the delivered price
of coal for Units 3 and 4 and allows for the joint owners to review and approve
mining plans and budgets.
       In November 1998, the Company announced that it had signed an agreement
to sell its interest in the Colstrip plant, as well as associated transmission
facilities to PP&L Global, Inc., of Fairfax, Virginia, a subsidiary of PP&L
Resources, Inc.
       The Company owns a 7% interest (91,900 KW) in a coal-fired,
steam-electric generating plant near Centralia, Washington, with a total net
capability of 1,313,000 KW. In 1991, the Company and other owners of the
Centralia project renegotiated a long-term coal supply agreement with
PacifiCorp. The Company and other owners of the Centralia project are reviewing
emissions compliance options that will need to be adopted to meet Federal and
State emission requirements by the year 2000. The Company has joined with the
other owners of the Centralia project in offering for sale its ownership
interest in the facility. As part of the sale process, the Centralia owners are
reviewing the projected reclamation liability related to the coal mining
operations. 
       The Company also has the following plants with an aggregate net
generating capability of 982,050 KW: Upper Baker River hydro project (103,000
KW) constructed in 1959; Lower Baker River hydro project (71,400 KW)
reconstructed in 1960; White River hydro plant (63,400 KW) constructed in 1911
with installation of the last unit in 1924; Snoqualmie Falls hydro plant (44,000
KW), half the capability of which was installed during the period 1898 to 1910
and half in 1957; and one smaller hydro plant, Electron (26,400 KW), constructed
during the period 1904 to 1929; a standby internal combustion unit (2,750 KW)
installed in 1969; an oil-fired combustion turbine unit (67,500 KW) installed in
1974; four dual-fuel combustion turbine units (89,100 KW each) installed during
1981; and two dual-fuel combustion turbine units (123,600 KW each) installed
during 1984. All of these generating facilities are located in the Company's
service territory.

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<PAGE>

       The Company's combustion turbines installed in 1981 and 1984 may be
fueled with either natural gas or distillate oil. Short-term supplies of
distillate fuel are stored on-site. These plants are operated from time to time
for peaking purposes and to produce energy for sales to other utilities, either
directly or through tolling arrangements.
       On December 19, 1997, the Company was issued a 50 year license by FERC
for its existing and operating White River project which includes authorization
to install an additional 14,000 KW generating unit. The Company has filed for a
rehearing with FERC on certain articles of the license because certain
restrictions placed on the operation of the plant may make it uneconomic to
operate. The outcome of the Company's appeal before the FERC is uncertain at
this time. The initial license for the existing and operating Snoqualmie Falls
project expired in December 1993, and the Company continues to operate this
project under a temporary license. The Company is continuing the FERC
application process to relicense this project. The Company has also applied for
a license to expand its existing 1,750 KW Nooksack Falls project which is
currently unlicensed and not operating because of an electric generator fire in
1996.

COLUMBIA RIVER ELECTRIC ENERGY SUPPLY CONTRACTS
       During 1998, approximately 20.1% of the Company's energy output was
obtained at an average cost of approximately 11.5 mills per KWH through
long-term contracts with several of the Washington PUDs owning hydro-electric
projects on the Columbia River.
       The Company's purchases of power from the Columbia River projects is
generally on a "cost of service" basis under which the Company pays a
proportionate share of the annual debt service and operating and maintenance
costs of each project in proportion to the amount of power annually purchased by
the Company from such project. Such payments are not contingent upon the
projects being operable. These projects are financed through substantially level
debt service payments, and their annual costs may vary over the term of the
contracts as additional financing is required to meet the costs of major
maintenance, repairs or replacements or license requirements.
       The Company has contracted to purchase from Chelan County PUD ("Chelan")
a share of the output of the original units of the Rock Island Project which
equaled 54.9% through June 30, 1998. This share decreases gradually to 50% of
the output at July 1, 1999, and remains unchanged thereafter for the duration of
the contract. The Company has also contracted to purchase the entire output of
the additional Rock Island units for the duration of the contract, except that
the Company's share of output of the additional units may be reduced up to 10%
per year beginning July 1, 2000, subject to a maximum aggregate reduction of
50%, upon the exercise of rights of withdrawal by Chelan for use in its local
service area. Chelan has given notice of withdrawal of 5% on July 1, 2000. As of
December 31, 1998, the Company's aggregate annual capacity from all units of the
Rock Island Project was 480,000 KW. The Company has contracted to purchase from
Chelan 38.9% (505,000 KW as of December 31, 1998) of the annual output of the
Rocky Reach Project, which percentage remains unchanged for the remainder of the
contract. The Company's share of the annual output of the Wells Project
purchased from Douglas County PUD is currently 31.3% (261,000 KW as of December
31, 1998) upon the additional exercise of withdrawal rights by Douglas County
PUD. The Company has contracted to purchase from Grant County PUD 8.0% (72,000
KW as of December 31, 1998) of the annual output of the Priest Rapids project
and 10.8% (98,000 KW as of December 31, 1998) of the annual output of the
Wanapum project, which percentages remain unchanged for the remainder of the
contracts. (See Note 17 to the Company's Consolidated Financial Statements.)


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<PAGE>

     In 1964,  the Company  and  fifteen  other  utilities  and  agencies in the
Pacific  Northwest  entered into a long-term  coordination  agreement  extending
until June 30, 2003 (the "Coordination Agreement").  This agreement provides for
the  coordinated  operation of  substantially  all of the  hydro-electric  power
plants and reservoirs in the Pacific Northwest. A new Coordination Agreement was
negotiated  in 1997 and will  replace  the prior  agreement  in  February  1999.
Various  fishery  enhancement   measures,   including  most  recently  the  1995
"biological  opinion" from the National Marine Fisheries Service ("NMFS"),  have
reduced  the  flexibility   provided  by  the   Coordination   Agreement.   (See
"Environment - Federal Endangered Species Act.")
       Certain utilities in the northwest United States and Canada are obtaining
the benefits of additional firm power as a result of the ratification of a 1961
treaty between the United States and Canada under which Canada is providing
approximately 15,500,000 acre-feet of reservoir storage on the upper Columbia
River. As a result of this storage, streamflow which would otherwise not be
usable to serve firm regional load is stored and later released during periods
when it is usable. Pursuant to the treaty, one-half of the firm power benefits
produced by the additional storage accrue to Canada. The Company's benefits from
this storage are based upon its percentage participation in the Columbia River
projects and one-half of those benefits must be returned to Canada. Also in
1961, the Company contracted to purchase 17.5% of Canada's share of the power to
be returned resulting from such storage until a phased expiration of the
contract from 1998 through 2003. The Company has also contracted to purchase
from the Bonneville Power Administration ("BPA") supplemental capacity in
amounts that decrease gradually until a phased expiration of the contract from
1998 through 2003. In 1997, the Company entered into agreements with the Mid
Columbia PUDs which specify the amount of the Company's share of the obligation
to return one-half of the firm power benefits to Canada beginning in 1998 and
continuing until the earlier of the expiration of the PUD contracts or 2024.

ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH OTHER UTILITIES
       Under a 1985 settlement agreement relating to Washington Public Power
Supply System ("WPPSS") Nuclear Project No. 3, in which the Company had a 5%
interest, the Company is receiving from BPA for approximately 30.5 years,
beginning January 1, 1987, electric power during the months of November through
April. Under the contract, the Company is guaranteed to receive not less than
191,667 MWH in each contract year until the Company has received total
deliveries of 5,833,333 MWH.
       On April 4, 1988, the Company executed a 15-year contract, with
provisions for early termination by the Company, for the purchase of firm energy
supply from Avista Corporation (formerly Washington Water Power Company). This
agreement calls for the delivery of 100 MW of capacity and 657,000 MWH of energy
from the Avista system annually (75 annual average MW). Minimum and maximum
delivery rates are prescribed. Under this agreement, the energy is to be priced
at Avista's average generation and transmission cost, subject to certain price
ceilings.
       On October 27, 1988, the Company executed a 15-year contract for the
purchase of firm power and energy from PacifiCorp. Under the terms of the
agreement, the Company receives 120 average MW of energy and 200 MW of peak
capacity.
       On November 23, 1988, the Company executed an agreement to purchase
surplus firm power from BPA. Under the agreement, the Company receives 150
average MW of energy and 300 MW of peak capacity from BPA between October 1 and
March 31 of each contract year. In 1997, the Company elected to terminate the
agreement on June 30, 2001, the date that the purchase was to convert to a
summer-winter exchange.
       On October 1, 1989, the Company signed a contract with Montana Power
under which Montana Power provides the Company, from its share of Colstrip Unit
4, 71 average MW of energy (94 MW of peak capacity) over a 21-year period. On
February 27, 1995, the Company delivered to Montana Power notice of termination
of the contract based on Montana Power's failure to arrange for firm contractual
transmission rights for such energy as required by the contract. Pursuant to a
settlement between the Company and Montana Power on February 21, 1997, the
contract remains in effect and the price of power purchased by the Company is
reduced. The settlement also addressed certain price reductions and
restructuring activities in connection with the Colstrip coal supply
arrangements.

                                       9
<PAGE>

       On December 11, 1989, the Company executed a conservation transfer
agreement with Snohomish County PUD. Snohomish County PUD, together with Mason
and Lewis County PUDs, will install conservation measures in their service
areas. The agreement calls for the Company to receive the power saved over the
expected 20-year life of the measures. The agreement calls for BPA to deliver
the conservation power to the Company from March 1, 1990, through June 30, 2001,
and for Snohomish County PUD to deliver the conservation power for the remaining
term of the agreement. Annual power deliveries gradually increased over the
first five years of the agreement and will remain at 6 average MW of energy
throughout the remaining term of the agreement.
       The Company executed an exchange agreement with Pacific Gas & Electric
Company which became effective on January 1, 1992. Under the agreement, 300 MW
of capacity together with 413,000 MWH of energy are exchanged seasonally every
year on a unit for unit basis. No payments are made under this agreement.
Pacific Gas & Electric Company is a summer peaking utility and will provide
power during the months of November through February. The Company is a winter
peaking utility and will provide power during the months of June through
September. Each party may terminate the contract for various reasons. The
Company has obtained 400,000 KW of transmission rights (similar in nature to
ownership type rights) on the Pacific Northwest-Southwest AC Intertie to
California. These transmission rights which are used, in part, to transmit power
under this agreement, have been subject to unanticipated limitations and
curtailments over the past several years. The Company is working with BPA to
obtain a restoration of these rights and compensation for damages.
       In October 1997 a 10-year power exchange agreement between the Company
and Powerex (a subsidiary of a British Columbia utility) became effective. Under
this agreement Powerex pays the Company for the right to deliver power to the
Company at the Canadian border in exchange for the Company delivering power to
Powerex at various locations in the United States. The Company also obtained
425,000 KW of transmission rights (similar in nature to ownership type rights)
on the Westside Northern Intertie to Canada in October 1997. These transmission
rights which are used, in part, to transmit power under this agreement have been
subject to unanticipated limitations and curtailments. The Company is working
with BPA to obtain a restoration of these rights.

ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH NON-UTILITIES
       As required by the federal Public Utility Regulatory Policies Act
("PURPA"), the Company entered into long-term firm purchased power contracts
with non-utility generators. The most significant of these are the five
contracts described below which the Company entered into in 1989, 1990 and 1991
with operators of natural gas-fired cogeneration projects. The Company purchases
the net electrical output of these five projects at fixed and annually
escalating prices which were intended to approximate the Company's avoided cost
of new generation projected at the time these agreements were made. Principally
as a result of dramatic changes in natural gas price levels, the power purchase
prices under these agreements are significantly above the current market price
of power and, based upon projections of future market prices, are expected to
remain well above market for the duration of the contracts. The Company's
estimated payments under these five contracts are $280 million for 1999, $284
million for 2000, $308 million for 2001, $313 million for 2002, $318 million for
2003 and in the aggregate, $2.4 billion thereafter through 2012. These payments
reflect the Tenaska contract restructuring described below. The Company
continues to seek restructuring of the other four contracts. If retail electric
energy prices move to market levels as a result of electric industry
restructuring, the Company plans to seek to continue to recover in rates the
above market portion of these contract costs.
     On June 29, 1989,  the Company  executed a 20-year  contract to purchase 70
average MW of energy and 80 MW of capacity, beginning October 11, 1991, from the
March Point  Cogeneration  Company  ("March  Point"),  which owns and operates a
natural gas-fired cogeneration facility known as March Point Phase I, located at
a Texaco  refinery in Anacortes,  Washington.  On December 27, 1990, the Company
executed a second contract  (having a term  coextensive with the first contract)
to  purchase  an  additional  53  average  MW of energy  and 60 MW of  capacity,
beginning in January 1993, from another natural gas-fired  cogeneration facility
owned and operated by March Point,  which facility is known as March Point Phase
II and is located at the Texaco refinery in Anacortes, Washington.

                                       10
<PAGE>

       On February 24, 1989, the Company executed a 20-year contract to purchase
108 average MW of energy and 123 MW of capacity, beginning in April 1993, from
Sumas Cogeneration Company, L.P., which owns and operates a natural gas-fired
cogeneration project located in Sumas, Washington.
       On September 26, 1990, the Company executed a 15-year contract to
purchase 141 average MW of energy and 160 MW of capacity, beginning in July
1993, from Encogen Northwest L.P. ("Encogen") (a limited partnership having a
general partner that is a subsidiary of Enserch Development Corp.), which owns
and operates a natural-gas fired cogeneration facility located at the Georgia
Pacific mill near Bellingham, Washington.
       On March 20, 1991, the Company executed a 20-year contract to purchase
216 average MW of energy and 245 MW of capacity, beginning in April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas fired
cogeneration project located near Ferndale, Washington. In December 1997 and
January 1998, the Company and Tenaska Washington Partners entered into revised
agreements which will lower purchased power costs from the Tenaska project by
restructuring its natural gas supply. The Company paid $215 million to buy out
the project's existing long-term gas supply contracts, which contained fixed and
escalating gas prices that were well above current and projected future market
prices for natural gas. The Company became the principal natural gas supplier to
the project and power purchase prices under the Tenaska contract were revised to
reflect market-based prices for the natural gas supply. The Company obtained an
order from the Washington Commission creating a regulatory asset related to the
$215 million restructuring payment. Under terms of the order, the Company is
allowed to accrue as an additional regulatory asset one-half the carrying costs
of the deferred balance over the first five years. These revised arrangements
are expected to reduce the Company's power supply costs from the Tenaska project
between 15 and 20 percent annually over the remaining 13-year life of the
contract, net of the costs of the restructuring payment. The Company's purchased
electric energy cost associated with the Tenaska contract was $80.1 million in
1998.

ENERGY TRADING
       On April 1, 1998, the Company and Duke Energy Trading and Marketing
("DETM") of Houston, a unit of Duke Energy Corp., signed an agreement relating
to energy-marketing and trading activities in 14 western States and British
Columbia. The purpose of this agreement is to coordinate the two companies'
activities in serving Puget Sound Energy's native power load with DETM's western
power and natural gas marketing and trading operations. The companies share the
benefits of this coordination proportionally up to certain stipulated amounts
intended to be reflective of the value the companies would have realized from
their respective operations in the absence of the agreement. The companies share
equally any benefits created above the stipulated amounts.
       Under the terms of the agreement, DETM performs the forward electric
energy trading function. As a result, the Company's future wholesale "sales to
other utilities" revenues and related "secondary purchase" power expenses, which
previously have reflected trading activity by the Company, will be lower than
amounts which the Company would report absent this agreement. During 1998, the
Company continued to execute in its own name transactions in which electric
energy is delivered within the next 30 days. Therefore, the Company's results
include those transactions. The Company recorded its share of the benefits that
result from the agreement as a credit to purchased power expense. The agreement
provides that forward trading activities will be conducted according to DETM's
energy price risk and credit policies, and that the Company is not responsible
for any losses caused by deviation from these policies. The Company and DETM are
presently considering modifications to the agreement.

                                       11
<PAGE>

ELECTRIC RATES AND REGULATION
       The order approving the merger of the Company, Washington Energy Company
and Washington Natural Gas Company ("Merger"), issued by the Washington
Commission on February 5, 1997, contains a rate plan designed to provide a
five-year period of rate certainty for customers and to provide the Company with
an opportunity to achieve a reasonable return on investment. General electric
tariff rates were stipulated to increase between 1.0% to 1.5% depending on rate
class on January 1, 1999 through 2001, while those for certain customers will
increase by 1.5% in 2002.

                                       12
<PAGE>
<TABLE>

       ELECTRIC UTILITY OPERATING STATISTICS
<CAPTION>
  Year Ended on December 31               1998          1997          1996           1995          1994
--------------------------------- ------------- ------------- ------------- -------------- -------------
<S>                               <C>           <C>           <C>           <C>            <C>
  Operating revenues by classes:
  (thousands)
--------------------------------- ------------- ------------- ------------- -------------- -------------
    Residential                       $540,549      $529,990      $554,318       $524,748      $532,124
    Commercial                         431,752       414,480       423,139        397,211       375,751
                                       180,959       166,473       170,596        168,501       163,574
  Industrial
    Other                               42,952        32,453        44,125         38,730        38,759
  consumers
--------------------------------- ------------- ------------- ------------- -------------- -------------
      Operating revenues
      billed to consumers  (a)       1,196,212     1,143,396     1,192,178      1,129,190     1,110,208
    Unbilled revenues -
    net increase (decrease)              4,024       (4,921)        13,201        (6,382)       (2,522)
    PRAM                                    --      (40,777)      (74,326)          3,955        25,835
  accrual
--------------------------------- ------------- ------------- ------------- -------------- -------------
      Total operating revenues
      from consumers                 1,200,236     1,097,698     1,131,053      1,126,763     1,133,521
    Other utilities and                274,972       133,726        67,716         52,567        60,537
  marketers
--------------------------------- ------------- ------------- ------------- -------------- -------------
      Total operating revenues      $1,475,208    $1,231,424    $1,198,769     $1,179,330    $1,194,058
--------------------------------- ------------- ------------- ------------- -------------- -------------
  Number of customers (average):
    Residential                        782,095       767,476       754,097        739,173       723,566
                                        94,118        91,517        89,613         87,404        85,203
  Commercial
                                         4,193         4,090         3,993          3,908         3,851
  Industrial
                                         1,437         1,389         1,371          1,346         1,325
  Other
--------------------------------- ------------- ------------- ------------- -------------- -------------
      Total customers                  881,843       864,472       849,074        831,831       813,945
  (average)
--------------------------------- ------------- ------------- ------------- -------------- -------------
  KWH generated, purchased and 
   interchanged (thousands):
    Company generated                7,934,730     6,641,118     5,585,595      6,371,416     7,011,932
    Purchased power                 24,231,978    22,611,963    20,573,983     17,897,922    16,268,042
    Interchanged power (net)            91,230       103,959        99,942         48,485       (87,771)
--------------------------------- ------------- ------------- ------------- -------------- -------------
      Total energy output           32,257,938    29,357,040    26,259,520     24,317,823    23,192,203
    Losses and company use          (1,413,331)   (1,414,101)   (1,322,262)    (1,235,457)   (1,291,322)
--------------------------------- ------------- ------------- ------------- -------------- -------------
      Total energy sales            30,844,607    27,942,939    24,937,258     23,082,366    21,900,881
--------------------------------- ------------- ------------- ------------- -------------- -------------
</TABLE>

       (a) Operating revenues in 1998, 1997, 1996 and 1995 were reduced by $46.7
million, $40.5 million, $41.0 million and $25.1 million, respectively, as a
result of the Company's sale of $237.7 million of its investment in
customer-owned energy conservation measures. (See "Operating Revenues-Electric"
in Management's Discussion and Analysis and Note 1 to the Consolidated Financial
Statements.)

                                       13
<PAGE>

       (continued from previous page)
<TABLE>
<CAPTION>
  YEAR ENDED ON DECEMBER 31                           1998         1997         1996         1995         1994
--------------------------------------------- ------------- ------------ ------------ ------------ ------------
<S>                                           <C>           <C>          <C>          <C>          <C>         
  Electric energy sales, KWH:
  (thousands)
--------------------------------------------- ------------- ------------ ------------ ------------ ------------
    Residential                                  9,313,652    9,319,508    9,350,292    8,972,498    8,913,903
    Commercial                                   7,191,164    7,022,092    6,807,465    6,538,533    6,301,568
    Industrial                                   4,072,722    3,994,748    3,793,966    3,720,641    3,724,931
    Other consumers                                284,312      206,330      205,066      205,232      200,622
--------------------------------------------- ------------- ------------ ------------ ------------ ------------
       Total energy billed to consumers         20,861,850   20,542,678   20,156,789   19,436,904   19,141,024
    Unbilled energy sales -
       net increase (decrease)                      43,027      (45,556)     224,412     (158,920)     (72,352)
--------------------------------------------- ------------- ------------ ------------ ------------ ------------
       Total energy sales to consumers          20,904,877   20,497,122   20,381,201   19,277,984   19,068,672
    Sales to other utilities and marketers       9,939,730    7,445,817    4,556,057    3,804,382    2,832,209
--------------------------------------------- ------------- ------------ ------------ ------------ ------------
       Total energy sales                       30,844,607   27,942,939   24,937,258   23,082,366   21,900,881
--------------------------------------------- ------------- ------------ ------------ ------------ ------------
  Per residential customer:
    Annual use (KWH)                                11,909       12,143       12,399       12,139       12,319
    Annual billed revenue                          $721.09      $716.88      $762.35      $726.95      $735.42
    Billed revenue per KWH                          $.0606       $.0590       $.0615       $.0599       $.0597
  Company-owned generation capability - KW:
    Hydro                                          308,200      309,950      309,950      309,950      309,950
    Steam                                          771,900      771,900      771,900      771,900      771,900
    Natural gas/oil                                673,850      702,350      702,350      702,350      702,350
--------------------------------------------- ------------- ------------ ------------ ------------ ------------
       Total                                     1,753,950    1,784,200    1,784,200    1,784,200    1,784,200
--------------------------------------------- ------------- ------------ ------------ ------------ ------------
  Heating degree days                                4,498        4,599        4,953        3,994        4,341
  % of normal of 30 year
    average                                          91.6%        93.7%       100.9%        81.4%        88.4%
  Load factor                                        52.6%        58.7%        55.5%        56.7%        54.7%
</TABLE>

                                       14
<PAGE>

GAS UTILITY OPERATIONS

GAS SUPPLY
       The Company currently purchases a blended portfolio of long-term firm,
short-term firm, and spot gas supplies from a diverse group of major and
independent producers and gas marketers in the United States and Canada. All of
the Company's gas supply is ultimately transported through Northwest Pipeline
Corporation ("NPC"), the sole interstate pipeline delivering directly into the
western Washington area.


  PEAK FIRM GAS SUPPLY AT DECEMBER 31, 1998     DTH PER DAY       %
---------------------------------------------- ------------- -------
  Purchased Gas Supply
     British Columbia                               212,400    27.8
     Alberta                                         75,900     9.9
     United States                                   50,900     6.7
---------------------------------------------- ------------- -------
  Total Purchased Gas Supply                        339,200    44.4
---------------------------------------------- ------------- -------
  Purchased Storage Capacity
     Clay Basin                                      89,900    11.8
     Jackson Prairie                                 47,700     6.2
     LNG                                             69,600     9.1
---------------------------------------------- ------------- -------
  Total Purchased Storage Capacity                  207,200    27.1
---------------------------------------------- ------------- -------
  Owned Storage Capacity
     Jackson Prairie                                188,400    24.6
     Propane-Air Injection                           30,000     3.9
---------------------------------------------- ------------- -------
  Total Owned Storage Capacity                      218,400    28.5
---------------------------------------------- ------------- -------
  Total Peak Firm Gas Supply                        764,800   100.0
---------------------------------------------- ------------- -------
All supplies and storage are connected to PSE's market with firm transportation
capacity.

       For baseload and peak-shaving purposes, the Company supplements its firm
gas supply portfolio by purchasing natural gas at generally lower prices in
summer, injecting it into underground storage facilities and withdrawing it
during the winter heating season. Storage facilities at Jackson Prairie in
Western Washington and at Clay Basin in Utah are used for this purpose. Peaking
needs are also met by using Company-owned gas held in NPC's liquefied natural
gas ("LNG") facility at Plymouth, Washington, and by producing propane-air gas
at a plant owned by the Company and located on its distribution system.
       In 1998, the Company took assignment from Cascade Natural Gas of a
Peaking Gas Supply Service ("PGSS") contract whereby the Company can divert up
to 48,000 MMBTu per day of gas supply away from the Tenaska Cogeneration
Facility and toward the core gas load by causing Tenaska to operate its facility
on distillate fuel and paying any additional costs of such operation.
       The Company expects to meet its firm peak-day requirements for
residential, commercial and industrial markets through its firm gas purchase
contracts, firm transportation capacity, firm storage capacity and other firm
peaking resources. The Company believes that it will be able to acquire
incremental firm gas supply resources which are reliable and reasonably priced,
to meet anticipated growth in the requirements of its firm customers for the
foreseeable future.

                                       15
<PAGE>

GAS SUPPLY PORTFOLIO
       For the 1998-99 winter heating season, the Company has contracted for
approximately 28% of its expected peak-day gas supply requirement from sources
originating in British Columbia under a combination of long-term and
winter-peaking purchase agreements. Long-term gas supplies from Alberta
represent approximately 10% of the peak-day requirement. Long-term and winter
peaking arrangements with U.S. suppliers and gas stored at Clay Basin make up
approximately 18% of the peak-day portfolio. The balance of the peak-day
requirement is expected to be met with gas stored at Jackson Prairie, LNG held
at NPC's Plymouth facility and propane-air resources, which represent
approximately 31%, 9% and 4%, respectively, of expected peak-day requirements.
       During 1998, approximately 46% of gas supplies purchased by the Company
originated from British Columbia while 27% originated in Alberta and 27%
originated in the U.S.
       The current firm, long-term gas supply portfolio consists of arrangements
with 16 producers and gas marketers, with no single supplier representing more
than 15% of expected peak-day requirements. Contracts have remaining terms
ranging from less than one year to 13 years, with an average term of 2 years.
All gas supply contracts contain market-sensitive pricing provisions based on
several published indices.
       The Company's firm gas supply portfolio is structured to capitalize on
regional price differentials when they arise. Gas and services are marketed
outside the Company's service territory ("off-system sales") whenever on-system
customer demand requirements permit. The geographic mix of suppliers and daily,
monthly and annual take requirements permit a high degree of flexibility in
selecting gas supplies during off-peak periods to minimize costs.

GAS TRANSPORTATION CAPACITY
       The Company currently holds firm transportation capacity on pipelines
owned by NPC and PG&E Gas Transmission-Northwest, formerly known as Pacific Gas
Transportation ("PGT"). Accordingly, the Company pays fixed monthly demand
charges for the right, but not the obligation, to transport specified quantities
of gas from receipt points to delivery points on such pipelines each day for the
term or terms of the applicable agreements.
       The Company holds firm capacity on NPC's pipeline totaling 454,533
Dekatherms per day (one Dekatherm "Dth" is equal to one million British thermal
units or "MMBTu" per day), acquired under several agreements at various times.
The Company has exchanged certain segments of its firm capacity with third
parties to effectively lower transportation costs. The Company's firm
transportation capacity contracts with NPC have remaining terms ranging from 6
to 17 years. However, the Company has either the unilateral right to extend the
contracts under their current terms or the right of first refusal to extend such
contracts under current FERC orders. The Company's firm transportation capacity
on PGT's pipeline has a remaining term of 25 years.

GAS STORAGE CAPACITY
       The Company holds storage capacity in the Jackson Prairie and Clay Basin
underground gas storage facilities adjacent to NPC's pipeline. The Jackson
Prairie facility, operated and one-third owned by the Company, is used primarily
for intermediate peaking purposes, able to deliver a large volume of gas over a
relatively short time period. Combined with capacity contracted from NPC's
one-third stake in Jackson Prairie, the Company has peak, firm delivery capacity
of over 230,000 Dth per day and total firm storage capacity exceeding 6,000,000
Dth at the facility. The location of the Jackson Prairie facility in the
Company's market area provides significant cost savings by reducing the amount
of annual pipeline capacity required to meet peak-day gas requirements. The
Company, as project operator of the facility, received approval from FERC on
September 30, 1998, to expand the Jackson Prairie facility. The Company's share
of the expanded project will provide additional firm delivery capacity of over
100,000 Dth per day and additional firm storage capacity of above 1,000,000 Dth
at the start of the 1999-2000 heating season. The Company has secured rights to
additional firm seasonal pipeline capacity to be utilized in conjunction with
the expanded project.

                                       16
<PAGE>

       The Clay Basin storage facility is supply area storage and is withdrawn
over the entire winter, capturing savings due to injecting lower cost gas
supplies during the summer. The Company has maximum firm withdrawal capacity of
over 100,000 Dth per day from the facility with total storage capacity exceeding
13,000,000 Dth. The capacity is held under two contracts with remaining terms of
15 and 21 years.

LNG AND PROPANE-AIR RESOURCES
       LNG and propane-air resources provide gas supply on short notice for
short periods of time. Due to their high cost, these resources are utilized as
the supply of last resort in extreme peak-demand periods, typically lasting a
few hours or days. The Company has long-term contracts for storage of nearly
250,000 Dth of Company-owned gas as LNG at NPC's Plymouth facility, which
equates to approximately three and one-half days' supply at maximum daily
deliverability of 70,500 Dth. The Company owns storage capacity for
approximately 1.4 million gallons of propane. The propane-air injection
facilities are capable of delivering the equivalent of 30,000 Dth of gas per day
for up to four days directly into the Company's distribution system.

CAPACITY RELEASE
       FERC provided a capacity release mechanism as the means for holders of
firm pipeline and storage entitlements to relinquish temporarily unutilized
capacity to others in order to recoup all or a portion of the cost of such
capacity. Capacity may be released through several methods including open
bidding and by pre-arrangement. The Company continues to successfully mitigate a
substantial portion of the demand charges related to both storage and NPC and
PGT pipeline capacity not utilized during off-peak periods. WNG CAP I, a wholly
owned subsidiary of the Company, was formed to provide additional flexibility
and benefits from capacity release. Washington Energy Gas Marketing
Company ("WEGM"), a wholly-owned subsidiary of the Company, also markets excess
capacity on the PGT pipeline. (See Note 17 to the Consolidated Financial
Statements.)

GAS RATES AND REGULATION
       The order approving the Merger, issued by the Washington Commission on
February 5, 1997, contains a rate plan which provided unchanged rates for all
classes of natural gas customers until January 1, 1999, when rates decreased by
1% on gas utility margins.
       On March 25, 1998, the WUTC approved the Company's Purchase Gas
Adjustment ("PGA") and deferral amortization (true-up) filing effective April 1,
1998. The PGA filing reflected a reduction in expected gas costs of
approximately $4.3 million. The deferral amortization filing was a refund to
customers for prior period over-collections of gas costs. This filing replaced a
larger deferral amortization refund that had been in effect since May 1995. The
combined filings reduced gas rates to all sales customers less than 1%.
       On June 25, 1998, the Company received approval from the Washington
Commission to begin a new performance-based mechanism for strengthening its
gas-supply purchasing and gas-storage practices. The PGA Incentive Mechanism,
which encourages competitive gas purchasing and management of pipeline and
storage-capacity became effective July 1, 1998. Incentive gains and losses from
the three-year program are shared between customers and shareholders. After the
first $0.5 million, which is allocated to customers, gains and losses are shared
40%/60% between the Company and customers up to $26.5 million, and 33%/67%
thereafter. Gains or losses are determined relative to a weighted average index
which is reflective of the Company's gas supply and transportation contract
costs. The Company's share of incentive gains under the PGA Incentive Mechanism
in 1998 were approximately $1.1 million while customers received approximately
$2.0 million.

                                       17
<PAGE>
<TABLE>
        GAS UTILITY OPERATING STATISTICS
<CAPTION>

  Twelve Months Ended December 31                       1998             1997            1996             1995            1994
--------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
<S>                                           <C>             <C>              <C>             <C>              <C>   
  Operating revenues by classes (thousands):
  Regulated utility sales:
    Residential sales                               $253,169         $246,747        $238,560         $231,202        $206,602
    Commercial firm sales                             96,116           97,233          94,251           97,396          91,749
    Industrial firm sales                             18,557           19,524          20,024           25,860          28,827
    Interruptible sales                               22,190           19,832          23,376           44,511          51,425
    Transportation services                           14,211           14,631          12,812           10,762           8,399
    Other                                             12,308           11,480          11,085           10,317           9,405
--------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
      Total gas operating revenues                  $416,551         $409,447        $400,108         $420,048        $396,407
--------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
  Customers, average number served
    Residential                                      486,553          465,185         440,586          423,195         403,642
    Commercial firm                                   42,273           41,158          39,651           38,378          37,112
    Industrial firm                                    2,850            2,839           2,762            2,754           2,824
    Interruptible                                        940              962           1,000            1,037           1,009
    Transportation                                       123              128             106               55              36
--------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
      Total customers (average)                      532,739          510,272         484,105          465,419         444,623
--------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
  Gas volumes (thousands of therms):
    Residential sales                                444,611          434,179         421,727          398,283         371,472
    Commercial firm sales                            193,765          195,087         188,321          179,725         174,668
    Industrial firm sales                             42,737           44,563          46,640           55,365          62,698
    Interruptible sales                               72,115           60,244          72,229          132,316         151,175
    Transportation volumes                           254,368          277,092         242,299          156,941         119,590
--------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
      Total gas volumes                            1,007,596        1,011,165         971,216          922,630         879,603
--------------------------------------------- --------------- ---------------- --------------- ---------------- ---------------
  Working-gas volumes in storage at year end
  (thousands of therms)
      Jackson Prairie                                 37,683           52,430          65,834           65,834          65,834
      Clay Basin                                      58,827           64,930          82,847          130,970          47,557
  Average use per customer (therms):
    Residential                                          914              933             957              941             921
    Commercial firm                                    4,584            4,740           4,749            4,683           4,708
    Industrial firm                                   14,995           15,697          16,886           20,103          22,035
    Interruptible                                     76,718           62,624          72,229          127,595         147,315
    Transportation                                 2,068,033        2,164,781       2,285,840        2,853,473       3,400,694
</TABLE>

                                       18
<PAGE>

(continued from prior page)
<TABLE>
<CAPTION>
  TWELVE MONTHS ENDED DECEMBER 31              1998          1997         1996        1995         1994
--------------------------------------- ------------ ------------- ------------ ----------- ------------
<S>                                     <C>          <C>           <C>          <C>         <C>  
  Average revenue per customer:
    Residential                              $  520        $  530       $  541      $  546       $  512
    Commercial firm                           2,274         2,362        2,377       2,538        2,472
    Industrial firm                           6,511         6,877        7,250       9,390       10,208
    Interruptible                            23,606        20,615       23,376      42,923       50,966
    Transportation                          115,537       114,305      120,868     195,673      233,306
  Average revenue per therm (cents):
    Residential                                56.9          56.8         56.6        58.0         55.6
    Commercial firm                            49.6          49.8         50.0        54.2         52.5
    Industrial firm                            43.4          43.8         42.9        46.7         46.0
    Interruptible                              30.8          32.9         32.4        33.6         34.0
      Total sales to customers                 51.8          52.2         51.6        52.1         49.8
    Transportation                              5.6           5.3          5.3         6.9          7.0

  Weather - degree days                       4,498         4,599        4,953       3,994        4,341
    % of normal (30-year average)             91.6%         93.7%       100.9%       81.4%        88.4%
</TABLE>

Note:  Data prior to January 1, 1997, is for the period ending September 30.

ENERGY CONSERVATION
       The Company offers programs designed to help new and existing customers
use energy efficiently. The primary emphasis is to provide information and
technical services to enable customers to make energy-efficient choices with
respect to building design, equipment and building systems, appliance purchases
and operating practices.
       Since May 1997, the Company has recovered electric energy conservation
expenditures through a tariff rider mechanism. The rider mechanism allows the
Company to defer the conservation expenditures and amortize them to expense as
the Company concurrently collects the conservation expenditures in rates over a
one year period. As a result of the rider, there is no effect on earnings per
share.
       Since 1995, the Company has been authorized by the Washington Commission
to defer gas energy conservation expenditures and recover them through a tariff
tracker mechanism. The tracker mechanism allows the Company to defer
conservation expenditures and recover them in rates over the subsequent year.
The tracker mechanism also allows the Company to recover an Allowance for Funds
Used to Conserve Energy (AFUCE) on any outstanding balance that is not being
recovered in rates.

                                       19
<PAGE>

ENVIRONMENT
       The Company's operations are subject to environmental regulation by
federal, state and local authorities. Due to the inherent uncertainties
surrounding the development of federal and state environmental and energy laws
and regulations, the Company cannot determine the impact such laws may have on
its existing and future facilities. (See Note 17 to the Consolidated Financial
Statements for further discussion of environmental sites.)

FEDERAL CLEAN AIR ACT AMENDMENTS OF 1990
       The Company has an ownership interest in coal-fired, steam-electric
generating plants at Centralia, Washington and Colstrip, Montana, which are
subject to the federal Clean Air Act Amendments of 1990 ("CAAA") and other
regulatory requirements.
       The Centralia Project and the Colstrip Projects met the sulfur dioxide
limits of the CAAA in Phase I (1995). The Company and other joint owners of the
Centralia Project are exploring alternative emission compliance options and
project economics in light of compliance costs to meet the Phase II limits in
the year 2000. All four units at the Colstrip Project, operated by Montana
Power, meet Phase II emission limits.
       The Company owns combustion turbine units, most of which are capable of
being fueled by natural gas or oil. The nature of these units provides
operational flexibility in meeting air emission standards.
     There  is  no  assurance  that  in  the  future  environmental  regulations
affecting  sulfur  dioxide  or  nitrogen  oxide  emissions  may  not be  further
restricted,  or that  restrictions  on  emissions  of  carbon  dioxide  or other
combustion by-products may not be imposed. 

FEDERAL ENDANGERED SPECIES ACT
       In November 1991, the National Marine Fisheries Service ("NMFS") listed
the Snake River Sockeye as an endangered species pursuant to the federal
Endangered Species Act ("ESA"). Since the Sockeye listing, the Snake River fall
and spring/summer Chinook have also been listed as threatened. In response to
the listings, a team of experts was formed to develop a plan for the recovery
needs of these species. In 1995, the NMFS issued a biological opinion which has
significantly changed the operation of the Federal Columbia River Power System.
       The plans developed by NMFS affect the Mid-Columbia projects from which
the Company purchases power on a long-term basis, and will further reduce the
flexibility of the regional hydro-electric system. Although the full impacts are
unknown at this time, the plan developed by NMFS shifts an amount of the
Company's generation from the Mid-Columbia projects from winter periods into the
spring when it is not needed for system loads, and will increase the potential
for spill and loss of generation at the Mid-Columbia projects.
     Since the 1991 listings, one more species of salmon has been listed and two
more have been proposed which may further influence  operations.  Upper Columbia
River Steelhead were listed by NMFS in August 1997.  Anticipating  the Steelhead
listing, the Mid-Columbia PUDs initiated consultation with the federal and state
agencies,  Native American tribes and  non-governmental  organizations to secure
operational  protection through a long-term  settlement and habitat conservation
plan which includes fish protection and enhancement  measurement for the next 50
years. The negotiations  have concluded among the Chelan and Douglas County PUDs
and  various  fishery  agencies,  and final  agreement  is subject to a National
Environmental  Policy Act review and power purchaser  approval.  Generally,  the
agreement obligates the PUDs to achieve certain levels of passage efficiency for
downstream  migrants  at their  hydro-electric  facilities  and to fund  certain
habitat  conservation  measures.  Grant County PUD has yet to reach agreement on
these issues.

                                       20
<PAGE>

     The proposed  listings of Puget Sound Chinook salmon and spring Chinook for
the upper  Columbia will be final,  if approved,  in March 1999.  The listing of
spring  Chinook for the upper Columbia  should not result in markedly  differing
conditions for operations  from previous  listings in the area.  However,  Puget
Sound has not experienced ESA listing to date and listing of Puget Sound Chinook
could cause a number of changes to operations of government agencies and private
entities in the region  including the Company.  These may adversely affect hydro
plant  operations,  permit  issuance for facilities  construction  and increased
costs for process and facilities.  Because the Company relies substantially less
on  hydro-electric  energy from the Puget Sound area than from the  Mid-Columbia
and  because  the impact on Company  operations  in the Puget  Sound area is not
likely to impair  significant  generating  resources,  the impact of listing for
Puget Sound  Chinook  salmon  should be  proportionately  less than the Columbia
River listings.

                                       21
<PAGE>

EXECUTIVE OFFICERS AT DECEMBER 31, 1998:
<TABLE>
<CAPTION>
  NAME                  AGE      OFFICES
--------------------- -------- --------------------------------------------------------------------------------
<S>                   <C>      <C>                
  W. S. Weaver          54       President & Chief Executive Officer since January 1998; President, May 1997
                                 - January 1998; Vice Chairman and Chairman of Unregulated Subsidiaries,
                                 February 1997 - May 1997; Executive Vice President and Chief Financial
                                 Officer 1991-1997; Director since 1991.
  R. R. Sonstelie       53       Chairman of the Board since February 1997; President and Chief Executive
                                 Officer 1992-1997; President and Chief Operating Officer 1991-1992;
                                 President and Chief Financial Officer 1987-1991; Executive Vice President
                                 1985-1987; Senior Vice President Finance 1983-1985; Vice President
                                 Engineering and Operations 1980-1983; Director since 1987.
  J. W. Eldredge        48       Chief Accounting Officer since 1994; Corporate Secretary and Controller
                                 since 1993; Controller since 1988.
  D. E. Gaines          41       Treasurer since 1994; Director Strategic Planning 1992-1994; Manager
                                 Financial Planning 1986 - 1992.
  W. A. Gaines          43       Vice President Energy Supply since February 1997; Manager Power Management
                                 1996-1997; Manager Operations Planning 1986-1996.
  D.A. Graham           58       Vice President Human Resources since April 1998; Director Human Resources
                                 1989-1998.
  R. L. Hawley          49       Vice President and Chief Financial Officer since March 1998. For more than
                                 five years prior to that time, he was a partner with Coopers & Lybrand
                                 L.L.P. (now PricewaterhouseCoopers LLP).
  T. J. Hogan           47       Vice President Systems Operations since February 1997; Washington Energy
                                 Company positions held: Executive Vice
                                 President and Chief Operating Officer
                                 1995-1997; Vice President Supply,
                                 Administration and Corporate Secretary
                                 1994-1995; Vice President Legal and
                                 Corporate Secretary 1991-1994.
  S. A. McKeon          52       Vice President and General Counsel since June 1997. For more than five years
                                 prior to that time he was a partner at Perkins Coie LLP.
  S. McLain             42       Vice President Corporate Performance since December 1997; Director Planning
                                 and Work Practices 1997; various positions in Human Resources, Operations,
                                 Customer Service and Strategic Planning 1988-1997.
  J. Quintana           50       Vice President External Affairs since April 1998. For more than five years
                                 prior to that time, he was Sr. Vice President Public Affairs for the Rockey
                                 Company, a public relations consulting firm.
  G. B. Swofford        57       Vice President Customer Operations since February 1997; Senior Vice
                                 President Customer Operations 1994-1997; Vice President Divisions and
                                 Customer Services 1991-1994; Vice President Rates and Customer Programs
                                 1986-1991.
</TABLE>

Officers are elected for one-year terms.

                                       22
<PAGE>

         ITEM 2. PROPERTIES

       The principal electric generating plants and underground gas storage
facilities owned by the Company are described under Item 1 - "Business -
Electric Utility Operations and Gas Utility Operations." The Company owns its
transmission and distribution facilities and various other properties.
Substantially all properties of the Company are subject to the liens of the
Company's Mortgage Indentures.

         ITEM  3.  LEGAL PROCEEDINGS

       See Note 17 to the Consolidated Financial Statements.

         ITEM  4.  SUBMISSION OF MATTERS TO A VOTE
         OF SECURITY HOLDERS
       None

         PART II

         ITEM  5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND
         RELATED STOCKHOLDER MATTERS.

       The Company's common stock is traded on the New York Stock Exchange
(symbol PSD). The number of stockholders of record of the Company's common stock
at December 31, 1998, was 58,650.
       The Company has paid dividends on its common stock each year since 1943
when such stock first became publicly held. Future dividends will be dependent
upon earnings, the financial condition of the Company and other factors.
       The payment of dividends on common stock is restricted by provisions of
certain covenants applicable to preferred stock and long-term debt contained in
the Company's Articles of Incorporation and electric and gas mortgage
indentures. Under the most restrictive covenants, earnings reinvested in the
business unrestricted as to payment of cash dividends were approximately $183
million at December 31, 1998. (See Note 7 to the Consolidated Financial
Statements.)

                                       23
<PAGE>

       Dividends paid and high and low stock prices for each quarter over the
last two years were:

<TABLE>
<CAPTION>
                              1998                                    1997 (A)
----------------- ------------------------- --------------- ------------------------ -------------
                           PRICE RANGE        DIVIDENDS             PRICE RANGE        DIVIDENDS

  QUARTER ENDED     HIGH         LOW          PAID            HIGH          LOW        PAID
----------------- ------------ ------------ --------------- ------------- ---------- -------------
<S>               <C>          <C>          <C>             <C>           <C>        <C>     
  March 31          30-1/4       26-5/8       $.46            26            23-1/2     $.46
  June 30           28-5/8       25           $.46            26-1/2        23-3/4     $.46
  September 30      28           24-1/16      $.46            26-15/16      25-1/8     $.46
  December 31       29           25-7/8       $.46            30-3/16       25-1/2     $.46
</TABLE>

       (A) Data for Puget Sound Power & Light Company prior to February 10, 1997

                                       24
<PAGE>

         ITEM  6.  SELECTED FINANCIAL DATA

(Dollars in thousands except per share data)
<TABLE>
<CAPTION>

  YEAR ENDED DECEMBER 31                             1998             1997            1996           1995           1994
-------------------------------------------    -----------      -----------     -----------    -----------    -----------
<S>                                            <C>              <C>             <C>            <C>            <C>       
  Operating revenue                            $1,907,340       $1,676,902      $1,649,279     $1,631,118     $1,632,485
  Operating income                                298,980          215,866         284,474        270,344        224,772
  Income from continuing
    operations                                    169,612          125,698         167,351        128,381         79,312
  Income for common stock from
    continuing operations                         156,609          107,421         145,170        105,727         58,929

  Basic and diluted earnings
    per common share from
    continuing operations (Note 1 to the             1.85             1.28            1.72           1.26           0.70
       financial statements)
  Dividends per common share                         1.84             1.78            1.67           1.67           1.67
  Book value per common share                       16.00            16.06           16.31          16.27          17.01
-------------------------------------------    -----------      -----------     -----------    -----------    -----------
  Total assets at year-end                     $4,720,689       $4,493,370      $4,227,470     $4,244,568     $4,496,770
  Long-term obligations                         1,474,748        1,411,707       1,165,584      1,230,499      1,253,498
  Redeemable preferred stock                       73,162           78,134          87,839         89,039         91,242
  Corporation obligated, 
   mandatorily redeemable
   preferred securities of
   subsidiary trust holding
   solely junior subordinated
   debentures of the
   corporation                                    100,000          100,000              --             --             --
-------------------------------------------    -----------      -----------     -----------    -----------    -----------
</TABLE>

                                       25
<PAGE>

         ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
         OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

       The following discussion of the Company's business includes some
forward-looking statements that involve risks and uncertainties. Words such as
"estimates," "expects," "anticipates," "plans," and similar expressions identify
forward-looking statements involving risks and uncertainty. Those risks and
uncertainties include, but are not limited to, the ongoing restructuring of the
electric and gas industries and the outcome of regulatory proceedings related to
that restructuring. The ultimate impacts of both increased competition and the
changing regulatory environment on future results are uncertain, but are
expected to fundamentally change how the Company conducts its business. The
outcome of these changes and other matters discussed below may cause future
results to differ materially from historic results, or from results or outcomes
currently expected or sought by the Company.

FINANCIAL CONDITION AND RESULTS OF OPERATIONS
       Financial condition and results of operations for 1998 and 1997 reflect
the results of Puget Sound Energy, Inc., formerly Puget Sound Power & Light
Company ("Puget"). Financial condition and results of operations for 1996
reflect combined results for the fiscal years ended December 31 for Puget and
September 30 for Washington Energy Company ("WECO"). On February 10, 1997, WECO
and its subsidiary, Washington Natural Gas Company, merged into Puget, which
then changed its name to Puget Sound Energy, Inc.
       Net income in 1998 was $169.6 million on operating revenues of $1.907
billion, compared to $123.1 million on operating revenues of $1.677 billion in
1997 and $165.5 million on operating revenues of $1.649 billion in 1996. Income
for common stock was $156.6 million in 1998, compared to $105.7 million in 1997
and $143.3 million in 1996.
       Basic and diluted earnings per share in 1998 were $1.85 on 84.6 million
weighted average common shares outstanding compared to $1.25 on 84.6 million
weighted average common shares outstanding in 1997 including a $.03 loss per
share from discontinued operations and $1.70 on 84.4 million weighted average
common shares outstanding in 1996 including a $.02 loss per share from
discontinued operations.
       Contributing to the increase in net income and basic and diluted earnings
per share in 1998 compared to 1997 were continued growth in retail electric and
gas customers and a reduction in utility operations and maintenance expense of
approximately $13.6 million or 5% in 1998 compared to 1997. Net income for 1997
included an after-tax charge of $36.3 million ($0.43 per share) for costs
related to the merger including transaction expenses, employee separation and
system and facilities integration. Net income in 1997 also included an after-tax
charge of $2.6 million ($0.03 per share), to write off the Company's remaining
investment in undeveloped coal reserves and related activities in southeastern
Montana (See Note 18 to the Consolidated Financial Statements). These charges in
1997 were partially offset by $13.6 million ($0.16 per share) related to an
income tax refund received in 1997. Excluding the impact of these charges and
credits to income, continuing operations for 1997 produced earnings of $1.55 per
share. Total kilowatt-hour sales to ultimate consumers in 1998 were 20.9
billion, compared with 20.5 billion in 1997 and 20.4 billion in 1996.
Kilowatt-hour sales to other utilities were 9.9 billion in 1998, 7.4 billion in
1997 and 4.6 billion in 1996.
       Total gas volumes sold, including transported gas, were 1,008 million
therms in 1998, 1,011 million therms in 1997 and 971 million therms in 1996.

                                       26
<PAGE>

  INCREASE (DECREASE) OVER PRECEDING YEAR

  YEARS ENDED DECEMBER 31 (DOLLARS IN MILLIONS)

                                                     1998       1997      1996
------------------------------------------------ --------- ---------- ---------
  Operating revenues:
    General rate increases                          $18.5      $16.9      $ --
    PRAM electric revenue surcharges/refunds         44.8      (22.6)    (37.1)
    BPA Residential Purchase and
      Sale Agreement                                 (1.2)       2.7     (15.8)
    Electric sales to other utilities               141.2       66.0      15.1
    Electric revenue sold to conservation trust      (6.2)       0.5     (15.9)
    Electric load and other changes                  46.7      (30.8)     73.1
    Gas revenue change                                7.1        9.3     (19.9)
    Other revenues                                  (20.5)     (14.4)     18.7
------------------------------------------------ ---------- ---------- --------
       Total operating revenue changes              230.4       27.6      18.2
------------------------------------------------ --------- ---------- ---------
  Operating expenses:
    Energy costs:
      Purchased electricity                         137.2       52.6      38.8
      Residential exchange                           16.4       31.2     (15.1)
      Purchased gas                                  (3.5)       1.6     (41.3)
      Electric generation fuel                       15.1        0.8       5.0
    Utility operations and maintenance              (13.6)       8.3     (16.6)
    Other operations and maintenance                (13.6)     (11.0)      2.7
    Depreciation and amortization                     3.7       17.6       3.2
    Merger and related costs                        (55.8)      51.0       4.8
    Taxes other than federal income taxes             1.2        4.1       6.3
    Federal income taxes                             60.2      (60.0)     16.2
------------------------------------------------ --------- ---------- ---------
       Total operating expense changes              147.3       96.2       4.0
------------------------------------------------ --------- ---------- ---------
  Other income                                      (18.9)      26.5      16.4
  Interest charges                                   20.3       (0.5)     (8.3)
  Discontinued operations                             2.6       (0.8)     24.8
------------------------------------------------ --------- ----------- --------
  Net income changes                               $ 46.5     $(42.4)   $ 63.7
------------------------------------------------ --------- ----------- --------

       The following information pertains to the changes outlined in the table
above:

OPERATING REVENUES - ELECTRIC
       Electric operating revenues increased $18.5 million in 1998 and $16.9
million in 1997 when compared to the prior years due to an overall average 1.8%
general rate increase effective February 8, 1997 and an overall average 1.2%
general rate increase effective January 1, 1998.
     Electric  operating  revenues in 1998 increased  $44.8 million  compared to
1997 as a result of a $48.6 million Periodic Rate Adjustment  Mechanism ("PRAM")
revenue  reduction in 1997  associated  with an IRS 1991-1994  Conservation  tax
refund and related  interest income.  Based on the Company's  agreement with the
Washington  Commission,  the  benefit  of the tax refund was passed on to retail
customers as a reduction of the PRAM accrued revenue balance.  The $48.6 million
reduction  in revenues  in 1997 was offset by a decrease  in federal,  state and
local  taxes as well as a decrease  in interest  expense  and a  recognition  of
interest income.

                                       27
<PAGE>

       On September 30, 1996, the PRAM was discontinued pursuant to a negotiated
settlement and the Washington Commission issued an order granting a joint motion
by the Company and the Washington Commission staff to transfer annual revenues
of $165.5 million which were being collected in PRAM rates to the Company's
permanent rate schedules. A $17.0 million overcollection of the PRAM, which
resulted from the pass-through of conservation tax refunds, was refunded to
customers in 1997.
       Electric revenues in 1998, 1997 and 1996 were reduced because of the
credit that the Company received through the Residential Purchase and Sale
Agreement with the Bonneville Power Administration ("BPA"). This agreement
enables the Company's residential and small farm customers to receive the
benefits of lower-cost federal power. A related reduction is included in
purchased and interchanged power expenses. On January 29, 1997, the Company and
the BPA signed a Residential Exchange Termination Agreement. The Agreement ends
the Company's participation in the Residential Purchase and Sale Agreement with
BPA. As part of the Termination Agreement, the Company will receive payments by
the BPA of approximately $235 million over an approximately 5-year period ending
June 2001. Under the rate plan approved by the Washington Commission in its
merger order, the Company will continue to reflect through the rate stability
period, in customers' bills, the current level of Residential Exchange benefits.
Over the remainder of the Residential Exchange Termination Agreement from
January 1999 through June 2001, it is projected that the Company will credit
customers approximately $172.3 million more than it will receive from BPA during
the following periods:

                                                          Dollars in
               Period                                       Millions
               ---------------------------------- -------------------
               January - December 1999                         $68.0
               January - December 2000                          67.4
               January - June 2001                              36.9
                                                  -------------------
                                                              $172.3

       The Company and other investor owned utilities in the northwest region
are participating in the BPA's subscription process pursuant to which
allocations of federal power in the northwest beginning in 2001 will be
determined. Through this process the Company may receive a combination of low
cost energy from the federal power system in the northwest or financial exchange
agreements for the benefit of their residential and small farm customers, which
would be in lieu of the residential and small farm customer benefits required by
the Regional Power Act of 1980. The amount of such BPA power purchases and
financial exchange arrangements that may be available for the Company's
residential and small farm customers, and the BPA rates and contractual terms
and conditions applicable thereto, are generally not established at this time.
Subsequent to the rate stability period, the Company intends to seek regulatory
approval to pass through benefits equal to amounts received from the BPA to its
residential and small farm customers.
       Electric revenues in 1998, 1997 and 1996 were reduced by $46.7 million,
$40.5 million and $41.0 million, respectively, as a result of the Company's sale
of revenues associated with $237.7 million of its investment in conservation
assets to a grantor trust. The revenue decrease represents the portion of rate
revenues that were sold and forwarded to the trust. The impact of this revenue
decrease, however, was offset by related reductions in other utility operations
and maintenance and interest expenses.
       To meet customer demand, the Company's power supply portfolio includes
net purchases of power under long-term supply contracts. However, depending
principally upon streamflow available for hydro-electric generation and weather
effects on customer demand, from time to time the Company may have surplus power
available for sale at wholesale to other utilities. In addition, the Company has
increased its wholesale surplus power business through short and
intermediate-term purchases, sales, arbitrage and other trading and marketing
techniques. Sales to other utilities increased $141.2 million, $66.0 million and
$15.1 million in 1998, 1997 and 1996, respectively, due primarily to increased
wholesale power transactions. Wholesale sales generally have small margins.
However, there may be certain times when the market price of power may cause
margins to fluctuate.

                                       28
<PAGE>

OPERATING REVENUES - GAS
       Regulated gas utility sales revenue in 1998 increased by $7.1 million
from the prior year on a 2.6% increase in gas volumes sold. Total gas volumes,
including transported gas, decreased 0.35% in 1998 from 1997. The increase in
sales revenue was primarily the result of a 4.4% increase in gas customers
during 1998, decreases in industrial and transportation sales volumes with lower
prices and margins and an increase in residential firm and commercial sales with
higher prices and margins. Utility gas margin (the difference between gas
revenues and gas purchases) increased by $10.6 million, or 4.6 %, in 1998 over
1997.
       Regulated gas utility sales revenue in 1997 increased by $9.3 million, or
2.3%, from the prior year on a 0.7% decrease in gas volumes sold. Total gas
volumes, including transported gas, increased 4.1% in 1997 from 1996. Regulated
gas utility sales revenue in 1996 decreased by $19.9 million, or 4.7%, from the
prior year on a 4.8% decrease in gas volumes sold. Total gas volumes, including
transported gas, increased 5.2% in 1996. Other revenues decreased $20.5 million
in 1998 compared to 1997 and $14.4 million in 1997 from 1996 due primarily to
the sale of an unregulated subsidiary (Washington Energy Services Company) in
October 1997.

OPERATING EXPENSES
       Purchased electricity expenses increased $137.2 million in 1998 when
compared to 1997 and $52.6 million in 1997 when compared to 1996. The increase
in 1998 was due primarily to a $112.3 million increase in secondary power
purchases from other utilities to support wholesale sales and increased payments
of $18.8 million for firm power purchases from non-utility generators. The
increase in 1997 was the result of increased secondary power purchases from
other utilities of $47.5 million and a $5.4 million increase in transmission
wheeling and associated costs compared to 1996. The increase of $38.8 million in
1996 over 1995 was the result of higher payments for firm power purchases from
non-utility generators and increased secondary power purchases from other
utilities.
       Residential exchange credits associated with the Residential Purchase and
Sale Agreement with BPA decreased $16.4 million in 1998 when compared to 1997.
The primary reason for the decrease was the Residential Exchange Termination
Agreement between the Company and BPA in January 1997. Residential exchange
credits decreased $31.2 million in 1997 as compared to 1996 and increased $15.1
million in 1996 as compared to 1995. Residential exchange credits received in
1998 were $55.6 million and are estimated to be $39.0 million, $41.0 million and
$27.0 million in the years 1999 through 2001. (See discussion of the Residential
Purchase and Sale Agreement under Operating Revenues.)
       Purchased gas expenses decreased $3.5 million in 1998 compared to 1997
despite the 2.6% increase in gas volumes sold. This was primarily the result of
a $5.4 million credit to purchased gas costs in the fourth quarter of 1998 due
to a true-up of gas costs through the PGA mechanism.
     Purchased gas expenses increased $1.6 million in 1997 compared to 1996 as a
result of a 0.7% increase in gas volumes sold.  Purchased gas expenses decreased
$41.3  million in 1996  compared to 1995.  The decrease  resulted from the lower
average  per-therm  cost  of gas  established  in the  May  1995  PGA and the 5%
reduction in gas volumes sold.
       Electric generation fuel expense increased $15.1 million in 1998
primarily due to the Company generating more electricity at Company-owned
gas-fired combustion turbine plants. These increases were partially offset by
reductions to Colstrip fuel expense. In September 1998, the Company recorded a
reduction of $4.9 million in fuel expense and $3.5 million of interest income
related to the resolution of outstanding issues with the Colstrip fuel supplier.
       Electric generation fuel expense increased $5.0 million in 1996 compared
to 1995. The increase was due in part to an arbitration panel's decision in 1995
of a dispute involving the coal supply agreement at the Company's 50%-owned
Colstrip 1 and 2 plants that resulted in a $4.6 million decrease to fuel expense
recorded in the first quarter of 1995. In addition, the Company recorded a
one-time charge of $1.8 million in the second quarter of 1996 relating to a loss
on the sale of oil stocks at a combustion turbine site.

                                       29
<PAGE>

       Utility operations and maintenance expenses decreased $13.6 million in
1998 compared to 1997. The decrease is primarily the result of improved
operating efficiencies.
       Utility operations and maintenance expenses increased $8.3 million in
1997 compared to 1996 and decreased $16.6 million in 1996 compared to 1995. The
changes were largely the result of an $11.6 million decrease in amortization
expense in 1995 associated with the Company's conservation program. In June
1995, the Company sold, to a grantor trust, approximately $202.5 million of its
investment in customer-owned energy conservation measures.
       Other operations and maintenance expenses decreased $13.6 million in 1998
compared to 1997 and $11.0 million in 1997 compared to 1996. The decreases
resulted primarily from the sale of the Company's unregulated subsidiary,
Washington Energy Services Company, in October 1997.
       Depreciation and amortization expense increased $3.7 million in 1998
compared to 1997. Depreciation and amortization expense due to capital spending
related to adding customers, distribution and transmission system improvements
and computer software amortization increased $12.3 million in 1998. Partially
offsetting these increases in 1998 were decreases from 1997 as a result of an
August 1997 Washington Commission Order which authorized the Company to record
interest income of $8.3 million related to a conservation tax refund, but
required the Company to expense deferred storm damage costs in the amount of
$7.4 million and establish a $1.0 million reserve to cover the costs of a
Company retail pilot program.
       Depreciation and amortization expense increased $17.6 million in 1997
compared to 1996 due primarily to capital spending related to adding customers
and transmission and distribution system improvements. In addition, the
aforementioned Washington Commission Order resulted in a write-off of deferred
storm damage costs in the amount of $7.4 million and the establishment of a $1.0
million reserve to cover the costs of a Company retail pilot program.
       Depreciation and amortization expense increased $3.2 million in 1996
compared to 1995 due primarily to new plant placed in service.
       Taxes other than federal income taxes increased $4.1 million in 1997
compared to 1996 and $6.3 million in 1996 compared to 1995. The increases were
primarily due to higher state property tax payments and higher revenue-based
municipal and state excise tax payments.
       Federal income taxes in 1997 were $60.2 million less than in 1998 and
$60.0 million less than in 1996 as a result of the following factors. An IRS tax
refund related to the method of accounting for taxes on conservation
expenditures during the first quarter of 1997 decreased federal income taxes by
$26.5 million. In addition, there was a $17.0 million reduction associated with
a decrease in PRAM revenues of $48.6 million. Merger costs expensed in the first
quarter of 1997 further reduced federal income taxes by $19.3 million.
       Federal income taxes increased by $16.2 million in 1996 over 1995. The
increase was primarily due to higher pre-tax utility earnings. Also, there was a
decrease in energy conservation expenditures in 1996 which are deducted for
federal income taxes.

OTHER INCOME
       Other income, net of federal income tax, decreased $18.9 million in 1998
from 1997. The decrease was due primarily to the receipt of interest income in
1997 of $13.6 million from the IRS on tax refunds for prior years in connection
with a plant abandonment loss, conservation tax refunds and certain additional
research and experimental credits claimed for tax purposes.
       Other income, net of federal income tax, increased $26.5 million in 1997
from 1996. The increase was due primarily to interest income received from the
IRS on tax refunds for prior years as explained in the preceding paragraph.
Other income for 1997 includes after-tax losses of $1.0 million and $5.3 million
related to the sale of an unregulated subsidiary (Washington Energy Services
Company) and operations of a subsidiary, ConneXt, respectively.
       Total other income increased $16.4 million in 1996 as compared to 1995.
The increase is due primarily to pre-tax charges in 1995 related to Cabot
totaling $24.8 million, partially offset by a $8.7 million deferred tax benefit
of write-downs.

                                       30
<PAGE>

INTEREST CHARGES
       Interest charges, which consist of interest and amortization on long-term
debt and other interest, increased $20.3 million in 1998 compared to 1997
primarily as a result of the issuance of $300 million 7.02% Senior Medium-Term
Notes, Series A, in December 1997, the issuance of $100 million 8.231% Capital
Trust Debentures in June 1997 and the issuance of $200 million 6.74% Senior
Medium-Term Notes, Series A, in June 1998. These increases were partially offset
by the maturity of $151 million Secured Medium-Term Notes during the 15 months
ended December 31, 1998 and the redemption of $30 million 9.14% Secured
Medium-Term Notes, Series A, in June 1998.
       Interest charges decreased $0.5 million in 1997 compared to 1996.
Interest and amortization on long-term debt increased $2.4 million which
included dividend payments on the Company-obligated, mandatorily redeemable
preferred securities of $4.7 million. Interest on short-term debt decreased $1.5
million and capitalized interest (AFUDC) increased $1.3 million.
       Interest charges decreased $8.3 million in 1996 compared to 1995.
Interest and amortization on long-term debt decreased $8.8 million. Contributing
to the reduced interest expense were five First Mortgage Bond retirements or
redemptions totaling $151 million over the previous 17 months. Other interest
expense increased in 1996 over 1995 due primarily to increased interest on PGA
balances.

CONSTRUCTION, CAPITAL RESOURCES AND LIQUIDITY
       Current construction expenditures, primarily transmission and
distribution-related, are designed to meet continuing customer growth.
Construction expenditures in 1998 and 1999 also include costs of new accounting
and customer information systems. Construction expenditures, which include
energy conservation expenditures and exclude AFUDC, were $333.3 million in 1998.
The Company expects construction expenditures for the period 1999 through 2001
will be approximately $303 million, $259 million and $252 million, respectively.
Construction expenditure estimates are subject to periodic review and
adjustment.
       The Company expects cash from operations (net of dividends and AFUDC)
during the period 1999 through 2001 will, on average, be approximately 68.4% of
average estimated construction expenditures (excluding AFUDC) during the same
period.
       In June 1998, the Company issued $200 million 6.74% Senior Medium-Term
Notes, Series A and redeemed $30 million 9.14% Secured Medium-Term Notes, Series
A, due June 2001 at a redemption price of 100%.
       In September 1998, the Company filed a shelf-registration statement with
the Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to $500 million principal amount of Senior Notes secured
by a pledge of First Mortgage Bonds. On March 9, 1999, the Company issued $250
million principal amount of Senior Medium-Term Notes, Series B, which consisted
of $150 million principal amount due March 9, 2009 at an interest rate of 6.46%
and $100 million principal amount due March 9, 2029 at an interest rate of 7.0%.
       The Company's ability to finance its future construction program is
dependent upon market conditions and maintaining a level of earnings sufficient
to permit the sale of additional securities. In determining the type and amount
of future financings, the Company may be limited by restrictions contained in
its electric and gas mortgage indentures, Articles of Incorporation and certain
loan agreements.
       Under the most restrictive tests, at December 31, 1998, the Company could
issue either (i) approximately $731 million of additional first mortgage bonds,
(ii) approximately $853 million of additional preferred stock at an assumed
dividend rate of 5.5%, or (iii) a combination thereof.
       Short-term borrowings from banks and the sale of commercial paper are
used to provide working capital for the construction program. At December 31,
1998, the Company had available $375 million in lines of credit with various
banks, which provide credit support for outstanding commercial paper and bank
borrowing of $142 million and $25 million, respectively, effectively reducing
the available borrowing capacity under these lines of credit to $208 million.
(See Note 9 to the Consolidated Financial Statements.)
       Under the most restrictive covenants in the Company's Articles of
Incorporation and electric and gas mortgage indentures, earnings reinvested in
the business unrestricted as to payment of cash dividends were approximately
$183 million at December 31, 1998.

                                       31
<PAGE>

RATE MATTERS - ELECTRIC

       The order approving the Merger, issued by the Washington Commission on
February 5, 1997, contains a rate plan designed to provide a five-year period of
rate certainty for customers and to provide the Company with an opportunity to
achieve a reasonable return on investment. General electric tariff rates were
stipulated to increase between 1.0% to 1.5% depending on rate class on January 1
of 1999 through 2001, while those for certain customers will increase by 1.5% in
2002.
       On September 22, 1995, the Washington Commission issued a rate order
relating to the Company's fifth annual rate adjustment under the PRAM. In
addition, on September 30, 1996, the Washington Commission issued an order
granting a joint motion by the Company and the Washington Commission Staff to
transfer annual revenues of $165.5 million which were being collected in PRAM
rates to the Company's permanent rate schedules. As a result of the order, the
Company also wrote off $4.5 million in previously accrued revenues related to
special industrial customer service contracts. PRAM accrued revenues of $40.5
million, recorded at December 31, 1996, were recovered in the first quarter of
1997. Over-collection of PRAM revenues were refunded to customers in the second
quarter of 1997.
       With the discontinuance of the PRAM, the Company no longer has a rate
adjustment mechanism to adjust for changes in energy or fuel costs or variances
in hydro and weather conditions. These variances may now significantly influence
earnings.
       On July 8, 1998, the Washington Commission approved the Company's
requested accounting treatment for its program to reduce costly tree-caused
power outages. The Tree Watch program, which focuses on controlling vegetation
outside the Company's rights-of-way, should improve service reliability for its
customers and result in future savings in outage recovery costs. The five-year,
$43 million program will be treated as an investment that will be amortized over
ten years. The Company expects the Tree Watch investment to be offset by savings
from lower outage restoration and storm damage costs over the same period.

RATE MATTERS - GAS

       The order approving the Merger, issued by the Washington Commission on
February 5, 1997, contains a rate plan which provided unchanged rates for all
classes of natural gas customers until January 1, 1999, when rates decreased by
1% on gas utility margins. See Note 1 to the Consolidated Financial Statements
for a description of the Company's PGA mechanism.

YEAR 2000 CONVERSION

BACKGROUND
     The Year 2000  issue  result  from the use of two digits  rather  than four
digits in computer  hardware and software to define the applicable  year. If not
corrected  on computer  systems  that must  process  dates both before and after
January 1, 2000,  two-digit year fields may create  processing  errors or system
failures.  The  Company  expects  to be Year 2000  ready  which  means  that all
mission-critical systems, devices,  applications and business relationships have
been evaluated and are suitable for continued use into and beyond the Year 2000,
or contingency plans are in place.

PROJECT APPROACH AND PROGRESS
     The Company has  established a central  project team to coordinate all Year
2000  activities  and  identified  exposure  in  three  categories:  information
technology;  embedded chip technology;  and external non-compliance by customers
and  suppliers.  The project team is taking a phased  approach in conducting the
Year 2000  project  for its  internal  systems.  The phases  include  inventory,
assessment,  planning/prioritizing,  remediation,  testing,  implementation  and
contingency planning.  In addition,  the Company has engaged outside consultants
and  technicians to aid in formulating and  implementing  its plan. All business
units  have  completed  the  inventory  phase,  and  with the  exception  of the
Company's customer information system ("CIS") discussed below, assessment is 95%
complete for all business units,  with remediation,  testing and  implementation
scheduled to be completed during the second quarter of 1999.

                                       32
<PAGE>

     The Company has been  upgrading  mainframe and client server  financial and
business  applications  since 1997 and replacing many of its business systems as
part of its business plans  following its merger in 1997. In September 1998, the
Company implemented a Systems, Applications, Products in Data Processing ("SAP")
business  system  which  includes  essentially  all  of the  Company's  business
applications  with the  exception  of its  CIS.  This SAP  system  is Year  2000
compliant.  The remainder of applications and operating  environments  excluding
the CIS are in the  remediation/testing  phase.  Full  implementation  of  those
applications and components of the Company's  internal systems are scheduled for
completion by mid-year 1999.
     A new CIS, which is designed to be Year 2000 compliant,  is currently being
developed by the Company.  Development  is expected to be completed in 1999. The
Company has also begun  implementation  actiities with respect to the new system
which will  continue  during  1999.  The Company has also  elected to  remediate
critical  elements of its existing CIS for Year 2000  compliance  purposes.  The
Company has formed a specialized  team which has  completed the inventory  phase
and is  currently  conducting  assessment  and  remediation  activities  for the
existing  system.  The Company expects to complete the assessment  phase of this
project early in May of 1999 followed  immediately  by  remediation  and testing
activities which are expected to be completed in the third quarter of 1999.
     A  specialized  embedded  systems  team has been  formed by the  Company to
inventory,  assess and remediate  microprocessor  technology in its  generation,
transmission and distribution systems for both gas and electric operations.  The
inventory  and  assessment  phases of the project are  complete.  Although  some
remediation  planning is still in process,  significant  remediation efforts are
underway and proceeding  according to schedule.  Testing and  implementation are
scheduled to be completed by the end of the second quarter of 1999.  Contingency
planning  specific to the Year 2000 issue began in  November  1998,  and initial
reports  were  submitted to the  Washington  Commission  and the North  American
Electric  Reliability Council ("NERC").  These plans will be refined and updated
as remediation and test results are analyzed, and are scheduled for finalization
in the third quarter of 1999.
       The Company is also communicating with suppliers, financial institutions
and other business partners to coordinate Year 2000 conversion and determine the
extent to which the Company is exposed to third party compliance failures.
Approximately 85% of vendors and suppliers have been contacted to date. All
third party assessment is scheduled to be completed in March 1999.
       In addition, the Company is working with various industry groups
including the NERC and the regional reliability council, the Western Systems
Coordinating Council ("WSCC") during the millennium transition. The United
States Department of Energy has asked NERC to assume a leadership role in
preparing the U.S. electric industry for the transition to the Year 2000.

COSTS
       While the replacement of business systems under business plans developed
as a result of the Merger are not included in the Company's Year 2000 project,
those replacements substantially reduce the number of internal business
applications that require remediation. In addition to the costs of replacing new
business systems, the Company has expended approximately $3.6 million through
December 31, 1998, on Year 2000 remediation efforts, exclusive of internal labor
costs. Although it is difficult to determine the total remaining costs of
implementing the Year 2000 plan, the Company's current estimate is approximately
$14 million, of which approximately $3 million will be capitalized.

RISK ASSESSMENT
       The electric power supply systems of North America are connected into
three major interconnections called grids. The western grid covers the western
third of the U.S., western Canada and parts of Mexico. The BPA is the largest
supplier of transmission services in the Pacific Northwest. Operational
component failures of any entity connected to the grid could cause other
failures in that grid. The Company will need to continue to assess this risk as
the millennium approaches to evaluate the likelihood of power failures and
develop approaches for mitigating the risk of failures.
     Much of the natural gas and electric  distribution systems are comprised of
wires, poles and pipes containing no embedded chips.  However,  these systems do
employ  some  computer  components  that  could be  affected  by the  Year  2000
transition.  Since many of the components  used by the Company exist in multiple
sub-station  locations,  there is a risk that a  component  could be  missed,  a
component  manufacturer  could provide erroneous  information,  or the component
(while deemed and tested compliant) could fail in a specific configuration found
at the Company. The Company has formed a special  team to handle these types of
components (embedded systems), and has retained an independent  engineering firm
with specific utility experience to assist in the effort.  Results of assessment
to date reveal that there are fewer components that are not Year 2000 ready than
initially  thought.  This is consistent with industry findings  published in the
NERC report to the Department of Energy dated January 11, 1999.

                                       33
<PAGE>

       The failure to correct a material Year 2000 problem could result in an
interruption in, or a failure of, Company business activities or operations.
Such failures could materially and adversely affect the Company's results of
operations, liquidity and financial condition. Due to the general uncertainty
inherent in the Year 2000 problem, resulting in part from the uncertainty of the
Year 2000 readiness of third-party suppliers and customers, the Company is
unable to determine at this time whether the consequences of Year 2000 failures
will have a material impact on the Company's results of operations, liquidity or
financial condition. The Year 2000 project is expected to significantly reduce
the Company's level of uncertainty about the Year 2000 problem and the Year 2000
readiness of its material vendors. The Company believes that, with the
implementation of new business systems and completion of the project as
scheduled, the possibility of significant interruptions of normal operations
should be reduced.
     As discussed above, elements of the Company's current CIS are not Year 2000
compliant.  If the current CIS remediation  activities are not successful by the
year 2000,  certain  normal  business  activities  such as customer  billing and
collections could be adversely affected by interruptions.

CONTINGENCY PLANS
       The Company is identifying various scenarios that could occur in the
event that Year 2000 issues are not resolved in a timely manner. These efforts
will build upon the work in scenario development and contingency planning that
is being done by the WSCC contingency planning task force. A specialized team is
being formed that will develop contingency plans and update existing emergency
preparedness plans to identify and address risk scenarios for the Company.
Contingency planning is scheduled to continue through the third quarter of 1999.

FORWARD LOOKING STATEMENTS
       Readers are cautioned that forward-looking statements contained in the
Year 2000 update are based on management's best estimates and may be influenced
by factors that could cause actual outcomes and results to be materially
different than projected. Specific factors that might cause differences between
the estimates and actual results include, but are not limited to, the
availability and cost of personnel trained in these areas, the ability to locate
and correct all relevant computer code, timely responses to and corrections by
third-parties and suppliers, the ability to implement new systems in a timely
manner, the ability to implement interfaces between the new systems and the
systems not being replaced, and similar uncertainties. Due to the general
uncertainty inherent in the Year 2000 problem, resulting in part from the
uncertainty of the Year 2000 readiness of third-parties and the interconnection
of global businesses, the Company cannot ensure its ability to timely and
cost-effectively resolve problems associated with Year 2000 issues that may
affect its operations and business, or expose it to third-party liability.

INDUSTRY OVERVIEW
       The electric and gas industries in the United States are undergoing
significant changes. The focus of these changes is to promote competition among
suppliers of electricity and gas and associated services. In 1996 and 1997, the
Federal Energy Regulatory Commission ("FERC") issued orders that require
utilities, including the Company, to file open access transmission tariffs that
will make the utilities' electric transmission systems available to wholesale
sellers and buyers on a non-discriminatory basis. A number of states, including
California, have restructured their electric industries to separate or
"unbundle" power generation, transmission and distribution in order to permit
new competitors to enter the marketplace. In part because electric rates in the
Pacific Northwest have been among the lowest in the nation, certain of the
legislatures in this region, including Washington, have not yet enacted laws to
provide for competition at the retail level. The Washington Commission has
initiated a pilot program, in which the Company participates, that permits
consumers limited direct access to competitive energy suppliers. The Company is
actively monitoring developments in this area and has indicated its support for
the enactment of legislation that would provide increased choice for electric
service customers in the State of Washington.

                                       34
<PAGE>

       In order to better position itself to respond to customer needs and
future restructuring of the utility industry, and in anticipation of a
competitive environment for electric energy sales, the Company in 1997 organized
its utility operations into separate business units: energy delivery; energy
supply; and customer solutions
       The Company has an Optional Large Power Sales Rate and certain "special
contracts" for its largest customers. Customers who elect the Optional Large
Power Sales Rate are no longer considered "core" customers, and the Company no
longer has an obligation to plan for future resources to serve their needs. The
non-core customers receive access to electric energy that is priced at current
market cost and pay a charge for energy delivery (including a charge for
conservation programs) and a transition charge (representing the difference
between the Company's present cost and the current market cost of electric
energy and capacity). The transition charge will be phased out before the end of
the year 2000. Non-core customers also take on the risk that market costs could
become volatile and that electricity could be unavailable on the open market. In
November 1998, a number of industrial customers filed a complaint with the
Washington Commission that the Company was incorrectly billing for energy under
the Optional Large Power Sales Rate. If the Washington Commission finds that the
Company used an incorrect index, the Company would owe approximately $2.6
million in refunds. However, management believes the proper index has been used
and expects the Company will prevail on this issue.
       Since 1986 the Company has been offering gas transportation as a separate
service to industrial and commercial customers who choose to purchase their gas
supply directly from producers and gas marketers. The continued evolution of the
natural gas industry, resulting primarily from FERC Orders 436, 500 and 636, has
served to increase the ability of large gas end-users to bypass the Company in
obtaining gas supply and transportation services. Though the Company has not
lost any substantial industrial or commercial load as a result of such bypass,
in certain years up to 160 customers annually have taken advantage of unbundled
transportation service. During 1998, an average of 123 commercial and industrial
customers chose to use such service.

OTHER
       On March 20, 1991, the Company executed a 20-year contract to purchase
216 average MW of energy and 245 MW of capacity, beginning in April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas fired
cogeneration project located near Ferndale, Washington. In December 1997 and
January 1998, the Company and Tenaska Washington Partners entered into revised
agreements which will lower purchased power costs from the Tenaska project by
restructuring its natural gas supply. The Company paid $215 million to buy out
the project's existing long-term gas supply contracts, which contained fixed and
escalating gas prices that were well above current and projected future market
prices for natural gas. The Company became the principal natural gas supplier to
the project and power purchase prices under the Tenaska contract were revised to
reflect market-based prices for the natural gas supply. The Company obtained an
order from the Washington Commission creating a regulatory asset related to the
$215 million restructuring payment. Under terms of the order, the Company is
allowed to accrue as an additional regulatory asset one-half the carrying costs
of the deferred balance over the first five years. These revised arrangements
are expected to reduce the Company's power supply costs from the Tenaska project
between 15 and 20 percent annually over the remaining 14 year life of the
contract, net of the costs of the restructuring payment. The Company's purchased
electric energy cost associated with the Tenaska contract was $80.1 million in
1998.
     On April 1,  1998,  the  Company  and Duke  Energy  Trading  and  Marketing
("DETM") of Houston,  a unit of Duke Energy Corp.,  signed an agreement relating
to  energy-marketing  and trading  activities  in 14 western  States and British
Columbia.  The purpose of this  agreement is to  coordinate  the two  companies'
activities in serving Puget Sound Energy's native power load with DETM's Western
power and natural gas marketing and trading operations.  The companies share the
benefits of this coordination  proportionally up to certain  stipulated  amounts
intended to be reflective  of the value the  companies  would have realized from
their respective operations in the absence of the agreement. The companies share
equally any benefits created above the stipulated amounts.

                                       35
<PAGE>

       Under the terms of the agreement, DETM performs the forward electric
energy trading function. As a result, the Company's future wholesale "sales to
other utilities" revenues and related "secondary purchase" power expenses, which
previously have reflected trading activity by the Company, will be lower than
amounts which the Company would report absent this agreement. During 1998 the
Company continued to execute in its own name transactions in which electric
energy is delivered within the next 30 days. Therefore, the Company's results
include those transactions. The Company recorded its share of the benefits that
resulted from the agreement as a credit to Purchased Power Expense. The
agreement provides that forward trading activities will be conducted according
to DETM's energy price risk and credit policies, and that the Company is not
responsible for any losses caused by deviation from these policies. The Company
and DETM are presently considering modifications to the agreement.
       On November 2, 1998, the Company announced it signed an agreement to sell
the Company's 735-megawatt interest in the four-unit, coal-fired Colstrip
generation plant in eastern Montana, as well as associated transmission
facilities. The Company signed the agreement with PP&L Global, Inc., of Fairfax,
Virginia, a subsidiary of PP&L Resources, Inc. Included in the sale are the
Company's 50% interest in Colstrip Units 1 and 2; 25% interest in Units 3 and 4;
and associated Colstrip transmission capacity across Montana. The sales price is
expected to be $549 million before taxes and expenses. The net book value of
these assets and related regulatory assets is approximately $464 million. After
consideration of taxes and other costs, the gain on the sale is expected to be
approximately $37.6 million. The Company expects the Colstrip sale to close in
the second half of 1999. Completion of the sale is contingent on receipt of
acceptable regulatory treatment from the Washington Commission and the FERC.
     The Company has also agreed to join with the other owners of the coal-fired
generating plant at Centralia,  Washington, by offering for sale its 92 megawatt
ownership interest in the facility.  As part of the sale process,  the Centralia
owners are  reviewing the projected  reclamation  liability  related to the coal
mining operations.
       In the fourth quarter of 1998, the Company incurred $4.7 million of
transmission and distribution repair costs in connection with restoring electric
service following a severe wind storm that occurred on November 23, 1998. Under
an order established by the Washington Commission, these costs were deferred for
collection in future rates.
     For a discussion  of Issue 98-10,  "Accounting  For  Contracts  Involved in
Energy Trading and Risk  Management  Activities"  issued by the Emerging  Issues
Task force of the Financial  Accounting  Standards  Board  ("FASB") in 1998, see
Note 1 to the Consolidated Financial Statements.
       For a discussion of Statement of Position 98-5, "Reporting on the Costs
of Start-up Activities" ("SOP 98-5") issued by the Accounting Standards
Executive Committee in April 1998, see Note 1 to the Consolidated Financial
Statements.
     For a discussion  of Statement of Financial  Accounting  Standards No. 133,
"Accounting for Derivative  Instruments and Hedging Activities"  ("Statement No.
133") issued by the FASB in June 1998, see Note 1 to the Consolidated  Financial
Statements.

MARKET RISKS
       The Company is exposed to market risks, including changes in commodity
prices and interest rates.

COMMODITY PRICE RISK
       The prices of energy commodities and transportation services are subject
to fluctuations due to unpredictable factors including weather, transportation
congestion and other factors which impact supply and demand. This commodity
price risk is a consequence of purchasing energy at fixed and variable prices
and providing deliveries at different tariff and variable prices. Costs
associated with ownership and operation of production facilities are another
component of this risk. The Company may use forward delivery agreements and
option contracts for the purpose of hedging commodity price risk. Unrealized
changes in the market value of these derivatives are deferred and recognized
upon settlement along with the underlying hedged transaction. In addition, the
Company believes its current rate design, including its Optional Large Power
Sales Rate, various special contracts and the PGA mechanism mitigate a portion
of this risk.

                                       36
<PAGE>

       Four option contracts entered into directly by the Company were
outstanding at December 31, 1998, and had a market value at that date which
approximated the option premiums paid by the Company.
       Operating results are also influenced by the impact of market prices on
the value of physical and derivative commodity contracts entered into by DETM as
part of their agreement with the Company. Changes in the market value of all of
these derivatives are recorded on a mark-to-market basis into income by DETM and
can affect the Company's revenues from the DETM agreement.
       DETM measures the market risk of physical and financial contracts entered
into under the DETM Agreement using a value at risk model. The Company's
proportionate share of the value at risk at December 31, 1998 was not material.
       Market risk is managed subject to parameters established by the Board of
Directors. A Risk Management Committee separate from the units that create these
risks monitors compliance with the Company's policies and procedures. In
addition, the Audit Committee of the Company's Board of Directors has oversight
of the Risk Management Committee.

INTEREST RATE RISK
       The Company believes interest rate risks of the Company primarily relate
to the use of short-term debt instruments and new long-term debt financing
needed to fund capital requirements. The Company manages its interest rate risk
through the issuance of mostly fixed-rate debt of various maturities. The
Company does utilize bank borrowings, commercial paper and line of credit
facilities to meet short-term cash requirements. These short-term obligations
are commonly refinanced with fixed rate bonds or notes when needed and when
interest rates are considered favorable. The Company may enter into swap
instruments to manage the interest rate risk associated with these debts, and
one interest rate swap was outstanding as of December 31, 1998. The carrying
amounts and fair values of the Company's fixed rate debt instruments are
described in Note 10 to the Consolidated Financial Statements.

                                       37
<PAGE>

         ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

       See index on page 44.

         ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING 
                  AND FINANCIAL DISCLOSURE

       None.


         PART III

       Part III is incorporated by reference from the Company's definitive proxy
statement issued in connection with the 1999 Annual Meeting of Shareholders.

       Certain information regarding executive officers is set forth in Part I.


         PART IV

         ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K

       (a)        Documents filed as part of this report:

         1)       Financial statement schedule - see index on page 44.

         2)       Exhibits - see index on page 80.

       (b)        Reports on Form 8-K:

         1) Form 8-K filed November 13, 1998 - Item 5 - Other Events, and Item 7
- Exhibits, related to an Asset Purchase Agreement for the sale of the Company's
interest in the Colstrip coal-fired generating plant.

                                       38
<PAGE>

         SIGNATURES

       Pursuant to the requirements of Section 13 of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.

                                           PUGET SOUND ENERGY, INC.

                                           /s/ William S. Weaver
                                           -------------------------------------
                                           William S. Weaver
                                           President and Chief Executive Officer

                                           Date:      March 4, 1999             

       Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.


  SIGNATURE                     TITLE                       DATE
---------------------------- ---------------------------- -------------------


  /s/  William S. Weaver       President, Chief Executive    March 4, 1999
----------------------------                              -------------------
  (William S. Weaver)          Officer and Director


  /s/  R. R. Sonstelie         Chairman of the Board
----------------------------
  (R. R. Sonstelie)


  /s/  James W. Eldredge       Corporate Secretary
----------------------------
  (James W. Eldredge)          and Controller and
                               Chief Accounting Officer


  /s/  Douglas P. Beighle      Director
----------------------------
  (Douglas P. Beighle)


  /s/  Charles W. Bingham      Director
----------------------------
  (Charles W. Bingham)


  /s/  Phyllis J. Campbell     Director
----------------------------
  (Phyllis J. Campbell)

                                       39
<PAGE>


  SIGNATURE                    TITLE                        DATE
---------------------------- ---------------------------- -------------------


  /s/  Donald J. Covey         Director
----------------------------
  (Donald J. Covey)


  /s/  Robert L. Dryden        Director
----------------------------
  (Robert L. Dryden)


  /s/  John D. Durbin          Director
----------------------------
  (John D. Durbin)


                               Director
----------------------------
  (John W. Ellis)


  /s/  Daniel J. Evans         Director
----------------------------
  (Daniel J. Evans)


  /s/  Tomio Moriguchi         Director
----------------------------
  (Tomio Moriguchi)


  /s/  Sally G. Narodick       Director
----------------------------
  (Sally G. Narodick)

                                       40
<PAGE>

         REPORT OF MANAGEMENT
         PUGET SOUND ENERGY, INC.

       The accompanying consolidated financial statements of Puget Sound Energy,
Inc. have been prepared under the direction of management, which is responsible
for their integrity and objectivity. The statements have been prepared in
accordance with generally accepted accounting principles and include amounts
based on judgments and estimates by management where necessary. Management also
prepared the other information in the Annual Report on Form 10-K and is
responsible for its accuracy and consistency with the financial statements.
       The Company maintains a system of internal control which, in management's
opinion, provides reasonable assurance that assets are properly safeguarded and
transactions are executed in accordance with management's authorization and
properly recorded to produce reliable financial records and reports. The system
of internal control provides for appropriate division of responsibility and is
documented by written policy and updated as necessary. The Company's internal
audit staff assesses the effectiveness and adequacy of the internal controls on
a regular basis and recommends improvements when appropriate. Management
considers the internal auditor's and independent auditor's recommendations
concerning the Company's internal controls and takes steps to implement those
that they believe are appropriate in the circumstances.
       In addition, PricewaterhouseCoopers LLP, the independent auditors, have
performed audit procedures deemed appropriate to obtain reasonable assurance
about whether the financial statements are free of material misstatement.
       The Board of Directors pursues its oversight role for the financial
statements through the audit committee, which is composed solely of outside
Directors. The audit committee meets regularly with management, the internal
auditors and the independent auditors, jointly and separately, to review
management's process of implementation and maintenance of internal accounting
controls and auditing and financial reporting matters. The internal and
independent auditors have unrestricted access to the audit committee.




/s/ William S. Weaver   /s/ Richard L. Hawley      /s/ James W. Eldredge
----------------------  -------------------------  -----------------------------
William S. Weaver       Richard L. Hawley          James W. Eldredge
President and Chief     Vice President and Chief   Corporate Secretary and 
Executive Officer       Financial Officer          Controller
                                                   (Chief Accounting Officer)

                                       41
<PAGE>

         REPORT OF INDEPENDENT ACCOUNTANTS 
To the Shareholders of Puget Sound Energy, Inc.

       In our opinion, based upon our audits and the report of other auditors,
the consolidated financial statements listed on page 44 of this Annual Report on
Form 10-K present fairly, in all material respects, the financial position of
Puget Sound Energy, Inc. and its subsidiaries (the "Company") at December 31,
1998 and 1997, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule listed on page 44 of this document presents fairly,
in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and the financial statement schedule are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements and the financial statement schedule based on our audits.
The consolidated financial statements give retroactive effect to the February
10, 1997 merger of Washington Energy Company ("WECo") and its principal
subsidiary, Washington Natural Gas ("WNG"), in a transaction accounted for as a
pooling of interests which is discussed in Note 1 to the consolidated financial
statements. We did not audit the consolidated financial statements and the
financial statement schedule of WECo and its principal subsidiary, WNG, which
statements reflect total revenues of $426 million for the year ended December
31, 1996. Those financial statements and the financial statement schedule were
audited by other auditors whose report thereon has been furnished to us, and our
opinion expressed herein, insofar as it relates to the amounts included in the
year ended December 31, 1996 for WECo and WNG, is based solely on the report of
the other auditors. We conducted our audits of these financial statements in
accordance with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits and the report of other auditors provide a reasonable
basis for the opinion expressed above.


                                                      PricewaterhouseCoopers LLP

                                                      Seattle, Washington
                                                      February 11, 1999

                                       42
<PAGE>

         REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS 
To the Board of Directors of Washington Energy Company:

       We have audited the consolidated statements of income, shareholders'
earnings (deficit) reinvested in the business, premium on common stock and cash
flows of Washington Energy Company (a Washington corporation) and subsidiaries
for the year ended September 30, 1996, and the consolidated statements of
income, shareholders' earnings reinvested in the business, premium on common
stock and cash flows of Washington Natural Gas Company (a Washington
corporation) and subsidiaries for the year ended September 30, 1996. These
financial statements, which are not included in this Form 10-K, are the
responsibility of the companies' management. Our responsibility is to express an
opinion on these financial statements based on our audits.
       We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
       On February 10, 1997, Washington Energy Company and its principal
subsidiary Washington Natural Gas Company, in a transaction accounted for as a
pooling-of-interests, merged with Puget Sound Power and Light to form Puget
Sound Energy.
       In our opinion, the financial statements referred to above present
fairly, in all material respects, the results of operations of Washington Energy
Company and subsidiaries and of Washington Natural Gas Company and subsidiaries
and their cash flows for the year ended September 30, 1996, in conformity with
generally accepted accounting principles.



                                 ARTHUR ANDERSEN LLP

                                 Seattle, Washington,
                                 October 31, 1996 (except with respect to the
                                 matter discussed in the third paragraph above,
                                 for which the date is February 10, 1997)

                                       43
<PAGE>

Consolidated  Financial  Statements,  Financial Statement Schedule and Exhibits
Covered by the Foregoing Report of Independent Accountants

         CONSOLIDATED FINANCIAL STATEMENTS:                                PAGE

         Consolidated Statements of Income for the years ended December 31, 
         1998, 1997 and 1996                                                 45

         Consolidated Balance Sheets, December 31, 1998 and 1997          46-47

         Consolidated Statements of Capitalization, December 31, 1998 
         and 1997                                                            48

         Consolidated Statements of Earnings Reinvested in the Business
           for the years ended December 31, 1998, 1997 and 1996              49

         Consolidated Statements of Comprehensive Income for the years
           ended December 31, 1998, 1997 and 1996                            49

         Consolidated Statements of Cash Flows for the years
           ended December 31, 1998, 1997 and 1996                            50

         Notes to Consolidated Financial Statements                          51


         Schedule:

         II.  Valuation and Qualifying Accounts and Reserves for the
              years ended December 31, 1998, 1997 and 1996

         All other schedules have been omitted because of the absence of the
         conditions under which they are required, or because the information
         required is included in the financial statements or the notes thereto.

         Financial statements of the Company's subsidiaries are not filed
         herewith inasmuch as the assets, revenues, earnings and earnings
         reinvested in the business of the subsidiaries are not material in
         relation to those of the Company.


         Exhibits:

         Exhibit Index                                                       80

                                       44
<PAGE>
<TABLE>

Consolidated Statements of
         INCOME
<CAPTION>

   (FOR YEARS ENDED DECEMBER 31; DOLLARS IN THOUSANDS, 
   EXCEPT PER SHARE AMOUNTS)                                      1998             1997            1996
 ------------------------------------------------------ ---------------- ---------------- ---------------
 <S>                                                    <C>              <C>              <C>    
  Operating Revenues:
  Electric                                                  $1,475,208       $1,231,424      $1,198,769
  Gas                                                          416,551          409,447         400,108
  Other                                                         15,581           36,031          50,402
------------------------------------------------------ ---------------- ---------------- ---------------
       Total operating revenues                              1,907,340        1,676,902       1,649,279
------------------------------------------------------ ---------------- ---------------- ---------------
  Operating Expenses:
  Energy costs:
    Purchased electricity                                      752,148          614,929         562,314
    Residential Exchange                                       (55,562)         (71,970)       (103,154)
    Purchased gas                                              175,805          179,287         177,719
  Fuel                                                          56,557           41,455          40,645
  Utility operations and maintenance                           237,835          251,390         243,085
  Other operations and maintenance                               7,614           21,256          32,234
  Depreciation, depletion and amortization                     165,587          161,865         144,206
  Merger and related costs                                          --           55,789           4,835
  Taxes other than federal income taxes                        160,472          159,310         155,174
  Federal income taxes                                         107,904           47,725         107,747
------------------------------------------------------ ---------------- ---------------- ---------------
       Total operating expenses                              1,608,360        1,461,036       1,364,805
------------------------------------------------------ ---------------- ---------------- ---------------
  Operating Income                                             298,980          215,866         284,474
------------------------------------------------------ ---------------- ---------------- ---------------
  Other Income                                                   9,192           28,066           1,593
------------------------------------------------------ ---------------- ---------------- ---------------
  Income Before Interest Charges                               308,172          243,932         286,067
------------------------------------------------------ ---------------- ---------------- ---------------
  Interest Charges:
  AFUDC                                                        (7,580)           (5,205)         (3,919)
  Interest expense                                             146,140          123,439         122,635
------------------------------------------------------ ---------------- ---------------- ---------------
       Total interest charges                                  138,560          118,234         118,716
------------------------------------------------------ ---------------- ---------------- ---------------
  Income from Continuing Operations                            169,612          125,698         167,351
  Discontinued Operations:                                                                
    Loss from operations, net of tax                                --               --          (1,386)
    Loss on disposal, net of tax                                    --           (2,622)           (446)
------------------------------------------------------ ---------------- ---------------- ---------------
  Net Income                                                   169,612          123,076         165,519
------------------------------------------------------ ---------------- ---------------- ---------------
  Less Preferred Stock Dividends Accrual                        13,003           17,806          22,181
  Preferred Stock Redemptions                                       --              471              --
------------------------------------------------------ ---------------- ---------------- ---------------
  Income for Common Stock                                     $156,609         $105,741        $143,338
------------------------------------------------------ ---------------- ---------------- ---------------
  Common Shares Outstanding Weighted Average                    84,561           84,560          84,418
------------------------------------------------------ ---------------- ---------------- ---------------
  Basic and Diluted Earnings (Loss) Per Common Share:
     From continuing operations                                  $1.85            $1.28           $1.72
     From discontinued operations                                   --            (0.03)          (0.02)
------------------------------------------------------ ---------------- ---------------- ---------------
       Basic and diluted earnings per common share               $1.85            $1.25           $1.70
------------------------------------------------------ ---------------- ---------------- ---------------
</TABLE>

The accompanying notes are an integral part of the consolidated financial
statements.

                                       45
<PAGE>

Consolidated Balance Sheets
         ASSETS
<TABLE>
<CAPTION>


   (AT DECEMBER 31; DOLLARS IN THOUSANDS)                          1998              1997
----------------------------------------------------- ------------------ -----------------
<S>                                                   <C>                <C>   
  Utility Plant:
    Electric plant                                           $3,827,685        $3,632,652
    Gas plant                                                 1,324,323         1,231,109
    Less: Accumulated depreciation and amortization           1,721,096         1,613,300
----------------------------------------------------- ------------------ -----------------
  Net utility plant                                           3,430,912         3,250,461
----------------------------------------------------- ------------------ -----------------
  Other Property and Investments:
    Investment in Bonneville Exchange Power Contract             70,537            78,880
    Other                                                       192,863           200,764
----------------------------------------------------- ------------------ -----------------
  Total other property and investments                          263,400           279,644
----------------------------------------------------- ------------------ -----------------
  Current Assets:
    Cash                                                         25,278             7,759
----------------------------------------------------- ------------------ -----------------
    Accounts receivable                                         201,980           158,927
    Less:  Allowance for doubtful accounts                       (1,021)             (971)
----------------------------------------------------- ------------------ -----------------
  Total accounts receivable                                     200,959           157,956
----------------------------------------------------- ------------------ -----------------
    Unbilled revenues                                           126,740           122,831
    Purchased gas receivable                                      5,492                --
    Materials and supplies, at average cost                      58,534            54,423
    Prepayments and other                                         7,296             5,420
----------------------------------------------------- ------------------ -----------------
  Total current assets                                          424,299           348,389
----------------------------------------------------- ------------------ -----------------
  Long-Term Assets:
    Regulatory asset for deferred income taxes                  241,406           258,430
    PURPA buyout costs                                          221,802           215,000
    Other                                                       138,870           141,446
----------------------------------------------------- ------------------ -----------------
  Total long-term assets                                        602,078           614,876
===================================================== ================== =================
  Total Assets                                               $4,720,689        $4,493,370
===================================================== ================== =================
</TABLE>

The accompanying notes are an integral part of the consolidated financial
statements.

                                       46
<PAGE>
<TABLE>

Consolidated Balance Sheets
         CAPITALIZATION AND LIABILITIES

<CAPTION>

   (AT DECEMBER 31; DOLLARS IN THOUSANDS)                                   1998           1997
------------------------------------------------------------------ -------------- --------------
<S>                                                                <C>            <C>   
  Capitalization:
  (See "Consolidated Statements of Capitalization"):
     Common equity                                                    $1,352,680     $1,358,077
     Preferred stock not subject to mandatory redemption                  95,075         95,488
     Preferred stock subject to mandatory redemption                      73,162         78,134
     Corporation obligated, mandatorily redeemable preferred
       securities of subsidiary trust holding solely junior
       subordinated debentures of the corporation                        100,000        100,000
     Long-term debt                                                    1,474,748      1,411,707
------------------------------------------------------------------ -------------- --------------
       Total capitalization                                            3,095,665      3,043,406
------------------------------------------------------------------ -------------- --------------
  Current Liabilities:
     Accounts payable                                                    167,691        124,899
     Short-term debt                                                     450,905        372,538
     Current maturities of long-term debt                                107,000         51,000
     Purchased gas liability                                                  --            876
     Accrued expenses:
       Taxes                                                              72,883         73,636
       Salaries and wages                                                 16,053         15,326
       Interest                                                           39,062         27,704
     Other                                                                23,008         24,847
------------------------------------------------------------------ -------------- --------------
       Total current liabilities                                         876,602        690,826
------------------------------------------------------------------ -------------- --------------
  Deferred Income Taxes                                                  628,554        629,018
------------------------------------------------------------------ -------------- --------------
  Other Deferred Credits                                                 119,868        130,120
------------------------------------------------------------------ -------------- --------------
  Commitments and Contingencies                                               --             --
================================================================== ============== ==============
  Total Capitalization and Liabilities                                $4,720,689     $4,493,370
================================================================== ============== ==============
</TABLE>

The accompanying notes are an integral part of the consolidated financial
statements.

                                       47
<PAGE>
<TABLE>

Consolidated Statements of
         CAPITALIZATION
<CAPTION>

  (AT DECEMBER 31; DOLLARS IN THOUSANDS)                                                 1998           1997
------------------------------------------------------------------------------- -------------- --------------
<S>                                                                             <C>            <C>  
  Common Equity:
    Common stock ($10 stated value) - 150,000,000 shares
      authorized, 84,560,561 and 84,560,645 shares outstanding                       $845,606       $845,606
    Additional paid-in capital                                                        450,724        450,845
    Earnings reinvested in the business                                                47,548         46,672
    Accumulated other comprehensive income - net                                        8,802         14,954
------------------------------------------------------------------------------- -------------- --------------
       Total common equity                                                          1,352,680      1,358,077
------------------------------------------------------------------------------- -------------- --------------
  Preferred Stock Not Subject to Mandatory Redemption - cumulative - $25 par
    value: (a) Adjustable Rate, Series B - 2,000,000 shares
        authorized, 203,006 and 219,506 shares outstanding                              5,075          5,488
    7.45% series II - 2,400,000 shares authorized and outstanding                      60,000         60,000
    8.50% series III - 1,200,000 shares authorized
        and outstanding                                                                30,000         30,000
------------------------------------------------------------------------------- -------------- --------------
       Total preferred stock not subject to mandatory redemption                       95,075         95,488
------------------------------------------------------------------------------- -------------- --------------
  Preferred Stock Subject To Mandatory Redemption - cumulative
    $100 par value:*
      4.84% series - 150,000 shares authorized,
         14,808 shares outstanding                                                      1,481          1,481
      4.70% series - 150,000 shares authorized,
         4,311 shares outstanding                                                         431            431
      8% series - 150,000 shares authorized,
         -0- and 12,224 shares outstanding                                                 --          1,222
      7.75% series - 750,000 shares authorized, 712,500 and 750,000
        shares outstanding                                                             71,250         75,000
------------------------------------------------------------------------------- -------------- --------------
       Total preferred stock subject to mandatory redemption                           73,162         78,134
------------------------------------------------------------------------------- -------------- --------------
  Corporation obligated, mandatorily redeemable preferred
    securities of subsidiary trust holding solely junior
    subordinated debentures of the corporation                                        100,000        100,000
------------------------------------------------------------------------------- -------------- --------------
  Long-Term Debt:
    First mortgage bonds and senior notes                                           1,420,000      1,301,000
  Pollution control revenue bonds:
      Revenue refunding 1991 series, due 2021                                          50,900         50,900
      Revenue refunding 1992 series, due 2022                                          87,500         87,500
      Revenue refunding 1993 series, due 2020                                          23,460         23,460
  Other notes                                                                              12             17
  Unamortized discount - net of premium                                                  (124)          (170)
  Long-term debt due within one year                                                 (107,000)       (51,000)
------------------------------------------------------------------------------- -------------- --------------
  Total long-term debt excluding current maturities                                 1,474,748      1,411,707
------------------------------------------------------------------------------- -------------- --------------
  Total Capitalization                                                             $3,095,665     $3,043,406
------------------------------------------------------------------------------- -------------- --------------
</TABLE>

(a) 13,000,000 shares authorized for $25 par value preferred stock and 3,000,000
shares authorized for $100 par value preferred stock.

The accompanying notes are an integral part of the consolidated financial
statements.

                                       48
<PAGE>
<TABLE>

Consolidated Statements of
         EARNINGS REINVESTED

<CAPTION>

  (FOR YEARS ENDED DECEMBER 31; DOLLARS IN THOUSANDS, 
   EXCEPT PER SHARE AMOUNTS)                               1998           1997          1996
 ------------------------------------------------ --------------- -------------- ------------
 <S>                                              <C>             <C>            <C>     
  Balance at Beginning of Year                         $ 46,672       $ 86,355      $ 84,254
  Net Income                                            169,612        123,076       165,519
  Adjustment to conform fiscal year of WECo                  --         10,835            --
------------------------------------------------ --------------- -------------- -------------
       Total                                            216,284        220,266       249,773
------------------------------------------------ --------------- -------------- -------------
  Deductions:
       Dividends declared:
          Preferred stock:
            Adjustable Rate Series B                        272          2,010         2,716
            $1.86 per share on 7.45% series II            4,470          4,470         4,470
            $2.13 per share on 8.50% series III           2,550          2,550         2,550
            $4.84 per share on 4.84% series                  72            192           232
            $4.70 per share on 4.70% series                  20            203           265
            $8.00 per share on 8% series                     25            122           218
            $7.75 per share on 7.75% series               5,667          5,813         5,813
            $1.97 per share on 7.875% series                 --          3,940         5,906
         Common Stock                                   155,591        150,591       141,248
       Preferred stock redemptions                           69          3,703            --
------------------------------------------------ --------------- -------------- -------------
         Total deductions                               168,736        173,594       163,418
------------------------------------------------ --------------- -------------- -------------
  Balance at End of Year                               $ 47,548        $46,672       $86,355
------------------------------------------------ --------------- -------------- -------------
  Dividends Declared Per Common Share                     $1.84          $1.78         $1.67
------------------------------------------------ --------------- -------------- -------------
</TABLE>



<TABLE>

Consolidated Statements of
         COMPREHENSIVE INCOME
<CAPTION>

  (FOR YEARS ENDED DECEMBER 31; DOLLARS IN THOUSANDS)           1998          1997          1996
------------------------------------------------------- ------------- ------------- -------------
<S>                                                     <C>           <C>           <C>     
  Net Income                                                $169,612      $123,076      $165,519
  Other comprehensive income, net of tax:
      Unrealized holding gains (losses) on available
           for sale securities                                (6,152)       14,954            --
------------------------------------------------------- ------------- ------------- -------------
  Comprehensive Income                                      $163,460      $138,030      $165,519
------------------------------------------------------- ------------- ------------- -------------
</TABLE>

The accompanying notes are an integral part of the consolidated financial
statements.

                                       49
<PAGE>
<TABLE>

Consolidated Statements of
         CASH FLOW
<CAPTION>

  (FOR YEARS ENDED DECEMBER 31; DOLLARS IN THOUSANDS)                       1998             1997            1996
------------------------------------------------------------------ -------------- ---------------- ---------------
<S>                                                                <C>            <C>              <C>  
  Operating Activities:
     Income from continuing operations                                  $169,612         $125,698        $167,351
     Adjustments to reconcile income from continuing
        operations to net cash provided by operating activities:
          Depreciation and amortization                                  165,587          161,865         144,206
          Deferred income taxes and tax credits - net                     16,560           27,422           6,842
          PRAM accrued revenues - net                                         --           40,777          74,326
          Pretax write-down and equity in undistributed
            losses of unconsolidated affiliate                                --            4,044             961
          PURPA buyout costs                                                  --         (215,000)             --
          Other                                                          (14,792)          43,286         (21,918)
          Change in certain current assets and liabilities               (22,692)         (58,394)         27,809
------------------------------------------------------------------ -------------- ---------------- ---------------
            Net cash provided by operating activities                    314,275          129,698         399,577
------------------------------------------------------------------ -------------- ---------------- ---------------
  Investing Activities:
     Construction expenditures - excluding equity AFUDC                 (335,471)        (257,900)       (205,050)
     Energy conservation expenditures                                     (6,745)          (4,864)         (6,683)
     Cash received from sale of conservation assets - net                     --           34,372              --
     Proceeds from property sales                                          6,877            7,013          34,000
     Other                                                                 1,967           17,703          (7,384)
------------------------------------------------------------------ --------------- ---------------- ---------------
            Net cash used by investing activities                       (333,372)        (203,676)       (185,117)
------------------------------------------------------------------ --------------- ---------------- ---------------
  Financing Activities:
     Increase (decrease) in short-term debt                               78,367           85,975         (30,921)
     Dividends paid                                                     (168,667)        (169,892)       (163,418)
     Issuance of common and preferred stock                                   --               65           3,686
     Issuance of company obligated, mandatorily
        redeemable preferred securities                                       --          100,000              --
     Redemption of preferred stock                                        (5,454)        (128,747)         (1,200)
     Issuance of bonds                                                   200,000          300,000          34,470
     Redemption of bonds and notes                                       (81,004)        (102,844)        (72,612)
     Other                                                                13,374           (4,572)           (558)
------------------------------------------------------------------ -------------- ---------------- ----------------
            Net cash provided (used) by financing activities              36,616           79,985        (230,553)
------------------------------------------------------------------ -------------- ---------------- ----------------
  Increase (Decrease) in cash from continuing operations                  17,519            6,007         (16,093)
  Decrease in cash from discontinued operations:
     Operating activities                                                     --               --          (1,386)
     Investing activities                                                     --           (2,622)             --
------------------------------------------------------------------ -------------- ----------------- --------------
  Net Increase (Decrease) in Cash                                         17,519            3,385         (17,479)
  Cash at Beginning of Year                                                7,759            4,335          21,814
  Adjustment to conform fiscal year of WECo                                   --               39              --
------------------------------------------------------------------ -------------- ---------------- ---------------
  Cash at End of Year                                                    $25,278           $7,759          $4,335
------------------------------------------------------------------ -------------- ---------------- ---------------
</TABLE>

The accompanying notes are an integral part of the consolidated financial
statements.

                                       50
<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.
         SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION
       Puget Sound Energy, Inc., formerly Puget Sound Power & Light Company
("the Company"), is an investor-owned public utility incorporated in the State
of Washington furnishing electric, and since February 10, 1997, gas service in a
territory covering approximately 6,000 square miles, principally in the Puget
Sound region of Washington state. On February 10, 1997, the Company completed a
merger ("the Merger") with Washington Energy Company ("WECo") and its principal
subsidiary, Washington Natural Gas Company ("WNG"). The change of the Company's
name was effective with the merger. Herein, the Company refers to the combined
entity; Puget Power and WECo refer to the individual entities.
       The merger has been structured as a tax-free exchange of shares, and is
accounted for as a pooling of interests for financial statement purposes.
Accordingly, the consolidated financial statements have been retroactively
restated to include the results of operations, financial position and cash flows
of WECo and WNG for all periods prior to consummation of the merger. Financial
information prior to January 1, 1997, contained herein reflects fiscal years
ended December 31 for Puget Power and September 30 for WECo. Certain
reclassifications have been made to the 1997 and 1996 financial statements to
conform to the 1998 presentation with no effect impact on consolidated net
income, total assets or common equity.
       The consolidated financial statements include the accounts of the Company
and all its significant wholly-owned subsidiaries, after elimination of all
significant intercompany items and transactions. One immaterial subsidiary is
stated on an equity basis.
       The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period.
Actual results could differ from those estimates.

UTILITY PLANT
       The costs of additions to utility plant, including renewals and
betterments, are capitalized at original cost. Costs include indirect costs such
as engineering, supervision, certain taxes and pension and other employee
benefits, and an allowance for funds used during construction. Replacements of
minor items of property are included in maintenance expense. The original cost
of operating property together with removal cost, less salvage, is charged to
accumulated depreciation when the property is retired and removed from service.

REGULATORY ASSETS & AGREEMENTS
     The Company prepares its financial  statements in accordance with Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" ("Statement No. 71"). Statement No. 71 requires the Company
to defer  certain  costs that would  otherwise  be charged to expense,  if it is
probable that future rates will permit recovery of such costs.  Accounting under
Statement No. 71 is appropriate as long as: rates are  established by or subject
to  approval  by  independent,  third-party  regulators;  rates are  designed to
recover the  specific  enterprise's  cost-of-service;  and in view of demand for
service,  it is  reasonable to assume that rates set at levels that will recover
costs can be charged to and collected from customers.  In applying Statement No.
71, the  Company  must give  consideration  to changes in the level of demand or
competition  during the cost recovery  period.  In accordance with Statement No.
71,  the  Company  capitalizes  certain  costs  in  accordance  with  regulatory
authority whereby those costs will be expensed and recovered in future periods.

                                       51
<PAGE>

       Net regulatory assets and liabilities at December 31, 1998 and 1997,
included the following:

  (DOLLARS IN MILLIONS)                               1998           1997
-------------------------------------------- -------------- --------------
  Deferred income taxes                             $241.4         $258.4
  PURPA buyout costs                                 221.8          215.0
  Investment in BEP Exchange Contract                 70.5           78.9
  Unamortized energy conservation charges              7.1            6.9
  Storm damage costs                                  34.6           33.4
  Various other costs                                 63.0           68.2
  Deferred gains on property sales                   (17.2)          (17.5)
-------------------------------------------- -------------- --------------
  Total                                             $621.2         $643.3
-------------------------------------------- -------------- --------------

     If the  Company,  at some  point in the  future,  determines  that all or a
portion of the utility  operations  no longer meets the  criteria for  continued
application  of  Statement  No. 71, the  Company  would be required to adopt the
provisions of Statement of Financial  Accounting  Standards No. 101,  "Regulated
Enterprises  -  Accounting  for  the  Discontinuation  of  Application  of  FASB
Statement No. 71"  ("Statement  No.  101").  Adoption of Statement No. 101 would
require the Company to write off the regulatory  assets and liabilities  related
to those operations not meeting  Statement No. 71 requirements.  Discontinuation
of  Statement  No. 71 could have a material  impact on the  Company's  financial
statements.
       The Emerging Issues Task Force ("EITF") of the Financial Accounting
Standards Board ("FASB") met in May and July of 1997 to address the issues of
when an entity should discontinue the application of Statement No. 71, and how
Statement No. 101 should be applied to a portion of an entity subject to a
transition-to-competition plan. As a result of these meetings, a consensus was
reached that Statement No. 71 should be discontinued at a date no later than
when the details of the transition-to-competition plan for all or a portion of
the entity subject to such plan are known. Additionally, the EITF reached a
consensus that stranded costs which are to be recovered through cash flows
derived from another portion of the entity which continues to apply Statement
No. 71 should not be written off; rather, they should be considered regulatory
assets of the segment which will continue to apply Statement No. 71.
       The Company's financial statements continue to apply Statement No. 71 for
regulated operations. Although discussions with regulatory authorities regarding
retail competition have occurred and are expected to continue, no final
transition to competition plans for the Company's regulated operations have yet
been adopted or proposed.
       The Company, in prior years, incurred costs associated with its 5%
interest in a now-terminated nuclear generating project (identified herein as
"Investment in Bonneville Exchange Power ("BEP")"). Under terms of a settlement
agreement with the Bonneville Power Administration ("BPA"), which settled claims
of the Company relating to construction delays associated with that project, the
Company is receiving, over 30.5 years, power from the federal power system
resources marketed by BPA. Approximately two-thirds of the Company's investment
in BEP is included in rate base and amortized on a straight-line basis over the
life of the contract (amortization is included in "Purchased and interchanged
power"). The remainder of the Company's investment is being recovered in rates
over ten years, without a return during the recovery period (the related
amortization is included in "Depreciation and Amortization", pursuant to a FERC
accounting order).
       The Company has recorded a regulatory asset for $215 million related to
the buyout of a gas sales contract of a non-utility generator. A Washington
Commission accounting order approved the payment for deferral and collection in
rates over the remaining life of the energy supply contract. Under terms of the
order, the Company is allowed to accrue as an additional regulatory asset
one-half the carrying costs of the deferred balance over the first five years.

                                       52
<PAGE>

       The Company also has agreements under which ConneXt, a wholly owned
subsidiary of the Company, performs certain billing and customer information
technology functions. Under an accounting order approved by the Washington
Commission, the Company records payments to ConneXt as if such costs were paid
to third-party providers and these costs will be reviewed in a future rate
filing.

OPERATING REVENUES
       Operating revenues are recorded on the basis of service rendered, which
includes estimated unbilled revenue and, prior to October 1, 1996, revenue
accrued under the Periodic Rate Adjustment Mechanism ("PRAM").

ENERGY CONSERVATION
       The Company accumulates energy conservation expenditures which are
included in rate base and amortized to expense as prescribed by the Washington
Commission.
       In June 1995, the Company sold approximately $202.5 million of its
investment in customer-owned energy conservation measures to a grantor trust
which, in turn, issued securities backed by a Washington state statute enacted
in 1994. The Company sold an additional investment of $35.2 million in
customer-owned energy conservation measures in August 1997. The proceeds of the
sales were used to pay down short-term debt. The Company recognized no gain or
loss on the sales.

SELF-INSURANCE
       The Company currently has no insurance coverage for storm damage and is
self-insured for a portion of the risk associated with comprehensive liability,
industrial accidents and catastrophic property losses. With approval of the
Washington Commission, the Company is able to defer for collection in future
rates certain uninsured storm damage costs associated with major storms.

DEPRECIATION AND AMORTIZATION
       For financial statement purposes, the Company provides for depreciation
on a straight-line basis. The depreciation of automobiles, trucks, power
operated equipment and tools is allocated to asset and expense accounts based on
usage. The annual depreciation provision stated as a percent of average original
cost of depreciable electric utility plant was 3.0% in 1998, 1997 and 1996 and
for depreciable gas utility plant was 3.4% in 1998 and 1997 and 3.6% in 1996.

FEDERAL INCOME TAXES
     The Company  normalizes,  with the approval of the  Washington  Commission,
certain items.  Deferred taxes have been determined under Statement of Financial
Accounting  Standards No. 109. Investment tax credits are deferred and amortized
based on the  average  useful life of the related  property in  accordance  with
regulatory and income tax requirements. (See Note 13)

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
       The Allowance for Funds Used During Construction ("AFUDC") represents the
cost of both the debt and equity funds used to finance utility plant additions
during the construction period. The amount of AFUDC recorded in each accounting
period varies depending principally upon the level of construction work in
progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of
utility plant and is credited as a non-cash item to other income and interest
charges currently. Cash inflow related to AFUDC does not occur until these
charges are reflected in rates.
       The AFUDC rate allowed by the Washington Commission for gas utility plant
additions was 9.15% in 1998 and 1997 and 9.03% in 1996. The allowed AFUDC rate
on electric utility plant was 8.94% during the same period. To the extent
amounts calculated using this rate exceed the AFUDC calculated using the Federal
Energy Regulatory Commission ("FERC") formula, the Company capitalizes the
excess as a deferred asset, crediting miscellaneous income. The amounts included
in income were: $3,409,000 for 1998, $2,704,000 for 1997 and $2,112,000 for
1996. The deferred asset is being amortized over the average useful life of the
Company's non-project utility plant.

                                       53
<PAGE>

PERIODIC RATE ADJUSTMENT MECHANISM
       In April 1991, the Washington Commission issued an order establishing a
PRAM designed to operate as an interim rate adjustment mechanism between
electric general rate cases. Under the PRAM, Puget Power was allowed to request
annual rate adjustments, on a prospective basis, to reflect changes in certain
costs as set forth in the PRAM order. Also, under terms of the order, recovery
of certain costs was decoupled from levels of electricity sales.
       Rates established for the PRAM period were subject to future adjustment
based on actual customer growth and variations in certain costs, principally
those affected by hydro and weather conditions. To the extent revenue billed to
customers varied from amounts allowed under the methodology established in the
PRAM order, the difference was accumulated, without interest, for rate recovery
which was then established in the next PRAM hearing. In its September 22, 1995,
order, the Washington Commission approved Puget Power's last PRAM filing and the
recovery of $71.2 million over the period October 1, 1995, through September 30,
1996. In addition to approval of the rate adjustment, the Commission also
agreed, pursuant to a negotiated settlement, to discontinue the PRAM on
September 30, 1996, the end of the last PRAM period. PRAM accrued revenues of
$40.5 million, recorded at December 31, 1996, were recovered in the first
quarter of 1997. Over-collection of PRAM revenues was refunded to customers in
the second quarter of 1997.
       With the discontinuance of the PRAM, the Company no longer has a rate
adjustment mechanism to adjust for changes in energy or fuel costs or variances
in hydro and weather conditions. These variances may now significantly influence
earnings.

PGA MECHANISM
       Differences between the actual cost of the Company's gas supplies and
that currently allowed by the Washington Commission are deferred and recovered
or repaid through the purchased gas adjustment ("PGA") mechanism.
       On June 25, 1998, the Company received approval from the Washington
Commission to begin a new performance-based mechanism for strengthening its
gas-supply purchasing and gas-storage practices. The PGA Incentive Mechanism,
which encourages competitive gas purchasing and management of pipeline and
storage-capacity, became effective July 1, 1998. Incentive gains and losses from
the three-year program are shared between customers and shareholders. After the
first $0.5 million, which is allocated to customers, gains and losses are shared
40%/60% between the Company and customers up to $26.5 million and 33%/67%
thereafter. Gains or losses are determined relative to a weighted average index
which is reflective of the Company's gas supply and transportation contract
costs. The Company's share of incentive gains under the PGA Incentive Mechanism
in 1998 were approximately $1.1 million while customers received approximately
$2.0 million.

OFF-SYSTEM SALES AND CAPACITY RELEASE
       The Company has been selling excess gas supplies and entering into gas
supply exchanges with third parties outside of its distribution area since 1992.
The Company began releasing to third parties excess interstate gas pipeline
capacity and gas storage rights on a short-term basis in 1993 and 1994,
respectively. The Company contracts for firm gas supplies and holds firm
transportation and storage capacity sufficient to meet the expected peak winter
demand for gas for space heating by its firm customers. Due to the variability
in weather and other factors, however, the Company holds contractual rights to
gas supplies and transportation and storage capacity in excess of its immediate
requirements to serve firm customers on its distribution system for much of the
year which, therefore, are available for third-party gas sales, exchanges and
capacity releases. The net proceeds from such activities are accounted for as
reductions in the cost of purchased gas and passed on to customers through the
PGA mechanism, with no direct impact on net income. As a result, the Company
does not reflect sales revenue or associated cost of sales for these
transactions in its income statement. The net proceeds from these activities
were $22,071,881, $16,759,000 and $10,711,000 for 1998, 1997 and 1996,
respectively.

                                       54
<PAGE>

RISK MANAGEMENT AND ENERGY TRADING
       The Company's energy related businesses are exposed to risks related to
changes in commodity prices. As part of its business, the Company markets power
to other utilities and power marketers by entering into contracts to purchase or
supply electric energy or natural gas at specified delivery points and at
specified future delivery dates. The Company's energy trading function manages
the Company's core electric and gas supply portfolios as well as non-core
incremental energy supply trading activities.
       The Company enters into futures and options for the purpose of hedging
commodity price picks. Gains or losses on these derivatives are deferred and
recognized upon settlement along with the underlying sales or purchase contract.
The Company has established policies and procedures to manage these risks. A
Risk Management Committee separate from the units that create these risks
monitors compliance with the Company's policies and procedures. In addition, the
Audit Committee of the Company's Board of Directors has oversight of the Risk
Management Committee.

OTHER
       Debt premium, discount and expenses are amortized over the life of the
related debt. The premiums and costs associated with reacquired debt are being
amortized over the life of the related new issuances, in accordance with
ratemaking treatment.
       In June 1997, the FASB issued Statement of Financial Accounting Standards
No. 130, "Reporting Comprehensive Income" ("Statement No. 130"), which
establishes rules for reporting and displaying comprehensive income and its
components. In June 1997, the FASB issued Statement of Financial Accounting
Standards No. 131, "Disclosures about Segments of an Enterprise and Related
Information" ("Statement No. 131"), which established requirements that
companies report certain information about operating segments. In February 1998,
the FASB issued Statement of Financial Accounting Standards No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits" ("Statement No.
132"), which standardizes the disclosure requirements for pensions and other
postretirement benefits. The Company adopted these statements in 1998 which
resulted in additional financial disclosures but no impact on the Company's
financial position or results of operations.
       During 1998, the EITF of the FASB released Issue 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities" ("EITF
98-10"). EITF 98-10 addresses accounting for the purchase and sale of energy
trading contracts. The conclusion reached by the EITF was that such energy
trading contracts should be recorded at fair value with the mark-to-market gains
or losses recorded in current earnings. EITF 98-10 is effective for fiscal years
beginning after December 15, 1998. The Company does not consider its current
operations to meet the definition of trading activities as described by EITF
98-10, other than the activities entered into on the Company's behalf through
the contract with DETM. These activities are currently accounted for using fair
value and mark-to-market accounting. Accordingly, the Company has concluded that
the adoption of EITF 98-10 will not have a material impact on the Company's
financial position or results of operations.
       In April 1998, the Accounting Standards Executive Committee issued
Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities"
("SOP 98-5"). SOP 98-5 is effective for fiscal years beginning after December
15, 1998. SOP 98-5 provides guidance on the financial reporting of start-up
costs and organization costs. It requires costs of start-up activities and
organization costs to be expensed as incurred. The Company has not yet
determined the impact that the adoption of SOP 98-5 will have on its financial
position or results of operations.
     In June 1998, the FASB issued Statement of Financial  Accounting  Standards
No.  133,  "Accounting  for  Derivative   Instruments  and  Hedging  Activities"
("Statement No. 133"). Statement No. 133 is effective for the fiscal year ending
December 31, 2000. Statement No. 133 requires that all derivative instruments be
recorded on the balance sheet at their fair value.  Changes in the fair value of
derivatives are recorded each period in current earnings or other  comprehensive
income,  depending  on whether a  derivative  is  designated  as part of a hedge
transaction  and, if it is, the type of hedge  transaction.  The Company has not
yet  determined  the impact that the adoption of Statement  No. 133 will have on
its financial statements or the timing of adoption.

                                       55
<PAGE>

EARNINGS PER COMMON SHARE
     During  1997,  the  Company  adopted  Statement  of  Financial   Accounting
Standards No. 128, "Earnings per Share" ("Statement No. 128"). As required under
Statement  No. 128,  earnings  per share data have been  restated  for all prior
periods presented.
       Basic earnings per common share have been computed based on weighted
average common shares outstanding of 84,561,000, 84,560,000 and 84,418,000 for
1998, 1997 and 1996, respectively. Diluted earnings per common share have been
computed based on weighted average common shares outstanding of 84,768,000,
84,628,000 and 84,449,000 for 1998, 1997 and 1996, respectively, which include
the dilutive effect of securities related to employee compensation plans.

NOTE 2.
         PROPERTY PLANT AND EQUIPMENT

  DECEMBER 31 (DOLLARS IN THOUSANDS)                    1998          1997
----------------------------------------------- ------------- -------------
  Electric and gas utility plant classified
  by Prescribed accounts at original cost:
    Distribution plant                            $2,794,906    $2,674,234
    Production plant                                 943,808       939,211
    Transmission plant                               641,526       625,779
    General plant                                    375,612       333,140
    Construction work in progress                    266,242       123,690
    Completed work not classified                         --        58,216
    Intangible plant                                  99,776        78,491
    Underground storage                               16,307        16,277
    Plant held for future use                          9,016        10,263
    Other                                              4,815         4,460
----------------------------------------------- ------------- -------------
       Total electric and gas utility plant       $5,152,008    $4,863,761
----------------------------------------------- ------------- -------------

                                       56
<PAGE>

Note 3.
         Capital Stock
<TABLE>
<CAPTION>

                                                         PREFERRED STOCK
                                             ------------------------------------------
                                              NOT SUBJECT TO          SUBJECT TO           COMMON STOCK
                                                 MANDATORY            MANDATORY
                                                 REDEMPTION           REDEMPTION         WITHOUT PAR VALUE
                                              $25 PAR VALUE         $100 PAR VALUE      ($10 STATED VALUE)
-------------------------------------------- ------------------- ------------------- ------------------------
<S>                                          <C>                 <C>                 <C>                   
  SHARES OUTSTANDING JANUARY 1, 1996                 8,600,000             890,395               84,340,755
-------------------------------------------- ------------------- ------------------- ------------------------
  Issued to Shareholders Under the Stock 
  Purchase and Dividend Reinvestment Plan:
       1996                                                  --                  --                  148,417
       1997                                                  --                  --                   33,930
-------------------------------------------- ------------------- ------------------- ------------------------
  Issued Pursuant to Employee Compensation 
  Plans:
       1996                                                  --                  --                   21,886
       1997                                                  --                  --                   17,063
-------------------------------------------- ------------------- ------------------- ------------------------
  Issued Pursuant to Directors' Stock Bonus
  Plan:

       1996                                                  --                  --                      187
-------------------------------------------- ------------------- ------------------- ------------------------
  Acquired for Sinking Fund:
       1996                                                  --             (12,000)                      --
       1997                                                  --             (12,050)                      --
       1998                                                  --             (49,500)                      --
-------------------------------------------- ------------------- -------------------- -----------------------
  Called for Redemption and Canceled:
       1997                                          (4,780,494)            (85,002)                      --
       1998                                             (16,500)               (224)                      --
-------------------------------------------- -------------------- ------------------- -----------------------
  Fractional Share Redemptions in 
  Connection with Merger Exchange:
       1997                                                  --                  --                   (1,593)
       1998                                                  --                  --                      (84)
-------------------------------------------- ------------------- ------------------- ------------------------
  Shares outstanding December 31, 1998                3,803,006             731,619               84,560,561
-------------------------------------------- ------------------- ------------------- ------------------------
</TABLE>

See "Consolidated Statements of Capitalization" for details on specific series.

       On January 15, 1991, the Board of Directors declared a dividend of one
preference share purchase right (a "Right") on each outstanding common share of
the Company. The dividend was distributed on January 25, 1991, to shareholders
of record on that date. The Rights will be exercisable only if a person or group
acquires 10 percent or more of the Company's common stock or announces a tender
offer which, if consummated, would result in ownership by a person or group of
10 percent or more of the common stock. Each Right entitles the registered
holder to purchase from the Company one one-thousandth of a share of Preference
Stock, $50 par value per share, at an exercise price of $45, subject to
adjustments. The description and terms of the Rights are set forth in a Rights
Agreement between the Company and The Bank of New York, as Rights Agent. The
Rights expire on January 25, 2001, unless earlier redeemed by the Company.

                                       57
<PAGE>

       The weighted average dividend rate for the Adjustable Rate Cumulative
Preferred Stock ("ARPS"), Series B ($25 par value) was 4.83% for 1998, 5.61% for
1997 and 5.49% for 1996. The Company reacquired 16,500 shares of ARPS Series B
through open-market purchases during 1998 and redeemed the remaining ARPS on
February 2, 1999 at $25 par plus accrued dividends through February 2, 1999.
       The 8.50% and 7.45% Series Preferred may be redeemed at par on or after
September 1, 1999, and November 1, 2003, respectively.

NOTE 4.
         PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION

       The Company is required to deposit funds annually in a sinking fund
sufficient to redeem the following number of shares of each series of preferred
stock at $100 per share plus accrued dividends: 4.84% Series and 4.70% Series,
3,000 shares each and 7.75% Series, 37,500 shares. All previous sinking fund
requirements have been satisfied. At December 31, 1998, there were 36,192 shares
of the 4.84% Series and 52,689 shares of the 4.70% Series acquired by the
Company and available for future sinking fund requirements. Upon involuntary
liquidation, all preferred shares are entitled to their par value plus accrued
dividends.
       The preferred stock subject to mandatory redemption may also be redeemed
by the Company at the following redemption prices per share plus accrued
dividends: 4.84% Series, $102 and 4.70% Series, $101. The 7.75% Series may be
redeemed by the Company, subject to certain restrictions, at $104.65 per share
plus accrued dividends through February 15, 1999, and at per share amounts which
decline annually to a price of $100 after February 15, 2007.
       On February 15, 1998, the Company redeemed all outstanding shares of the
8% Series, $100 par value Preferred including 12,000 shares for the sinking fund
at par and 224 shares at $101.00 per share.

NOTE 5.
         COMPANY-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES

       In 1997, the Company formed Puget Sound Energy Capital Trust I (the
"Trust") for the sole purpose of issuing and selling common and preferred
securities ("Trust Securities"). The proceeds from the sale of Trust Securities
were used to purchase Junior Subordinated Debentures ("Debentures") from the
Company. The Debentures are the sole assets of the Trust and the Company owns
all common securities of the Trust.
       The Debentures have an interest rate of 8.231% and a stated maturity date
of June 1, 2027. The Trust Securities are subject to mandatory redemption at par
on the stated maturity date of the Debentures. The Trust Securities may be
redeemed earlier, under certain conditions, at the option of the Company.
Dividends relating to preferred securities are included in interest expense.

                                       58
<PAGE>

NOTE 6.
         ADDITIONAL PAID-IN CAPITAL

  (DOLLARS IN THOUSANDS)                           1998         1997       1996
-------------------------------------------- ----------- ------------ ----------
  Balance at beginning of year                 $450,845     $446,910   $444,928
  Excess of proceeds over stated values of
   common stock issued                               --          428      2,022
  Par value over cost of reacquired
   preferred stock                                   --          471         --
  Retained earnings adjustment for
   preferred redemption                              --        3,036         --
  Issue costs and other expenses                   (121)          --        (40)
-------------------------------------------- ----------- ------------ ----------
  Balance at end of year                       $450,724     $450,845   $446,910
-------------------------------------------- ----------- ------------ ----------

NOTE 7.
         EARNINGS REINVESTED IN THE BUSINESS

       The payment of dividends on common stock is restricted by provisions of
certain covenants applicable to preferred stock and long-term debt contained in
the Company's Articles of Incorporation and Mortgage Indentures. Under the most
restrictive covenants, earnings reinvested in the business unrestricted as to
payment of cash dividends were approximately $183 million at December 31, 1998.
       The adjustments made to the carrying value of costs associated with the
terminated generating projects and Bonneville Exchange Power as a result of
Statement No. 90, adjustments made as a result of Statement No. 121 and the
disallowance of certain terminated generating project costs by the Washington
Commission do not impact the amount of earnings reinvested in the business for
purposes of payment of dividends on common stock under the terms of the
Company's Articles and Mortgage Indentures. (See Note 1.)

                                       59
<PAGE>

NOTE 8.
         LONG-TERM DEBT
  FIRST MORTGAGE BONDS AND SENIOR NOTES 
(At December 31; dollars in thousands):
Series               Due           1998             1997
---------------- -------- -------------- ----------------
  6.17%             1998             --           10,000
  5.70%             1998             --            5,000
  8.25%             1998             --           11,000
  8.83%             1998             --           25,000
  6.50%             1999         16,500           16,500
  6.65%             1999         10,000           10,000
  6.41%             1999         20,500           20,500
  7.08%             1999         10,000           10,000
  7.25%             1999         50,000           50,000
  6.61%             2000         10,000           10,000
  9.60%             2000         25,000           25,000
  8.51 - 8.55%      2001         19,000           19,000
  9.14%             2001             --           30,000
  7.53 - 7.91%      2002         30,000           30,000
  7.85%             2002         30,000           30,000
  7.07%             2002         27,000           27,000
  7.15%             2002          5,000            5,000
  7.625%            2002         25,000           25,000
  6.23 - 6.31%      2003         28,000           28,000
  7.02%             2003         30,000           30,000
  6.20%             2003          3,000            3,000
  6.40%             2003         11,000           11,000
  6.07 & 6.10%      2004         18,500           18,500
  7.70%             2004         50,000           50,000
  7.80%             2004         30,000           30,000
  6.92 & 6.93%      2005         31,000           31,000
  6.58%             2006         10,000           10,000
  8.06%             2006         46,000           46,000
  8.14%             2006         25,000           25,000
  7.02 & 7.04%      2007         25,000           25,000
  7.75%             2007        100,000          100,000
  8.40%             2007         10,000           10,000
  6.51 & 6.53%      2008          4,500            4,500
  6.61 & 6.62%      2009          8,000            8,000
  7.12%             2010          7,000            7,000
  8.59%             2012          5,000            5,000
  8.20%             2012         30,000           30,000

                                       60
<PAGE>

Series               Due           1998             1997
---------------- -------- -------------- ----------------
  6.83% & 6.90%     2013         13,000           13,000
  7.35 & 7.36%      2015         12,000           12,000
  6.74%             2018        200,000               --
  9.57%             2020         25,000           25,000
  8.25 - 8.40%      2022         35,000           35,000
  7.19%             2023         13,000           13,000
  7.35%             2024         55,000           55,000
  7.15 & 7.20%      2025         17,000           17,000
  7.02%             2027        300,000          300,000
---------------- -------- -------------- ----------------
  Total                      $1,420,000       $1,301,000
---------------- -------- -------------- ----------------

     On June 15, 1998, the Company issued $200 million principal amount of 6.74%
Senior Medium Term Notes, Series A. The Notes are due June 15, 2018.
       On June 22, 1998, the Company redeemed $30 million principal amount of
First Mortgage Bonds, 9.14% Series due June 21, 2001, at a redemption price of
100%.
       In September 1998, the Company filed a shelf-registration statement for
the offering on a delayed or continuous basis of up to $500 million principal
amount of Senior Notes secured by a pledge of First Mortgage Bonds.
       Substantially all utility properties owned by the Company are subject to
the lien of the Company's electric and gas mortgage indentures.

POLLUTION CONTROL BONDS
       The Company has outstanding three series of Pollution Control Bonds.
Amounts outstanding were borrowed from the City of Forsyth, Montana ("the
City"). The City obtained the funds from the sale of Customized Pollution
Control Refunding Bonds issued to finance pollution control facilities at
Colstrip Units 3 and 4.
       Each series of bonds are collateralized by a pledge of the Company's
First Mortgage Bonds, the terms of which match those of the Pollution Control
Bonds. No payment is due with respect to the related series of First Mortgage
Bonds so long as payment is made on the Pollution Control Bonds. Interest rates
for the 1992 and 1993 series are 6.80% and 5.875%, respectively. The 1991 series
consists of $27.5 million principal amount bearing interest at 7.05% and $23.4
million principal amount bearing interest at 7.25%.

LONG-TERM DEBT MATURITIES
       The principal amounts of long-term debt maturities for the next five
years are as follows:


  (DOLLARS IN THOUSANDS)       1999       2000        2001       2002      2003
-------------------------- --------   --------    --------   --------  --------
  Maturities of
    long-term debt         $107,000   $ 35,000    $ 19,000   $117,000  $ 72,000

                                       61
<PAGE>

NOTE 9.
         SHORT-TERM DEBT AND OTHER FINANCING ARRANGEMENTS

       At December 31, 1998, the Company had short-term borrowing arrangements
which included a $375 million line of credit with thirteen banks. The agreement
provides the Company with the ability to borrow at different interest rate
options and includes variable fee levels. The options are: (1) the higher of the
prime rate or the Federal Funds rate plus 1/2 of 1 percent or (2) the Eurodollar
rate plus .25 percent. The current availability fee is .08 percent per annum on
the unused loan commitment.
       In addition, the Company has agreements with several banks to borrow on
an uncommitted, as available, basis at money-market rates quoted by the banks.
There are no costs, other than interest, for these arrangements. The Company
also uses commercial paper to fund its short-term borrowing requirements.


  AT DECEMBER 31: (DOLLARS IN THOUSANDS)         1998         1997        1996
  -------------------------------------      --------     --------    --------
  Short-term borrowings outstanding:
    Commercial paper notes                   $142,105     $124,538    $266,422
    Bank line of credit borrowing             $25,000     $215,000          --
    Uncommitted bank borrowings              $283,800      $33,000     $31,700
    Weighted average interest rate              5.90%        6.88%       6.05%
    Credit availability  (a)                 $375,000     $375,000    $426,500

       (a) Provides liquidity support for outstanding commercial paper and
borrowing from credit line banks in the amount of $167.1 million, $339.5 million
and $266.4 million for 1998, 1997 and 1996 respectively, effectively reducing
the available borrowing capacity under these credit lines to $207.9 million,
$35.5 million and $160.1 million, respectively.

       The Company has, on occasion, entered into interest rate swap agreements
to reduce the impact of changes in interest rates on portions of its
floating-rate, short-term debt. The one agreement outstanding at December 31,
1998, effectively changes the Company's interest rate on outstanding commercial
paper to 9.64% on a notional principal amount of $16.5 million expiring March
31, 2000.

                                       62
<PAGE>

NOTE 10.
         ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

       The following table presents the carrying amounts and estimated fair
values of the Company's financial instruments at December 31, 1998 and 1997:
<TABLE>
<CAPTION>

                                                    1998        1998         1997       1997
                                                CARRYING        FAIR     CARRYING       FAIR
  (DOLLARS IN MILLIONS)                           AMOUNT       VALUE       AMOUNT      VALUE
--------------------------------------------- ----------- ----------- ------------ ----------
<S>                                           <C>         <C>         <C>          <C>   
  Financial Assets:
    Cash                                          $ 25.3      $ 25.3        $ 7.8      $ 7.8
    Cabot common stock                             $40.0       $40.0        $41.5      $41.5
    Cabot preferred stock                         $ 51.6       $51.6        $51.6      $51.6
  Financial Liabilities:
    Short-term debt                               $450.9      $450.9       $372.5     $372.5
    Preferred stock subject to
      mandatory redemption                         $73.2       $75.8       $ 78.1     $ 82.5
    Corporation obligated, mandatorily
      redeemable preferred securities of
       subsidiary trust holding solely
       junior subordinated debentures of
       the corporation                            $100.0      $109.3       $100.0     $107.6
    Long-term debt                              $1,581.7    $1,686.0     $1,462.7   $1,547.3
  Unrecognized financial instruments:
    Interest rate swaps                               --       $(1.3)          --      $(1.2)
--------------------------------------------- ----------- ------------ ----------- -----------
</TABLE>

     The  fair  value of  outstanding  bonds  including  current  maturities  is
estimated based on quoted market prices.
     The  preferred  stock  subject  to  mandatory  redemption  and  corporation
obligated,  mandatorily  redeemable  preferred  securities of  subsidiary  trust
holding solely junior  subordinated  debentures of the  corporation is estimated
based on dealer quotes.
     The carrying  value of  short-term  debt is  considered  to be a reasonable
estimate of fair value.  The carrying amount of cash,  which includes  temporary
investments with original  maturities of 3 months or less, is also considered to
be a reasonable estimate of fair value.
       The fair value of interest rate swaps (used for hedging purposes) is the
estimated amount that the Company would receive or pay to terminate each swap
agreement at the reporting date, taking into account current interest rates and
the current credit-worthiness of all the parties to each swap.
       Derivative instruments have been used by the Company on a limited basis.
The Company has a policy that financial derivatives are to be used only to
mitigate business risk and not for speculative purposes.

                                       63
<PAGE>

NOTE 11.
         SUPPLEMENTARY INCOME STATEMENT INFORMATION

  (DOLLARS IN THOUSANDS)                       1998          1997         1996
-------------------------------------- ------------- ------------- ------------
  Taxes:
    Real estate and personal property      $ 40,422      $ 46,252     $ 43,762
    State business                           62,855        58,466       60,787
    Municipal, occupational and other        48,090        45,252       43,681
    Other                                    20,010        21,242       12,729
-------------------------------------- ------------- ------------- ------------
  Total taxes                              $171,377      $171,212     $160,959
-------------------------------------- ------------- ------------- ------------
  Charged to:
    Operating expense                      $160,472      $159,310     $155,174
    Other accounts, including
      construction work in progress          10,905        11,902        5,785
-------------------------------------- ------------- ------------- ------------
  Total taxes                              $171,377      $171,212     $160,959
-------------------------------------- ------------- ------------- ------------
       See "Consolidated Statements of Income" for maintenance and depreciation
expense.

       Advertising, research and development expenses and amortization of
intangibles are not significant. The Company pays no royalties.

NOTE 12.
         LEASES

       The Company treats all leases as operating leases for ratemaking purposes
as required by the Washington Commission. Certain leases contain purchase
options, renewal and escalation provisions. Capitalized leases are not material.
       Rental and operating lease expense for the years ended December 31, 1998,
1997 and 1996, were approximately $17,798,000, $19,428,000 and $19,394,000,
respectively. Payments due for the years ended December 31, 1998, 1997 and 1996,
for the sublease of properties were approximately $1,242,000, $962,000 and
$1,674,000, respectively.
       Future minimum lease payments for noncancelable leases are approximately
$14,562,000 for 1999, $14,762,000 for 2000, $13,501,000 for 2001, $13,040,000
for 2002, $10,833,000 for 2003 and in the aggregate, $7,137,000 thereafter.
Future minimum sublease receipts for noncancelable subleases are $1,883,000 for
1999, $1,681,000 for 2000, $669,000 for 2001, $669,000 for 2002, $390,000 for
2003 and in the aggregate, $0 thereafter.

                                       64
<PAGE>

NOTE 13.
         FEDERAL INCOME TAXES

       The details of federal income taxes ("FIT") are as follows:

  (DOLLARS IN THOUSANDS)                          1998        1997       1996
-------------------------------------------- ---------- ----------- ----------
  Charged to Operating Expense:
  Current                                      $90,696    $ 31,672   $111,989
  Deferred - net                                17,948      16,677     (3,058)
  Deferred investment tax credits                 (740)       (624)    (1,184)
-------------------------------------------- ---------- ----------- ----------
  Total FIT charged to operations              107,904      47,725    107,747
-------------------------------------------- ---------- ----------- ----------
  Charged to Miscellaneous Income:
  Current                                        5,601      16,709       (784)
  Deferred - net                                  (648)     (1,902)        --
-------------------------------------------- ---------- ----------- -----------
  Total FIT charged to miscellaneous income      4,953      14,807       (784)
-------------------------------------------- ---------- ----------- -----------
  Credited to discontinued operations               --      (1,412)      (986)
-------------------------------------------- ---------- ----------- ----------
  Total FIT                                   $112,857    $ 61,120   $105,977
-------------------------------------------- ---------- ----------- ----------

       The following is a reconciliation of the difference between the amount of
FIT computed by multiplying pre-tax book income by the statutory tax rate, and
the amount of FIT in the Consolidated Statements of Income:

  (DOLLARS IN THOUSANDS)                              1998      1997       1996
------------------------------------------------- --------- --------- ----------
  FIT at the statutory rate                        $98,864   $64,469    $95,024
------------------------------------------------- --------- --------- ----------
  Increase (Decrease):
    Depreciation expense deducted in the
      financial statements in excess of tax
      depreciation, net of depreciation
      treated as a temporary difference              7,756     7,019      6,603
    AFUDC included in income in the financial
      statements but excluded from taxable income    (3,953)  (2,774)    (2,191)
    Accelerated benefit on early retirement
      of depreciable assets                          (1,241)    (805)    (1,105)
    Investment tax credit amortization                 (740)    (624)    (1,184)
    Energy conservation expenditures - net          12,754    11,028      3,380
    Conservation Settlement                             --   (26,197)        --
    Other - net                                        (583)   9,004      5,450
------------------------------------------------- --------- --------- ----------
  Total FIT                                       $112,857   $61,120   $105,977
------------------------------------------------- --------- --------- ----------
  Effective tax rate                                 40.0%     33.2%      39.0%
------------------------------------------------- --------- --------- ----------

                                       65
<PAGE>
<TABLE>

       The following are the principal components of FIT as reported:
<CAPTION>

  (DOLLARS IN THOUSANDS)                                   1998            1997           1996
-------------------------------------------------- ------------- --------------- --------------
<S>                                                <C>           <C>             <C>     
  Current FIT                                           $96,297         $48,381       $111,205
-------------------------------------------------- ------------- --------------- --------------
  Deferred FIT - other:
    Conservation tax settlement                           3,257          14,404           (759)
    Periodic rate adjustment mechanism (PRAM)               107         (14,272)       (26,014)
    Deferred taxes related to insurance reserves         (1,224)         (2,768)          (938)
    Reversal of Statement No. 90 present
      Value adjustments                                     255             408            552
    Residential Purchase and Sale Agreement - net         3,441          (6,047)        (2,178)
    Normalized tax benefits of the
      Accelerated cost recovery system                   20,118          22,575         23,407
    Energy conservation program                          (2,437)          5,101         (1,208)
    Environmental remediation                            (2,946)         (3,092)         1,148
    WNP 3 tax settlement                                   (826)         21,360             --
    Merger costs                                             42          (7,322)            --
    Demand charges                                        3,273          (3,558)            --
    Other                                                (5,760)        (12,014)         2,932
-------------------------------------------------- --------------- ------------- --------------
  Total deferred FIT - other                             17,300          14,775         (3,058)
-------------------------------------------------- ------------- --------------- --------------
  Deferred investment tax credits -
    net of amortization                                    (740)           (624)        (1,184)
  Credited to discontinued operations                        --          (1,412)          (986)
-------------------------------------------------- ------------- --------------- --------------
  Total FIT                                            $112,857         $61,120       $105,977
-------------------------------------------------- ------------- --------------- --------------
</TABLE>

       Deferred tax amounts shown above result from temporary differences for
tax and financial statement purposes. Deferred tax provisions are not recorded
in the income statement for certain temporary differences between tax and
financial statement purposes because they are not allowed for ratemaking
purposes.
       The Company calculates its deferred tax assets and liabilities under
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("Statement No. 109"). Statement No. 109 requires recording deferred tax
balances, at the currently enacted tax rate, for all temporary differences
between the book and tax bases of assets and liabilities, including temporary
differences for which no deferred taxes had been previously provided because of
use of flow-through tax accounting for rate-making purposes. Because of prior
and expected future ratemaking treatment for temporary differences for which
flow-through tax accounting has been utilized, a regulatory asset for income
taxes recoverable through future rates related to those differences has also
been established. At December 31, 1998, the balance of this asset is $241.4
million.

                                       66
<PAGE>

       The deferred tax liability at December 31, 1998 and 1997, is comprised of
amounts related to the following types of temporary differences

  (DOLLARS IN THOUSANDS)                        1998           1997
--------------------------------------- ------------- --------------
  Utility plant                             $567,642       $558,170
  Investment in Cabot stock                   13,435         13,435
  Energy conservation charges                 57,919         74,376
  Contributions in aid of construction       (31,874)       (30,350)
  Bonneville Exchange Power                   26,513         30,240
  Other                                       (5,081)       (16,853)
--------------------------------------- ------------- --------------
  Total                                     $628,554       $629,018
--------------------------------------- ------------- --------------

       The totals of $628.6 million and $629.0 million for 1998 and 1997 consist
of deferred tax liabilities of $712.2 million and $712.0 million net of deferred
tax assets of $83.6 million and $83.0 million, respectively.

NOTE 14.
         RETIREMENT BENEFITS

       The Company has a defined benefit pension plan covering substantially all
of its employees. Benefits are a function of both age and salary. Additionally,
the Company maintains a non-qualified supplemental retirement plan for officers
and certain director-level employees.
       In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees. These benefits
are provided principally through an insurance company whose premiums are based
on the benefits paid during the year.
       Prior to March 1, 1997, the Company had separate defined benefit plans
covering electric and gas employees. Prior to 1997, the plan covering electric
employees had a measurement date of December 31 and the plan covering gas
employees had a measurement date of September 30.

<TABLE>
<CAPTION>

                                                            PENSION BENEFITS            OTHER BENEFITS
       (DOLLARS IN THOUSANDS)                                  1998         1997         1998         1997
                                                      ---------------------------   -----------------------
       <S>                                                 <C>          <C>           <C>          <C>    
       Change in benefit obligation
       Benefit obligation at beginning of year             $325,063     $293,535      $27,433      $26,243
       Service cost                                           8,550        8,268          229          216
       Interest cost                                         22,862       21,412        1,985        1,895
       Amendments                                             2,540        2,828           --            -
       Actuarial (gain)/loss                                 15,272        3,532        1,896          884
       Mergers, sales and closures                               --       16,304           --           --
       Benefits paid                                        (21,865)     (20,816)      (2,105)      (1,805)
---------------------------------------------------------------------------------   -----------------------
       Benefit obligation at end of year                   $352,422     $325,063      $29,438      $27,433
---------------------------------------------------------------------------------   -----------------------
       Change in plan assets
       Fair value of plan assets at beginning of year      $415,270     $354,634      $14,445      $13,718
       Actual return on plan assets                          67,544       80,548          570          803
       Employer contribution                                  3,246          904        1,222        1,729
       Benefits paid                                        (21,865)     (20,816)      (2,105)      (1,805)
---------------------------------------------------------------------------------   -----------------------
       Fair value of plan assets at end of year            $464,195     $415,270      $14,132      $14,445
---------------------------------------------------------------------------------   -----------------------
</TABLE>

                                       67
<PAGE>

<TABLE>
(continued from previous page)
<CAPTION>
                                                           PENSION BENEFITS                  OTHER BENEFITS
       (DOLLARS IN THOUSANDS)                                  1998         1997               1998         1997
                                                     ----------------------------     ---------------------------
<S>                                                        <C>           <C>               <C>           <C>      
       Funded status                                       $111,773      $90,207           $(15,306)     $(12,988)
       Unrecognized actuarial (gain)/loss                  (133,189)     (117,841)           (1,532)       (3,822)
       Unrecognized prior service cost                       25,510       26,301               (463)         (497)
       Unrecognized net initial (asset)/obligation           (7,563)       (8,794)            8,775        9,402
-----------------------------------------------------------------------------------   -----------------------------
       Net amount recognized                                $(3,469)     $(10,127)          $(8,526)      $(7,905)
-----------------------------------------------------------------------------------   -----------------------------
       Amounts recognized on statement of
         financial position consist of:
       Prepaid benefit cost                                  $8,900       $2,238            $(8,526)      $(7,905)
       Accrued benefit liability                            (22,988)      (16,828)                            --
       Intangible asset                                      10,619        4,463                              --
-----------------------------------------------------------------------------------   -----------------------------
       Net amount recognized                                $(3,469)     $(10,127)          $(8,526)      $(7,905)
-----------------------------------------------------------------------------------   -----------------------------
</TABLE>

       In accounting for pension and other benefits costs under the plans, the
following weighted average actuarial assumptions were used:

<TABLE>
<CAPTION>

                                                    PENSION BENEFITS                          OTHER BENEFITS
                                                1998        1997         1996              1998         1997         1996
                                         ------------ ----------- ------------       ----------- ------------ ------------
<S>                                      <C>          <C>         <C>                <C>         <C>          <C>        
  Discount rate                                   7%   7.25-7.5%         7.5%                7%        7.25%         7.5%
  Return on plan assets                        9.75%          9%       8.5-9%            6-8.5%       6-8.5%       6-8.5%
  Rate of compensation increase                   5%          5%       5-5.5%                --           --           --
  Medical Trend Rate                              --          --           --              7.5%         7.5%           8%
---------------------------------------- ------------ ----------- ------------       ----------- ------------ ------------
</TABLE>

<TABLE>
<CAPTION>

                                                    PENSION BENEFITS                          OTHER BENEFITS
                                                1998        1997         1996              1998         1997         1996
                                         ------------ ----------- ------------       ----------- ------------ ------------
 <S>                                     <C>          <C>         <C>                <C>         <C>          <C>        
 Components of net periodic benefit
  cost:
  (DOLLARS IN THOUSANDS)
  Service cost                                $8,550      $8,268       $6,958              $229         $216         $424
  Interest cost                               22,862      21,412       16,715             1,985        1,895        2,157
  Expected return on plan assets             (33,744)    (27,997)     (20,944)             (867)        (821)        (687)
  Amortization of prior service cost           3,330       2,247        1,258               (34)         (34)          32
  Recognized net actuarial 
  (gain)/loss                                 (3,180)     (1,144)          (3)              (97)        (204)         (230)
  Amortization of transition                  (1,230)     (1,095)        (420)              627          627         1,057
  (asset)/obligation
  Plan curtailments, mergers                      --       5,138       (1,613)                           712         1,418
---------------------------------------- ------------ -----------    ---------       ----------- ------------ ------------
  Net pension benefit cost under              (3,412)      6,829        1,951             1,843        2,391        4,171
  FASB Statement No. 87
  Regulatory adjustment                        1,263       1,263        1,263                --           --           --
---------------------------------------- ------------- ------------- ---------       ----------- ------------ ------------
  Net periodic benefit cost                  $(2,149)     $8,092       $3,214            $1,843       $2,391       $4,171
---------------------------------------- ------------- ------------- ---------       ----------- ------------ ------------
</TABLE>

                                       68
<PAGE>

       The projected benefit obligation, accumulated benefit obligation, and
fair value of plan assets for the pension plans with accumulated benefit
obligations in excess of plan assets were $27.7 million, $23.0 million, and $0,
respectively, as of December 31, 1998.
       The assumed medical inflation rate is 7.5% in 1998 decreasing to 6% in
2003. A 1% change in the assumed medical inflation rate would have the following
effects:

<TABLE>
<CAPTION>

                                                              1998                                1997
                                                     1%                1%                 1%                1%
  (DOLLARS IN THOUSANDS)                          INCREASE          DECREASE             INCREASE        DECREASE
                                              -----------------------------------    ---------------------------------
<S>                                                      <C>               <C>                 <C>              <C>   
  Effect on service and interest cost                    $690              $(671)              $643             $(625)
  components
  Effect on postretirement benefit obligation            $ 45              $(44)                $42              $(41)
</TABLE>

       In December 1995, in connection with the proposed merger with WECo, the
Company offered to its employees a Voluntary Separation Plan. A total of 204
employees elected to participate in the Voluntary Separation Plan resulting in a
curtailment gain for 1996 of $1.6 million under Statement of Financial
Accounting Standards No. 88. In addition, curtailment losses under Statement No.
106 for 1997 of $4.7 million and 1996 of $1.4 million resulted from the 1995
Voluntary Separation Plan. Also in connection with the merger was a curtailment
loss of $5.1 million in 1997 related to the supplemental retirement plans.

NOTE 15.
         EMPLOYEE INVESTMENT PLAN & EMPLOYEE STOCK PURCHASE PLAN

       The Company has qualified Employee Investment Plans under which employee
salary deferrals and after-tax contributions are used to purchase several
different investment fund options. The Company makes a monthly contribution
equal to 100% on up to 4% of participant contributions and 50% on the next 4% of
participant contributions which equates to a maximum contribution of 6% of
eligible earnings. In addition, the Company contributes an amount equal to 1% of
each participant's base pay at the end of the plan year.
       The Company contributions to the Employee Investment Plan were
$6,141,400, $5,068,100 and $4,102,000 for the years 1998, 1997 and 1996,
respectively. The shareholders have authorized the issuance of up to 2,000,000
shares of common stock under the plan, of which 959,142 were issued through
December 31, 1998. The Employee Investment Plan eligibility requirements are set
forth in the plan documents.
       The Company also has an Employee Stock Purchase Plan which was approved
by shareholders on May 19, 1997, and commenced July 1, 1997, under which options
are granted to eligible employees who elect to participate in the plan on
January 1st and July 1st of each year. Participants are allowed to exercise
those options six months later to the extent of payroll deductions or cash
payments accumulated during that six-month period. The option price under the
plan is 90% of either the fair market value of the common stock at the grant
date or the fair market value at the exercise date, whichever is less. The
Company contributions to the Plan were $98,237 and $97,615 for 1998 and 1997,
respectively.

                                       69
<PAGE>

NOTE 16.
         INVESTMENT IN CABOT OIL AND GAS

       In May 1994, the Company merged its oil and gas exploration and
production subsidiary, Washington Energy Resources Company ("Resources"), with a
wholly-owned subsidiary of Cabot Oil and Gas Corporation ("Cabot") in a tax-free
exchange. At December 31, 1998, the Company owned 15.4% of Cabot's outstanding
voting securities consisting of 2,133,000 shares of common stock and 1,134,000
shares of 6% convertible voting preferred stock, stated value $50. Prior to
October 1, 1997, the Company's interest in Cabot's common stock was accounted
for using the equity method because the Company, through its representation on
Cabot's board of directors, had the ability to exercise significant influence
over operating and financial policies of Cabot. Effective October 1, 1997, the
Company discontinued equity-method accounting for Cabot and records its interest
as an investment in stock because the Company no longer has representation on
Cabot's board of directors. Equity in earnings (losses) from Cabot were $948,000
and ($619,000) for 1997 and 1996, respectively.
       The investment in Cabot common stock has been classified as an
available-for-sale security and is reported at its fair value, based on the
closing price on the NYSE on December 31, 1998, of $31,995,000. The unrealized
gain of $8,802,000 (net of deferred taxes of $4,739,000) is reported as a
separate component of common equity. No fair value is readily available for the
Cabot preferred stock as it is not publicly traded; however, its cost basis of
$51,619,000 is believed to be a reasonable approximation of fair value at
December 31, 1998.
       See Note 17 regarding certain gas transportation, storage and other
contractual arrangements of Resources that were excluded from the Cabot merger
and retained by a subsidiary of the Company.

NOTE 17.
         COMMITMENTS AND CONTINGENCIES

Commitments - Electric
       For the twelve months ended December 31, 1998, approximately 20.1% of the
Company's energy output was obtained at an average cost of approximately 11.5
mills per KWH through long-term contracts with several of the Washington public
utility districts ("PUDs") owning hydro-electric projects on the Columbia River.
       The purchase of power from the Columbia River projects is generally on a
"cost-of-service" basis under which the Company pays a proportionate share of
the annual cost of each project in direct proportion to the amount of power
annually purchased by the Company from such project. Such payments are not
contingent upon the projects being operable. These projects are financed through
substantially level debt service payments, and their annual costs should not
vary significantly over the term of the contracts unless additional financing is
required to meet the costs of major maintenance, repairs or replacements or
license requirements. The Company's share of the costs and the output of the
projects is subject to reduction due to various withdrawal rights of the PUDs
and others over the lives of the contracts.
       As of December 31, 1998, the Company was entitled to purchase portions of
the power output of the PUDs' projects as set forth in the following tabulation:

                                       70
<PAGE>

<TABLE>
<CAPTION>

                                                                   BONDS                     COMPANY'S ANNUAL AMOUNT
                                                                OUTSTANDING                 PURCHASABLE (APPROXIMATE)
                                                                                -------------------------------------------------
                           CONTRACT         LICENSE (A)         12/31/98 (B)         % OF          MEGAWATT         COSTS (C)
  PROJECT                  EXP. DATE         EXP. DATE           (MILLIONS)         OUTPUT         CAPACITY         (MILLIONS)
---------------------- ---------------- ------------------- ------------------- ------------- ----------------- -----------------
<S>                               <C>                 <C>                 <C>           <C>                <C>             <C>    
Rock Island
     Original units               2012                2029                72.2          53.9               480             $39.1
     Additional units             2012                2029               319.7         100.0
  Rocky Reach                     2011                2006               227.2          38.9               505              20.8
  Wells                           2018                2012               172.5          31.3               261               9.0
  Priest Rapids                   2005                2005               171.9           8.0                72               2.1
  Wanapum                         2009                2005               194.7          10.8                98               3.2
                                                                                              ----------------- -----------------
  Total                                                                                                  1,416             $74.2
</TABLE>

       (a) The Company is unable to predict whether the licenses under the
Federal Power Act will be renewed to the current licensees. The FERC has issued
orders for Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section
22 of the Federal Power Act, which affirm the Company's contractual rights to
receive power under existing terms and conditions even if a new licensee is
granted a license prior to expiration of the contract term.

       (b) The contracts for purchases initially were generally coextensive with
the term of the PUD bonds associated with the project. Under the terms of some
financings and refinancings, however, long-term bonds were sold to finance
certain assets whose estimated useful lives extend beyond the expiration date of
the power sales contracts. Of the total outstanding bonds sold for each project,
the percentage of principal amount of bonds which mature beyond the contract
expiration date are: 43.7% at Rock Island; 52.2% at Rocky Reach; 80.2% at Priest
Rapids; and 47.8% at Wanapum.

       (c) The components of 1998 costs associated with the interest portion of
debt service are: Rock Island, $23.6 million for all units; Rocky Reach, $4.8
million; Wells, $2.7 million; Priest Rapids, $0.9 million; and Wanapum, $1.2
million.

       The Company's estimated payments for power purchases from the Columbia
River projects are $82 million for 1999, $80 million for 2000, $80 million for
2001, $80 million for 2002, $78 million for 2003 and in the aggregate, $685
million thereafter through 2018.
       The Company also has numerous long-term firm purchased power contracts
with other utilities in the region. The Company is generally not obligated to
make payments under these contracts unless power is delivered. The Company's
estimated payments for firm power purchases from other utilities, excluding the
Columbia River projects, are $151 million for 1999, $157 million for 2000, $151
million for 2001, $143 million for 2002, $132 million for 2003 and in the
aggregate, $1.0 billion thereafter through 2037. These contracts have varying
terms and may include escalation and termination provisions.
       As required by the federal Public Utility Regulatory Policies Act
("PURPA"), the Company entered into long-term firm purchased power contracts
with non-utility generators. The Company purchases the net electrical output of
five significant projects at fixed and annually escalating prices which were
intended to approximate the Company's avoided cost of new generation projected
at the time these agreements were made. Principally, as a result of dramatic
changes in natural gas price levels, the power purchase prices under these
agreements are significantly above the current market price of power and, based
upon projections of future market prices, are expected to remain well above
market for the duration of the contracts. The Company's estimated payment under
these five contracts are $280 million for 1999, $284 million for 2000, $308
million for 2001, $313 million for 2002, $318 million for 2003 and in the
aggregate, $2.4 billion thereafter through 2012. If retail electric energy
prices move to market levels as a result of electric industry restructuring, the
Company plans to seek to continue to recover in rates the above-market portion
of these contract costs.

                                       71
<PAGE>

       The following table summarizes the Company's obligations for future power
purchases.

<TABLE>
<CAPTION>

                                                                                           2004 &
                                                                                           THERE-
(In Millions)                       1999       2000       2001       2002       2003        AFTER        TOTAL
------------------------------ ---------- ---------- ---------- ---------- ---------- ------------ ------------
<S>                            <C>        <C>        <C>        <C>        <C>        <C>          <C>   
  Columbia River Projects            $82        $80        $80        $80        $78         $685       $1,085
  Other Utilities                    151        157        151        143        132        1,000        1,734
  Non-Utility Generators             280        284        308        313        318        2,400        3,903
------------------------------ ---------- ---------- ---------- ---------- ---------- ------------ ------------
      Total                         $513       $521       $539       $536       $528       $4,085       $6,722
------------------------------ ---------- ---------- ---------- ---------- ---------- ------------ ------------
</TABLE>

       Total purchased power contracts provided the Company with approximately
15.8 million, 15.6 million and 17.1 million MWH of firm energy at a cost of
approximately $481.6 million, $464.5 million and $485.6 million for the years
1998, 1997 and 1996, respectively.
       As part of its electric operations and in connection with the 1997
restructuring of the Tenaska Power Purchase Agreement the Company is obligated
to deliver to Tenaska up to 48,000 MMBtu per day of natural gas for operation of
Tenaska's cogeneration facility. This obligation continues for the remaining
term of the agreement, provided that no deliveries are required during the month
of May. The price paid by Tenaska for this gas is reflective of the daily price
of gas at the U.S./Canada border near Sumas, Washington.
       The following table indicates the Company's percentage ownership and the
extent of the Company's investment in jointly-owned generating plants in service
at December 31, 1998:

<TABLE>
<CAPTION>

                                                                             COMPANY'S SHARE
                                                               ------------------------------------------
                              ENERGY            COMPANY'S        PLANT IN SERVICE        ACCUMULATED
        PROJECT           SOURCE (FUEL)      OWNERSHIP SHARE         AT COST            DEPRECIATION
                                                   (%)              (MILLIONS)           (MILLIONS)
----------------------- ----------------- -------------------- ------------------- ----------------------
<S>                     <C>               <C>                  <C>                 <C>
  Centralia               Coal                             7%              $ 26.7                 $ 18.5
  Colstrip 1 & 2          Coal                            50%               187.1                  106.6
  Colstrip 3 & 4          Coal                            25%               452.1                  181.0
</TABLE>

       Financing for a participant's ownership share in the projects is provided
for by such participant. The Company's share of related operating and
maintenance expenses is included in corresponding accounts in the Consolidated
Statements of Income. The Company and other joint owners of the Centralia
Project are exploring alternative emission compliance options and project
economics in light of compliance costs to meet the Phase II limits in the year
2000 and other regulations.
       In November, 1998, the Company announced that it signed an agreement to
sell its interest in the Colstrip plant, as well as associated transmission
facilities to PP&L Global, Inc., of Fairfax, Virginia, a subsidiary of PP&L
Resources, Inc. The sales price is expected to be $549 million before taxes and
expenses. The net book value of these assets and related regulatory assets is
approximately $464 million. After consideration of taxes and other costs, the
gain on the sale is expected to be approximately $37.6 million. The Company
expects the Colstrip sale to close in the second half of 1999. Completion of the
sale is contingent on receipt of acceptable regulatory treatment from the
Washington Commission and the Federal Energy Regulatory Commission. The Company
has also joined with the other owners of the Centralia project in offering for
sale its ownership interest in the facility.
       Certain purchase commitments have been made in connection with the
Company's construction program.

GAS
       The Company has also entered into various firm supply, transportation and
storage service contracts in order to assure adequate availability of gas supply
for its firm customers. Many of these contracts, which have remaining terms from
one to 25 years, provide that the Company must pay a fixed demand charge each
month, regardless of actual usage. Certain of the Company's firm gas supply
agreements also obligate the Company to purchase a minimum annual quantity at
market-based contract prices. Generally, if the minimum volumes are not
purchased and taken during the year, the Company is obligated to pay either: 1)
a monthly or annual gas inventory charge calculated as a percentage of the
then-current contract commodity price times the minimum quantity not taken; or
2) pay for gas not taken. Alternatively, under some of the contracts, the
supplier may exercise a right to reduce its subsequent obligation to provide
firm gas to the Company. The Company incurred demand charges in 1998 for firm
gas supply, firm transportation service and firm storage and peaking service of
$29,571,000, $52,917,000 and $8,832,000, respectively.

                                       72
<PAGE>

       The following tables summarize the Company's obligations for future
demand charges through the primary terms of its existing contracts and the
minimum annual take requirements under the gas supply agreements. The quantified
obligations are based on current contract prices and FERC authorized rates,
which are subject to change.

  DEMAND CHARGE OBLIGATIONS

<TABLE>
<CAPTION>
                                                                                                             2004 &
                                                                                                             THERE-
(In Thousands)                         1999      2000      2001      2002      2003      AFTER      TOTAL
----------------------------------  --------  --------  --------  --------  --------  ---------  ---------
<S>                                 <C>       <C>       <C>       <C>       <C>       <C>        <C>     
  Firm gas supply                   $29,580   $27,271   $27,271   $26,941   $23,442   $ 17,382   $151,887
  Firm transportation service        51,331    51,331    51,279    51,227    51,227    136,291    392,686
  Firm storage & peaking service      8,885     8,885     8,885     8,885     8,885     87,481    131,906
----------------------------------  --------  --------  --------  --------  --------  ---------  ---------
      Total                         $89,796   $87,487   $87,435   $87,053   $83,554   $241,154   $676,479
----------------------------------  --------  --------  --------  --------  --------  ---------  ---------
</TABLE>

  MINIMUM ANNUAL TAKE OBLIGATIONS

<TABLE>
<CAPTION>
                                                                          2004 &
                                                                          THERE-
(In thousands of therms)       1999     2000     2001     2002     2003    AFTER      TOTAL
--------------------------- -------- -------- -------- -------- -------- -------- ----------
<S>                         <C>      <C>      <C>      <C>      <C>      <C>      <C>      
  Firm gas supply           472,443  333,957  333,957  329,157  278,132  121,835  1,869,481
</TABLE>

       The Company believes that all demand charges will be recoverable in rates
charged to its customers. Further, pursuant to implementation of FERC Order No.
636, the Company has the right to resell or release to others any of its
unutilized gas supply or transportation and storage capacity.
       The Company does not anticipate any difficulty in achieving the minimum
annual take obligations shown, as such volumes represent less than 57% of
expected annual sales for 1999 and less than 39% of expected sales in subsequent
years.
       The Company's current firm gas supply contracts obligate the suppliers to
provide, in the aggregate, annual volumes up to those shown below:

  MAXIMUM SUPPLY AVAILABLE UNDER CURRENT FIRM SUPPLY CONTRACTS

<TABLE>
<CAPTION>
                                                                                         2004 &
                                                                                         THERE-
(In thousands of therms)     1999      2000      2001      2002      2003     AFTER       TOTAL
------------------------  --------  --------  --------  --------  --------  --------  ----------
<S>                       <C>       <C>       <C>       <C>       <C>       <C>       <C>      
  Firm gas supply         663,402   511,489   511,489   505,489   444,739   289,209   2,925,817
</TABLE>

       Washington Energy Gas Marketing Company ("WEGM"), a wholly-owned
subsidiary, holds firm rights to transport natural gas on the Nova Corporation
of Alberta ("Nova"), Alberta Natural Gas Company ("ANG") and PG&E Gas
Transmission - Northwest pipelines from Alberta, Canada, to the northern border
of California, as well as certain gas storage rights at the Alberta Energy
Company ("AECO") field in Alberta and the Jackson Prairie field in western
Washington. These rights were formerly held by a wholly-owned subsidiary of
Resources but were excluded from the merger of Resources and Cabot completed in
May 1994. Following the merger, WEGM entered into a five-year contract with IGI
Resources ("IGI"), Boise, Idaho, to manage these rights.

                                       73
<PAGE>

       The transportation rights on the PGT pipeline initially consisted of
approximately 25,000 MMBtu per day of annual capacity and 20,000 MMBtu per day
of winter-only capacity to Stanfield, Oregon, and approximately 20,000 MMBtu per
day of annual capacity to the California border. WEGM held similar rights on
Nova and ANG.
       Effective November 1, 1995, WEGM permanently assigned to IGI all of its
Stanfield capacity and associated rights on Nova and ANG. In addition, WEGM
segmented its capacity to California at Stanfield and permanently assigned
10,000 MMBtu per day of the Alberta to Stanfield rights to a third party
effective November 1, 1995. WEGM's remaining PGT rights expire in October 2023,
and the ANG and Nova rights expire in October 2008, with annual renewal options.
WEGM, as an expansion capacity holder, has been unable to fully recoup its
demand charges, which have been approximately 70% higher than those paid by
holders of vintage capacity. On September 11, 1996, the FERC approved a request
from PGT for the cost of the expansion capacity to be "rolled in" with the cost
of the vintage capacity to establish a uniform rate for holders of both types of
capacity. This change will be implemented in two stages over six years with the
first stage effective November 1, 1996. WEGM's annual obligations for future
demand charges through the primary term of WEGM's gas transportation and storage
contracts are as follows: 1999, $2,847,000; 2000, $2,843,000; 2001, $2,829,000;
2002, $2,819,000; 2003, $2,296,000 and thereafter, $33,413,000. The IGI
management contract provides for incentive payments to IGI based on actual
mitigation of demand charges relative to targets established on an annual basis.
       As of December 31, 1998, WEGM has a reserve for future losses associated
with these contractual obligations of $4,611,000. WEGM initially established the
reserve for estimated future losses associated with the transportation and
storage obligations with a $16,000,000 ($10,400,000 after tax) charge to
earnings upon completion of the merger of Resources and Cabot in May 1994. In
the fourth quarter of 1995, WEGM recorded a $5,000,000 ($3,250,000 after tax)
charge to increase the reserve based on an assessment of the likelihood and
timing of approval of rolled-in rates and actual mitigation results in 1995.
During 1998, 1997 and 1996, pre-tax losses totaling $1,916,000, $2,235,000 and
$2,652,000, respectively, were charged against the reserve.

CONTINGENCIES
       The Company is subject to environmental regulation by federal, state and
local authorities. The Company has been named a Potentially Responsible Party by
the Environmental Protection Agency ("EPA") at several contaminated disposal
sites and manufactured gas plant sites. The Company has implemented an ongoing
program to test, replace and remediate certain underground storage tanks as
required by federal and state laws. Remediation and testing of Company vehicle
service facilities and storage yards is also continuing.
       During 1992, the Washington Commission issued orders regarding the
treatment of costs incurred by the Company for certain sites under its
environmental remediation program. The orders authorize the Company to
accumulate and defer prudently incurred cleanup costs paid to third parties for
recovery in rates established in future rate proceedings. The Company believes a
significant portion of its past and future environmental remediation costs are
recoverable from either insurance companies, third parties or under the
Washington Commission's order.
       The information presented here as it relates to estimates of future
liability is as of December 31, 1998.

ELECTRIC SITES
       The Company has expended approximately $14.5 million related to the
remediation activities covered by the Washington Commission's order, of which
approximately $7.5 million has been recovered from insurance carriers. At
December 31, 1998, approximately $1.8 million has been accrued as a liability
for future remediation costs for these and other remediation activities.

                                       74
<PAGE>

GAS SITES
       Five former WNG or predecessor companies manufactured gas plant ("MGP")
sites are currently undergoing investigation, remedial actions or monitoring
actions relating to environmental contamination: 1) Everett, Washington; 2) "Gas
Works Park" in Seattle, Washington; 3) "Tacoma 22nd and A St." Site in Tacoma,
Washington; 4) Chehalis, Washington; and 5) the "Tideflats" area of Tacoma,
Washington. Legal and remedial costs incurred to date total approximately $50.9
million and currently estimated future remediation costs are approximately $7.0
million. Work at both the Chehalis and Tideflats sites is substantially
completed. To date, the Company has recovered approximately $59 million from
insurance carriers and other third parties.
       Based on all known facts and analyses, the Company believes it is not
likely that the identified environmental liabilities will result in a material
adverse impact on the Company's financial position, operating results or cash
flow trends.

LITIGATION
       Other contingencies, arising out of the normal course of the Company's
business, exist at December 31, 1998. The ultimate resolution of these issues is
not expected to have a material adverse impact on the financial condition,
results of operations or liquidity of the Company.

NOTE 18.
         DISCONTINUED OPERATIONS

     On March 5, 1997, the Company  conveyed its interests in  undeveloped  coal
properties  through its wholly-owned  subsidiary  Thermal Energy,  Inc. to Wesco
Resources, Inc. effective February 1, 1997. The Company's remaining $4.0 million
investment in Thermal Energy, Inc. was written off to expense and appears in the
consolidated financial statements as discontinued operations. Prior periods have
been  restated  to include  Thermal  Energy,  Inc.  operations  as  discontinued
operations.

                                       75
<PAGE>

NOTE 19.
         SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)

       The following unaudited amounts, in the opinion of the Company, include
all adjustments (consisting of normal recurring adjustments) necessary for a
fair presentation of the results of operations for the interim periods.
Quarterly amounts vary during the year due to the seasonal nature of the utility
business.

<TABLE>
<CAPTION>

  (UNAUDITED; DOLLARS IN THOUSANDS EXCEPT PER-SHARE AMOUNTS)
----------------------------- ----------------- ------------------ ------------------- ----------------
  1998 Quarter                           First             Second               Third           Fourth
----------------------------- ----------------- ------------------ ------------------- ----------------
<S>                           <C>               <C>                <C>                 <C>     
  Operating revenues                  $522,069           $365,525            $427,357         $592,389
  Operating income                    $ 99,257           $ 50,012         (a)$ 53,217         $ 96,494
  Other income                          $1,160             $3,512         (a) $ 1,433           $3,087
  Net income                          $ 66,003           $ 19,542            $ 21,091         $ 62,976
  Basic and diluted earnings
    per common share                    $ 0.74             $ 0.19              $ 0.21           $ 0.71
----------------------------- ----------------- ------------------ ------------------- ----------------
</TABLE>

<TABLE>
<CAPTION>

  (UNAUDITED; DOLLARS IN THOUSANDS EXCEPT PER-SHARE AMOUNTS)
------------------------------ ----------------- ------------------ ------------------- ----------------
  1997 Quarter                            First             Second               Third           Fourth
------------------------------ ----------------- ------------------ ------------------- ----------------
<S>                            <C>               <C>                <C>                 <C>     
  Operating revenues                   $463,319           $352,618            $341,021         $519,944
  Operating income                     $ 56,828           $ 45,233            $ 35,421         $ 78,384
  Other income                           $4,884           $ 17,804              $6,029          $  (651)
  Income from continuing
    Operations                         $ 32,608           $ 33,440            $ 11,998         $ 47,652
  Net income                           $ 29,986           $ 33,440            $ 11,998         $ 47,652
  Basic and diluted earnings
    per common share from
    Continuing operations                $ 0.32             $ 0.33              $ 0.11           $ 0.52
------------------------------ ----------------- ------------------ ------------------- ----------------
</TABLE>

       (a) Operating income and other income in the amount of $3.4 million and
$4.3 million, respectively, were reclassed to conform third quarter 1998 Form
10-Q with year-end presentation.

                                       76
<PAGE>

NOTE 20.
         CONSOLIDATED STATEMENT OF CASH FLOWS

       For purposes of the Statement of Cash Flows, the Company considers all
temporary investments to be cash equivalents. These temporary cash investments
are securities held for cash management purposes, having maturities of three
months or less. The net change in current assets and current liabilities for
purposes of the Statement of Cash Flows excludes short-term debt, current
maturities of long-term debt and the current portion of PRAM accrued revenues.
At December 31, 1998, $15,710,000 related to a book overdraft was included in
accounts payable.
       The following provides additional information concerning cash flow
activities:

<TABLE>
<CAPTION>

------------------------------------------------------------------ ------------- -------------- --------------
  (YEAR ENDED DECEMBER 31; DOLLARS IN THOUSANDS)                           1998           1997           1996
------------------------------------------------------------------ ------------- -------------- --------------
<S>                                                                <C>           <C>            <C>    
  Changes in certain current assets and current liabilities:
      Accounts receivable                                              $(43,003)      $ (4,164)      $(22,242)
      Unbilled revenue                                                   (3,909)         4,591        (11,104)
      Materials and supplies                                             (4,111)         3,316         16,737
      Prepayments and other                                              (1,876)         5,339          1,491
      Purchased gas liability                                            (6,368)       (34,966)        25,814
      Accounts payable                                                   27,082          7,132         15,997
      Accrued expenses and other                                          9,493        (39,642)         1,116
------------------------------------------------------------------ ------------- -------------- --------------
  Net change in certain current assets
    and current liabilities                                            $(22,692)      $(58,394)       $27,809
------------------------------------------------------------------ ------------- --------------- -------------
  Cash payments:
      Interest (net of capitalized interest)                           $131,567       $119,810       $113,634
      Income taxes                                                     $119,664       $104,161       $ 98,609
------------------------------------------------------------------ ------------- -------------- --------------
</TABLE>

NOTE 21.
         MERGER OF PUGET POWER AND WECO

       Included in consolidated results of operations for the month of January
1997 and for the year ended December 31, 1996, are the following results of the
previously separate companies for those periods (Dollars in Thousands):

                                       MONTH ENDED              YEAR ENDED
                                     JANUARY 31, 1997          DECEMBER 31, 1996
                                    PUGET        WECO         PUGET         WECO
                             ------------- ----------- ------------- -----------
  Revenues                       $123,051     $60,486    $1,223,568     $425,711
  Net Income                      $19,671      $9,378     $ 135,371     $ 30,148
  Common Dividends Declared       $29,244          --     $ 117,099     $ 24,149

       WECo's operations for the three months ended December 31, 1996, have been
reported as an adjustment of $10.8 million to consolidated retained earnings in
the first quarter of 1997. WECo's revenues for the three months ended December
31, 1996, were $148.6 million, net income was $16.9 million, common stock issued
was $1.0 million and common stock dividends declared were $6.1 million for the
same period.

                                       77
<PAGE>

       In connection with the merger, the Company recognized direct and indirect
merger-related expenses of $55.8 million during the first quarter of 1997. The
charge consisted primarily of severance costs of $15.5 million, benefit-related
curtailment costs of $9.1 million, transaction costs of $13.7 million and
systems and facilities integration costs of $7.2 million. The nonrecurring
charge reduced net income by approximately $36.3 million or $0.43 per share. In
addition, merger-related costs of $4.8 million were recognized in the fourth
quarter of 1996 by Puget Power.

NOTE 22.
         SEGMENT INFORMATION

       The Company primarily operates in one business segment, Regulated Utility
Operations. The Company's regulated utility operation generates, purchases and
sells electricity and purchases, transports and sells natural gas. The Company's
service territory covers approximately 6,000 square miles in the state of
Washington.
       Principal non-utility lines of business include real estate investment
and development, home security services and energy-related services. Reconciling
items between segments are not material.

       Financial data for business segments are as follows:

  (DOLLARS IN THOUSANDS)
                                      Regulated
                       1998             UTILITY         OTHER          TOTAL
-----------------------------------------------------------------------------
  Revenues                           $1,891,759       $15,581     $1,907,340
  Depreciation & Amortization           165,491            96        165,587
  Federal Income Tax                    106,967           937        107,904
  Operating Income                      292,337         6,643        298,980
  Interest Charges, net of AFUDC        138,560             0        138,560
  Net Income                            170,435          (823)       169,612
  Total Assets                        4,630,501        90,188      4,720,689
-----------------------------------------------------------------------------

                                      REGULATED
                       1997             UTILITY         OTHER          TOTAL
-----------------------------------------------------------------------------
  Revenues                           $1,640,871       $36,031     $1,676,902
  Depreciation & Amortization           161,402           463        161,865
  Federal Income Tax                     34,230        13,495         47,725
  Operating Income                      215,126           740        215,866
  Interest Charges, net of AFUDC        117,258           976        118,234
  Net Income                            123,872          (796)       123,076
  Total Assets                        4,414,396        78,974      4,493,370
-----------------------------------------------------------------------------

                                      REGULATED
                       1996             UTILITY         OTHER          TOTAL
-----------------------------------------------------------------------------
  Revenues                           $1,598,877       $50,402     $1,649,279
  Depreciation & Amortization           143,613           593        144,206
  Federal Income Tax                    105,236         2,511        107,747
  Operating Income                      269,652        14,822        284,474
  Interest Charges, net of AFUDC        108,688        10,028        118,716
  Net Income                            171,144        (5,625)       165,519
  Total Assets                        4,049,113       178,357      4,227,470
-----------------------------------------------------------------------------

                                       78
<PAGE>

SCHEDULE II.
         VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

  (DOLLARS IN THOUSANDS)
                                                ADDITIONS
                                   BALANCE AT  CHARGED TO                BALANCE
                                    BEGINNING   COSTS AND                 AT END
                                    OF PERIOD    EXPENSES  DEDUCTIONS  OF PERIOD
                                     --------- ----------- ----------- ---------
---------------------------------
  YEAR ENDED DECEMBER 31, 1998
---------------------------------
  Accounts deducted from assets 
  on balance sheet:
    Allowance for doubtful
      accounts receivable               $ 971      $5,905      $5,855    $1,021
--------------------------------- ------------ ----------- ----------- ---------
  YEAR ENDED DECEMBER 31, 1997
---------------------------------
  Accounts deducted from assets 
  on balance sheet:
    Allowance for doubtful
      accounts receivable  (a)         $1,700      $5,080      $5,809      $971
--------------------------------- ------------ ----------- ----------- ---------
  YEAR ENDED DECEMBER 31, 1996
---------------------------------
  Accounts deducted from assets 
  on balance sheet:
    Allowance for doubtful
      accounts receivable              $1,865      $5,920      $6,085    $1,700
--------------------------------- ------------ ----------- ----------- ---------

     (a) Includes  additions of $369 and  deductions  of $384 related to October
through December 1996 for WECo.

                                       79
<PAGE>

EXHIBIT INDEX

       Certain of the following exhibits are filed herewith. Certain other of
the following exhibits have heretofore been filed with the Commission and are
incorporated herein by reference.
     2.1  Agreement  and Plan of Merger dated as of October 18, 1995,  among the
Registrant,  Washington  Energy  Company and  Washington  Natural  Gas  Company.
(Exhibit 2.1 to Registration No. 333-617)
       3-a Restated Articles of Incorporation of the Company. (Included as Annex
F to the Joint Proxy Statement/Prospectus filed February 1, 1996, Registration
No. 333-617)
     3-b  Restated  Bylaws of the  Company.  (Exhibit 3 to  Company's  Quarterly
Report on Form 10-Q for the quarter  ended June 30,  1997,  Commission  File No.
1-4393)
       4.1 Fortieth through Seventy-seventh Supplemental Indentures defining the
rights of the holders of the Company's First Mortgage Bonds. (Exhibit 2-d to
Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347; Exhibits 2-e
through and including 2-k to Registration No. 2-60200; Exhibit 4-h to
Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No. 2-60200;
Exhibits 2-m to Registration No. 2-37645; Exhibit 2-o through and including 2-s
to Registration No. 2-60200; Exhibit 5-b to Registration No. 2-62883; Exhibit
2-h to Registration No. 2-65831; Exhibit (4)-j-1 to Registration No. 2-72061;
Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No.
1-4393; Exhibits (4)(a) and (4)(b) to Company's Current Report on Form 8-K,
dated April 22, 1986; Exhibit (4)a to Company's Current Report on Form 8-K,
dated September 5, 1986; Exhibit (4)-b to Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1986, Commission File No. 1-4393;
Exhibit (4)-c to Registration No. 33-18506; Exhibit (4)-b to Annual Report on
Form 10-K for the fiscal year ended December 31, 1989, Commission File No.
1-4393; Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended
December 31, 1990, Commission File No. 1-4393; Exhibits (4)-b and (4)-c to
Registration No. 33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit
(4)-a to Registration No. 33-53056; Exhibit 4.3 to Registration No. 33-63278;
Exhibit 4.25 to Registration No. 333-41181; and Exhibit 4.27 to Current Report
on Form 8-K dated March 5, 1999.)
       4.2 Rights Agreement, dated as of January 15, 1991, between the Company
and The Chase Manhattan Bank, N.A., as Rights Agent. (Exhibit 2.1 to
Registration Statement on Form 8-A filed on January 17, 1991, Commission File
No. 1-4393)
       4.3 Amendment No. 1 dated as of August 30, 1991, to the Rights Agreement
dated as of January 15, 1991, between the Registrant and the Bank of New York
(as successor to The Chase Manhattan Bank, N.A.), as Rights Agent. (Exhibit 2.1
to Registration Statement on Form 8 filed on August 30, 1991)
       4.4 Amendment No. 2 dated as of October 18, 1995, to the Rights Agreement
dated as of January 15, 1991, between the Registrant and The Bank of New York
(as successor to The Chase Manhattan Bank, N.A.), as Rights Agent. (Exhibit 1 to
Registration Statement on Form 8-A/A filed on October 27, 1995)
     4.5 Pledge  Agreement  dated  August 1, 1991,  between  the Company and The
First National Bank of Chicago,  as Trustee.  (Exhibit (4)-j to Registration No.
33-45916)
     4.6 Loan  Agreement  dated  August 1, 1991,  between  the City of  Forsyth,
Rosebud  County,  Montana and the Company.  (Exhibit (4)-k to  Registration  No.
33-45916)
       4.7 Statement of Relative Rights and Preferences for the Adjustable Rate
Cumulative Preferred Stock, Series B ($25 Par Value). (Exhibit 1.1 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File No.
1-4393)
     4.8 Statement of Relative Rights and Preferences for the Preference  Stock,
Series R, $50 Par Value.  (Exhibit  1.5 to  Registration  Statement  on Form 8-A
filed February 14, 1994, Commission File No. 1-4393)
     4.9  Statement  of Relative  Rights and  Preferences  for the 7 3/4% Series
Preferred  Stock  Cumulative,  $100  Par  Value.  (Exhibit  1.6 to  Registration
Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
       4.10 Pledge Agreement, dated as of March 1, 1992, by and between the
Company and Chemical Bank relating to a series of first mortgage bonds. (Exhibit
4.15 to Annual Report on Form 10-K for the fiscal year ended December 31, 1993,
Commission File No. 1-4393)

                                       80
<PAGE>

       4.11 Pledge Agreement, dated as of April 1, 1993, by and between the
Company and The First National Bank of Chicago, relating to a series of first
mortgage bonds. (Exhibit 4.16 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, Commission File No. 1-4393)
       4.12 Form of Statement of Relative Rights and Preferences for the Series
II Cumulative Preferred Stock, $25 Par Value (included as Annex F to the Joint
Proxy Statement/Prospectus filed February 1, 1996).
       4.13 Form of Statement of Relative Rights and Preferences for the Series
III Cumulative Preferred Stock, $25 Par Value (included as Annex F to the Joint
Proxy Statement/Prospectus filed February 1, 1996).
       4.14 Indenture of First Mortgage dated as of April 1, 1957 (incorporated
herein by reference to Washington Natural Gas Company Exhibit 4-B, Registration
No. 2-14307).
       4.15 Sixth Supplemental Indenture dated as of August 1, 1966
(incorporated herein by reference to Washington Natural Gas Company Exhibit to
Form 8-K for month of August 1966, File No. 0-951).
       4.16 Twelfth Supplemental Indenture dated as of November 1, 1972
(incorporated herein by reference to Washington Natural Gas Company Exhibit to
Form 8-K for November 1972, File No. 0-951).
       4.17 Seventeenth Supplemental Indenture dated as of August 9, 1978
(incorporated herein by reference to Washington Energy Company Exhibit 5-K.18,
Registration No. 2-64428).
       4.18 Twenty-sixth Supplemental Indenture dated as of September 1, 1990
(incorporated herein by reference to Washington Natural Gas Company Exhibit
4-B.19, Form 10-K for the year ended September 30, 1990, File No. 0-951).
       4.19 Twenty-seventh Supplemental Indenture dated as of September 1, 1990
(incorporated herein by reference to Washington Natural Gas Company Exhibit
4-B.20, Form 10-K for the year ended September 30, 1988, File No. 0-951).
       4.20 Twenty-eighth Supplemental Indenture dated as of July 31, 1991
(incorporated herein by reference to Washington Natural Gas Company Exhibit 4-A,
Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
       4.21 Twenty-ninth Supplemental Indenture dated as of June 1, 1993
(incorporated herein by reference to Exhibit 4-A of Washington Natural Gas
Company's S-3 Registration Statement, Registration No. 33-49599).
       4.22 Thirtieth Supplemental Indenture dated as of August 15, 1995
(incorporated herein by reference to Exhibit 4-A of Washington Natural Gas
Company's S-3 Registration Statement, Registration No. 33-61859).
     10.1 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 1 of Chelan County, Washington and the Company, relating to
the Rock Island Project. (Exhibit 13-b to Registration No. 2-24262)
     10.2 First Amendment,  dated as of October 4, 1961, to Power Sales Contract
between  Public  Utility  District No. 1 of Chelan  County,  Washington  and the
Company,  relating to the Rocky Reach Project. (Exhibit 13-d to Registration No.
2-24252)
     10.3 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 1 of Chelan County, Washington and the Company, relating to
the Rocky Reach Project. (Exhibit 13-e to Registration No. 2-24252)
     10.4 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 2 of Grant County,  Washington and the Company, relating to
the Priest Rapids Development. (Exhibit 13-j to Registration No. 2-24252)
     10.5 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 2 of Grant County,  Washington and the Company, relating to
the Wanapum Development. (Exhibit 13-n to Registration No. 2-24252)
     10.6 First  Amendment,  dated  February 9, 1965,  to Power  Sales  Contract
between  Public  Utility  District No. 1 of Douglas  County,  Washington and the
Company,  relating to the Wells  Development.  (Exhibit 13-p to Registration No.
2-24252)
     10.7 First  Amendment,  executed as of February 9, 1965, to Reserved  Share
Power Sales Contract  between Public Utility  District No. 1 of Douglas  County,
Washington and the Company, relating to the Wells Development.  (Exhibit 13-r to
Registration No. 2-24252)
     10.8 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 1 of Douglas County,  Washington and the Company,  relating
to the Wells Development. (Exhibit 13-u to Registration No. 2-24252)

                                       81
<PAGE>

     10.9 Pacific Northwest Coordination Agreement, executed as of September
15, 1964, among the United States of America, the Company and most of the other
major electrical utilities in the Pacific Northwest. (Exhibit 13-gg to
Registration No. 2-24252)
     10.10 Contract dated November 14, 1957, between Public Utility District No.
1 of Chelan  County,  Washington  and the  Company,  relating to the Rocky Reach
Project. (Exhibit 4-1-a to Registration No. 2-13979)
     10.11 Power Sales Contract,  dated as of November 14, 1957,  between Public
Utility District No. 1 of Chelan County, Washington and the Company, relating to
the Rocky Reach Project. (Exhibit 4-c-1 to Registration No. 2-13979)
     10.12 Power Sales  Contract,  dated May 21, 1956,  between  Public  Utility
District No. 2 of Grant  County,  Washington  and the  Company,  relating to the
Priest Rapids Project. (Exhibit 4-d to Registration No. 2-13347)
     10.13 First  Amendment to Power Sales  Contract dated as of August 5, 1958,
between  the  Company  and  Public  Utility  District  No.  2 of  Grant  County,
Washington,  relating  to  the  Priest  Rapids  Development.  (Exhibit  13-h  to
Registration No. 2-15618)
     10.14 Power Sales  Contract  dated June 22, 1959,  between  Public  Utility
District No. 2 of Grant  County,  Washington  and the  Company,  relating to the
Wanapum Development. (Exhibit 13-j to Registration No. 2-15618)
     10.15  Reserve  Share Power Sales  Contract  dated June 22,  1959,  between
Public  Utility  District  No. 2 of Grant  County,  Washington  and the Company,
relating  to the  Priest  Rapids  Project.  (Exhibit  13-k to  Registration  No.
2-15618)
     10.16 Agreement to Amend Power Sales Contracts dated July 30, 1963, between
Public  Utility  District  No. 2 of Grant  County,  Washington  and the Company,
relating to the Wanapum Development. (Exhibit 13-1 to Registration No. 2-21824)
     10.17 Power Sales  Contract  executed as of  September  18,  1963,  between
Public  Utility  District No. 1 of Douglas  County,  Washington and the Company,
relating to the Wells Development (Exhibit 13-r to Registration No. 2-21824)
     10.18  Reserved  Share Power Sales  Contract  executed as of September  18,
1963,  between Public Utility  District No. 1 of Douglas County,  Washington and
the Company,  relating to the Wells  Development.  (Exhibit 13-s to Registration
No. 2-21824)
       10.19 Exchange Agreement dated April 12, 1963, between the United States
of America, Department of the Interior, acting through the Bonneville Power
Administration and Washington Public Power Supply System and the Company,
relating to the Hanford Project. (Exhibit 13-u to Registration 2-21824)

       10.20 Replacement Power Sales Contract dated April 12, 1963, between the
United States of America, Department of the Interior, acting through the
Bonneville Power Administrator and the Company, relating to the Hanford Project.
(Exhibit 13-v to Registration No. 2-21824)
     10.21 Contract  covering  undivided  interest in ownership and operation of
Centralia  Thermal Plant,  dated May 15, 1969.  (Exhibit 5-b to Registration No.
2-3765)
     10.22  Construction  and  Ownership  Agreement  dated as of July 30,  1971,
between The Montana Power Company and the Company.  (Exhibit 5-b to Registration
No. 2-45702)
     10.23  Operation  and  Maintenance  Agreement  dated as of July  30,  1971,
between The Montana Power Company and the Company.  (Exhibit 5-c to Registration
No. 2-45702)
     10.24 Coal Supply  Agreement,  dated as of July 30, 1971, among The Montana
Power  Company,  the  Company  and  Western  Energy  Company.  (Exhibit  5-d  to
Registration No. 2-45702)
     10.25 Power Purchase  Agreement with Washington  Public Power Supply System
and the Bonneville Power  Administration dated February 6, 1973. (Exhibit 5-e to
Registration No. 2-49029)
     10.26 Ownership Agreement among the Company, Washington Public Power Supply
System and others dated September 17, 1973.  (Exhibit 5-a-29 to Registration No.
2-60200)
     10.27 Contract dated June 19, 1974,  between the Company and P.U.D No. 1 of
Chelan County. (Exhibit D to Form 8-K dated July 5, 1974)

                                       82
<PAGE>

       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)

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       10.44 Settlement Exchange Agreement ("Bonneville Exchange Power
Contract") executed by the United States of America Department of Energy acting
by and through the Bonneville Power Administration and the Company, dated
September 17, 1985. (Exhibit B of Exhibit (10)-50 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
       10.45 Settlement Agreement and Covenant Not to Sue between the Company
and Northern Wasco County People's Utility District, dated October 16, 1985.
(Exhibit (10)-53 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1985, Commission File No. 1-4393)
       10.46 Settlement Agreement and Covenant Not to Sue between the Company
and Tillamook People's Utility District, dated October 16, 1985. (Exhibit
(10)-54 to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No. 1-4393)
       10.47 Settlement Agreement and Covenent Not to Sue between the Company
and Clatskanie People's Utility District, dated September 30, 1985. (Exhibit
(10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No.
1-4393)
       10.48 Stipulation and Settlement Agreement between the Company and
Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October 31, 1986.
(Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1986, Commission File No. 1-4393)
       10.49 Transmission Agreement dated April 17, 1981, between the Bonneville
Power Administration and the Company (Colstrip Project). (Exhibit (10)-55 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
       10.50 Transmission Agreement dated April 17, 1981, between the Bonneville
Power Administration and Montana Intertie Users (Colstrip Project). (Exhibit
(10)-56 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No.
1-4393)
       10.51 Ownership and Operation Agreement dated as of May 6, 1981, between
the Company and other Owners of the Colstrip Project (Colstrip 3 and 4).
(Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No.
1-4393)
       10.52 Colstrip Project Transmission Agreement dated as of May 6, 1981,
between the Company and Owners of the Colstrip Project. (Exhibit (10)-58 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
       10.53 Common Facilities Agreement dated as of May 6, 1981, between the
Company and Owners of Colstrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File
No. 1-4393)
       10.54 Agreement for the Purchase of Power dated as of October 29, 1984,
between South Fork II, Inc. and the Company (Weeks Falls Hydroelectric Project).
(Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
       10.55 Agreement for the Purchase of Power dated as of October 29, 1984,
between South Fork Resources, Inc. and the Company (Twin Falls Hydroelectric
Project). (Exhibit (10)-61 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
       10.56 Agreement for Firm Purchase Power dated as of January 4, 1988,
between the City of Spokane, Washington and the Company (Spokane Waste
Combustion Project). (Exhibit (10)-62 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
       10.57 Agreement for Evaluating, Planning and Licensing dated as of
February 21, 1985 and Agreement for Purchase of Power dated as of February 21,
1985 between Pacific Hydropower Associates and the Company (Koma Kulshan
Hydroelectric Project). (Exhibit (10)-63 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
       10.58 Power Sales Agreement dated as of August 1, 1986, between Pacific
Power & Light Company ("PacifiCorp")and the Company. (Exhibit (10)-64 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File
No. 1-4393)
       10.59 Agreement for Purchase and Sale of Firm Capacity and Energy dated
as of August 1, 1986 between The Washington Water Power Company ("Avista") and
the Company. (Exhibit (10)-65 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)

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<PAGE>

       10.60 Amendment dated as of June 1, 1968, to Power Sales Contract between
Public Utility District No. 1 of Chelan County, Washington and the Company
(Rocky Reach Project). (Exhibit (10)-66 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
       10.61 Coal Supply Agreement dated as of October 30, 1970, between the
Washington Irrigation & Development Company and the Company and other Owners of
the Centralia Thermal Project (Centralia Generating Plant). (Exhibit (10)-67 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
       10.62 Interruptible Natural Gas Service Agreement dated as of May 14,
1980, between Cascade Natural Gas Corporation and the Company (Whitehorn
Combustion Turbine). (Exhibit (10)-68 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
       10.63 Interruptible Natural Gas Service Agreement dated as of January 31,
1983, between Cascade Natural Gas Corporation and the Company (Fredonia
Generating Station). (Exhibit (10)-69 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
       10.64 Interruptible Gas Service Agreement dated May 14, 1981, between
Washington Natural Gas Company and the Company (Fredrickson Generating Station).
(Exhibit (10)-70 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
       10.65 Settlement Agreement dated April 24, 1987, between Public Utility
District No. 1 of Chelan County, the National Marine Fisheries Service, the
State of Washington, the State of Oregon, the Confederated Tribes and Bands of
the Yakima Indian Nation, Colville Indian Reservation, Umatilla Indian
Reservation, the National Wildlife Federation and the Company (Rock Island
Project). (Exhibit (10)-71 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
       10.66 Amendment No. 2 dated as of September 1, 1981, and Amendment No. 3
dated September 14, 1987, to Coal Supply Agreement between Western Energy
Company and the Company and the other Owners of Colstrip 3 and 4. (Exhibit
(10)-72 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
       10.67 Amendatory Agreement No. 1 dated August 27, 1982, and Amendatory
Agreement No. 2 dated August 27, 1982, to the Power Sales Contract between the
Company and the Bonneville Power Administration dated August 27, 1982. (Exhibit
(10)-73 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
       10.68 Transmission Agreement dated as of December 30, 1987, between the
Bonneville Power Administration and the Company (Rock Island Project). (Exhibit
(10)-74 to Annual Report on Form 10-K for the fiscal year ended December 31,
1988, Commission File No.
1-4393)
       10.69 Agreement for Purchase and Sale of Firm Capacity and Energy between
The Washington Water Power Company and the Company dated as of January 1, 1988.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31,
1988, Commission File No. 1-4393)
       10.70 Amendment dated as of August 10, 1988, to Agreement for Firm
Purchase Power dated as of January 4, 1988, between the City of Spokane,
Washington and the Company (Spokane Waste Combustion Project).(Exhibit (10)-76
to Annual Report on Form 10-K for the fiscal year ended December 31, 1988,
Commission File No. 1-4393)
       10.71 Agreement for Firm Power Purchase dated October 24, 1988, between
Northern Wasco People's Utility District and the Company (The Dalles Dam North
Fishway). (Exhibit (10)-77 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1988, Commission File No. 1-4393)
       10.72 Agreement for the Purchase of Power dated as of October 27, 1988,
between Pacific Power & Light Company (PacifiCorp) and the Company. (Exhibit
(10)-78 to Annual Report on Form 10-K for the fiscal year ended December 31,
1988, Commission File No. 1-4393)
       10.73 Agreement for Sale and Exchange of Firm Power dated as of November
23, 1988, between the Bonneville Power Administration and the Company. (Exhibit
(10)-79 to Annual Report on Form 10-K for the fiscal year ended December 31,
1988, Commission File No.
1-4393)

                                       85
<PAGE>

       10.74 Agreement for Firm Power Purchase, dated as of February 24, 1989,
between Sumas Energy, Inc. and the Company. (Exhibit (10)-1 to Quarterly Report
on Form 10-Q for the quarter ended March 31, 1989, Commission File No. 1-4393)
       10.75 Settlement Agreement, dated as of April 27, 1989, between Public
Utility District No. 1 of Douglas County, Washington, Portland General Electric
Company ("Enron"), PacifiCorp, The Washington Water Power Company ("Avista") and
the Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q quarter ended
September 30, 1989, Commission File No. 1-4393)
       10.76 Agreement for Firm Power Purchase (Thermal Project), dated as of
June 29, 1989, between San Juan Energy Company and the Company. (Exhibit (10)-2
to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989,
Commission File No. 1-4393)
       10.77 Agreement for Verification of Transfer, Assignment and Assumption,
dated as of September 15, 1989, between San Juan Energy Company, March Point
Cogeneration Company and the Company. (Exhibit (10)-3 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)
       10.78 Power Sales Agreement between The Montana Power Company and the
Company, dated as of October 1, 1989. (Exhibit (10)-4 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)
       10.79 Conservation Power Sales Agreement dated as of December 11, 1989,
between Public Utility District No. 1 of Snohomish County and the Company.
(Exhibit (10)-87 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1989, Commission File No. 1-4393)
       10.80 Memorandum of Understanding dated as of January 24, 1990, between
the Bonneville Power Administration and The Washington Public Power Supply
System, Portland General Electric Company ("Enron"), Pacific Power & Light
Company ("PacifiCorp"), The Montana Power Company, and the Company. (Exhibit
(10)-88 to Annual Report on Form 10-K for the fiscal year ended December 31,
1989, Commission File No. 1-4393)
       10.81 Amendment No. 1 to Agreement for the Assignment of Power from the
Centralia Thermal Project dated as of January 1, 1990, between Public Utility
District No. 1 of Grays Harbor County, Washington and the Company. (Exhibit
(10)-89 to Annual Report on Form 10-K for the fiscal year ended December 31,
1990, Commission File No. 1-4393)
       10.82 Preliminary Materials and Equipment Acquisition Agreement dated as
of February 9, 1990, between Northwest Pipeline Corporation and the Company.
(Exhibit (10)-90 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1990, Commission File No. 1-4393)
       10.83 Amendment No. 1 to the Colstrip Project Transmission Agreement
dated as of February 14, 1990, among the Montana Power Company, The Washington
Water Power Company ("Avista"), Portland General Electric Company ("Enron"),
PacifiCorp and the Company. (Exhibit (10)-91 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1990, Commission File No. 1-4393)
       10.84 Settlement Agreement dated as of February 27, 1990, among United
States of America Department of Energy acting by and through the Bonneville
Power Administration, the Washington Public Power Supply System, and the
Company. (Exhibit (10)-92 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1990, Commission File No. 1-4393)
       10.85 Amendment No. 1 to the Fifteen-Year Power Sales Agreement dated as
of April 18, 1990, between Pacificorp and the Company. (Exhibit (10)-93 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1990,
Commission File No. 1-4393)
       10.86 Settlement Agreement dated as of October 1, 1990, among Public
Utility District No. 1 of Douglas County, Washington, the Company, Pacific Power
and Light Company ("PacifiCorp"), The Washington Water Power Company ("Avista"),
Portland General Electric Company ("Enron"), the Washington Department of
Fisheries, the Washington Department of Wildlife, the Oregon Department of Fish
and Wildlife, the National Marine Fisheries Service, the U.S. Fish and Wildlife
Service, the Confederated Tribes and Bands of the Yakima Indian Nation, the
Confederated Tribes of the Umatilla Reservation, and the Confederated Tribes of
the Colville Reservation. (Exhibit (10)-95 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)
       10.87 Agreement for Firm Power Purchase dated July 23, 1990, between
Trans-Pacific Geothermal Corporation, a Nevada corporation, and the Company.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31,
1991, Commission File No. 1-4393)

                                       86
<PAGE>

       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)

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<PAGE>

       10.103 Centralia Fuel Supply Agreement, dated as of January 1, 1991,
between Pacificorp Electric Operations and the Company and other Owners of the
Centralia Steam-Electric Power Plant. (Exhibit (10)-113 to Annual Report on Form
10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
       10.104 Agreement for Firm Power Purchase dated August 10, 1992, between
Pyrowaste Corporation, Puget Sound Pyroenergy Corporation and the Company.
(Exhibit (10)-114 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, Commission File No. 1-4393)
       10.105 Memorandum of Termination dated August 31, 1992, between Encogen
Northwest, L.P. and the Company. (Exhibit (10)-115 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
       10.106 Agreement Regarding Security dated August 31, 1992, between
Encogen Northwest, L.P. and the Company. (Exhibit (10)-116 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
       10.107 Consent and Agreement dated December 15, 1992, between the
Company, Encogen Northwest, L.P. and The First National Bank of Chicago, as
collateral agent. (Exhibit (10)-117 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1992, Commission File No. 1-4393)
       10.108 Subordination Agreement dated December 17, 1992, between the
Company, Encogen Northwest, L.P., Rolls-Royce & Partners Finance Limited and The
First National Bank of Chicago. (Exhibit (10)-118 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
       10.109 Letter Agreement dated December 18, 1992, between Encogen
Northwest, L.P. and the Company regarding arrangements for the application of
insurance proceeds. (Exhibit (10)-119 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
       10.110 Guaranty of Ensearch Corporation in favor of the Company dated
December 15, 1992. (Exhibit (10)-120 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
       10.111 Letter Agreement dated October 12, 1992, between Tenaska
Washington Partners, L.P. and the Company regarding clarification of issues
under the Agreement for Firm Power Purchase. (Exhibit (10)-121 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
       10.112 Consent and Agreement dated October 12, 1992, between the Company
and The Chase Manhattan Bank, N.A., as agent. (Exhibit (10)-122 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
       10.113 Settlement Agreement dated December 29, 1992, between the Company
and the Bonneville Power Administration (BPA) providing for power purchase by
BPA. (Exhibit (10)-123 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, Commission File No. 1-4393)
       10.114 Contract with W. S. Weaver, Executive Vice President & Chief
Financial Officer, dated April 24, 1991. (Exhibit 10.114 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1993, Commission File No.
1-4393)
       10.115 General Transmission Agreement dated as of December 1, 1994,
between the Bonneville Power Administration and the Company (BPA Contract No.
DE-MS79-94BP93947) (Exhibit 10.115 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1994, Commission File No. 1-4393)
       10.116 PNW AC Intertie Capacity Ownership Agreement dated as of October
11, 1994 between the Bonneville Power Administration and the Company (BPA
Contract No. DE-MS79-94BP94521) (Exhibit 10.116 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, Commission File No. 1-4393)
       10.117 Power Exchange Agreement dated as of September 27, 1995, between
British Columbia Power Exchange Corporation and the Company. (Exhibit 10.117 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1996,
Commission File No. 1-4393)
     10.118  Contract  with W. S. Weaver,  Executive  Vice  President  and Chief
Financial Officer,  dated October 18, 1996.  (Exhibit 10.118 to Annual Report on
Form 10-K for the fiscal  year ended  December  31,  1996,  Commission  File No.
1-4393)
     10.119  Contract with S. M. Vortman,  Senior Vice  President  Corporate and
Regulatory  Relations,  dated October 18, 1996. (Exhibit 10.119 to Annual Report
on Form 10-K for the fiscal year ended  December 31, 1996,  Commission  File No.
1-4393)

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<PAGE>

     10.120  Contract  with G.  B.  Swofford,  Senior  Vice  President  Customer
Operations,  dated  October 18, 1996.  (Exhibit  10.120 to Annual Report on Form
10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393)
       10.121 Service Agreement dated September 1, 1987 between Northwest
Pipeline Corporation and Washington Natural Gas Company for SGS-1 firm storage
service at Jackson Prairie (incorporated herein by reference to Washington
Natural Gas Company Exhibit 10-A Form 10-K for the year ended September 30,
1994, File No. 11271).
       10.122 Service Agreement dated April 14, 1993 between Questar Pipeline
Corporation and Washington Natural Gas Company for FSS-1 firm storage service at
Clay Basin (incorporated herein by reference to Washington Natural Gas Company
Exhibit 10-B Form 10-K for the year ended September 30, 1994, File No. 11271).
       10.123 Service Agreement dated November 1, 1989, with Northwest Pipeline
Corporation covering liquefaction storage gas service filed under cover of Form
SE dated December 27, 1989.
       10.124 Firm Transportation Service Agreement dated October 1, 1990,
between Northwest Pipeline Corporation and Washington Natural Gas Company
(incorporated herein by reference to Washington Natural Gas Company Exhibit 10-D
Form 10-K for the year ended September 30, 1994, File No. 11271).
       10.125 Gas Transportation Service Contract dated June 29, 1990, between
Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated
herein by reference to Washington Natural Gas Company Exhibit 4-A Form 10-Q for
the quarter ended March 31, 1993, File No. 0-951).
       10.126 Gas Transportation Service Contract dated July 31, 1991, between
Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated
herein by reference to Washington Natural Gas Company Exhibit 4-A Form 10-Q for
the quarter ended March 31, 1993, File No. 0-951).
       10.127 Amendment to Gas Transportation Service Contract dated July 31,
1991, between Washington Natural Gas Company and Northwest Pipeline Corporation.
     10.128 Gas  Transportation  Service  Contract dated July 15, 1994,  between
Washington Natural Gas Company and Northwest Pipeline Corporation
       10.129 Amendment to Gas Transportation Service Contract dated August 15,
1994, between Washington Natural Gas Company and Northwest Pipeline Corporation.
     10.130 Washington Natural Gas Company Deferred  Compensation Plan effective
September 1, 1995.
       10.131 Form of Washington Natural Gas Company - Executive Retirement
Compensation Agreement reflecting all amendments through August 16, 1995.
       10.132 Second Washington Energy Company Performance Share Plan (amended
and restated effective October 1, 1991) (incorporated herein by reference to
Washington Energy Company Exhibit 10-L.1, Form 10-K for the year ended September
30, 1991, File No. 0-8745).
     10.133 Washington  Energy Company Interim  Performance Share Plan effective
December 7, 1994.
       10.134 Washington Energy Company Stock Option Plan (incorporated herein
by reference to Exhibit 10-C Washington Energy Company Form 10-Q for the quarter
ended March 31, 1984, File No. 0-8745).
       10.135 Amendment to Washington Energy Company Stock Option Plan
(incorporated herein by reference to Washington Energy Company Exhibit 10-S,
Form 10-K for the year ended September 30, 1986, File No. 0-8745).
       10.136 Amendment to Washington Energy Company Stock Option Plan dated as
of February 26, 1988 (incorporated herein by reference to Washington Energy
Company Form S-8, Registration No. 33-24221).
       10.137 Washington Energy Company Stock Option Plan effective December 15,
1993 (incorporated herein by reference to Washington Energy Company Exhibit 99,
Registration No. 33-55381).
       10.138 Washington Energy Company Directors Stock Bonus Plan (incorporated
herein by reference to Washington Energy Company Exhibit 10-O, Form 10-K for the
year ended September 30, 1990, File No. 0-8745).
       10.139 Form of Conditional Executive Employment Contract, filed under
cover of Form SE dated December 27, 1988 (incorporated herein by reference to
Washington Natural Gas Company Exhibit 10-M.2, Form 10-K for the year ended
September 30, 1994, File No.
1-11271).
       10.140 Amended and restated Washington Energy Company and subsidiaries
Annual Incentive Plan for Vice Presidents and above, dated October 1994.

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<PAGE>

       10.141 Interest Rate Swap Agreement dated September 27, 1989 between
Thermal Resources, Inc. and the First National Bank of Chicago, filed under
cover of Form SE dated December 27, 1989, (incorporated herein by reference to
Washington Natural Gas Company Exhibit 10-N, Form 10-K for the year ended
September 30, 1994, File No. 1-11271).
       10.142 Firm Transportation Service Agreement dated March 1, 1992 between
Northwest Pipeline Corporation and Washington Natural Gas Company (incorporated
herein by reference to Washington Natural Gas Company Exhibit 10-O, Form 10-K
for the year ended September 30, 1994, File No. 1-11271).
       10.143 Firm Transportation Service Agreement dated January 12, 1994
between Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transportation service from Jackson Prairie (incorporated herein by
reference to Washington Natural Gas Company Exhibit 10-P, Form 10-K for the year
ended September 30, 1994, File No. 1-11271).
       10.144 Firm Transportation Service Agreement dated January 12, 1994
between Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transportation service from Jackson Prairie (incorporated herein by
reference to Washington Natural Gas Company Exhibit 10-Q, Form 10-K for the year
ended September 30, 1994, File No. 1-11271).
       10.145 Firm Transportation Service Agreement dated January 12, 1994
between Northwest Pipeline Corporation and Washington Natural Gas Company for
firm transportation service from Plymouth, LNG (incorporated herein by reference
to Washington Natural Gas Company Exhibit 10-R, Form 10-K for the year ended
September 30, 1994, File No. 1-11271).
       10.146 Service Agreement dated July 9, 1991 with Northwest Pipeline
Corporation for SGS-2F Storage Service filed under cover of Form SE dated
December 23, 1991 (incorporated herein by reference to Washington Natural Gas
Company Exhibit 10-S, Form 10-K for the year ended September 30, 1994, File No.
1-11271).
       10.147 Firm Transportation Agreement dated October 27, 1993 between
Pacific Gas Transmission Company and Washington Natural Gas Company for firm
transportation service from Kingsgate (incorporated herein by reference to
Washington Natural Gas Company Exhibit 10-T, Form 10-K for the year ended
September 30, 1994, File No. 1-11271).
     10.148 Firm Storage  Service  Agreement and Amendment  dated April 30, 1991
between  Questar  Pipeline  Company and Washington  Natural Gas Company for firm
storage  service at Clay Basin filed under cover of Form SE dated  December  23,
1991.
     10.149  Employment  agreement with R. R. Sonstelie,  Chairman of the Board,
dated  January 13,  1998.(Exhibit  10.150 to Annual  Report on Form 10-K for the
fiscal year ended December 31, 1997, Commission File No. 1-4393)
     10.150 Change in control agreement with T. J. Hogan, dated August 17, 1995.
(Exhibit 10.152 to Annual Report on Form 10-K for the fiscal year ended December
31, 1997, Commission File No. 1-4393)
     10.151 Asset Purchase Agreement between PP&L Global,  Inc. and the Company.
(Exhibit 2a to Current Report on Form 8-K dated November 13, 1998)
     *10.152 Employment  agreement with S. A. McKeon, Vice President and General
Counsel, dated May 27, 1997.
     *10.153  Employment  agreement with R. L. Hawley,  Vice President and Chief
Financial Officer, dated March 16, 1998.
     *10.154  Employment  agreement  with J. Quintana,  Vice President  External
Affairs, dated March 20, 1998.
     *12-a  Statement  setting forth  computation of ratios of earnings to fixed
charges (1994 through 1998).
     *12-b Statement setting forth computation of ratios of earnings to combined
fixed charges and preferred stock dividends (1994 through 1998).
       *21    Subsidiaries of the Registrant.
       *23.1  Consent of independent accountants.
       *23.2  Consent of independent accountants.
       *27    Financial Data Schedules.

       ---------------------------------
       *Filed herewith.

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