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

                                   FORM 10-K/A

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

                   For the fiscal year ended December 31, 1998
                                       OR

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


                          Commission File Number 1-4393


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

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


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

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


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<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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                                     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 conditions of the license related to measures designed to
enhance  salmon runs on the White River,  because those  conditions may make the
plant uneconomic to operate. The outcome of the Company's appeal before the FERC
is uncertain at this time.  The initial  license for the existing and  operating
Snoqualmie Falls project expired in December 1993, and the Company  continues to
operate this project under a temporary  license.  The Company is continuing  the
FERC application process to relicense this project. The Company has also applied
for a license to expand its existing  1,750 KW Nooksack  Falls  project which is
currently  unlicensed and not operating because of an electric generator fire in
1996.
    

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

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<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.

                                       7
<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.

                                       8
<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.

                                       9
<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.

                                       10
<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.)

                                       11
<PAGE>

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

                                       12
<PAGE>
Gas Utility Operations

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

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

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

                                       13
<PAGE>

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

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

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

                                       14
<PAGE>

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

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

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

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

                                       15
<PAGE>

<TABLE>
        GAS UTILITY OPERATING STATISTICS
<CAPTION>

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

                                       16
<PAGE>

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

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

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

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

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

Federal Clean Air Act Amendments of 1990
       The  Company has an  ownership  interest  in  coal-fired,  steam-electric
generating  plants at Centralia,  Washington  and Colstrip,  Montana,  which are
subject to the  federal  Clean Air Act  Amendments  of 1990  ("CAAA")  and other
regulatory requirements.
       The Centralia  Project and the Colstrip  Projects met the sulfur  dioxide
limits of the CAAA in Phase I (1995).  The Company and other joint owners of the
Centralia  Project are exploring  alternative  emission  compliance  options and
project  economics in light of  compliance  costs to meet the Phase II limits in
the year  2000.  All four units at the  Colstrip  Project,  operated  by Montana
Power, meet Phase II emission limits.

                                       17
<PAGE>

       The Company owns combustion  turbine units,  most of which are capable of
being  fueled  by  natural  gas or oil.  The  nature  of  these  units  provides
operational flexibility in meeting air emission standards.
       There  is no  assurance  that  in the  future  environmental  regulations
affecting  sulfur  dioxide  or  nitrogen  oxide  emissions  may  not be  further
restricted,  or that  restrictions  on  emissions  of  carbon  dioxide  or other
combustion by-products may not be imposed.

Federal Endangered Species Act
       In November 1991, the National Marine  Fisheries  Service ("NMFS") listed
the Snake  River  Sockeye  as an  endangered  species  pursuant  to the  federal
Endangered Species Act ("ESA").  Since the Sockeye listing, the Snake River fall
and  spring/summer  Chinook have also been listed as threatened.  In response to
the  listings,  a team of experts was formed to develop a plan for the  recovery
needs of these species.  In 1995, the NMFS issued a biological opinion which has
significantly changed the operation of the Federal Columbia River Power System.
       The plans developed by NMFS affect the  Mid-Columbia  projects from which
the Company  purchases power on a long-term  basis,  and will further reduce the
flexibility of the regional hydro-electric system. Although the full impacts are
unknown  at this  time,  the plan  developed  by NMFS  shifts  an  amount of the
Company's generation from the Mid-Columbia projects from winter periods into the
spring when it is not needed for system  loads,  and will increase the potential
for spill and loss of generation at the Mid-Columbia projects.
       Since the 1991  listings,  one more species of salmon has been listed and
two more have  been  proposed  which may  further  influence  operations.  Upper
Columbia River  Steelhead were listed by NMFS in August 1997.  Anticipating  the
Steelhead listing, the Mid-Columbia PUDs initiated consultation with the federal
and state agencies, Native American tribes and non-governmental organizations to
secure  operational  protection  through  a  long-term  settlement  and  habitat
conservation plan which includes fish protection and enhancement measurement for
the next 50 years. The negotiations  have concluded among the Chelan and Douglas
County PUDs and various  fishery  agencies,  and final agreement is subject to a
National   Environmental   Policy  Act  review  and  power  purchaser  approval.
Generally, the agreement obligates the PUDs to achieve certain levels of passage
efficiency for  downstream  migrants at their  hydro-electric  facilities and to
fund certain habitat  conservation  measures.  Grant County PUD has yet to reach
agreement on these issues.
       The proposed  listings of Puget Sound Chinook  salmon and spring  Chinook
for the upper Columbia will be final, if approved, in March 1999. The listing of
spring  Chinook for the upper Columbia  should not result in markedly  differing
conditions for operations  from previous  listings in the area.  However,  Puget
Sound has not experienced ESA listing to date and listing of Puget Sound Chinook
could cause a number of changes to operations of government agencies and private
entities in the region  including the Company.  These may adversely affect hydro
plant  operations,  permit  issuance for facilities  construction  and increased
costs for process and facilities.  Because the Company relies substantially less
on  hydro-electric  energy from the Puget Sound area than from the  Mid-Columbia
and  because  the impact on Company  operations  in the Puget  Sound area is not
likely to impair  significant  generating  resources,  the impact of listing for
Puget Sound  Chinook  salmon  should be  proportionately  less than the Columbia
River listings.

                                       18
<PAGE>

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

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

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

                                       19
<PAGE>

  INCREASE (DECREASE) OVER PRECEDING YEAR

  YEARS ENDED DECEMBER 31 (DOLLARS IN MILLIONS)

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

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

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

                                       20
<PAGE>

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

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

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

                                       21
<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.
   

                                       22
<PAGE>

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

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

                                       23
<PAGE>

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

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

                                       24
<PAGE>

Rate Matters - Electric

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

Rate Matters - Gas

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

Year 2000 Conversion

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

Project Approach and Progress
   
       The number of people working full time on the Company's Year 2000 project
fluctuates  between 20 and 40; dozens of additional  employees  contribute  some
time to the effort each month.  The Company has  established  a central  project
team to coordinate all Year 2000  activities  and  identified  exposure in three
categories:  information  technology;  embedded  chip  technology;  and external
non-compliance  by customers and suppliers.  The project team is taking a phased
approach in  conducting  the Year 2000  project for its  internal  systems.  The
phases  include  inventory,  assessment,   planning/prioritizing,   remediation,
testing,  implementation and contingency planning. In addition,  the Company has
engaged   outside   consultants  and  technicians  to  aid  in  formulating  and
implementing  its plan. All business  units have completed the inventory  phase,
and with the  exception of the Company's  Customer  Information  System  ("CIS")
discussed  below,  assessment  is 95%  complete  for all  business  units,  with
remediation,  testing and  implementation  scheduled to be completed  during the
second quarter of 1999.
    

                                       25
<PAGE>

       The Company has been upgrading  mainframe and client server financial and
business  applications  since 1997 and replacing many of its business systems as
part of its business plans  following its merger in 1997. In September 1998, the
Company implemented a Systems, Applications, Products in Data Processing ("SAP")
business  system  which  includes  essentially  all  of the  Company's  business
applications  with the  exception  of its  CIS.  This SAP  system  is Year  2000
compliant.  The remainder of applications and operating  environments  excluding
the CIS are in the  remediation/testing  phase.  Full  implementation  of  those
applications and components of the Company's  internal systems are scheduled for
completion by mid-year 1999.
       A new CIS,  which is designed  to be Year 2000  compliant,  is  currently
being developed by the Company. Development is expected to be completed in 1999.
The Company has also begun  implementation  activities  with  respect to the new
system  which  will  continue  during  1999.  The  Company  has also  elected to
remediate  critical  elements  of its  existing  CIS for  Year  2000  compliance
purposes.  The Company has formed a  specialized  team which has  completed  the
inventory  phase  and  is  currently   conducting   assessment  and  remediation
activities  for the  existing  system.  The  Company  expects  to  complete  the
assessment  phase of this project early in May of 1999 followed  immediately  by
remediation  and testing  activities  which are  expected to be completed in the
third quarter of 1999.
       A  specialized  embedded  systems  team has been formed by the Company to
inventory,  assess and remediate  microprocessor  technology in its  generation,
transmission and distribution systems for both gas and electric operations.  The
inventory  and  assessment  phases of the project are  complete.  Although  some
remediation  planning is still in process,  significant  remediation efforts are
underway and proceeding  according to schedule.  Testing and  implementation are
scheduled to be completed by the end of the second quarter of 1999.  Contingency
planning  specific to the Year 2000 issue began in  November  1998,  and initial
reports  were  submitted to the  Washington  Commission  and the North  American
Electric  Reliability Council ("NERC").  These plans will be refined and updated
as remediation and test results are analyzed, and are scheduled for finalization
in the third quarter of 1999.
   
     The Company sent letters to its suppliers, financial institutions and other
business partners to coordinate Year 2000 conversion and determine the extent to
which the Company is exposed to third party compliance  failures.  Approximately
85% of vendors  and  suppliers  have been  contacted  to date.  All third  party
assessment is scheduled to be completed in March 1999. If the Company identifies
concerns,  it follows  up with third  parties by  telephone.  In  addition,  the
Company  schedules  meetings with critical  vendors  described below in order to
assess and monitor compliance measures.  Virtually all the vendors and suppliers
who have  responded to the  Company's  written  requests and follow up telephone
calls  have  indicated  either  that they are year 2000  compliant  or that they
expect to be compliant later in 1999. Approximately one-third of the vendors and
suppliers  have not yet  responded to inquiries  from the Company.  Company line
managers  are  seeking  to  obtain  responses  from  them as well as to  develop
alternate  sources or other  contingency  plans for  vendors and  suppliers  who
either do not respond or who indicate that they do not expect to be compliant.
     The Company  depends upon third  parties for a  significant  portion of its
energy supply and transportation.  The majority of the high voltage transmission
facilities  used by the  Company  are owned and  operated  by  Bonneville  Power
Administration  and the Company's  natural gas supplies are  transported  to its
service area by natural gas  pipelines in the western  United States and Canada.
The Company  purchases 100% of its natural gas supplies and approximately 75% of
its  electric  power  supplies.  Major energy  suppliers  and  transporters  are
considered critical vendors because their failure to supply or deliver energy to
the Company could adversely affect the reliability of the Company's  electric or
gas service to its customers.
    
       In  addition,  the  Company  is  working  with  various  industry  groups
including the NERC and the regional  reliability  council,  the Western  Systems
Coordinating  Council  ("WSCC")  during the  millennium  transition.  The United
States  Department  of Energy  has asked  NERC to  assume a  leadership  role in
preparing the U.S. electric industry for the transition to the Year 2000.

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

                                       26
<PAGE>

Risk Assessment
   
     The electric power supply systems of North America are connected into three
major  interconnections  called grids. The western grid covers the western third
of the U.S., western Canada and parts of Mexico. The BPA is the largest supplier
of  transmission  services in the Pacific  Northwest.  The Company's  reasonably
likely worst case scenario is that operational  component failures of any entity
connected  to the grid could cause other  failures in that grid.  Such  failures
would adversely affect the Company's  ability to provide reliable service to its
customers and correspondingly reduce revenues. The Company will need to continue
to assess this risk as the  millennium  approaches to evaluate the likelihood of
power failures and develop approaches for mitigating the risk of failures.
    
       Much of the natural gas and electric  distribution  systems are comprised
of wires, poles and pipes containing no embedded chips.  However,  these systems
do employ  some  computer  components  that could be  affected  by the Year 2000
transition.  Since many of the components  used by the Company exist in multiple
sub-station  locations,  there is a risk that a  component  could be  missed,  a
component  manufacturer  could provide erroneous  information,  or the component
(while deemed and tested compliant) could fail in a specific configuration found
at the Company . The Company has formed a special  team to handle these types of
components (embedded systems), and has retained an independent  engineering firm
with specific utility experience to assist in the effort.  Results of assessment
to date reveal that there are fewer components that are not Year 2000 ready than
initially  thought.  This is consistent with industry findings  published in the
NERC report to the Department of Energy dated January 11, 1999.
       The failure to correct a material  Year 2000  problem  could result in an
interruption  in, or a failure of,  Company  business  activities or operations.
Such failures  could  materially and adversely  affect the Company's  results of
operations,  liquidity and financial  condition.  Due to the general uncertainty
inherent in the Year 2000 problem, resulting in part from the uncertainty of the
Year 2000  readiness of  third-party  suppliers  and  customers,  the Company is
unable to determine at this time whether the  consequences of Year 2000 failures
will have a material impact on the Company's results of operations, liquidity or
financial  condition.  The Year 2000 project is expected to significantly reduce
the Company's level of uncertainty about the Year 2000 problem and the Year 2000
readiness  of  its  material  vendors.  The  Company  believes  that,  with  the
implementation  of  new  business  systems  and  completion  of the  project  as
scheduled,  the possibility of significant  interruptions  of normal  operations
should be reduced.
       As discussed  above,  elements of the Company's  current CIS are not Year
2000 compliant.  If the current CIS remediation activities are not successful by
the year 2000,  certain normal business  activities such as customer billing and
collections could be adversely affected by interruptions.

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

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

                                       27
<PAGE>

Industry Overview
       The  electric  and gas  industries  in the United  States are  undergoing
significant  changes. The focus of these changes is to promote competition among
suppliers of electricity and gas and associated services.  In 1996 and 1997, the
Federal  Energy  Regulatory  Commission  ("FERC")  issued  orders  that  require
utilities,  including the Company, to file open access transmission tariffs that
will make the utilities'  electric  transmission  systems available to wholesale
sellers and buyers on a non-discriminatory  basis. A number of states, including
California,   have  restructured  their  electric   industries  to  separate  or
"unbundle"  power  generation,  transmission and distribution in order to permit
new competitors to enter the marketplace.  In part because electric rates in the
Pacific  Northwest  have been  among the  lowest in the  nation,  certain of the
legislatures in this region, including Washington,  have not yet enacted laws to
provide for  competition  at the retail level.  The  Washington  Commission  has
initiated a pilot  program,  in which the  Company  participates,  that  permits
consumers limited direct access to competitive energy suppliers.  The Company is
actively monitoring  developments in this area and has indicated its support for
the enactment of legislation  that would provide  increased  choice for electric
service customers in the State of Washington.
       In order to better  position  itself to  respond  to  customer  needs and
future  restructuring  of  the  utility  industry,  and  in  anticipation  of  a
competitive environment for electric energy sales, the Company in 1997 organized
its utility  operations into separate  business units:  energy delivery;  energy
supply; and customer solutions
       The Company has an Optional  Large Power Sales Rate and certain  "special
contracts"  for its largest  customers.  Customers who elect the Optional  Large
Power Sales Rate are no longer considered  "core" customers,  and the Company no
longer has an obligation to plan for future  resources to serve their needs. The
non-core  customers  receive access to electric energy that is priced at current
market  cost  and pay a charge  for  energy  delivery  (including  a charge  for
conservation  programs) and a transition  charge  (representing  the  difference
between  the  Company's  present  cost and the  current  market cost of electric
energy and capacity). The transition charge will be phased out before the end of
the year 2000.  Non-core customers also take on the risk that market costs could
become volatile and that electricity could be unavailable on the open market. In
November  1998,  a number of  industrial  customers  filed a complaint  with the
Washington  Commission that the Company was incorrectly billing for energy under
the Optional Large Power Sales Rate. If the Washington Commission finds that the
Company  used an  incorrect  index,  the Company  would owe  approximately  $2.6
million in refunds. However,  management believes the proper index has been used
and expects the Company will prevail on this issue.
       Since 1986 the Company has been offering gas transportation as a separate
service to industrial and commercial  customers who choose to purchase their gas
supply directly from producers and gas marketers. The continued evolution of the
natural gas industry, resulting primarily from FERC Orders 436, 500 and 636, has
served to increase  the ability of large gas  end-users to bypass the Company in
obtaining  gas supply and  transportation  services.  Though the Company has not
lost any  substantial  industrial or commercial load as a result of such bypass,
in certain years up to 160 customers  annually have taken advantage of unbundled
transportation service. During 1998, an average of 123 commercial and industrial
customers chose to use such service.

Other
       On March 20, 1991,  the Company  executed a 20-year  contract to purchase
216 average MW of energy and 245 MW of capacity,  beginning in April 1994,  from
Tenaska Washington  Partners,  L.P., which owns and operates a natural-gas fired
cogeneration  project  located near Ferndale,  Washington.  In December 1997 and
January 1998, the Company and Tenaska  Washington  Partners entered into revised
agreements  which will lower  purchased  power costs from the Tenaska project by
restructuring  its natural gas supply.  The Company paid $215 million to buy out
the project's existing long-term gas supply contracts, which contained fixed and
escalating  gas prices that were well above current and projected  future market
prices for natural gas. The Company became the principal natural gas supplier to
the project and power purchase prices under the Tenaska contract were revised to
reflect  market-based prices for the natural gas supply. The Company obtained an
order from the Washington  Commission creating a regulatory asset related to the
$215 million  restructuring  payment.  Under terms of the order,  the Company is
allowed to accrue as an additional  regulatory asset one-half the carrying costs
of the deferred  balance over the first five years.  These revised  arrangements
are expected to reduce the Company's power supply costs from the Tenaska project
between  15 and 20  percent  annually  over the  remaining  14 year  life of the
contract, net of the costs of the restructuring payment. The Company's purchased
electric energy cost  associated with the Tenaska  contract was $80.1 million in
1998.

                                       28
<PAGE>

     On April 1,  1998,  the  Company  and Duke  Energy  Trading  and  Marketing
("DETM") of Houston,  a unit of Duke Energy Corp.,  signed an agreement relating
to  energy-marketing  and trading  activities  in 14 western  States and British
Columbia.  The purpose of this  agreement is to  coordinate  the two  companies'
activities in serving Puget Sound Energy's native power load with DETM's Western
power and natural gas marketing and trading operations.  The companies share the
benefits of this coordination  proportionally up to certain  stipulated  amounts
intended to be reflective  of the value the  companies  would have realized from
their respective operations in the absence of the agreement. The companies share
equally any benefits created above the stipulated amounts.
       Under the terms of the  agreement,  DETM  performs  the forward  electric
energy trading function.  As a result,  the Company's future wholesale "sales to
other utilities" revenues and related "secondary purchase" power expenses, which
previously have reflected  trading  activity by the Company,  will be lower than
amounts which the Company would report  absent this  agreement.  During 1998 the
Company  continued  to execute in its own name  transactions  in which  electric
energy is delivered within the next 30 days.  Therefore,  the Company's  results
include those transactions.  The Company recorded its share of the benefits that
resulted  from the  agreement  as a  credit  to  Purchased  Power  Expense.  The
agreement provides that forward trading  activities will be conducted  according
to DETM's  energy  price risk and credit  policies,  and that the Company is not
responsible for any losses caused by deviation from these policies.  The Company
and DETM are presently considering modifications to the agreement.
       On November 2, 1998, the Company announced it signed an agreement to sell
the  Company's  735-megawatt  interest  in the  four-unit,  coal-fired  Colstrip
generation  plant  in  eastern  Montana,  as  well  as  associated  transmission
facilities. The Company signed the agreement with PP&L Global, Inc., of Fairfax,
Virginia,  a subsidiary  of PP&L  Resources,  Inc.  Included in the sale are the
Company's 50% interest in Colstrip Units 1 and 2; 25% interest in Units 3 and 4;
and associated Colstrip transmission capacity across Montana. The sales price is
expected to be $549  million  before taxes and  expenses.  The net book value of
these assets and related regulatory assets is approximately $464 million.  After
consideration  of taxes and other costs,  the gain on the sale is expected to be
approximately  $37.6 million.  The Company expects the Colstrip sale to close in
the second  half of 1999.  Completion  of the sale is  contingent  on receipt of
acceptable regulatory treatment from the Washington Commission and the FERC.
       The  Company  has also  agreed  to join  with  the  other  owners  of the
coal-fired generating plant at Centralia,  Washington,  by offering for sale its
92 megawatt ownership interest in the facility. As part of the sale process, the
Centralia owners are reviewing the projected  reclamation  liability  related to
the coal mining operations.
       In the fourth  quarter of 1998,  the  Company  incurred  $4.7  million of
transmission and distribution repair costs in connection with restoring electric
service  following a severe wind storm that occurred on November 23, 1998. Under
an order established by the Washington Commission, these costs were deferred for
collection in future rates.
       For a discussion of Issue 98-10,  "Accounting  For Contracts  Involved in
Energy Trading and Risk  Management  Activities"  issued by the Emerging  Issues
Task force of the Financial  Accounting  Standards  Board  ("FASB") in 1998, see
Note 1 to the Consolidated Financial Statements.
       For a discussion of Statement of Position  98-5,  "Reporting on the Costs
of  Start-up  Activities"  ("SOP  98-5")  issued  by  the  Accounting  Standards
Executive  Committee  in April 1998,  see Note 1 to the  Consolidated  Financial
Statements.
     For a discussion  of Statement of Financial  Accounting  Standards No. 133,
"Accounting for Derivative  Instruments and Hedging Activities"  ("Statement No.
133") issued by the FASB in June 1998, see Note 1 to the Consolidated  Financial
Statements.

                                       29
<PAGE>

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

Commodity Price Risk
       The prices of energy commodities and transportation  services are subject
to fluctuations due to unpredictable  factors including weather,  transportation
congestion  and other  factors which impact  supply and demand.  This  commodity
price risk is a consequence  of purchasing  energy at fixed and variable  prices
and  providing  deliveries  at  different  tariff  and  variable  prices.  Costs
associated  with  ownership and operation of production  facilities  are another
component  of this risk.  The Company may use forward  delivery  agreements  and
option  contracts for the purpose of hedging  commodity  price risk.  Unrealized
changes in the market value of these  derivatives  are  deferred and  recognized
upon settlement along with the underlying hedged transaction.  In addition,  the
Company  believes its current rate design,  including  its Optional  Large Power
Sales Rate,  various special contracts and the PGA mechanism  mitigate a portion
of this risk.
       Four  option  contracts   entered  into  directly  by  the  Company  were
outstanding  at December  31,  1998,  and had a market  value at that date which
approximated the option premiums paid by the Company.
       Operating  results are also  influenced by the impact of market prices on
the value of physical and derivative commodity contracts entered into by DETM as
part of their agreement with the Company.  Changes in the market value of all of
these derivatives are recorded on a mark-to-market basis into income by DETM and
can affect the Company's revenues from the DETM agreement.
       DETM measures the market risk of physical and financial contracts entered
into  under  the DETM  Agreement  using a value  at risk  model.  The  Company's
proportionate share of the value at risk at December 31, 1998 was not material.
       Market risk is managed subject to parameters  established by the Board of
Directors. A Risk Management Committee separate from the units that create these
risks  monitors  compliance  with the  Company's  policies  and  procedures.  In
addition,  the Audit Committee of the Company's Board of Directors has oversight
of the Risk Management Committee.

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

                                       30
<PAGE>

         SIGNATURES

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

                                           PUGET SOUND ENERGY, INC.

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

                                           Date:      April 23, 1999            

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


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


   William S. Weaver           President, Chief Executive    April 23, 1999
----------------------------                              -------------------
  (William S. Weaver)          Officer and Director


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


   Richard L. Hawley           Vice President and Chief
----------------------------
  (Richard L. Hawley)          Financial Officer


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


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


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


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

                                       31
<PAGE>


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


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


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


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


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


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


   Tomio Moriguchi             Director
----------------------------
  (Tomio Moriguchi)


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


                                       32
<PAGE>