UNITED STATES

                       SECURITIES AND EXCHANGE COMMISSION

                             Washington, D. C. 20549

                                    FORM 10-K

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

                   For the fiscal year ended December 31, 1999
                                       OR

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


                          Commission File Number 1-4393

                            PUGET SOUND ENERGY, INC.

             (Exact name of registrant as specified in its charter)

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


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

                                 (425) 454-6363

              (Registrant's telephone number, including area code)

                                       1
<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.


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

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

  Preferred Stock (Cumulative; $100 Par Value)

  Preferred Stock (Cumulative; $25 Par Value)

  8.231% Capital Securities

     Indicate  by check mark  whether the  registrant  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days.

     Yes/X/ No/ /

     Indicate by check mark if disclosure of delinquent  filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's  knowledge,  in definitive proxy or information  statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. / /

     The aggregate  market value of the voting stock held by  non-affiliates  of
the registrant at December 31, 1999, was approximately $1,645,000,000

     The number of shares of the registrant's  common stock outstanding at March
1, 2000 was 85,225,296.

                       Documents Incorporated by Reference

     The Company's  definitive  proxy  statement for its 2000 Annual  Meeting of
Shareholders is incorporated by reference in Part III hereof.

                                       2
<PAGE>

                                  DEFINITIONS

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

                                       3
<PAGE>

         INDEX

       Item       Page

       Part I

           1.     Business                                                     5
                         General                                               5
                         Industry Overview                                     6
                         Regulation and Rates                                  6
                         Electric Utility Operations                           6
                         Electric Utility Operating Statistics                11
                         Gas Utility Operations                               13
                         Gas Utility Operating Statistics                     16
                         Environment                                          17
                         Executive Officers                                   19
           2.     Properties                                                  20
           3.     Legal Proceedings                                           20
           4.     Submission of Matters to a Vote of Security Holders         20

       Part II

           5.     Market for Registrant's Common Equity and Related
                  Shareholder Matters                                         20
           6.     Selected Financial Data                                     22
           7.     Management's Discussion and Analysis of
                  Financial Condition and Results of Operations               23
           7a.    Quantitative and Qualitative Disclosures about
                  Market Risk                                                 32
           8.     Financial Statements and Supplementary Data                 33
           9.     Changes in and Disagreements with Accountants
                  on Accounting and Financial Disclosure                      33

       Part       III  (Incorporated by reference from the Company's
                  definitive proxy  statement  issued in  connection
                  with the 2000  Annual Meeting of Shareholders)

           10.    Directors and Executive Officers of the Registrant
           11.    Executive Compensation
           12.    Security Ownership of Certain Beneficial Owners
                  and Management
           13.    Certain Relationships and Related Transactions

       Part IV    Exhibits, Financial Statement Schedules and

                  Reports on Form 8-K                                         33
                  Signatures                                                  35
                  Exhibit Index                                               74

                                       4
<PAGE>

         PART I

         ITEM 1.  BUSINESS

GENERAL

       Puget Sound Energy,  Inc. (the "Company"),  is an  investor-owned  public
utility  incorporated  in the State of  Washington  furnishing  electric and gas
service in a territory covering approximately 6,000 square miles, principally in
the Puget Sound region of Washington state.

       At December  31, 1999,  the Company had  approximately  907,000  electric
customers;   consisting  of  803,700  residential,   97,600  commercial,   4,200
industrial and 1,500 other  customers and  approximately  569,900 gas customers;
consisting of 521,800 residential,  45,000 commercial,  3,000 industrial and 100
other customers.  In 1999,  approximately 290,000 customers purchased both forms
of energy from the Company.  For the year 1999, the Company added  approximately
16,300 electric customers and approximately  26,000 gas customers,  representing
annualized  growth  rates of 1.8%  and  4.8%,  respectively.  During  1999,  the
Company's billed retail revenues from electric  utility  operations were derived
46%  from  residential  customers,  37%  from  commercial  customers,  14%  from
industrial customers and 3% from other customers.  The Company's retail revenues
from gas utility  operations were derived 61% from  residential  customers,  28%
from commercial customers,  6% from industrial customers, 3% from transportation
customers and 2% from other customers.  During this period, the largest customer
accounted for 1.8% of the Company's utility operating revenues.

       The Company is affected by various seasonal  weather patterns  throughout
the year and,  therefore,  operating  revenues and  associated  expenses are not
generated evenly during the year.  Variations in energy usage by consumers occur
from season to season and from month to month  within a season,  primarily  as a
result of weather  conditions.  The  Company  normally  experiences  its highest
energy sales in the first and fourth quarters of the year.  Sales of electricity
to wholesale  customers  also vary by quarters and years  depending  principally
upon streamflow  conditions for the generation of surplus  hydro-electric power,
customer  usage and the market  demand by  wholesale  customers.  Earnings  from
electric operations therefore,  can be significantly influenced by surplus sales
and variations in weather, hydro conditions and regional electric energy prices.
Earnings from gas  operations can be  significantly  influenced by variations in
weather. The Company has a Purchased Gas Adjustment  mechanism ("PGA") in retail
rates to  recover  variations  in gas  supply  and  transportation  costs.  (See
"Management's  Discussion  and  Analysis of Financial  Condition  and Results of
Operations - Rate Matters.")

       During the period from  January 1, 1995 through  December  31, 1999,  the
Company  made  gross  electric  utility  plant  additions  of $845  million  and
retirements  of $146 million.  In the five-year  period ended December 31, 1999,
the  Company  made  gross  gas  utility  plant  additions  of $479  million  and
retirements  of $58  million.  In the same  five-year  period, the Company made
gross common  utility  plant  additions of $131 million and  retirements  of $10
million.  Gross electric  utility plant at December 31, 1999, was  approximately
$4.0  billion  which  consisted  of  46%  distribution,   28%  generation,   15%
transmission  and 11%  general  plant  and  other.  Gross gas  utility  plant at
December  31,  1999,  was  approximately  $1.4  billion  which  consisted of 83%
distribution, 5% transmission and 12% general plant and other.

       At year-end the Company had 2,869 aggregate full-time  equivalent utility
employees.

       On June 23,  1999,  Company  shareholders  approved  the  formation  of a
holding  company  structure for the Company and its  subsidiaries.  The proposed
holding  company  structure has been approved by the Federal  Energy  Regulatory
Commission and the Federal Trade Commission,  but is still subject to regulatory
approval  by the  Washington  Commission.  The  primary  purpose for the holding
company  formation  is to allow the Company to separate  its  regulated  utility
business  from its other  businesses,  which will enhance the holding  company's
ability to respond to the changing industry  environment and will permit greater
financing flexibility.  The Company's utility business is expected to constitute
the principal part of the holding company's  earnings for the foreseeable future
after the restructuring.

                                       5
<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 market place. In part because electric rates in the
Pacific  Northwest  have been  among the  lowest in the  nation,  certain of the
legislatures in this region, including Washington,  have not yet enacted laws to
provide for competition at the retail level. The Company is actively  monitoring
developments  in this area and has  indicated  its support for the  enactment of
legislation that would provide  increased choice for electric service  customers
in the state of Washington.

       On December 20, 1999 FERC issued  Order 2000 to advance the  formation of
Regional Transmission Organizations (RTOs). This regulation requires each public
utility  that owns,  operates or controls  facilities  for the  transmission  of
electric  energy in  interstate  commerce  to file with FERC by October 15, 2000
their plans for forming and  participating  in an RTO. FERC's goal is to promote
efficiency  in  wholesale  electricity  markets and to ensure  that  electricity
consumers pay the lowest price possible for reliable service.

       Since  1986,  the  Company  has been  offering  gas  transportation  as a
separate  service to industrial and commercial  customers who choose to purchase
their gas supply  directly  from  producers  and gas  marketers.  The  continued
evolution of the natural gas industry, resulting primarily from FERC Orders 436,
500 and 636, has served to increase the ability of large gas end-users to bypass
the Company in obtaining gas supply and  transportation  services.  Although the
Company has not lost any  substantial  industrial or commercial load as a result
of such  bypass,  in  certain  years up to 160  customers  annually  have  taken
advantage of unbundled  transportation  service;  in 1999,  103  commercial  and
industrial  customers,  on average,  chose to use such service.  The shifting of
customers  from  sales to  transportation  does not  materially  impact  utility
margin,  as the Company earns similar  margins on  transportation  service as it
does on large volume, interruptible gas sales.

REGULATION AND RATES

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

ELECTRIC UTILITY OPERATIONS

       At December 31, 1999, the Company's  peak electric  power  resources were
approximately  5,101,647 KW. The Company's historical peak load of approximately
4,847,000 KW occurred on December 21, 1998.

       During 1999, the Company's total electric energy  production was supplied
23% by its own resources,  23% through  long-term  contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydro-electric projects on
the  Columbia  River,  22% from  other  firm  purchases  and 32%  from  non-firm
purchases.

                                       6
<PAGE>

       The following table shows the Company's  electric energy supply resources
at December 31, 1999, and energy production during the year:
<TABLE>
<CAPTION>
                                PEAK POWER RESOURCES
                                AT DECEMBER 31, 1999       1999 ENERGY PRODUCTION
                            ---------------------------- -----------------------------
                                   KILOWATTS          %    KILOWATT-HOURS           %
                                                                  (THOUSANDS)
                            ---------------------------- -----------------------------
<S>                                <C>             <C>         <C>            <C>
  Purchased Resources:
    Columbia River
    PUD Contracts (Hydro)           1,414,000       27.7%        8,058,572       23.2%
    Other Hydro1                      547,322       10.7%        3,440,026        9.9%
    Other  Producers (1)            1,244,675       24.4%       15,237,380       44.0%
------------------------------ --------------- ----------- ---------------- -----------
  Total Purchased                   3,205,997       62.8%       26,735,978       77.1%
------------------------------ --------------- ----------- ---------------- -----------
  Company-owned Resources:
    Hydro                             310,700        6.1%        1,648,200        4.8%
    Coal                              771,900       15.1%        5,630,670       16.2%
    Natural gas/oil                   813,050       16.0%          662,762        1.9%
------------------------------ --------------- ----------- ---------------- -----------
  Total Company-owned               1,895,650       37.2%        7,941,632       22.9%
------------------------------ --------------- ----------- ---------------- -----------
  Total                             5,101,647      100.0%       34,677,610      100.0%
------------------------------ --------------- ----------- ---------------- -----------
</TABLE>

COMPANY-OWNED ELECTRIC GENERATION RESOURCES

       The  Company and other  utilities  are joint  owners of four  mine-mouth,
coal-fired,  steam-electric generating units at Colstrip, Montana, approximately
100 miles east of Billings,  Montana.  The Company owns a 50% interest  (330,000
KW) in  Units 1 and 2 and a 25%  interest  (350,000  KW) in  Units 3 and 4.  The
owners of the Colstrip  Units  purchase  coal for the Units from Western  Energy
Company ("Western Energy"), under the terms of long-term coal supply agreements.
In the third quarter of 1998, Western Energy, the Company and other joint owners
of Units 3 and 4 revised the coal supply  contract  which  reduced the delivered
price of coal for Units 3 and 4 and  allows  for the joint  owners to review and
approve mining plans and budgets.

       In November 1998,  the Company  announced that it had signed an agreement
to sell its interest in the Colstrip plant,  as well as associated  transmission
facilities  to PP&L Global,  Inc.,  of Fairfax,  Virginia,  a subsidiary of PP&L
Resources,   Inc.  (See  "Management's  Discussion  and  Analysis  of  Financial
Condition and Results of Operations - Other" for a discussion of the sale.)

       The   Company   owns  a  7%  interest   (91,900  KW)  in  a   coal-fired,
steam-electric  generating  plant near Centralia,  Washington,  with a total net
capability  of  1,313,000  KW. In May 1999,  the  Company  and the other  owners
announced that they had signed an agreement to sell all their  ownership  shares
in the plant to TransAlta  Corporation of Calgary,  Canada.  (See  "Management's
Discussion  and  Analysis of  Financial  Condition  and Results of  Operations -
Other" for a discussion of the sale.)

       The Company owns a 160 megawatt  natural-gas fired cogeneration  facility
located near Bellingham,  Washington which was purchased from Encogen  Northwest
L.P.  ("Encogen") on November 1, 1999. (See Electric Energy Supply Contracts and
Agreements with Non-Utilities.)

       The  Company  also  has  the  following  plants  with  an  aggregate  net
generating  capability of 963,750 KW: Upper Baker River hydro  project  (103,000
KW)   constructed  in  1959;   Lower  Baker  River  hydro  project  (71,400  KW)
reconstructed  in 1960; White River hydro plant (63,400 KW) constructed in 1911;
Snoqualmie  Falls hydro plant  (45,500  KW),  half the  capability  of which was
installed during the period 1898 to 1910 and half in 1957; and one smaller hydro
plant,  Electron  (27,400  KW),  constructed  during the period 1904 to 1929;  a
standby  internal  combustion  unit (2,750 KW)  installed in 1969;  an oil-fired
combustion turbine unit (67,500 KW) installed in 1974; four dual-fuel combustion
turbine  units  (89,100  KW  each)  installed  during  1981;  and two  dual-fuel
combustion  turbine units (113,200 KW each) installed  during 1984. All of these
generating facilities are located in the Company's service territory.

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

                                       7
<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  wholesale  customers,
either directly or through tolling arrangements.

     On December 19, 1997,  the Company was issued a 50 year license by FERC for
its existing and operating White River project which includes  authorization  to
install an  additional  14,000 KW generating  unit.  The Company has filed for a
rehearing with FERC on conditions of the license related to measures designed to
enhance  salmon runs on the White River,  because those  conditions may make the
plant  uneconomic to operate.  On June 30, 1999,  FERC issued a two year stay in
the license proceeding. This additional time allows the Company, state agencies,
local  governments  and public interest groups to resolve common issues relating
to the plant's  continued  operation and economics.  The initial license for the
existing and operating  Snoqualmie  Falls project  expired in December 1993, and
the Company  continues to operate this project  under a temporary  license.  The
Company is continuing the FERC application process to relicense this project.

COLUMBIA RIVER ELECTRIC ENERGY SUPPLY CONTRACTS

       During  1999,  approximately  23.2% of the  Company's  energy  output was
obtained at an average cost of approximately 9.4 mills per KWH through long-term
contracts with several of the Washington PUDs owning hydro-electric  projects on
the Columbia River.

       The  Company's  purchases  of power from the Columbia  River  projects is
generally  on a  "cost  of  service"  basis  under  which  the  Company  pays  a
proportionate  share of the annual debt service and  operating  and  maintenance
costs of each project in proportion to the amount of power annually purchased by
the  Company  from such  project.  Such  payments  are not  contingent  upon the
projects being operable. These projects are financed through substantially level
debt  service  payments,  and their  annual  costs may vary over the term of the
contracts  as  additional  financing  is  required  to meet  the  costs of major
maintenance, repairs or replacements or license requirements.

     The Company has  contracted to purchase from Chelan County PUD ("Chelan") a
share of the  output of the  original  units of the Rock  Island  Project  which
equaled  50% as of  July 1,  1999,  and  remains  unchanged  thereafter  for the
duration of the contract. The Company has also contracted to purchase the entire
output of the  additional  Rock Island units for the  duration of the  contract,
except that the Company's share of output of the additional units may be reduced
up to 10% per year  beginning  July 1,  2000,  subject  to a  maximum  aggregate
reduction of 50%, upon the exercise of rights of withdrawal by Chelan for use in
its local service  area.  Chelan has given notice of withdrawal of 5% on July 1,
2000. As of December 31, 1999, the Company's  aggregate annual capacity from all
units of the Rock Island  Project was 478,000 KW. The Company has  contracted to
purchase  from Chelan  38.9%  (505,000 KW as of December 31, 1999) of the annual
output of the Rocky Reach Project,  which percentage  remains  unchanged for the
remainder of the contract. The Company's share of the annual output of the Wells
Project  purchased from Douglas County PUD is currently  31.3% (261,000 KW as of
December 31, 1999) upon the additional  exercise of withdrawal rights by Douglas
County PUD. The Company has  contracted  to purchase  from Grant County PUD 8.0%
(72,000 KW as of December  31, 1999) of the annual  output of the Priest  Rapids
project and 10.8%  (98,000 KW as of December 31,  1999) of the annual  output of
the Wanapum project, which percentages remain unchanged for the remainder of the
contracts. (See Note 17 to the Company's Consolidated Financial Statements.)

ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH OTHER UTILITIES

       Under a 1985  settlement  agreement  relating to Washington  Public Power
Supply  System  ("WPPSS")  Nuclear  Project No. 3, in which the Company had a 5%
interest,  the  Company is  receiving  from BPA for  approximately  30.5  years,
beginning January 1, 1987,  electric power during the months of November through
April.  Under the  contract,  the Company is guaranteed to receive not less than
191,667  MWH in  each  contract  year  until  the  Company  has  received  total
deliveries of 5,833,333 MWH.

                                       8
<PAGE>

       On  April  4,  1988,  the  Company  executed  a  15-year  contract,  with
provisions for early termination by the Company, for the purchase of firm energy
supply from Avista Corporation  (formerly Washington Water Power Company).  This
agreement calls for the delivery of 100 MW of capacity and 657,000 MWH of energy
from the Avista  system  annually (75 annual  average  MW).  Minimum and maximum
delivery rates are prescribed.  Under this agreement, the energy is to be priced
at Avista's average  generation and transmission  cost, subject to certain price
ceilings. This contract expires on December 31, 2002.

       On October 27,  1988,  the Company  executed a 15-year  contract  for the
purchase  of firm  power  and  energy  from  PacifiCorp.  Under the terms of the
agreement,  the  Company  receives  120  average MW of energy and 200 MW of peak
capacity. This contract expires on October 31, 2003.

       On November  23,  1988,  the Company  executed an  agreement  to purchase
surplus  firm power from BPA.  Under the  agreement,  the Company  receives  150
average MW of energy and 300 MW of peak capacity from BPA between  October 1 and
March 31 of each contract  year. In 1997,  the Company  elected to terminate the
agreement  on June 30,  2001,  the date that the  purchase  was to  convert to a
summer-winter exchange.

       On October 1, 1989,  the Company  signed a contract  with  Montana  Power
under which Montana Power provides the Company,  from its share of Colstrip Unit
4, 71 average MW of energy (94 MW of peak capacity) over a 21-year period.

       The Company  executed an exchange  agreement  with Pacific Gas & Electric
Company which became effective on January 1, 1992.  Under the agreement,  300 MW
of capacity  together with 413,000 MWH of energy are exchanged  seasonally every
year on a unit for unit  basis.  No  payments  are made  under  this  agreement.
Pacific Gas & Electric  Company is a summer  peaking  utility  and will  provide
power during the months of November  through  February.  The Company is a winter
peaking  utility  and will  provide  power  during  the  months of June  through
September. Each party may terminate the contract for various reasons.

       In October 1997 a 10-year power  exchange  agreement  between the Company
and Powerex (a subsidiary of a British Columbia utility) became effective. Under
this  agreement  Powerex pays the Company for the right to deliver  power to the
Company at the Canadian border in exchange for the Company  delivering  power to
Powerex at various locations in the United States.

ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH NON-UTILITIES

       As  required  by the  federal  Public  Utility  Regulatory  Policies  Act
("PURPA"),  the Company  entered into long-term firm purchased  power  contracts
with  non-utility  generators.  The most  significant of these are the contracts
described  below  which the  Company  entered  into in 1989,  1990 and 1991 with
operators of natural gas-fired  cogeneration projects. The Company purchases the
net  electrical  output of these four projects at fixed and annually  escalating
prices which were  intended to  approximate  the  Company's  avoided cost of new
generation  projected at the time these  agreements were made.  Principally as a
result of  dramatic  changes in natural  gas price  levels,  the power  purchase
prices under these agreements are  significantly  above the current market price
of power and, based upon  projections  of future market prices,  are expected to
remain  well above  market for the  duration  of the  contracts.  The  Company's
estimated  payments under these four  contracts are $181 million for 2000,  $204
million for 2001, $206 million for 2002, $207 million for 2003, $213 million for
2004 and in the aggregate,  $1.5 billion thereafter through 2012. These payments
reflect the Tenaska and Encogen  contract  restructurings  described  below. The
Company  continues  to seek  restructuring  of the  other  contracts.  If retail
electric  energy prices move to market  levels as a result of electric  industry
restructuring,  the  Company  plans to seek to  continue to recover in rates the
above market portion of these contract costs.

                                       9
<PAGE>

     On June 29, 1989,  the Company  executed a 20-year  contract to purchase 70
average MW of energy and 80 MW of capacity, beginning October 11, 1991, from the
March Point  Cogeneration  Company  ("March  Point"),  which owns and operates a
natural gas-fired cogeneration facility known as March Point Phase I, located at
the Equilon refinery in Anacortes, Washington. On December 27, 1990, the Company
executed a second contract  (having a term  coextensive with the first contract)
to  purchase  an  additional  53  average  MW of energy  and 60 MW of  capacity,
beginning in January 1993, from another natural gas-fired  cogeneration facility
owned and operated by March Point,  which facility is known as March Point Phase
II and is located at the Equilon refinery in Anacortes,  Washington.  A dispute,
currently being  litigated,  exists between the Company and March Point over the
PURPA status of and the Company's obligations to buy the output of Phase II.

       On February 24, 1989, the Company executed a 20-year contract to purchase
108 average MW of energy and 123 MW of capacity,  beginning in April 1993,  from
Sumas  Cogeneration  Company,  L.P., which owns and operates a natural gas-fired
cogeneration project located in Sumas, Washington.

       On  September  26,  1990,  the  Company  executed a 15-year  contract  to
purchase  141  average MW of energy and 160 MW of  capacity,  beginning  in July
1993, from Encogen Northwest L.P.  ("Encogen") (a limited  partnership  having a
general partner that is a subsidiary of Enserch Development Corp.),  which owned
and operated a natural-gas  fired  cogeneration  facility located at the Georgia
Pacific mill near Bellingham, Washington. The contract had obligated the Company
to pay Encogen fixed and escalating fees well above current and projected future
market prices through mid-2008 for the output of the plant. On November 1, 1999,
the Company purchased the 160 megawatt plant from Encogen.  The Company paid $55
million in cash and assumed  $109  million in debt to acquire  the  partnership,
which owned no significant  assets other than the plant.  Pursuant to an October
27,  1999 order from the  Washington  Commission  approving  the  purchase,  the
Company will  depreciate  the original  owner's net book value of the plant over
the  remaining 23 year useful life of the project.  The  difference  between the
purchase price and the net book value of the plant (approximately $72.5 million)
will be  amortized  over 9 years  (the  remaining  term  of the  power  purchase
contract).  The  purchase  is  expected to reduce the net cost of power from the
co-generation project by approximately 17% annually.

       In December  1999,  the Company bought out the remaining 8.5 years of one
of the  natural  gas  supply  contracts  serving  Encogen  from  Cabot Oil & Gas
Corporation  which  provided  approximately  60%  of  the  plant's  natural  gas
requirements.  The  Company  will  become the  replacement  gas  supplier to the
project for 60% of the supply under the terms of the Cabot Agreement and expects
the agreement  will reduce this portion of gas costs by 5% to 15% annually.  The
Washington  Commission has issued an order creating a regulatory  asset relating
to the $12 million payment that requires the Company to accrue carrying costs on
the unamortized balance over the first 3 years.

       On March 20, 1991,  the Company  executed a 20-year  contract to purchase
216 average MW of energy and 245 MW of capacity,  beginning in April 1994,  from
Tenaska Washington  Partners,  L.P., which owns and operates a natural gas-fired
cogeneration  project  located near Ferndale,  Washington.  In December 1997 and
January 1998, the Company and Tenaska  Washington  Partners entered into revised
agreements  which will lower  purchased  power costs from the Tenaska project by
restructuring  its natural gas supply.  The Company paid $215 million to buy out
the project's existing long-term gas supply contracts, which contained fixed and
escalating  gas prices that were well above current and projected  future market
prices for natural gas. The Company became the principal natural gas supplier to
the project and power purchase prices under the Tenaska contract were revised to
reflect  market-based prices for the natural gas supply. The Company obtained an
order from the Washington  Commission creating a regulatory asset related to the
$215 million  restructuring  payment.  Under terms of the order,  the Company is
allowed to accrue as an additional  regulatory asset one-half the carrying costs
of the deferred  balance over the first five years.  These revised  arrangements
are expected to reduce the Company's power supply costs from the Tenaska project
an  average  of between  15 and 20  percent  over the 14 year  period  from 1998
through 2011, net of the costs of the restructuring payment.

ELECTRIC RATES AND REGULATION

       The order approving the merger of the Company,  Washington Energy Company
and  Washington  Natural  Gas  Company  ("Merger"),  issued  by  the  Washington
Commission  on  February  5, 1997,  contains a rate plan  designed  to provide a
five-year period of rate certainty for customers and to provide the Company with
an opportunity to achieve a reasonable  return on investment.  General  electric
tariff rates were stipulated to increase annually between 1.0% to 1.5% depending
on rate class on  January 1 of 1998  through  2000.  Electric  tariff  rates for
certain customers will increase by 1.5% in 2001.

                                       10
<PAGE>

       ELECTRIC UTILITY OPERATING STATISTICS
<TABLE>
<CAPTION>
  YEAR ENDED ON DECEMBER 31                 1999          1998         1997
----------------------------------------------------------------------------
<S>                                     <C>           <C>          <C>
  Operating revenues by classes:
  (thousands)
----------------------------------------------------------------------------
    Residential                         $586,416      $540,549     $529,990
    Commercial                           457,339       431,752      414,480
    Industrial                           169,508       180,959      166,473
    Other consumers                       37,562        42,952       32,453
----------------------------------------------------------------------------
      Operating revenues

      billed to consumers (1)          1,250,825     1,196,212    1,143,396
    Unbilled revenues -
    net increase (decrease)               (9,541)        4,024       (4,921)
    PRAM accrual                              --            --      (40,777)
-----------------------------------------------------------------------------
      Total operating revenues

      from consumers                   1,241,284     1,200,236    1,097,698
    Wholesale customers                  316,728       274,972      133,726
----------------------------------------------------------------------------
      Total operating revenues        $1,558,012    $1,475,208   $1,231,424
----------------------------------------------------------------------------
  Number of customers (average):
    Residential                          797,421       782,095      767,476
    Commercial                            96,769        94,118       91,517
    Industrial                             4,224         4,193        4,090
    Other                                  1,497         1,437        1,389
----------------------------------------------------------------------------
      Total customers (average)          899,911       881,843      864,472
----------------------------------------------------------------------------
  KWH generated, purchased and
    interchanged (thousands):
    Company generated                  7,941,632     7,934,730    6,641,118
    Purchased power                   26,716,328    24,231,978   22,611,963
    Interchanged power (net)              19,650        91,230      103,959
----------------------------------------------------------------------------
      Total energy output             34,677,610    32,257,938   29,357,040
    Losses and company use            (1,512,571)   (1,413,331)  (1,414,101)
----------------------------------------------------------------------------
      Total energy sales              33,165,039    30,844,607   27,942,939
----------------------------------------------------------------------------
</TABLE>

_____________________________

     (2)  Operating  revenues  in  1999,  1998 and 1997  were  reduced  by $43.8
million,  $46.7  million and $40.5  million,  respectively,  as a result of the
Company's  sale  of  $237.7   million  of  its   investment  in   customer-owned
conservation  measures.  (See "Operating  revenues" in  Management's  Discussion
and Analysis and Note 1 to the Consolidated Financial Statements.)

                                       11
<PAGE>

       (continued from previous page)
<TABLE>
<CAPTION>
  YEAR ENDED ON DECEMBER 31                      1999         1998         1997
--------------------------------------------------------------------------------
<S>                                         <C>          <C>          <C>
  Electric energy sales, KWH:
  (thousands)
--------------------------------------------------------------------------------
    Residential                             9,861,791    9,313,652    9,319,508
    Commercial                              7,482,280    7,191,164    7,022,092
    Industrial                              3,980,246    4,072,722    3,994,748
    Other consumers                           262,238      284,312      206,330
--------------------------------------------------------------------------------
       Total energy billed to consumers    21,586,555   20,861,850   20,542,678
    Unbilled energy sales -
       net increase (decrease)               (155,023)      43,027      (45,556)
--------------------------------------------------------------------------------
       Total energy sales to consumers     21,431,532   20,904,877   20,497,122
    Sales to wholesale customers           11,733,507    9,939,730    7,445,817
--------------------------------------------------------------------------------
       Total energy sales                  33,165,039   30,844,607   27,942,939
--------------------------------------------------------------------------------
  Per residential customer:
    Annual use (KWH)                           12,367       11,909       12,143
    Annual billed revenue                     $762.78      $721.09      $716.88
    Billed revenue per KWH                     $.0617       $.0606       $.0590
  Company-owned generation
    capability - KW:
    Hydro                                     310,700      308,200      309,950
    Steam                                     771,900      771,900      771,900
    Natural gas/oil                           813,050      673,850      702,350
--------------------------------------------------------------------------------
       Total                                1,895,650    1,753,950    1,784,200
--------------------------------------------------------------------------------
  Heating degree days                           4,956        4,498        4,599
  Percent of normal of 30 year
    average                                    101.0%        91.6%        93.7%
  Load factor                                   62.6%        52.6%        58.7%
</TABLE>

                                       12
<PAGE>

Gas Utility Operations

Gas Supply

       The Company  currently  purchases a blended  portfolio of long-term firm,
short-term  firm,  and non-firm gas supplies  from a diverse  group of major and
independent  producers and gas marketers in the United States and Canada. All of
the Company's gas supply is ultimately  transported  through Northwest  Pipeline
Corporation  ("NPC"),  the sole interstate pipeline delivering directly into the
western Washington area.
<TABLE>
<CAPTION>
  PEAK FIRM GAS SUPPLY AT
  DECEMBER 31, 1999                         DTH PER DAY         %
-----------------------------------------------------------------
<S>                                         <C>            <C>
  Purchased Gas Supply

     British Columbia                          153,700      19.3
     Alberta                                    77,100       9.7
     United States                              75,000       9.4
-----------------------------------------------------------------
  Total Purchased Gas Supply                   305,800      38.4
-----------------------------------------------------------------
  Purchased Storage Capacity

     Clay Basin                                 76,200       9.6
     Jackson Prairie                            48,000       6.0
     LNG                                        69,900       8.8
-----------------------------------------------------------------
  Total Purchased Storage Capacity             194,100      24.4
-----------------------------------------------------------------
  Owned Storage Capacity

     Jackson Prairie                           267,400      33.5
     Propane-Air Injection                      30,000       3.7
-----------------------------------------------------------------
  Total Owned Storage Capacity                 297,400      37.2
-----------------------------------------------------------------
  Total Peak Firm Gas Supply                   797,300     100.0
-----------------------------------------------------------------
</TABLE>
All peak firm gas supplies  and storage are  connected to PSE's market with firm
transportation capacity.

       For baseload and peak-shaving  purposes, the Company supplements its firm
gas supply  portfolio by  purchasing  natural gas at  generally  lower prices in
summer,  injecting it into  underground  storage  facilities and  withdrawing it
during the winter  heating  season.  Storage  facilities  at Jackson  Prairie in
Western Washington and at Clay Basin in Utah are used for this purpose.  Peaking
needs are also met by using  Company-owned  gas held in NPC's liquefied  natural
gas ("LNG") facility at Plymouth,  Washington,  and by producing propane-air gas
at a plant owned by the Company and located on its distribution system.

       In 1998,  the  Company  took  assignment  from  Cascade  Natural Gas of a
Peaking Gas Supply Service  ("PGSS")  contract whereby the Company can divert up
to 48,000 Dth per day of gas supply away from the Tenaska Cogeneration  Facility
and toward the core gas load by causing  Tenaska  to  operate  its  facility  on
distillate fuel and paying any additional costs of such operation.

       The  Company  expects  to  meet  its  firm  peak-day   requirements   for
residential,  commercial  and industrial  markets  through its firm gas purchase
contracts,  firm transportation  capacity,  firm storage capacity and other firm
peaking  resources.  The  Company  believes  that it  will  be  able to  acquire
incremental firm gas supply resources which are reliable and reasonably  priced,
to meet  anticipated  growth in the  requirements  of its firm customers for the
foreseeable future.

                                       13
<PAGE>

Gas Supply Portfolio

       For the 1999-2000  winter heating season,  the Company has contracted for
approximately 19% of its expected  peak-day gas supply  requirement from sources
originating   in  British   Columbia   under  a  combination  of  long-term  and
winter-peaking   purchase  agreements.   Long-term  gas  supplies  from  Alberta
represent  approximately 10% of the peak-day  requirement.  Long-term and winter
peaking  arrangements  with U.S.  suppliers and gas stored at Clay Basin make up
approximately  19%  of the  peak-day  portfolio.  The  balance  of the  peak-day
requirement is expected to be met with gas stored at Jackson  Prairie,  LNG held
at  NPC's  Plymouth   facility  and  propane-air   resources,   which  represent
approximately 39%, 9% and 4%, respectively, of expected peak-day requirements.

       During 1999,  approximately 48% of gas supplies  purchased by the Company
originated  from  British  Columbia  while 26%  originated  in  Alberta  and 26%
originated in the U.S.

       The current firm, long-term gas supply portfolio consists of arrangements
with 18 producers and gas marketers,  with no single supplier  representing more
than 12% of expected  peak-day  requirements.  Contracts  have  remaining  terms
ranging  from less than one year to 12 years,  with an average  term of 2 years.
All gas supply contracts contain  market-sensitive  pricing  provisions based on
several published indices.

       The  Company's  firm gas supply  portfolio is structured to capitalize on
regional  price  differentials  when they arise.  Gas and  services are marketed
outside the Company's service territory  ("off-system sales") whenever on-system
customer demand requirements  permit. The geographic mix of suppliers and daily,
monthly and annual take  requirements  permit a high  degree of  flexibility  in
selecting gas supplies during off-peak periods to minimize costs.

GAS TRANSPORTATION CAPACITY

       The Company  currently  holds firm  transportation  capacity on pipelines
owned by NPC and  PG&E  Gas  Transmission-Northwest  ("PGT").  Accordingly,  the
Company pays fixed monthly demand charges for the right, but not the obligation,
to transport specified  quantities of gas from receipt points to delivery points
on such pipelines each day for the term or terms of the applicable agreements.

       The  Company  holds firm  capacity  on NPC's  pipeline  totaling  454,533
Dekatherms  per day (one  Dekatherm,  or Dth,  is equal to one  million  British
thermal units or "MMBtu" per day),  acquired under several agreements at various
times.  The Company has  exchanged  certain  segments of its firm  capacity with
third parties to  effectively  lower  transportation  costs.  The Company's firm
transportation  capacity  contracts with NPC have remaining terms ranging from 5
to 16 years.  However, the Company has either the unilateral right to extend the
contracts under their current terms or the right of first refusal to extend such
contracts under current FERC orders. The Company's firm transportation  capacity
on PGT's  pipeline,  totaling  90,392 Dth per day,  has a  remaining  term of 24
years.

GAS STORAGE CAPACITY

       The Company holds storage  capacity in the Jackson Prairie and Clay Basin
underground  gas  storage  facilities  adjacent to NPC's  pipeline.  The Jackson
Prairie facility, operated and one-third owned by the Company, is used primarily
for intermediate peaking purposes,  able to deliver a large volume of gas over a
relatively  short time period.  Combined  with  capacity  contracted  from NPC's
one-third stake in Jackson Prairie, the Company has peak, firm delivery capacity
of over 340,000 Dth per day and total firm storage capacity exceeding  7,500,000
Dth at the  facility.  The  location  of the  Jackson  Prairie  facility  in the
Company's  market area provides  significant cost savings by reducing the amount
of annual  pipeline  capacity  required to meet  peak-day gas  requirements.  On
November 1, 1999,  a facility  expansion  was placed in service.  The  Company's
share of the expanded service provides additional firm delivery capacity of over
100,000 Dth per day and additional firm storage  capacity in excess of 1,000,000
Dth. The Company secured rights to additional firm seasonal pipeline capacity to
be utilized in conjunction with the expanded service.

       The Clay Basin  storage  facility is supply area storage and is withdrawn
over the  entire  winter,  capturing  savings  due to  injecting  lower cost gas
supplies during the summer. The Company has maximum firm withdrawal  capacity of
over 100,000 Dth per day from the facility with total storage capacity exceeding
13,000,000 Dth. The capacity is held under two contracts with remaining terms of
14 and 20 years.

                                       14
<PAGE>

LNG AND PROPANE-AIR RESOURCES

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

CAPACITY RELEASE

       FERC  provided a capacity  release  mechanism as the means for holders of
firm pipeline and storage  entitlements  to  temporarily  relinquish  unutilized
capacity  to  others in order to  recoup  all or a  portion  of the cost of such
capacity.  Capacity  may be released  through  several  methods  including  open
bidding and by pre-arrangement. The Company continues to successfully mitigate a
portion of the demand  charges  related to both storage and NPC and PGT pipeline
capacity  not  utilized  during  off-peak  periods.  WNG CAP I, a  wholly  owned
subsidiary  of the Company,  was formed to provide  additional  flexibility  and
benefits  from  capacity  release.  Capacity  release  benefits are passed on to
customers through the PGA.

GAS RATES AND REGULATION

       The order  approving the Merger,  issued by the Washington  Commission on
February 5, 1997,  contains a rate plan which provided  unchanged  rates for all
classes of natural gas customers  until January 1, 1999, when rates decreased by
approximately $2 million annually.

       On October 27, 1999, the Washington Commission approved the Company's PGA
and deferral amortization  (true-up) filings effective November 1, 1999. The PGA
filing  allows the Company to recover an  expected  increase in annual gas costs
and the deferral  amortization filing allows the Company to recover prior period
gas  cost   undercollections.   The  filings   replaced  the  PGA  and  deferral
amortization  refund that had been  effective  since April 1, 1998. As a result,
gas rates to all sales customers  increased by an average of 16.3%,  while rates
for gas transportation service as well as gas margins remained unchanged.

       On June 25,  1998,  the Company  received  approval  from the  Washington
Commission  to begin a new  performance-based  mechanism for  strengthening  its
gas-supply  purchasing and gas-storage  practices.  The PGA Incentive Mechanism,
which  encourages  competitive  gas  purchasing  and  management of pipeline and
storage-capacity  became effective July 1, 1998. Incentive gains and losses from
the three-year program are shared between customers and shareholders.  After the
first $0.5 million, which is allocated to customers, gains and losses are shared
40%/60%  between the  Company and  customers  up to $26.5  million,  and 33%/67%
thereafter.  Gains or losses are determined relative to a weighted average index
which is  reflective of the  Company's  gas supply and  transportation  contract
costs. The Company's share of incentive gains under the PGA Incentive  Mechanism
in 1999 and 1998 were approximately $7.2 million and $1.1 million,  respectively
while  customers  received   approximately   $11.3  million  and  $2.0  million,
respectively.

                                       15
<PAGE>

        GAS UTILITY OPERATING STATISTICS
<TABLE>
<CAPTION>

  Twelve Months Ended December 31                     1999       1998       1997
--------------------------------------------------------------------------------
<S>                                              <C>         <C>        <C>
  Operating revenues by classes (thousands):
  Regulated utility sales:
    Residential sales                             $296,032   $253,169   $246,747
    Commercial firm sales                          113,058     96,116     97,233
    Industrial firm sales                           21,724     18,557     19,524
    Interruptible sales                             30,404     22,190     19,832
    Transportation services                         13,117     14,211     14,631
    Other                                           11,153     12,308     11,480
--------------------------------------------------------------------------------
      Total gas operating revenues                $485,488   $416,551   $409,447
--------------------------------------------------------------------------------
  Customers, average number served
    Residential                                    509,384    486,553    465,185
    Commercial firm                                 43,567     42,273     41,158
    Industrial firm                                  2,879      2,850      2,839
    Interruptible                                      873        940        962
    Transportation                                     103        123        128
--------------------------------------------------------------------------------
      Total customers (average)                    556,806    532,739    510,272
--------------------------------------------------------------------------------
  Gas volumes (thousands of therms):

    Residential sales                              507,978    444,611    434,179
    Commercial firm sales                          221,804    193,765    195,087
    Industrial firm sales                           48,422     42,737     44,563
    Interruptible sales                             93,791     72,115     60,244
    Transportation volumes                         236,704    254,368    277,092
--------------------------------------------------------------------------------
      Total gas volumes                          1,108,699  1,007,596  1,011,165
--------------------------------------------------------------------------------
  Working-gas volumes in storage at year end
  (thousands of therms)
      Jackson Prairie                               60,673     37,683     52,429
      Clay Basin                                    37,281     58,827     64,934
  Average use per customer (therms):
    Residential                                        997        914        933
    Commercial firm                                  5,091      4,584      4,740
    Industrial firm                                 16,819     14,995     15,697
    Interruptible                                  107,435     76,718     62,624
    Transportation                               2,298,097  2,068,033  2,164,781
</TABLE>
                                       16
<PAGE>

(continued from prior page)

<TABLE>
<CAPTION>
  TWELVE MONTHS ENDED DECEMBER 31                     1999       1998       1997
--------------------------------------------------------------------------------
<S>                                                 <C>       <C>        <C>
  Average revenue per customer:
    Residential                                     $  581     $  520     $  530
    Commercial firm                                  2,595      2,274      2,362
    Industrial firm                                  7,546      6,511      6,877
    Interruptible                                   34,827     23,606     20,615
    Transportation                                 127,350    115,537    114,305
  Average revenue per therm (cents):

    Residential                                       58.3       56.9       56.8
    Commercial firm                                   51.0       49.6       49.8
    Industrial firm                                   44.9       43.4       43.8
    Interruptible                                     32.4       30.8       32.9
      Total sales to customers                        52.9       51.8       52.2
    Transportation                                     5.5        5.6        5.3

  Weather - degree days                              4,956      4,498      4,599
    Percent of normal (30-year average)             101.0%      91.6%      93.7%
</TABLE>

ENERGY CONSERVATION

       The Company offers programs  designed to help new and existing  customers
use energy  efficiently.  The  primary  emphasis is to provide  information  and
technical  services to enable  customers to make  energy-efficient  choices with
respect to building design, equipment and building systems,  appliance purchases
and operating practices.

       Since May 1997, the Company has recovered  electric  energy  conservation
expenditures  through a tariff rider  mechanism.  The rider mechanism allows the
Company to defer the  conservation  expenditures and amortize them to expense as
the Company concurrently collects the conservation  expenditures in rates over a
one year  period.  As a result of the rider,  there is no effect on earnings per
share.

       Since 1995, the Company has been authorized by the Washington  Commission
to defer gas energy conservation  expenditures and recover them through a tariff
tracker   mechanism.   The  tracker   mechanism  allows  the  Company  to  defer
conservation  expenditures  and recover them in rates over the subsequent  year.
The tracker  mechanism also allows the Company to recover an Allowance for Funds
Used to Conserve  Energy  (AFUCE) on any  outstanding  balance that is not being
recovered in rates.

ENVIRONMENT

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

FEDERAL CLEAN AIR ACT AMENDMENTS OF 1990

       The  Company has an  ownership  interest  in  coal-fired,  steam-electric
generating  plants at Centralia,  Washington  and Colstrip,  Montana,  which are
subject to the  federal  Clean Air Act  Amendments  of 1990  ("CAAA")  and other
regulatory requirements.

                                       17
<PAGE>

       The Centralia  Project and the Colstrip  Projects met the sulfur  dioxide
limits of the CAAA in Phase I (1995).  All four units at the  Colstrip  Project,
operated by Montana Power, meet Phase II emission limits. In accordance with the
purchase agreement with TransAlta,  the Centralia Owners are installing flue gas
scrubbers and low NOx burners on both units of the Centralia  generating station
to meet state and federal emissions standards. The current cost estimate for the
Company's share of these additions is $14 million,  of which  approximately $4.2
million will have been committed by the anticipated  closing date of the sale of
Centralia to TransAlta. In accordance with the agreements with TransAlta,  these
expenditures will be reimbursed by TransAlta.

       The Company owns combustion  turbine units,  most of which are capable of
being  fueled  by  natural  gas or oil.  The  nature  of  these  units  provides
operational flexibility in meeting air emission standards.

       There  is no  assurance  that  in the  future  environmental  regulations
affecting  sulfur  dioxide  or  nitrogen  oxide  emissions  may  not be  further
restricted,  or that  restrictions  on  emissions  of  carbon  dioxide  or other
combustion by-products may not be imposed.

FEDERAL ENDANGERED SPECIES ACT

       In November 1991, the National Marine  Fisheries  Service ("NMFS") listed
the Snake  River  Sockeye  as an  endangered  species  pursuant  to the  federal
Endangered Species Act ("ESA").  Since the Sockeye listing, the Snake River fall
and  spring/summer  Chinook have also been listed as threatened.  In response to
the  listings,  a team of experts was formed to develop a plan for the  recovery
needs of these species.  In 1995, the NMFS issued a biological opinion which has
significantly changed the operation of the Federal Columbia River Power System.

       The plans developed by NMFS affect the  Mid-Columbia  projects from which
the Company  purchases power on a long-term  basis,  and will further reduce the
flexibility of the regional hydro-electric system. Although the full impacts are
unknown  at this  time,  the plan  developed  by NMFS  shifts  an  amount of the
Company's generation from the Mid-Columbia projects from winter periods into the
spring when it is not needed for system  loads,  and will increase the potential
for spill and loss of generation at the Mid-Columbia projects.

       Since the 1991  listings,  one more species of salmon has been listed and
two more have  been  proposed  which may  further  influence  operations.  Upper
Columbia River  Steelhead were listed by NMFS in August 1997.  Anticipating  the
Steelhead listing, the Mid-Columbia PUDs initiated consultation with the federal
and state agencies, Native American tribes and non-governmental organizations to
secure  operational  protection  through  a  long-term  settlement  and  habitat
conservation plan which includes fish protection and enhancement measurement for
the next 50 years. The negotiations  have concluded among the Chelan and Douglas
County PUDs and various  fishery  agencies,  and final agreement is subject to a
National   Environmental   Policy  Act  review  and  power  purchaser  approval.
Generally, the agreement obligates the PUDs to achieve certain levels of passage
efficiency for  downstream  migrants at their  hydro-electric  facilities and to
fund certain habitat  conservation  measures.  Grant County PUD has yet to reach
agreement on these issues.

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

                                       18
<PAGE>

EXECUTIVE OFFICERS AT MARCH 1, 2000



  NAME             AGE   OFFICES
--------------------------------------------------------------------------------
  W. S. Weaver     56    President & Chief Executive Officer since January 1998;
                         President, May  1997 -  January  1998;  Vice Chairman
                         and  Chairman  of Unregulated Subsidiaries, February
                         1997 - May 1997; Executive Vice President and Chief
                         Financial Officer 1991-1997; Director since 1991.
  J. W. Eldredge   49    Chief Accounting Officer since 1994; Corporate
                         Secretary and Controller since 1993; Controller since
                         1988.
  D. E. Gaines     43    Treasurer since 1994; Director Strategic Planning 1992-
                         1994; Manager Financial Planning 1986 - 1992.
  W. A. Gaines     44    Vice President Energy Supply since February 1997;
                         Manager Power Management 1996-1997; Manager Operations
                         Planning 1986-1996.
  D. A. Graham     59    Vice President Human Resources since April 1998;
                         Director Human Resources 1989-1998.
  R. L. Hawley     50    Vice President and Chief Financial Officer since March
                         1998. For more than five years prior to that time, he
                         was a partner with the accounting firm of
                         PricewaterhouseCoopers LLP.
  T. J. Hogan      48    Vice President Systems Operations since February 1997;
                         Washington Energy Company positions held: Executive
                         Vice President and Chief Operating Officer 1995-1997;
                         Vice President Supply, Administration and Corporate
                         Secretary 1994-1995; Vice President Legal and Corporate
                         Secretary 1991-1994.
  S. A. McKeon     54    Vice President and General Counsel since June 1997. For
                         more than five years prior to that time he was a
                         partner with the law firm of Perkins Coie LLP.
  S. McLain        43    Vice President Operations - Delivery since June 1999;
                         Vice President Corporate Performance 1997-1999;
                         Director Planning and Work Practices 1997; various
                         positions in Human Resources, Operations, Customer
                         Service and Strategic Planning 1988-1997.
  G. B. Swofford   58    Vice President and Chief Operating Officer - Delivery
                         since June 1999; Vice President Customer Operations
                         1997-1999; Senior Vice President Customer Operations
                         1994-1997; Vice President Divisions and Customer
                         Services 1991-1994; Vice President Rates and Customer
                         Programs 1986-1991.

Officers are elected for one-year terms.

                                       19
<PAGE>

         ITEM 2. PROPERTIES

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

         ITEM  3.  LEGAL PROCEEDINGS

       See Note 17 to the Consolidated Financial Statements.

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

         PART II

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

       The  Company's  common stock (symbol PSD) is traded on the New York Stock
Exchange.  The number of shareholders of record of the Company's common stock at
December 31, 1999, was 53,434.

       The Company has paid  dividends  on its common stock each year since 1943
when such stock first became publicly held.  Future  dividends will be dependent
upon earnings, the financial condition of the Company and other factors.

       The payment of dividends on common stock is  restricted  by provisions of
certain covenants  applicable to preferred stock and long-term debt contained in
the  Company's   Articles  of  Incorporation   and  electric  and  gas  mortgage
indentures.  Under the most restrictive  covenants,  earnings  reinvested in the
business  unrestricted as to payment of cash dividends were  approximately  $202
million  at  December  31,  1999.  (See  Note  7 to the  Consolidated  Financial
Statements.)


                                       20
<PAGE>


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

<TABLE>
<CAPTION>
                          1999                                  1998
-------------------------------------------------------------------------------

                       PRICE RANGE       DIVIDENDS      PRICE RANGE   DIVIDENDS

  QUARTER ENDED     HIGH      LOW         PAID        HIGH      LOW        PAID
-------------------------------------------------------------------------------
<S>                 <C>       <C>         <C>         <C>       <C>        <C>
  March 31          28-3/8    22-15/16    $.46        30-1/4    26-5/8     $.46
  June 30           26-3/8    23-1/8      $.46        28-5/8    25         $.46
  September 30      24-1/2    21-3/4      $.46        28        24-1/16    $.46
  December 31       23-1/4    18-3/4      $.46        29        25-7/8     $.46
</TABLE>

                                       21
<PAGE>

         ITEM  6.  SELECTED FINANCIAL DATA (1)

(Dollars in thousands except per share data)

<TABLE>
<CAPTION>
  YEAR ENDED DECEMBER 31                         1999         1998          1997         1996         1995
-----------------------------------------------------------------------------------------------------------
<S>                                        <C>          <C>           <C>          <C>          <C>
  Operating revenue                        $2,066,630   $1,923,856    $1,681,528   $1,652,265   $1,631,118
  Operating income                            310,132      295,098       210,638      282,876      270,344
  Income from continuing
    operations                                185,567      169,612       125,698      167,351      128,381
  Income for common stock from
    continuing operations                     174,502      156,609       108,363      145,170      105,727

  Basic and diluted earnings
    per common share from
    continuing operations (Note 1 to the         2.06         1.85          1.28         1.72         1.26
       financial statements)
  Dividends per common share                     1.84         1.84          1.78         1.67         1.67
  Book value per common share                   16.24        16.00         16.06        16.31        16.27
-----------------------------------------------------------------------------------------------------------
  Total assets at year-end                 $5,145,606   $4,709,687    $4,493,306   $4,230,855   $4,244,568
  Long-term obligations                     1,783,139    1,475,106     1,412,153    1,166,601    1,230,499
  Redeemable preferred stock                   65,662       73,162        78,134       87,839       89,039
  Corporation obligated,
    mandatorily redeemable
    preferred securities of
    subsidiary trust holding
    solely junior subordinated
    debentures of the
    corporation                               100,000      100,000       100,000           --           --
-----------------------------------------------------------------------------------------------------------
</TABLE>
     (1) Amounts for 1996 and 1995 have been  retroactively  restated to include
the results of operations, financial position and cash flows of WECo and WNG.

                                       22
<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 uncertainties.  Those risks and
uncertainties  include, but are not limited to, the ongoing restructuring of the
electric and gas industries and the outcome of regulatory proceedings related to
that restructuring.  The ultimate impacts of both increased  competition and the
changing  regulatory  environment  on  future  results  are  uncertain,  but are
expected to  fundamentally  change how the Company  conducts its  business.  The
outcome of these  changes and other  matters  discussed  below may cause  future
results to differ materially from historic results,  or from results or outcomes
currently expected or sought by the Company.

Financial Condition and Results of Operations

       Net income in 1999 was $185.6  million on  operating  revenues  of $2.067
billion,  compared to $169.6 million on operating  revenues of $1.924 billion in
1998 and $123.1 million on operating  revenues of $1.682 billion in 1997. Income
for common stock was $174.5 million in 1999,  compared to $156.6 million in 1998
and $105.7 million in 1997.

       Basic and diluted  earnings  per share in 1999 were $2.06 on 84.6 million
weighted  average  common shares  outstanding  compared to $1.85 on 84.6 million
weighted  average  common shares  outstanding  in 1998 and $1.25 on 84.6 million
weighted  average  common shares  outstanding in 1997 including a $0.03 loss per
share from discontinued operations.

       Net income in 1999 was positively  impacted by net gains of approximately
$7.8 million or $0.09 per share from non-utility operations. The $0.09 per share
included  gains from the sale of  Homeguard  Security  Services,  Inc., a wholly
owned  subsidiary,  and the Company's common stock investment in Cabot Oil & Gas
Corporation.  These  gains  were  offset in part by losses  related  to sales of
non-core assets and gas transportation contracts,  establishing reserves for two
proposed small hydroelectric  projects and costs of a subsidiary exiting certain
product lines. Net income for 1997 included an after-tax charge of $36.3 million
($0.43  per  share)  for  costs  related  to the  merger  including  transaction
expenses, employee separation and system and facilities integration.  Net income
in 1997 also included an after-tax charge of $2.6 million ($0.03 per share),  to
write off the Company's  remaining  investment in undeveloped  coal reserves and
related  activities  in  southeastern  Montana (See Note 18 to the  Consolidated
Financial  Statements).  These  charges in 1997 were  partially  offset by $13.6
million  ($0.16 per share)  related  to an income tax refund  received  in 1997.
Excluding  the  impact  of these  charges  and  credits  to  income,  continuing
operations for 1997 produced earnings of $1.55 per share.

       Total  kilowatt-hour  sales  to  ultimate  consumers  in 1999  were  21.4
billion,  compared  with  20.9  billion  in  1998  and  20.5  billion  in  1997.
Kilowatt-hour  sales to  wholesale  customers  were 11.7  billion  in 1999,  9.9
billion in 1998 and 7.4 billion in 1997.

       Total gas volumes,  including gas sales service and transportation,  were
1,109 million  therms in 1999,  1,008  million  therms in 1998 and 1,011 million
therms in 1997.


                                       23
<PAGE>

  INCREASE (DECREASE) OVER PRECEDING YEAR

  years ended December 31 (dollars in millions)

                                                     1999       1998
---------------------------------------------------------------------
  Operating revenues:
    General rate increases                          $17.3      $18.5
    PRAM electric revenue surcharges/refunds           --       44.8
    BPA Residential Purchase and

      Sale Agreement                                 (4.8)      (1.2)
    Electric sales to wholesale customers            41.8      141.2
    Electric revenue sold to conservation trust       2.9       (6.3)
    Electric load and other changes                  25.7       46.7
    Gas revenue change                               68.9        7.1
    Other revenues                                   (9.0)      (8.6)
---------------------------------------------------------------------
       Total operating revenue changes              142.8      242.2
---------------------------------------------------------------------
  Operating expenses:
    Energy costs:
      Purchased electricity                          28.0      137.2
      Residential exchange                           16.6       16.4
      Purchased gas                                  44.2       (3.5)
      Electric generation fuel                        2.9       15.1
    Utility operations and maintenance                9.0      (12.5)
    Other operations and maintenance                 (7.7)      (3.8)
    Depreciation and amortization                    10.1        3.7
    Conservation amortization                         1.6       (1.1)
    Merger and related costs                           --      (55.8)
    Taxes other than federal income taxes            19.7        1.2
    Federal income taxes                              3.3       60.9
---------------------------------------------------------------------
       Total operating expense changes              127.7      157.8
---------------------------------------------------------------------
  Other income                                       12.6      (20.2)
  Interest charges                                   11.7       20.3
  Discontinued operations                              --        2.6
---------------------------------------------------------------------
  Net income changes                               $ 16.0     $ 46.5
---------------------------------------------------------------------

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

Operating Revenues - Electric

       Electric  operating revenues increased $17.3 million and $18.5 million in
1999 and 1998,  respectively,  when  compared  to the prior years due to overall
average  1.2% general rate  increases  effective  January 1, 1998 and January 1,
1999.

       Electric  operating  revenues in 1998 increased $44.8 million compared to
1997 as a result of a $48.6 million Periodic Rate Adjustment  Mechanism ("PRAM")
revenue  reduction in 1997  associated  with an IRS 1991-1994  Conservation  tax
refund and related  interest income.  Based on the Company's  agreement with the
Washington  Commission,  the  benefit  of the tax refund was passed on to retail
customers  as a reduction  of the PRAM accrued  revenue  balance.  A decrease in
federal,  state and local taxes as well as a decrease  in  interest  expense and
recognition of interest income offset the $48.6 million reduction in revenues in
1997.

                                       24
<PAGE>

       Electric  revenues  in 1999,  1998 and 1997 were  reduced  because of the
credit  that the Company  received  through the  Residential  Purchase  and Sale
Agreement  with the  Bonneville  Power  Administration  ("BPA").  This agreement
enables  the  Company's  residential  and small farm  customers  to receive  the
benefits of lower-cost  federal power.  On January 29, 1997, the Company and the
BPA  signed  a  Residential  Exchange  Termination  Agreement.  The  Termination
Agreement ends the Company's  participation in the Residential Purchase and Sale
Agreement  with BPA. As part of the  Termination  Agreement,  the  Company  will
receive payments by the BPA of approximately  $235 million over an approximately
5-year  period ending June 2001.  These  payments are recorded as a reduction of
purchased electricity  expenses.  Under the rate plan approved by the Washington
Commission  in its merger  order,  the Company  will  continue  to  reflect,  in
customers'  bills,  the level of Residential  Exchange  benefits in place at the
time of the merger. Over the remainder of the Residential  Exchange  Termination
Agreement  from January 2000 through June 2001, it is projected that the Company
will credit  customers  approximately  $106.8  million more than it will receive
from BPA during the following periods:

                                 Credit to    Received from BPA   Excess Credits
                                 Customers
      Period                                   (in Millions)
      --------------------------------------------------------------------------
       January - December 2000       $111.2           $41.0             $70.2
      January - June 2001             63.6            27.0              36.6
                              --------------------------------------------------
                                    $174.8           $68.0            $106.8

       The  allocation of future  benefits of low-cost  federal  power,  for the
five-year BPA rate plan period 2002 to 2006 will be decided as part of a current
BPA rate case  process.  As part of its rate case,  the BPA has a  "subscription
plan" that  outlines how the agency  proposes to allocate  the low-cost  federal
power, or in some cases, the power's equivalent  monetary benefits.  Following a
public rate-hearing process, the BPA is expected to publish a record of decision
on final power rates and allocations in the latter part of 2000.

       Electric  revenues  in 1999 and 1998 were  reduced by $43.8  million  and
$46.7  million,  respectively,  when  compared to prior years as a result of the
Company's sale of revenues  associated  with $237.7 million of its investment in
conservation  assets to grantor  trusts.  The revenue  decrease  represents  the
portion of rate revenues that were sold and forwarded to the trusts.  The impact
of this revenue  decrease,  however,  was offset by related  reductions in other
utility operations and maintenance and interest expenses.

       To meet customer demand,  the Company's power supply  portfolio  includes
net purchases of power under  long-term  supply  contracts.  However,  depending
principally upon streamflow available for hydro-electric  generation and weather
effects on customer demand, from time to time the Company may have surplus power
available  for  sale to  wholesale  customers.  In  addition,  the  Company  has
increased  its  wholesale  surplus  power  business  in order to manage its core
energy portfolio through short and intermediate-term purchases, sales, arbitrage
and  other  risk  management  techniques.  The  Company  has a  Risk  Management
Committee which oversees energy price risk matters. Sales to wholesale customers
increased  $41.8  million  and $141.2  million  in 1999 and 1998,  respectively,
compared to the prior years due primarily to favorable hydroelectric  conditions
and increased wholesale power transactions. Wholesale sales generally have small
margins.  However, there may be certain times when the market price of power may
cause margins to fluctuate.

OPERATING REVENUES - GAS

       Regulated gas utility revenue in 1999 increased by $68.9 million from the
prior year on a 15.8% increase in gas volumes sold. Total gas volumes, including
transported  gas,  increased  10.0% in 1999 from  1998.  The  increase  in sales
revenue was  primarily  the result of a 4.5%  increase in gas  customers  during
1999, the impact of temperatures that averaged near normal as compared to warmer
than  normal  in the prior  year and a  Purchased  Gas  Adjustment  that  became
effective  November 1, 1999. The Purchased Gas  Adjustment  ("PGA") and deferral
amortization  (true-up) filings  effective  November 1, 1999 accounted for $17.3
million of this  increase.  (See "Rate Matters - Gas").  A larger  percentage of
firm gas sales with higher prices and less  transportation  volumes in 1999 when
compared to last year also contributed to increased revenues. Utility gas margin
(the  difference  between gas  revenues  and gas  purchases)  increased by $19.4
million, or 9.8 %, in 1999 over 1998.

       Regulated gas utility sales revenue in 1998 increased by $7.1 million, or
1.7%,  from the prior year on a 2.6%  increase  in gas volumes  sold.  Total gas
volumes, including transported gas, decreased 0.35% in 1998 from 1997.


                                       25
<PAGE>

OTHER REVENUES

       Other  revenues  decreased  $9.0  million  in 1999  compared  to 1998 due
primarily to  decreased  revenues at the  Company's  ConneXt  subsidiary.  Other
revenues  decreased  $8.6 million in 1998  compared to 1997 due primarily to the
sale of an  unregulated  subsidiary  (Washington  Energy  Services  Company)  in
October 1997.

OPERATING EXPENSES

       Purchased  electricity  expenses  increased  $28.0  million  in 1999 when
compared to 1998 and $137.2  million in 1998 when compared to 1997. The increase
in 1999 was due primarily to an increase in secondary power purchases from other
utilities  and marketers to support  wholesale  sales as a part of the Company's
energy price risk management policies and the increased load due to temperatures
that  averaged  near  normal as  compared  to warmer than normal in 1998 and the
increase in electric  customers in 1999  compared to 1998.  The increase in 1998
was due primarily to a $112.3 million increase in secondary power purchases from
other  utilities  to support  wholesale  sales and  increased  payments of $18.8
million for firm power purchases from non-utility generators.

       Residential exchange credits associated with the Residential Purchase and
Sale Agreement  with BPA decreased  $16.6 million in 1999 when compared to 1998,
primarily as a result of the 1997  Residential  Exchange  Termination  Agreement
discussed in "Operating Revenues - Electric."  Residential exchange credits also
decreased   $16.4  million  in  1998  compared  to  1997  as  a  result  of  the
aforementioned  Termination Agreement.  Residential exchange credits received in
1999 were $39.0  million and are estimated to be $41.0 million and $27.0 million
in the years 2000 and 2001,  respectively.  (See  discussion of the  Residential
Purchase and Sale Agreement under Operating Revenues.)

       Purchased gas expenses  increased  $44.2 million in 1999 compared to 1998
due to both the  increased  volumes of purchases  as a result of higher  heating
load and the increase in gas service  customers.  Purchased  gas  expenses  also
increased  by $17.3  million in 1999  compared  to 1998 due to  approval  of the
Company's PGA filing effective November 1, 1999. Changes in gas costs are passed
through to customers  with the PGA mechanism.  Purchased gas expenses  decreased
$3.5 million in 1998  compared to 1997 despite the 2.6%  increase in gas volumes
sold in 1998.  This  was  primarily  the  result  of a $5.4  million  credit  to
purchased gas costs in the fourth  quarter of 1998 due to a true up of gas costs
through the PGA mechanism.

       Electric  generation fuel expense increased $2.9 million in 1999 compared
to 1998 as a result of a $6.7 million Encogen fuel expense in the fourth quarter
of 1999 which was partially offset by the Company generating less electricity at
other Company-owned  combustion turbines.  The Company's  acquisition of the 160
megawatt  Encogen  natural  gas-fired  cogeneration  facility  was  completed on
November 1, 1999.  (See "Other").  Electric  generation  fuel expense  increased
$15.1 million in 1998 compared to 1997  primarily due to the Company  generating
more  electricity at Company-owned  gas-fired  combustion  turbine plants.  This
increase  was  partially  offset by  reductions  to Colstrip  fuel  expense.  In
September 1998, the Company recorded a reduction of $4.9 million in fuel expense
and $3.5 million of interest  income  related to the  resolution of  outstanding
issues with the Colstrip fuel supplier.

       Utility  operations and  maintenance  expenses  increased $9.0 million in
1999  compared to 1998.  The primary  reasons for the  increase  were  increased
storm-repair  costs of $8.3  million and  increased  expenditures  for Year 2000
remediation  efforts of $4.3 million (total expended in 1999  approximated  $7.1
million for Year 2000 remediation).  Utility operations and maintenance expenses
decreased $12.5 million in 1998 compared to 1997. The decrease was primarily the
result of the reduction in operating  expenses  resulting from  consolidation of
the joint  operations of two formerly  separate  electric and gas utilities with
overlapping  service  territories,  the elimination of duplicate  administrative
functions and the consolidation of Company facilities.

       Other operations and maintenance  expenses decreased $7.7 million in 1999
compared to 1998  primarily as a result of a wholly owned  subsidiary's  exiting
certain product lines. Other operations and maintenance  expenses decreased $3.8
million in 1998 compared to 1997. The decrease resulted  primarily from the sale
of the Company's unregulated subsidiary,  Washington Energy Services Company, in
October  1997.  The  decreases  were  partially  offset by  increased  operating
expenses at another subsidiary.

                                       26
<PAGE>

       Depreciation  and  amortization  expense  increased $10.1 million in 1999
compared to 1998 due  primarily  to the effects of new plant placed into service
during the past year.  Depreciation  and  amortization  expense  increased  $3.7
million in 1998 compared to 1997.  Depreciation and amortization  expense due to
capital  spending  related to adding  customers,  distribution  and transmission
system improvements and computer software  amortization  increased $12.3 million
in  1998.  Partially  offsetting  this  increase  in  1998  was  a  decrease  in
depreciation and amortization  expense  resulting from an August 1997 Washington
Commission  Order which authorized the Company to record in 1997 interest income
of $8.3 million related to a conservation  tax refund,  but required the Company
to expense in 1997 deferred storm damage costs in the amount of $7.4 million and
to establish a $1.0 million reserve to cover the costs of a Company retail pilot
program.

       Taxes other than federal  income taxes  increased  $19.7  million in 1999
compared  to 1998 and $1.2  million in 1998  compared to 1997 due  primarily  to
increases in municipal  taxes,  state  excise  taxes and state  property  taxes.
Federal  income taxes  increased by $3.3 million in 1999 over 1998 primarily due
to higher pre-tax operating income for the period.  Federal income taxes in 1997
were $60.9  million less than in 1998 as a result of the following  factors:  an
IRS tax refund  related to the method of  accounting  for taxes on  conservation
expenditures during the first quarter of 1997 decreased federal income taxes for
1997 by $26.5  million,  a decrease in PRAM  revenues  of $48.6  million in 1997
reduced  federal  income taxes by $17.0 million and merger costs expensed in the
first quarter of 1997 further reduced federal income taxes by $19.3 million.

OTHER INCOME

       Other income,  net of federal income tax, increased $12.6 million in 1999
compared to 1998 due primarily to net gains of  approximately  $7.8 million from
non-utility  operations in 1999 and an increase of $2.8 million in AFUDC income.
The $7.8 million of net gains included gains from the sale of Homeguard Security
Services,  Inc.,  a wholly  owned  subsidiary,  and the  Company's  common stock
investment  in Cabot Oil & Gas  Corporation.  These gains were offset in part by
losses  related to sales of non-core  assets and gas  transportation  contracts,
establishing reserves for two proposed small hydroelectric projects and expenses
of a subsidiary exiting certain product lines.

       Other income,  net of federal income tax, decreased $20.2 million in 1998
from 1997.  The decrease was due primarily to the receipt of interest  income in
1997 of $13.6  million from the IRS on tax refunds for prior years in connection
with a plant abandonment loss,  conservation tax refunds and certain  additional
research and experimental credits claimed for tax purposes.

INTEREST CHARGES

       Interest charges, which consist of interest and amortization on long-term
debt and other  interest,  increased $11.7 million in 1999 compared to 1998 as a
result of the issuance of $200 million 6.74% Senior Medium-Term Notes, Series A,
in June 1998 and $250 million Senior Medium-Term Notes, Series B, in March 1999.
These  increases  were  partially  offset by the maturity or  redemption of $188
million in Secured Medium-Term Notes since February 1998. Other interest expense
decreased $1.7 million  compared to 1998 as a result of lower  weighted  average
interest rates.

       Interest  charges  increased  $20.3  million  in  1998  compared  to 1997
primarily as a result of the issuance of $300 million  7.02% Senior  Medium-Term
Notes,  Series A, in December  1997, the issuance of $100 million 8.231% Capital
Trust  Debentures  in June 1997 and the  issuance of $200  million  6.74% Senior
Medium-Term Notes, Series A, in June 1998. These increases were partially offset
by the maturity of $151 million Secured  Medium-Term  Notes during the 15 months
ended  December  31,  1998  and the  redemption  of $30  million  9.14%  Secured
Medium-Term Notes, Series A, in June 1998.

CONSTRUCTION, CAPITAL RESOURCES AND LIQUIDITY

       Current   construction    expenditures,    primarily   transmission   and
distribution-related,  are designed to meet  continuing  customer  growth and to
improve  efficiencies  of the Company's  energy delivery  systems.  Construction
expenditures  in 1999 and 2000 also include  costs of  developing a new customer
information system. Construction expenditures, which include energy conservation
expenditures and exclude AFUDC, were $330.8 million in 1999. The Company expects
construction expenditures for the period 2000 through 2002 will be approximately
$269  million,  $250  million  and  $250  million,  respectively.   Construction
expenditure estimates are subject to periodic review and adjustment.

       The Company  expects cash from  operations  (net of dividends  and AFUDC)
during the period 2000 through 2002 will, on average,  be  approximately  95% of
average estimated  construction  expenditures  (excluding AFUDC) during the same
period.

       On November 1, 1999, the Company  assumed  approximately  $109 million of
project debt under the agreement to purchase the 160-megawatt  natural gas-fired
cogeneration  plant from Encogen  Northwest  L.P.  Interest rates on the project
debt ranged from 8.64% to 13.03%.  In February  2000, the Company used a portion
of the proceeds  from the issuance of $225  million  principal  amount of Senior
Medium-Term notes to pay off the project debt.

                                       27
<PAGE>

       In September 1998, the Company filed a shelf-registration  statement with
the  Securities  and  Exchange  Commission  for the  offering,  on a delayed  or
continuous basis, of up to $500 million principal amount of Senior Notes secured
by a pledge of First Mortgage  Bonds.  On March 9, 1999, the Company issued $250
million principal amount of Senior Medium-Term Notes,  Series B, which consisted
of $150 million  principal amount due March 9, 2009 at an interest rate of 6.46%
and $100 million principal amount due March 9, 2029 at an interest rate of 7.0%.
On February 22, 2000, the Company issued $225 million  principal amount of 7.96%
Senior  Medium-Term  Notes,  Series B. The Notes are due  February  22, 2010 and
proceeds were used to redeem the Encogen  project debt and pay down a portion of
the Company's short-term debt.

       In February 1999, the Company redeemed the remaining 203,006  outstanding
shares of Series B,  Adjustable  Rate Preferred  Stock.  In September  1999, the
Company redeemed $30 million 8.50% Series III Preferred Stock.

       The  Company's  ability to finance  its  future  construction  program is
dependent upon market conditions and maintaining a level of earnings  sufficient
to permit the sale of additional securities.  In determining the type and amount
of future financing, the Company may be limited by restrictions contained in its
electric and gas mortgage indentures, articles of incorporation and certain loan
agreements.

       Under the most restrictive tests, at December 31, 1999, the Company could
issue either (i) approximately  $867 million of additional first mortgage bonds,
(ii)  approximately  $712 million of  additional  preferred  stock at an assumed
dividend rate of 7.3%, or (iii) a combination thereof.

       Short-term  borrowings  from banks and the sale of  commercial  paper are
used to provide working capital for the  construction  program.  At December 31,
1999,  the Company had  available  $375  million in lines of credit with various
banks,  which provide credit support for outstanding  commercial paper of $105.7
million, effectively reducing the available borrowing capacity under these lines
of  credit  to  $269.3  million.  (See  Note  9 to  the  Consolidated  Financial
Statements.)

        Under  the most  restrictive  covenants  in the  Company's  Articles  of
Incorporation and electric and gas mortgage  indentures,  earnings reinvested in
the business  unrestricted  as to payment of cash dividends  were  approximately
$202 million at December 31, 1999.

RATE MATTERS - ELECTRIC

       The order  approving the Merger,  issued by the Washington  Commission on
February 5, 1997, contains a rate plan designed to provide a five-year period of
rate  certainty for customers and to provide the Company with an  opportunity to
achieve a reasonable  return on investment.  General  electric tariff rates were
stipulated to increase  annually between 1.0% to 1.5% depending on rate class on
January 1 of 1998 through 2000. Electric tariff rates for certain customers will
increase by 1.5% in 2001.

       In  September  1996,  pursuant  to  a  negotiated   settlement  with  the
Washington  Commission,  the  Company's  PRAM  was  discontinued.  PRAM  accrued
revenues of $40.5 million,  recorded at December 31, 1996, were recovered in the
first  quarter  of 1997.  Overcollections  of PRAM  revenues  were  refunded  to
customers in the second quarter of 1997.  With the  discontinuance  of the PRAM,
the Company no longer has a rate  adjustment  mechanism to adjust for changes in
energy  or fuel  costs or  variances  in hydro  and  weather  conditions.  These
variances may now significantly influence earnings.

       On July  8,  1998,  the  Washington  Commission  approved  the  Company's
requested  accounting  treatment  for its program to reduce  costly  tree-caused
power outages. The Tree Watch program,  which focuses on controlling  vegetation
outside the Company's rights-of-way,  should improve service reliability for its
customers and result in future savings in outage recovery costs.  The five-year,
$43 million program will be treated as an investment that will be amortized over
ten years. The Company expects the Tree Watch investment to be offset by savings
from lower outage restoration and storm damage costs over the same period.

       On October 13, 1999, the Company received from the Washington  Commission
an order  regarding  the  accounting  and  ratemaking  treatment  of a  proposed
Silicone Injection Program,  which extends the life of treated underground cable
providing  benefits  to future  periods.  The order  authorizes  the  Company to
capitalize  the cost of the program and to depreciate  the cost over the life of
the  underground  conductor.  Therefore,  this  ratemaking  treatment  will more
closely  match the cost of the  program  with the  extended  life of the treated
cables.  The Company  expects to spend between $20 and $30 million over the next
five years on the program.

RATE MATTERS - GAS

       The order  approving the Merger,  issued by the Washington  Commission on
February 5, 1997,  contains a rate plan which provided  unchanged  rates for all
classes of natural gas customers  until January 1, 1999, when rates decreased by
approximately $2 million annually.


                                       28
<PAGE>

       On October 27, 1999, the Washington Commission approved the Company's PGA
and deferral amortization  (true-up) filings effective November 1, 1999. The PGA
filing  allows the Company to recover an  expected  increase in annual gas costs
and the deferral  amortization filing allows the Company to recover prior period
gas  cost   undercollections.   The  filings   replaced  the  PGA  and  deferral
amortization refund that had been effective since April 1, 1998. As a result gas
rates to all sales  customers  increased  by an average of 16.3% while rates for
gas transportation service as well as gas margins remained unchanged.  (See Note
1 to the  Consolidated  Financial  Statements for a description of the Company's
PGA mechanism.)

YEAR 2000 CONVERSION

       Over the previous three years, the Company conducted an extensive program
to ensure the Company was ready for the Year 2000.  The  Company  established  a
central  project team to  coordinate  all Year 2000  activities  and  identified
exposure in three categories:  information technology; embedded chip technology;
and external  noncompliance by customers and suppliers.  The project team took a
phased approach in conducting the Year 2000 project for its internal systems. In
addition,  a  specialized  embedded  systems  team was formed by the  Company to
inventory,  assess and remediate  microprocessor  technology in its  generation,
transmission and distribution systems for both gas and electric operations.

       Through  December 31, 1999,  the Company's  total Year 2000 project costs
were approximately $13 million, exclusive of internal labor costs. Approximately
$3 million of these costs were capital  costs.  The Company does not  anticipate
incurring  any  further  costs  related  to the Year 2000  project.  During  the
rollover  to the Year 2000 and to date,  the  Company  has not  experienced  any
significant  problems or interruptions to normal operations  related to the Year
2000 issue.

Other

       A power  supply  operating  alliance  between the Company and Duke Energy
Trading and Marketing ("DETM"),  whereby the Company participated in the Western
market activities of DETM, was terminated  effective May 31, 1999. Going forward
the Company will perform the functions of minimizing the cost of, and optimizing
the value inherent in, its core power supply  portfolio.  The Company  augmented
its traditional supply management  activities with an energy risk management and
hedging program.

       In the second  quarter of 1999,  the Company sold its  investment  in the
common  stock of Cabot  Oil and Gas  Corporation.  The  after-tax  gain of $12.3
million was offset in part by the cost of ConneXt,  a  wholly-owned  subsidiary,
exiting certain product lines.

       In the third  quarter of 1999,  the Company sold the assets,  liabilities
and trade name of its wholly-owned subsidiary, Homeguard Security Services, Inc.
The  Company  also sold in the third  quarter  of 1999 the  majority  of the gas
pipeline  capacity  rights  and gas  storage  rights of  Washington  Energy  Gas
Marketing  ("WEGM",  a  wholly-owned  subsidiary),  in the United States and the
Province of Alberta, Canada.

       In March 1998,  the Company  entered into an agreement  with CellNet Data
Services Inc.  ("CellNet")  under which the Company would lend CellNet up to $35
million in the form of multiple  draws so that  CellNet can finance an Automated
Meter  Reading  (AMR)  network  system to be deployed in the  Company's  service
territory.  The  Company's  promissory  note with CellNet  calls for the network
system to serve as collateral  for the loan.  The term of the loan is five years
after the first loan under the agreement is made to CellNet.  The loan agreement
provides  for  interest  only  payments  during  the five  year  term,  with the
principal due at the end of the five year term. In September  1999,  the Company
announced  it was  expanding  its AMR  network  system  from  800,000  meters to
1,325,000  meters and as a result  increased the  authorized  loan amount to $72
million.  On June 30,  1999,  the  Company  made the first  loan  under the loan
agreement  and as of December 31, 1999,  there were loans  outstanding  of $31.1
million.  In February 2000,  CellNet announced it would be acquired by a unit of
energy services firm Schlumberger Ltd. The acquisition will be handled through a
bankruptcy court filing and requires bankruptcy court approval. The Company does
not anticipate a change in its AMR project due to the reorganization of CellNet.

     On March 20, 1991, the Company  executed a 20-year contract to purchase 216
average MW of energy  and 245 MW of  capacity,  beginning  in April  1994,  from
Tenaska Washington  Partners,  L.P., which owns and operates a natural gas-fired
cogeneration  project  located near Ferndale,  Washington.  In December 1997 and
January 1998, the Company and Tenaska  Washington  Partners entered into revised
agreements  which will lower  purchased  power costs from the Tenaska project by

                                       29
<PAGE>

restructuring  its natural gas supply.  The Company paid $215 million to buy out
the project's existing long-term gas supply contracts, which contained fixed and
escalating  gas prices that were well above current and projected  future market
prices for natural gas. The Company became the principal natural gas supplier to
the project and power purchase prices under the Tenaska contract were revised to
reflect  market-based prices for the natural gas supply. The Company obtained an
order from the Washington  Commission creating a regulatory asset related to the
$215 million  restructuring  payment.  Under terms of the order,  the Company is
allowed to accrue as an additional  regulatory asset one-half the carrying costs
of the deferred  balance over the first five years.  These revised  arrangements
are expected to reduce the Company's power supply costs from the Tenaska project
an average  of between  15% and 20% over the 14 year  period  from 1998  through
2011, net of the costs of the restructuring payment.

       On  September  26,  1990,  the  Company  executed a 15-year  contract  to
purchase  141  average MW of energy and 160 MW of  capacity,  beginning  in July
1993, from Encogen Northwest L.P.  ("Encogen") (a limited  partnership  having a
general partner that is a subsidiary of Enserch Development Corp.),  which owned
and operated a natural-gas  fired  cogeneration  facility located at the Georgia
Pacific mill near Bellingham, Washington. The contract had obligated the Company
to pay fixed and escalating fees well above current and projected  future market
prices  through  mid-2008 for the output of the plant.  On November 1, 1999, the
Company  purchased  the 160 megawatt  plant from  Encogen.  The Company paid $55
million in cash and assumed  $109  million in debt to acquire  the  partnership,
which owned no significant  assets other than the plant.  Pursuant to an October
27,  1999 order from the  Washington  Commission  approving  the  purchase,  the
Company will  depreciate  the original  owner's net book value of the plant over
the  remaining 23 year useful life of the project.  The  difference  between the
purchase price and the net book value of the plant (approximately $72.5 million)
will be  amortized  over 9 years  (the  remaining  term  of the  power  purchase
contract).  The  purchase  is  expected to reduce the net cost of power from the
co-generation project by approximately 17% annually.

       In December  1999,  the Company bought out the remaining 8.5 years of one
of the  natural  gas  supply  contracts  serving  Encogen  from  Cabot Oil & Gas
Corporation  which  provided  approximately  60%  of  the  plant's  natural  gas
requirements.  The  Company  will  become the  replacement  gas  supplier to the
project for 60% of the supply under terms of the Cabot agreement and expects the
agreement  will  reduce  this  portion of gas costs by 5% to 15%  annually.  The
Washington  Commission has issued an order creating a regulatory  asset relating
to the $12 million payment that requires the Company to accrue carrying costs on
the unamortized balance over the first 3 years.

       On November 2, 1998, the Company announced that it signed an agreement to
sell the Company's  735-megawatt interest in the four-unit,  coal-fired Colstrip
generation  plant  in  eastern  Montana,  as  well  as  associated  transmission
facilities. The Company signed the agreement with PP&L Global, Inc., of Fairfax,
Virginia,  a subsidiary  of PP&L  Resources,  Inc.  Included in the sale are the
Company's 50% interest in Colstrip Units 1 and 2; 25% interest in Units 3 and 4;
and associated Colstrip transmission capacity across Montana.  Completion of the
sale is  contingent  on  acceptable  regulatory  treatment  from the  Washington
Commission.  On September  30, 1999,  the  Washington  Commission  conditionally
approved the Colstrip  sale,  which at that time was fixed at $556 million.  The
net book value of these assets and related  regulatory  assets is  approximately
$464  million.  After taxes and other costs,  the Company  expected to realize a
gain of approximately  $37.6 million.  However,  the terms and conditions of the
Washington  Commission  order  made the sale  economically  unattractive  to the
Company. The Company appealed the Washington  Commission's  decision in December
1999.  Pending the outcome of the appeal,  the Company is working  with  various
parties to obtain other terms and conditions so the sale can proceed.

       In May 1999, the eight partners,  including the Company, in the Centralia
coal fired generating plant project announced the sale of the plant to TransAlta
Corporation of Calgary, Canada. The purchase price of the plant and the adjacent
mine (owned and operated by PacifiCorp)  is $554 million.  The Company owns a 7%
interest  in the  plant.  The  transaction  is  currently  under  review  by the
Washington Commission.

SAFE HARBOR

       The Company is including the following  cautionary statement in this Form
10-K to make  applicable and to take advantage of the safe harbor  provisions of
the Private  Securities  Litigation  Reform Act of 1995 for any  forward-looking
statements made by, or on behalf of, the Company.


                                       30
<PAGE>

       Any statements that express,  or involve  discussions as to expectations,
beliefs, plans, objectives,  assumptions or future events or performance (often,
but not  always,  through  the use of words or  phrases  such as  "anticipates",
"believes",  "estimates", "expects", "intends", "plans", "predicts", "projects",
"will  likely  result",  "will  continue",   or  similar  expressions)  are  not
statements of historical facts and may be forward-looking.

       Forward-looking  statements  involve risks and uncertainties  which could
cause actual results or outcomes to differ materially from those expressed.  The
Company's expectations,  beliefs and projections are expressed in good faith and
are  believed  by the  Company to have a  reasonable  basis,  including  without
limitation  management's   examination  of  historical  operating  trends,  data
contained in the Company's  records and other data available from third parties,
but  there can be no  assurance  that the  Company's  expectations,  beliefs  or
projections will be achieved or accomplished.

       In addition to other factors and matters discussed elsewhere herein, some
important factors that could cause actual results or outcomes for the Company to
differ materially from those discussed in forward-looking  statements include:

        -  prevailing legislative developments, governmental policies and
           regulatory actions with respect to allowed rates of return,
           financings, or industry and rate structures
        -  weather and hydroelectric conditions
        -  effect of competition
        -  changes in and compliance with environmental and endangered species
           laws and policies
        -  population growth rates and demographic patterns
        -  capital market conditions
        -  legal and regulatory proceedings

         Any forward-looking  statement speaks only as of the date on which such
statement  is made,  and the  Company  undertakes  no  obligation  to update any
forward-looking  statement to reflect events or circumstances  after the date on
which such  statement  is made or to reflect  the  occurrence  of  unanticipated
events.  New  factors  emerge  from  time to  time  and it is not  possible  for
management to predict all such factors, nor can it assess the impact of any such
factor on the  business or the extent to which any  factor,  or  combination  of
factors,  may cause  results to differ  materially  from those  contained in any
forward-looking statement.


                                       31
<PAGE>

         ITEM 7a.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Commodity Price Risk

       The Company manages its energy supply  portfolio to achieve three primary
objectives:

        (i) Ensure that  physical  energy  supplies are  available to serve
        retail  customer  requirements;
        (ii) Manage  portfolio risks to limit undesired impacts  on  Company
        financial  results;  and
        (iii)  Optimize  the value of the Company's energy supply assets.

       The portfolio is subject to major  sources of  variability  (e.g.,  hydro
generation,  temperature-sensitive  retail sales,  and market prices for gas and
power  supplies).  At certain times,  these sources of variability  can mitigate
portfolio imbalances; at other times they can exacerbate portfolio imbalances.

       Hedging  strategies for the Company's  energy supply  portfolio  interact
with portfolio optimization  activities.  Some hedges can be implemented in ways
that retain the Company's  ability to use its energy supply portfolio to produce
additional  value,  other  hedges can only be achieved by forgoing  optimization
opportunities.

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

       Market risk is managed subject to parameters  established by the Board of
Directors. A Risk Management Committee separate from the units that manage these
risks  monitors  compliance  with the  Company's  policies  and  procedures.  In
addition,  the Audit Committee of the Company's Board of Directors has oversight
of the Risk Management Committee.

Interest rate risk

       The Company believes  interest rate risk of the Company primarily relates
to the use of  short-term  debt  instruments  and new long-term  debt  financing
needed to fund capital requirements.  The Company manages its interest rate risk
through  the  issuance  of mostly  fixed-rate  debt of various  maturities.  The
Company  does  utilize  bank  borrowings,  commercial  paper  and line of credit
facilities to meet short-term cash  requirements.  These short-term  obligations
are  commonly  refinanced  with fixed  rate bonds or notes when  needed and when
interest  rates are  considered  favorable.  The  Company  may  enter  into swap
instruments to manage the interest rate risk  associated  with these debts,  and
three interest rate swaps were outstanding as of December 31, 1999. The carrying
amounts  and fair  values  of the  Company's  fixed  rate debt  instruments  are
described in Note 10 to the Consolidated Financial Statements.


                                       32
<PAGE>

         ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

       See index on page 38.

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

       None.

         PART III

       Part III is incorporated by reference from the Company's definitive proxy
statement issued in connection with the 2000 Annual Meeting of Shareholders.

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

         PART IV

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

       (a)        Documents filed as part of this report:

         1)       Financial statement schedule - see index on page 38.

         2)       Exhibits - see index on page 74.

       (b)        Reports on Form 8-K:

                  The  Company  did not file any  reports on Form 8-K during the
quarter ended December 31, 1999.


                                       33
<PAGE>

         SIGNATURES

       Pursuant  to the  requirements  of Section 13 or 15(d) of the  Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                         PUGET SOUND ENERGY, INC.

                                         William S. Weaver
                                         ------------------------
                                         William S. Weaver
                                         President and Chief Executive Officer
                                         Date:      March 3, 2000


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

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

  William S. Weaver             President, Chief Executive       March 3, 2000
-------------------------
  (William S. Weaver)           Officer and Director


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


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

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


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


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


  Craig W. Cole

-------------------------
  (Craig W. Cole)               Director


                                       34
<PAGE>


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

  Donald J. Covey               Director                         March 3, 2000
-------------------------
  (Donald J. Covey)


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


                                Director

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


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


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


  Tomio Moriguchi               Director

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


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

                                       35
<PAGE>

         REPORT OF MANAGEMENT
PUGET SOUND ENERGY, INC.

       The accompanying consolidated financial statements of Puget Sound Energy,
Inc. have been prepared under the direction of management,  which is responsible
for their  integrity  and  objectivity.  The  statements  have been  prepared in
accordance  with generally  accepted  accounting  principles and include amounts
based on judgments and estimates by management where necessary.  Management also
prepared  the  other  information  in the  Annual  Report  on Form  10-K  and is
responsible for its accuracy and consistency with the financial statements.

       The Company maintains a system of internal control which, in management's
opinion,  provides reasonable assurance that assets are properly safeguarded and
transactions  are executed in accordance  with  management's  authorization  and
properly recorded to produce reliable financial records and reports.  The system
of internal control provides for appropriate  division of responsibility  and is
documented by written  policy and updated as necessary.  The Company's  internal
audit staff assesses the  effectiveness and adequacy of the internal controls on
a  regular  basis  and  recommends  improvements  when  appropriate.  Management
considers  the internal  auditor's  and  independent  auditor's  recommendations
concerning the Company's  internal  controls and takes steps to implement  those
that they believe are appropriate in the circumstances.

       In addition,  PricewaterhouseCoopers  LLP, the  independent  accountants,
have  performed  audit  procedures  deemed   appropriate  to  obtain  reasonable
assurance   about  whether  the  financial   statements  are  free  of  material
misstatement.

       The Board of  Directors  pursues  its  oversight  role for the  financial
statements  through the audit  committee,  which is  composed  solely of outside
Directors.  The audit committee meets  regularly with  management,  the internal
auditors  and the  independent  auditors,  jointly  and  separately,  to  review
management's  process of implementation  and maintenance of internal  accounting
controls  and  auditing  and  financial  reporting  matters.  The  internal  and
independent auditors have unrestricted access to the audit committee.

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


                                       36
<PAGE>


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

       In our opinion,  the consolidated  financial statements listed on page 38
of this Annual Report on Form 10-K present fairly, in all material respects, the
financial  position  of Puget  Sound  Energy,  Inc.  and its  subsidiaries  (the
"Company")  at December 31, 1999 and 1998,  and the results of their  operations
and their cash flows for each of the three  years in the period  ended  December
31, 1999, in conformity with  accounting  principles  generally  accepted in the
United States. In addition,  in our opinion,  the financial  statement  schedule
listed on page 38 of this document  presents fairly,  in all material  respects,
the  information  set forth  therein when read in  conjunction  with the related
consolidated financial statements.  These financial statements and the financial
statement  schedule are the  responsibility  of the  Company's  management;  our
responsibility  is to express an opinion on these  financial  statements and the
financial  statement  schedule  based on our audits.  We conducted our audits of
these  financial  statements in accordance  with  auditing  standards  generally
accepted in the United  States which  require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and  disclosures in the financial  statements,  assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall  financial  statement  presentation.  We believe that our
audits provide a reasonable basis for the opinion expressed above.

                                                     PricewaterhouseCoopers LLP
                                                     Seattle, Washington
                                                     February 10, 2000


                                       37
<PAGE>

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

CONSOLIDATED FINANCIAL STATEMENTS:                                          PAGE

Consolidated Statements of Income for the years ended
December 31, 1999, 1998 and 1997                                              39

Consolidated Balance Sheets, December 31, 1999 and 1998                    40-41

Consolidated Statements of Capitalization, December 31, 1999 and 1998         42

Consolidated Statements of Earnings Reinvested in the Business

  for the years ended December 31, 1999, 1998 and 1997                        43

Consolidated Statements of Comprehensive Income for the years
  ended December 31, 1999, 1998 and 1997                                      43

Consolidated Statements of Cash Flows for the years
  ended December 31, 1999, 1998 and 1997                                      44

Notes to Consolidated Financial Statements                                    45


Schedule:

II.  Valuation and Qualifying Accounts and Reserves for the
     years ended December 31, 1999, 1998 and 1997                             73

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

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

Exhibits:

Exhibit Index                                                                 74


                                       38
<PAGE>

Consolidated Statements of

         INCOME
<TABLE>
(for years ended December 31;
dollars in thousands,
except per share amounts)                                1999        1998         1997
--------------------------------------------------------------------------------------
<S>                                                <C>         <C>          <C>
  Operating Revenues:
  Electric                                         $1,558,012  $1,475,208   $1,231,424
  Gas                                                 485,488     416,551      409,447
  Other                                                23,130      32,097       40,657
---------------------------------------------------------------------------------------
       Total operating revenues                     2,066,630   1,923,856    1,681,528
---------------------------------------------------------------------------------------
  Operating Expenses:
  Energy costs:
    Purchased electricity                             780,162     752,148      614,929
    Residential Exchange                              (39,000)    (55,562)     (71,970)
    Purchased gas                                     220,009     175,805      179,287
    Fuel                                               59,439      56,557       41,455
  Utility operations and maintenance                  240,645     231,636      244,072
  Other operations and maintenance                     22,387      30,102       33,919
  Depreciation, depletion and amortization            175,710     165,587      161,865
  Conservation amortization                             7,841       6,199        7,318
  Merger and related costs                                 --          --       55,789
  Taxes other than federal income taxes               180,141     160,472      159,310
  Federal income taxes                                109,164     105,814       44,916
---------------------------------------------------------------------------------------
       Total operating expenses                     1,756,498   1,628,758    1,470,890
---------------------------------------------------------------------------------------
  Operating Income                                    310,132     295,098      210,638
---------------------------------------------------------------------------------------
  Other Income                                         25,819      13,182       33,398
---------------------------------------------------------------------------------------
  Income Before Interest Charges                      335,951     308,280      244,036
---------------------------------------------------------------------------------------
  Interest Charges:
    AFUDC                                             (10,582)     (7,580)      (5,205)
    Interest expense                                  160,966     146,248      123,543
---------------------------------------------------------------------------------------
       Total interest charges                         150,384     138,668      118,338
---------------------------------------------------------------------------------------
  Income from Continuing Operations                   185,567     169,612      125,698
  Discontinued Operations:
    Loss on disposal, net of tax                           --          --       (2,622)
---------------------------------------------------------------------------------------
  Net Income                                          185,567     169,612      123,076
---------------------------------------------------------------------------------------
  Less Preferred Stock Dividends Accrual               11,065      13,003       17,806
  Preferred Stock Redemptions                              --          --          471
---------------------------------------------------------------------------------------
  Income for Common Stock                            $174,502    $156,609     $105,741
---------------------------------------------------------------------------------------
  Common Shares Outstanding Weighted Average           84,613      84,561       84,560
---------------------------------------------------------------------------------------
  Basic and Diluted Earnings (Loss)
    Per Common Share:
     From continuing operations                         $2.06       $1.85        $1.28
     From discontinued operations                          --          --        (0.03)
---------------------------------------------------------------------------------------
       Basic and diluted earnings per common share      $2.06       $1.85        $1.25
---------------------------------------------------------------------------------------
</TABLE>

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


                                       39
<PAGE>

Consolidated Balance Sheets

         ASSETS

   (at December 31; dollars in thousands)                     1999         1998
--------------------------------------------------------------------------------
  Utility Plant:
    Electric plant                                      $3,966,220   $3,640,647
    Gas plant                                            1,371,589    1,278,275
    Common plant                                           314,770      233,086
    Less: Accumulated depreciation and amortization      1,901,658    1,721,096
--------------------------------------------------------------------------------
        Net utility plant                                3,750,921    3,430,912
--------------------------------------------------------------------------------
  Other Property and Investments:
    Investment in Bonneville Exchange Power Contract        61,716       70,537
    Other                                                  202,488      189,550
--------------------------------------------------------------------------------
        Total other property and investments               264,204      260,087
--------------------------------------------------------------------------------
  Current Assets:
    Cash                                                    65,707       28,216
--------------------------------------------------------------------------------
    Accounts receivable                                    214,523      190,658
    Less:  Allowance for doubtful accounts                  (1,503)      (1,020)
--------------------------------------------------------------------------------
        Total accounts receivable                          213,020      189,638
--------------------------------------------------------------------------------
    Unbilled revenues                                      121,303      126,740
    Purchased gas receivable                                33,700        5,492
    Materials and supplies, at average cost                 69,241       58,534
    Prepayments and other                                    9,822        7,990
--------------------------------------------------------------------------------
        Total current assets                               512,793      416,610
--------------------------------------------------------------------------------
  Long-Term Assets:
    Regulatory asset for deferred income taxes             228,454      241,406
    PURPA buyout costs                                     238,734      221,802
    Other                                                  150,500      138,870
--------------------------------------------------------------------------------
  Total long-term assets                                   617,688      602,078
--------------------------------------------------------------------------------
  Total Assets                                          $5,145,606   $4,709,687
================================================================================

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


                                       40
<PAGE>

Consolidated Balance Sheets

         CAPITALIZATION AND LIABILITIES


   (AT DECEMBER 31; DOLLARS IN THOUSANDS)                    1999           1998
--------------------------------------------------------------------------------
  Capitalization:
  (See "Consolidated Statements of Capitalization"):
     Common equity                                     $1,379,073     $1,352,680
     Preferred stock not subject to mandatory
       redemption                                          60,000         95,075
     Preferred stock subject to mandatory redemption       65,662         73,162
     Corporation obligated, mandatorily redeemable
       preferred securities of subsidiary trust
       holding solely junior subordinated debentures
       of the corporation                                 100,000        100,000
     Long-term debt                                     1,783,139      1,475,106
--------------------------------------------------------------------------------
       Total capitalization                             3,387,874      3,096,023
--------------------------------------------------------------------------------
  Current Liabilities:
     Accounts payable                                     178,218        163,141
     Short-term debt                                      604,712        450,905
     Current maturities of long-term debt                  47,620        107,000
     Accrued expenses:
       Taxes                                               72,688         59,764
       Salaries and wages                                  18,023         18,650
       Interest                                            43,955         39,062
     Other                                                 24,129         23,150
--------------------------------------------------------------------------------
       Total current liabilities                          989,345        861,672
--------------------------------------------------------------------------------
  Deferred Income Taxes                                   636,735        628,554
--------------------------------------------------------------------------------
  Other Deferred Credits                                  131,652        123,438
--------------------------------------------------------------------------------
  Commitments and Contingencies                                --             --
--------------------------------------------------------------------------------
  Total Capitalization and Liabilities                 $5,145,606     $4,709,687
================================================================================

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


                                       41
<PAGE>
<TABLE>

Consolidated Statements of

         CAPITALIZATION
<CAPTION>
  (at December 31; dollars in thousands)                                    1999          1998
-----------------------------------------------------------------------------------------------
  <S>                                                                   <C>           <C>
Common Equity:
    Common stock ($10 stated value) - 150,000,000 shares
      authorized, 84,922,405 and 84,560,561 shares outstanding          $849,224      $845,606
    Additional paid-in capital                                           454,982       450,724
    Earnings reinvested in the business                                   66,019        47,548
    Accumulated other comprehensive income - net                           8,848         8,802
-----------------------------------------------------------------------------------------------
       Total common equity                                             1,379,073     1,352,680
-----------------------------------------------------------------------------------------------
  Preferred  Stock Not Subject to  Mandatory  Redemption  -
    cumulative - $25 par value:* Adjustable Rate,
    Series B - 2,000,000 shares

        authorized, 0 and 203,006 shares outstanding                          --         5,075
    7.45% series II - 2,400,000 shares authorized and outstanding         60,000        60,000
    8.50% series III - 1,200,000 shares authorized, 0
        and 1,200,000 shares outstanding                                      --        30,000
-----------------------------------------------------------------------------------------------
       Total preferred stock not subject to mandatory redemption          60,000        95,075
-----------------------------------------------------------------------------------------------
  Preferred Stock Subject To Mandatory Redemption -
    cumulative $100 par value:*

      4.84% series - 150,000 shares authorized,
         14,808 shares outstanding                                         1,481         1,481
      4.70% series - 150,000 shares authorized,
         4,311 shares outstanding                                            431           431
      7.75% series - 750,000 shares authorized, 637,500 and
         712,500 shares outstanding                                       63,750        71,250
-----------------------------------------------------------------------------------------------
       Total preferred stock subject to mandatory redemption              65,662        73,162
-----------------------------------------------------------------------------------------------
  Corporation obligated, mandatorily redeemable preferred
    securities of subsidiary trust holding solely junior
    subordinated debentures of the corporation                           100,000       100,000
-----------------------------------------------------------------------------------------------
  Long-Term Debt:
    First mortgage bonds and senior notes                              1,563,000     1,420,000
  Pollution control revenue bonds:
      Revenue refunding 1991 series, due 2021                             50,900        50,900
      Revenue refunding 1992 series, due 2022                             87,500        87,500
      Revenue refunding 1993 series, due 2020                             23,460        23,460
  Other notes                                                            105,980           370
  Unamortized discount - net of premium                                      (81)         (124)
  Long-term debt due within one year                                     (47,620)     (107,000)
-----------------------------------------------------------------------------------------------
      Total long-term debt excluding current maturities                1,783,139     1,475,106
-----------------------------------------------------------------------------------------------
  Total Capitalization                                                $3,387,874    $3,096,023
-----------------------------------------------------------------------------------------------
</TABLE>
* 13,000,000  shares  authorized for $25 par value preferred stock and 3,000,000
shares authorized for $100 par value preferred stock. The accompanying notes are
an integral part of the consolidated financial statements.


                                       42
<PAGE>
<TABLE>

Consolidated Statements of

         EARNINGS REINVESTED
<CAPTION>
   (for years ended December 31;
  dollars in thousands,
  except per share amounts)                             1999         1998          1997
----------------------------------------------------------------------------------------
<S>                                                 <C>          <C>           <C>
  Balance at Beginning of Year                      $ 47,548     $ 46,672      $ 86,355
  Net Income                                         185,567      169,612       123,076
  Adjustment to conform fiscal year of WECo               --           --        10,835
----------------------------------------------------------------------------------------
       Total                                         233,115      216,284       220,266
----------------------------------------------------------------------------------------
  Deductions:
       Dividends declared:
          Preferred stock:
            Adjustable Rate Series B                      38          272         2,010
            $1.86 per share on 7.45% series II         4,470        4,470         4,470
            $2.13 per share on 8.50% series III        1,700        2,550         2,550
            $4.84 per share on 4.84% series               72           72           192
            $4.70 per share on 4.70% series               20           20           203
            $8.00 per share on 8% series                  --           25           122
            $7.75 per share on 7.75% series            5,086        5,667         5,813
            $1.97 per share on 7.875% series              --           --         3,940
         Common Stock                                155,591      155,591       150,591
       Preferred stock redemptions                       119           69         3,703
----------------------------------------------------------------------------------------
         Total deductions                            167,096      168,736       173,594
----------------------------------------------------------------------------------------
  Balance at End of Year                            $ 66,019     $ 47,548       $46,672
----------------------------------------------------------------------------------------
  Dividends Declared Per Common Share                  $1.84        $1.84         $1.78
----------------------------------------------------------------------------------------
</TABLE>
<TABLE>

Consolidated Statements of


         COMPREHENSIVE INCOME
<CAPTION>
  (for years ended December 31;
  dollars in thousands)                                 1999         1998          1997
---------------------------------------------------------------------------------------
<S>                                                 <C>          <C>           <C>
  Net Income                                        $185,567     $169,612      $123,076
  Other comprehensive income, net of tax:
      Unrealized holding gains (losses) on
        available for sale securities                 12,330       (6,152)       14,954
  Reclassification adjustment for gains
    included in net income                           (12,284)          --            --
---------------------------------------------------------------------------------------
      Other comprehensive income                          46       (6,152)       14,954
---------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------
  Comprehensive Income                              $185,613     $163,460      $138,030
---------------------------------------------------------------------------------------
</TABLE>

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


                                       43
<PAGE>
<TABLE>

Consolidated Statements of

         CASH FLOW

<CAPTION>
  (for years ended December 31;
  dollars in thousands)                                            1999         1998          1997
--------------------------------------------------------------------------------------------------
<S>                                                            <C>          <C>           <C>
  Operating Activities:
     Income from continuing operations                         $185,567     $169,612      $125,698
     Adjustments to reconcile income from continuing
        operations to net cash provided by operating activities
          Depreciation and amortization                         175,710      165,587       161,865
          Deferred income taxes and tax credits - net            21,133       16,560        27,422
          Gain from sale of investment in Cabot common stock    (18,899)          --            --
          Gain from sale of investment in HomeGuard Security S  (11,659)          --            --
          PRAM accrued revenues - net                                --           --        40,777
         Pretax write-down and equity in undistributed losses
           unconsolidated affiliate                                  --           --         4,044
          PURPA buyout costs                                    (12,000)          --      (215,000)
          Other (including conservation amortization)            (3,708)     (14,321)       49,278
          Change in certain current assets and liabilities      (25,446)     (23,106)      (61,364)
---------------------------------------------------------------------------------------------------
            Net cash provided by operating activities           310,698      314,332       132,720
---------------------------------------------------------------------------------------------------
  Investing Activities:
     Construction expenditures - excluding equity AFUDC        (330,976)    (335,471)     (257,900)
     Energy conservation expenditures                            (5,583)      (6,745)       (4,864)
     Proceeds from sale of investment in Cabot common stock      37,353           --            --
     Proceeds from sale of HomeGuard Security Services           13,399           --            --
     Purchase of Encogen                                        (55,000)          --            --
     Loans to CellNet Data Services                             (31,075)          --            --
     Cash received from sale of conservation assets - net            --           --        34,372
     Other                                                        9,001        8,844        24,716
---------------------------------------------------------------------------------------------------
            Net cash used by investing activities              (362,881)    (333,372)     (203,676)
---------------------------------------------------------------------------------------------------
  Financing Activities:
     Increase in short-term debt - net                          153,807       78,367        85,975
     Dividends paid                                            (160,067)    (168,667)     (169,892)
     Issuance of common stock                                     1,136           --            65
     Issuance of company obligated, mandatorily redeemable
       preferred securities                                          --           --       100,000
     Redemption of preferred stock                              (42,575)      (5,454)     (128,747)
     Issuance of bonds                                          250,000      200,000       300,000
     Redemption of bonds and notes                             (110,370)     (81,093)     (103,415)
     Other                                                      (2,257)       13,374        (4,572)
---------------------------------------------------------------------------------------------------
            Net cash provided by financing activities            89,674       36,527        79,414
------------------------------------------------------------------------ ------------ -------------
  Increase in cash from continuing operations                    37,491       17,487         8,458
  Decrease in cash from discontinued operations:
     Investing activities                                            --           --        (2,622)
---------------------------------------------------------------------------------------------------
  Net Increase in Cash                                           37,491       17,487         5,836
  Cash at Beginning of Year                                      28,216       10,729         4,854
  Adjustment to conform fiscal year of WECo                          --           --            39
---------------------------------------------------------------------------------------------------
  Cash at End of Year                                           $65,707      $28,216       $10,729
---------------------------------------------------------------------------------------------------
</TABLE>
The  accompanying  notes  are an  integral  part of the  consolidated  financial
statements.


                                       44
<PAGE>

Notes

         To Consolidated Financial Statements
Note 1.

         Summary of Significant Accounting Policies

BASIS OF PRESENTATION

       Puget Sound  Energy,  Inc.,  formerly  Puget Sound Power & Light  Company
("the Company"),  is an investor-owned  public utility incorporated in the State
of Washington furnishing electric, and since February 10, 1997, gas service in a
territory covering  approximately  6,000 square miles,  principally in the Puget
Sound region of Washington  state. On February 10, 1997, the Company completed a
merger ("the Merger") with Washington  Energy Company ("WECo") and its principal
subsidiary,  Washington Natural Gas Company ("WNG"). The change of the Company's
name was effective with the merger.  Herein,  the Company refers to the combined
entity;  Puget Power and WECo refer to the individual  entities.  The merger was
structured as a tax-free  exchange of shares,  and is accounted for as a pooling
of interests for financial statement purposes

       The consolidated financial statements include the accounts of the Company
and all its  significant  wholly-owned  subsidiaries,  after  elimination of all
significant intercompany items and transactions.  Certain reclassifications have
been made to the prior year  financial  statements  to  conform  to the  current
year's  presentation  with no material effect on consolidated net income,  total
assets or common equity.

       The  preparation  of financial  statements in conformity  with  generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that  affect the  reported  amounts of assets and  liabilities  and
disclosure of  contingent  assets and  liabilities  at the date of the financial
statements  and the  reported  amounts  of  revenues  and  expenses  during  the
reporting period. Actual results could differ from those estimates.

UTILITY PLANT

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

REGULATORY ASSETS & AGREEMENTS

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


                                       45
<PAGE>

       Net  regulatory  assets and  liabilities  at December  31, 1999 and 1998,
included the following:
<TABLE>
<CAPTION>
  (DOLLARS IN MILLIONS)                                   1999         1998
----------------------------------------------------------------------------
<S>                                                     <C>          <C>
  Deferred income taxes                                 $228.5       $241.4
  PURPA electric energy supply contract buyout costs     238.7        221.8
  Investment in BEP Exchange Contract                     61.7         70.5
  Unamortized energy conservation charges                  4.6          7.1
  Storm damage costs - electric                           31.2         34.6
  Purchased gas receivable                                33.7          5.5
  Deferred AFUDC                                          25.0         21.6
  Various other costs                                     50.3         49.2
  Deferred gains on property sales                       (17.1)       (17.2)
----------------------------------------------------------------------------
  Total                                                 $656.6       $634.5
----------------------------------------------------------------------------
</TABLE>

     If the  Company,  at some  point in the  future,  determines  that all or a
portion of the utility  operations  no longer meets the  criteria for  continued
application  of  Statement  No. 71, the  Company  would be required to adopt the
provisions of Statement of Financial  Accounting  Standards No. 101,  "Regulated
Enterprises  -  Accounting  for  the  Discontinuation  of  Application  of  FASB
Statement No. 71"  ("Statement  No.  101").  Adoption of Statement No. 101 would
require the Company to write off the regulatory  assets and liabilities  related
to those operations not meeting  Statement No. 71 requirements.  Discontinuation
of  Statement  No. 71 could have a material  impact on the  Company's  financial
statements.

       The  Emerging  Issues  Task Force  ("EITF") of the  Financial  Accounting
Standards  Board ("FASB") has issued its Consensus 97-4 which  addresses when an
entity should discontinue the application of Statement No. 71, and how Statement
No.  101   should  be   applied  to  a  portion  of  an  entity   subject  to  a
transition-to-competition  plan.  The EITF states that Statement No. 71 shall be
discontinued   at  a   date   no   later   than   when   the   details   of  the
transition-to-competition  plan for all or a portion  of the  entity  subject to
such plan are known.  Additionally,  the EITF reached a consensus  that stranded
costs which are to be recovered  through cash flows derived from another portion
of the entity which  continues to apply  Statement  No. 71 should not be written
off; rather,  they should be considered  regulatory  assets of the segment which
will continue to apply Statement No. 71.

       Although  discussions  with  regulatory   authorities   regarding  retail
competition  have  occurred  and are  expected to  continue,  no  transition  to
competition plans for the Company's regulated operations have been proposed. The
Company's financial  statements continue to apply Statement No. 71 for regulated
operations.

       The  Company,  in prior  years,  incurred  costs  associated  with its 5%
interest in a now-terminated  nuclear generating  project  (identified herein as
"Investment in Bonneville Exchange Power ("BEP")").  Under terms of a settlement
agreement with the Bonneville Power Administration ("BPA"), which settled claims
of the Company relating to construction delays associated with that project, the
Company is  receiving,  over 30.5  years,  power from the federal  power  system
resources marketed by BPA. Approximately  two-thirds of the Company's investment
in BEP is included in rate base and amortized on a straight-line  basis over the
life of the contract  (amortization  is included in "Purchased and  interchanged
power").  The remainder of the Company's  investment was recovered in rates over
the ten years ended  December  31,  1999,  without a return  during the recovery
period (the related amortization is included in "Depreciation and Amortization",
pursuant to a FERC accounting order).

       The Company has regulatory  assets of approximately  $239 million related
to the buyout of  purchased  power and gas sales  contracts  of two  non-utility
generation projects.  Washington  Commission accounting orders have approved the
payments for deferral and  collection  in rates over the  remaining  life of the
energy supply  contracts.  Under terms of the orders,  the Company is allowed to
accrue as an additional  regulatory asset certain carrying costs of the deferred
balances.


                                       46
<PAGE>

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

OPERATING REVENUES

       Operating  revenues are recorded on the basis of service rendered,  which
includes estimated unbilled revenue.

ENERGY CONSERVATION

       The  Company  accumulates  energy  conservation  expenditures  which  are
included in rate base and amortized to expense as  prescribed by the  Washington
Commission.

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

SELF-INSURANCE

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

DEPRECIATION AND AMORTIZATION

       For financial statement  purposes,  the Company provides for depreciation
on a  straight-line  basis.  The  depreciation  of  automobiles,  trucks,  power
operated equipment and tools is allocated to asset and expense accounts based on
usage. The annual depreciation provision stated as a percent of average original
cost of depreciable  electric  utility plant was 3.0% in 1999, 1998 and 1997 and
for depreciable gas utility plant was 3.4% in 1999,1998 and 1997.

FEDERAL INCOME TAXES

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

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION

       The Allowance for Funds Used During Construction ("AFUDC") represents the
cost of both the debt and equity funds used to finance  utility plant  additions
during the construction  period. The amount of AFUDC recorded in each accounting
period  varies  depending  principally  upon the level of  construction  work in
progress and the AFUDC rate used.  AFUDC is capitalized as a part of the cost of
utility  plant and is credited as a non-cash  item to other  income and interest
charges  currently.  Cash  inflow  related to AFUDC does not occur  until  these
charges are reflected in rates.

       The AFUDC rate allowed by the Washington Commission for gas utility plant
additions was 9.15% in 1999,  1998 and 1997.  The allowed AFUDC rate on electric
utility plant was 8.94% during the same period. To the extent amounts calculated
using this rate exceed the AFUDC calculated using the Federal Energy  Regulatory
Commission  ("FERC") formula,  the Company  capitalizes the excess as a deferred
asset,  crediting  miscellaneous  income.  The amounts  included in income were:
$4,262,000  for 1999,  $3,409,000 for 1998 and $2,704,000 for 1997. The deferred
asset  is  being  amortized  over  the  average  useful  life  of the  Company's
non-project utility plant.


                                       47
<PAGE>

PERIODIC RATE ADJUSTMENT MECHANISM

       In April 1991, the Washington  Commission issued an order  establishing a
Periodic Rate Adjustment  Mechanism  ("PRAM")  designed to operate as an interim
rate adjustment  mechanism between electric general rate cases.  Under the PRAM,
Puget Power was allowed to request  annual rate  adjustments,  on a  prospective
basis, to reflect changes in certain costs as set forth in the PRAM order. Also,
under terms of the order, recovery of certain costs was decoupled from levels of
electricity sales.

       In  September  1996,  pursuant  to  a  negotiated   settlement  with  the
Washington Commission, the PRAM was discontinued. PRAM accrued revenues of $40.5
million,  recorded at December 31, 1996,  were recovered in the first quarter of
1997.  Over-collection  of PRAM revenues was refunded to customers in the second
quarter of 1997.

       With the  discontinuance  of the  PRAM,  the  Company  no  longer  has an
electric rate adjustment mechanism to adjust for changes in energy or fuel costs
or  variances  in  hydro  and  weather  conditions.   These  variances  may  now
significantly influence earnings.

PGA MECHANISM

       Differences between the actual cost of the Company's gas supplies and gas
transportation contracts and that currently allowed by the Washington Commission
are  deferred and  recovered  or repaid  through the  purchased  gas  adjustment
("PGA") mechanism.

       On June 25,  1998,  the Company  received  approval  from the  Washington
Commission  to begin a new  performance-based  mechanism for  strengthening  its
gas-supply  purchasing and gas-storage  practices.  The PGA Incentive Mechanism,
which  encourages  competitive  gas  purchasing  and  management of pipeline and
storage-capacity, became effective July 1, 1998. Incentive gains and losses from
the three-year program are shared between customers and shareholders.  After the
first $0.5 million, which is allocated to customers, gains and losses are shared
40%/60%  between  the  Company  and  customers  up to $26.5  million and 33%/67%
thereafter.  Gains or losses are determined relative to a weighted average index
which is  reflective of the  Company's  gas supply and  transportation  contract
costs. The Company's share of incentive gains under the PGA Incentive  Mechanism
in 1999 and 1998 were approximately $7.2 million and $1.1 million, respectively,
while customers received approximately $11.3 and $2.0 million, respectively.

OFF-SYSTEM SALES AND CAPACITY RELEASE

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


                                       48
<PAGE>

ENERGY RISK MANAGEMENT

       The Company's  energy related  businesses are exposed to risks related to
changes in commodity prices. As part of its business,  the Company markets power
to wholesale customers by entering into contracts to purchase or supply electric
energy or natural  gas at  specified  delivery  points and at  specified  future
delivery  dates.  The  Company's  energy risk  management  function  manages the
Company's core electric and gas supply portfolios.

       The Company manages its energy supply  portfolio to achieve three primary
objectives:

        (i) Ensure that  physical  energy  supplies are  available to serve
        retail  customer  requirements;
        (ii) Manage  portfolio risks to limit undesired impacts  on  Company
        financial  results;  and
        (iii)  Optimize  the value of the Company's energy supply assets.

       The Company  enters  into  futures and options for the purpose of hedging
commodity  price risk.  Gains or losses on these  derivatives  are  deferred and
recognized upon settlement along with the underlying sales or purchase contract.
The Company has  established  policies and  procedures to manage these risks.  A
Risk  Management  Committee  separate  from the units that  create  these  risks
monitors compliance with the Company's policies and procedures. In addition, the
Audit  Committee of the  Company's  Board of Directors has oversight of the Risk
Management Committee.

       During the first  quarter  of 1999,  the  Company  adopted  Issue  98-10,
"Accounting  for  Contracts  Involved  in  Energy  Trading  and Risk  management
Activities"  ("EITF  98-10")  issued by the  Emerging  Issues  Task Force of the
Financial Accounting  Standards Board ("FASB").  EITF 98-10 addresses accounting
for the  purchase and sale of energy  trading  contracts  and is  effective  for
fiscal years  beginning  after December 15, 1998. The conclusion  reached by the
EITF was that such contracts  should be recorded at fair value when entered into
for  trading  activities  with the  mark-to-market  gains or losses  recorded in
current earnings.  The Company does not consider its current  operations to meet
the  definition of trading  activities as described by EITF 98-10.  Accordingly,
the  adoption  of EITF 98-10 did not have an impact on the  Company's  financial
position or results of operations.

     In June 1998, the FASB issued Statement of Financial  Accounting  Standards
No.  133,  "Accounting  for  Derivative   Instruments  and  Hedging  Activities"
("Statement  No.  133").  In July 1999,  the FASB issued  Statement of Financial
Accounting  Standards No. 137 which delayed the effective  date of Statement No.
133 for one year, to fiscal years beginning  after June 15, 2000.  Statement No.
133 requires that all derivative instruments be recorded on the balance sheet at
their fair value.  Changes in the fair value of  derivatives  are recorded  each
period in current earnings or other comprehensive income, depending on whether a
derivative is designated as part of a hedge  transaction and, if it is, the type
of hedge  transaction.  The Company has not yet  determined  the impact that the
adoption of Statement No. 133 will have on its financial statements.

OTHER

       Debt premium,  discount and expenses are  amortized  over the life of the
related debt. The premiums and costs  associated  with reacquired debt are being
amortized  over  the life of the  related  new  issuances,  in  accordance  with
ratemaking treatment.

       In April  1998,  the  Accounting  Standards  Executive  Committee  issued
Statement  of Position  98-5,  "Reporting  on the Costs of Start-Up  Activities"
("SOP 98-5").  SOP 98-5 was adopted by the Company in the first quarter of 1999.
SOP 98-5  provides  guidance on the  financial  reporting of start-up  costs and
organization  costs. It requires costs of start-up  activities and  organization
costs to be expensed as  incurred.  Adoption of SOP 98-5 did not have a material
impact on the Company's financial position or results of operations.

EARNINGS PER COMMON SHARE

       Basic  earnings  per common  share have been  computed  based on weighted
average common shares  outstanding of 84,613,000,  84,561,000 and 84,560,000 for
1999, 1998 and 1997,  respectively.  Diluted earnings per common share have been
computed  based on weighted  average  common shares  outstanding  of 84,847,000,
84,768,000 and 84,628,000 for 1999, 1998 and 1997,  respectively,  which include
the dilutive effect of securities related to employee compensation plans.


                                       49
<PAGE>

NOTE 2.
         UTILITY PLANT

       Utility plant at December 31, 1999 and 1998 included the following:
<TABLE>
<CAPTION>
  December 31 (dollars in thousands)                    1999             1998
------------------------------------------------------------------------------
<S>                                               <C>             <C>
  Electric, gas and common  utility plant
    classified by prescribed  accounts at
       original cost:
    Distribution plant                            $2,970,643       $2,794,906
    Production plant                               1,116,351          943,808
    Transmission plant                               666,318          641,526
    General plant                                    383,075          375,612
    Construction work in progress                    311,317          266,242
    Plant acquisition adjustment                      72,495               --
    Intangible plant                                 103,276           99,776
    Underground storage                               14,801           16,307
    Plant held for future use                          9,755            9,016
    Other                                              4,548            4,815
    Less accumulated provision for depreciation    1,901,658        1,721,096
------------------------------------------------------------------------------
       Net utility plant                          $3,750,921       $3,430,912
------------------------------------------------------------------------------
</TABLE>

       On  November  1, 1999,  the  Company  purchased  a 160  megawatt  natural
gas-fired  cogeneration  plant from Encogen  Northwest  L.P.  for $164  million.
Pursuant to an October 27, 1999 order from the Washington  Commission  approving
the purchase, the Company will depreciate the original owner's net book value of
the plant over the remaining 23 year useful life of the project.  The difference
between the  purchase  price and the net book value of the plant  (approximately
$72.5 million) will be amortized over 9 years.

       In December  1999,  the Company bought out the remaining 8.5 years of one
of the  natural  gas  supply  contracts  serving  Encogen  from  Cabot Oil & Gas
Corporation  which  provided  approximately  60%  of  the  plant's  natural  gas
requirements.  The  Company  will  become the  replacement  gas  supplier to the
project for 60% of the supply under terms of the Cabot Agreement. The Washington
Commission has issued an order  creating a regulatory  asset relating to the $12
million  payment  that  requires  the  Company to accrue  carrying  costs on the
unamortized balance over the first 3 years.


                                       50
<PAGE>

NOTE 3.
         CAPITAL STOCK
<TABLE>
<CAPTION>
                                                                    PREFERRED STOCK
                                                    ---------------------------------------
                                                      NOT SUBJECT TO          SUBJECT TO        COMMON STOCK
                                                        MANDATORY             MANDATORY
                                                        REDEMPTION            REDEMPTION      WITHOUT PAR VALUE
                                                      $25 PAR VALUE         $100 PAR VALUE    ($10 STATED VALUE)
--------------------------------------------------- -------------------- ----------------- --------------------
<S>                                                           <C>                 <C>               <C>
  SHARES OUTSTANDING JANUARY 1, 1997                          8,600,000           878,395           84,511,245
--------------------------------------------------- -------------------- ----------------- --------------------
  Issued to Shareholders Under the Stock Purchase
    and Dividend Reinvestment Plan:
       1997                                                          --                --               33,930
       1999                                                          --                --              361,944
--------------------------------------------------- -------------------- ----------------- --------------------
  Issued Pursuant to Employee Compensation Plans:
       1997                                                          --                --               17,063
--------------------------------------------------- -------------------- ----------------- --------------------
  Acquired for Sinking Fund:
       1997                                                          --           (12,050)                  --
       1998                                                          --           (49,500)                  --
       1999                                                          --           (75,000)                  --
--------------------------------------------------- -------------------- --------------------------------------
  Called for Redemption and Canceled:
       1997                                                  (4,780,494)          (85,002)                  --
       1998                                                     (16,500)             (224)                  --
       1999                                                  (1,403,006)               --                   --
--------------------------------------------------- --------------------- ---------------- --------------------
  Fractional Share Redemptions in Connection with
    Merger Exchange:
       1997                                                          --                --               (1,593)
       1998                                                          --                --                  (84)
       1999                                                          --                --                 (100)
--------------------------------------------------- -------------------- ----------------- --------------------
  Shares outstanding December 31, 1999                        2,400,000           656,619           84,922,405
--------------------------------------------------- -------------------- ----------------- --------------------
</TABLE>

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

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


                                       51
<PAGE>

       The weighted  average  dividend rate for the Adjustable  Rate  Cumulative
Preferred Stock ("ARPS"), Series B ($25 par value) was 4.23% for 1999, 4.83% for
1998 and 5.61% for 1997. The Company  reacquired  16,500 shares of ARPS Series B
through  open-market  purchases  during 1998 and redeemed the remaining  ARPS on
February 2, 1999 at $25 par plus accrued dividends through February 2, 1999. The
8.50% Series  Preferred was redeemed at par plus accrued  dividends on September
1, 1999. The 7.45% Series  Preferred may be redeemed at par on or after November
1, 2003.

NOTE 4.
         PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION

       The  Company is  required to deposit  funds  annually  in a sinking  fund
sufficient to redeem the following  number of shares of each series of preferred
stock at $100 per share plus accrued  dividends:  4.84% Series and 4.70% Series,
3,000 shares each and 7.75% Series,  37,500  shares.  All previous  sinking fund
requirements have been satisfied. At December 31, 1999, there were 33,192 shares
of the 4.84%  Series  and  49,689  shares of the 4.70%  Series  acquired  by the
Company and available for future  sinking fund  requirements.  Upon  involuntary
liquidation,  all preferred  shares are entitled to their par value plus accrued
dividends.

       The preferred stock subject to mandatory  redemption may also be redeemed
by the  Company  at the  following  redemption  prices  per share  plus  accrued
dividends:  4.84% Series,  $102 and 4.70% Series,  $101. The 7.75% Series may be
redeemed by the Company,  subject to certain restrictions,  at $104.13 per share
plus accrued dividends through February 15, 2000, and at per share amounts which
decline annually to a price of $100 after February 15, 2007.

NOTE 5.
         COMPANY-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES

       In 1997,  the Company  formed  Puget Sound  Energy  Capital  Trust I (the
"Trust")  for the sole  purpose  of issuing  and  selling  common and  preferred
securities ("Trust Securities").  The proceeds from the sale of Trust Securities
were used to purchase Junior  Subordinated  Debentures  ("Debentures")  from the
Company.  The  Debentures  are the sole assets of the Trust and the Company owns
all common securities of the Trust.

       The Debentures have an interest rate of 8.231% and a stated maturity date
of June 1, 2027. The Trust Securities are subject to mandatory redemption at par
on the stated  maturity  date of the  Debentures.  The Trust  Securities  may be
redeemed  earlier,  under  certain  conditions,  at the  option of the  Company.
Dividends relating to preferred securities are included in interest expense.


                                       52
<PAGE>


NOTE 6.
         ADDITIONAL PAID-IN CAPITAL

       The changes in Additional Paid-in Capital are as follows:
<TABLE>
<CAPTION>
  (dollars in thousands)                           1999        1998       1997
-------------------------------------------------------------------------------
<S>                                            <C>         <C>        <C>
  Balance at beginning of year                 $450,724    $450,845   $446,910
  Excess of proceeds over stated values of
   common stock issued                            4,198          --        428
  Par value over cost of reacquired
   preferred stock                                   --          --        471
  Retained earnings adjustment for
   preferred redemption                             150          --      3,036
  Issue costs and other expenses                    (90)       (121)        --
-------------------------------------------------------------------------------
  Balance at end of year                       $454,982    $450,724   $450,845
-------------------------------------------------------------------------------
</TABLE>

NOTE 7.
         EARNINGS REINVESTED IN THE BUSINESS

       The payment of dividends on common stock is  restricted  by provisions of
certain covenants  applicable to preferred stock and long-term debt contained in
the Company's Articles of Incorporation and Mortgage Indentures.  Under the most
restrictive  covenants,  earnings reinvested in the business  unrestricted as to
payment of cash dividends were approximately $202 million at December 31, 1999.

       The adjustments  made to the carrying value of costs  associated with the
terminated  generating  projects and  Bonneville  Exchange  Power as a result of
Statement  No. 90,  adjustments  made as a result of  Statement  No. 121 and the
disallowance of certain  terminated  generating  project costs by the Washington
Commission  do not impact the amount of earnings  reinvested in the business for
purposes  of  payment  of  dividends  on  common  stock  under  the terms of the
Company's Articles and Mortgage Indentures. (See Note 1.)


                                       53
<PAGE>

NOTE 8.
         LONG-TERM DEBT
<TABLE>


  FIRST MORTGAGE BONDS AND SENIOR NOTES
  (at December 31; dollars in thousands):
<CAPTION>

  SERIES                DUE                  1999                 1998
-----------------------------------------------------------------------
<S>                    <C>              <C>                   <C>
  6.50%                1999                    --             $ 16,500
  6.65%                1999                    --               10,000
  6.41%                1999                    --               20,500
  7.08%                1999                    --               10,000
  7.25%                1999                    --               50,000
  6.61%                2000              $ 10,000               10,000
  9.60%                2000                25,000               25,000
  8.51 - 8.55%         2001                19,000               19,000
  7.53 - 7.91%         2002                30,000               30,000
  7.85%                2002                30,000               30,000
  7.07%                2002                27,000               27,000
  7.15%                2002                 5,000                5,000
  7.625%               2002                25,000               25,000
  6.23 - 6.31%         2003                28,000               28,000
  7.02%                2003                30,000               30,000
  6.20%                2003                 3,000                3,000
  6.40%                2003                11,000               11,000
  6.07 & 6.10%         2004                18,500               18,500
  7.70%                2004                50,000               50,000
  7.80%                2004                30,000               30,000
  6.92 & 6.93%         2005                31,000               31,000
  6.58%                2006                10,000               10,000
  8.06%                2006                46,000               46,000
  8.14%                2006                25,000               25,000
  7.02 & 7.04%         2007                25,000               25,000
  7.75%                2007               100,000              100,000
  8.40%                2007                10,000               10,000
  6.51 & 6.53%         2008                 4,500                4,500
  6.61 & 6.62%         2009                 8,000                8,000
  6.46%                2009               150,000                   --
  7.12%                2010                 7,000                7,000
  8.59%                2012                 5,000                5,000
  8.20%                2012                30,000               30,000
</TABLE>


                                       54
<PAGE>
<TABLE>
<CAPTION>

  SERIES                DUE                  1999                 1998
-----------------------------------------------------------------------
<S>       <C>          <C>                 <C>                  <C>
  6.83% & 6.90%        2013                13,000               13,000
  7.35 & 7.36%         2015                12,000               12,000
  6.74%                2018               200,000              200,000
  9.57%                2020                25,000               25,000
  8.25 - 8.40%         2022                35,000               35,000
  7.19%                2023                13,000               13,000
  7.35%                2024                55,000               55,000
  7.15 & 7.20%         2025                17,000               17,000
  7.02%                2027               300,000              300,000
  7.00%                2029               100,000                   --
---------------------------- --------------------- --------------------
  Total                                $1,563,000           $1,420,000
---------------------------- --------------------- --------------------
</TABLE>

       In September 1998, the Company filed a shelf-registration  statement with
the  Securities  and  Exchange  Commission  for the  offering,  on a delayed  or
continuous basis, of up to $500 million principal amount of Senior Notes secured
by a pledge of First Mortgage  Bonds.  On March 9, 1999, the Company issued $250
million principal amount of Senior Medium-Term Notes,  Series B, which consisted
of $150 million  principal amount due March 9, 2009 at an interest rate of 6.46%
and $100 million principal amount due March 9, 2029 at an interest rate of 7.0%.
On February 22, 2000, the Company issued $225 million  principal amount of 7.96%
Senior  Medium-Term  Notes,  Series B. The Notes are due  February  22, 2010 and
proceeds were used to redeem the Encogen  project debt and pay down a portion of
the Company's short-term debt.

       Substantially all utility  properties owned by the Company are subject to
the lien of the Company's electric and gas mortgage indentures.

POLLUTION CONTROL BONDS

       The Company has  outstanding  three  series of Pollution  Control  Bonds.
Amounts  outstanding  were  borrowed  from the City of  Forsyth,  Montana  ("the
City").  The City  obtained  the  funds  from the sale of  Customized  Pollution
Control  Refunding  Bonds  issued to finance  pollution  control  facilities  at
Colstrip Units 3 and 4.

       Each  series of bonds  are  collateralized  by a pledge of the  Company's
First Mortgage  Bonds,  the terms of which match those of the Pollution  Control
Bonds.  No payment is due with respect to the related  series of First  Mortgage
Bonds so long as payment is made on the Pollution Control Bonds.  Interest rates
for the 1992 and 1993 series are 6.80% and 5.875%, respectively. The 1991 series
consists of $27.5 million  principal  amount bearing interest at 7.05% and $23.4
million principal amount bearing interest at 7.25%.

PROJECT DEBT

       On November 1, 1999, the Company  assumed  approximately  $109 million of
project debt under the agreement to purchase the 160-megawatt  natural gas-fired
cogeneration  plant from Encogen  Northwest  L.P.  Interest rates on the project
debt ranged from 8.64% to 13.03%.  In February  2000, the Company used a portion
of the proceeds  from the issuance of $225  million  principal  amount of Senior
Medium-Term notes to pay off the project debt. At December 31, 1999, the project
debt was included in Other notes.

LONG-TERM DEBT MATURITIES

       The  principal  amounts of long-term  debt  maturities  for the next five
years are as follows:
<TABLE>
<CAPTION>
  (DOLLARS IN THOUSANDS)      2000        2001        2002       2003       2004
 -------------------------------------------------------------------------------
<S>                       <C>         <C>         <C>        <C>        <C>
 Maturities of:
    Long-term debt        $ 35,000    $ 19,000    $117,000   $ 72,000   $ 98,500

</TABLE>


                                       55
<PAGE>

NOTE 9.
         SHORT-TERM DEBT AND OTHER FINANCING ARRANGEMENTS

       At December 31, 1999, the Company had short-term  borrowing  arrangements
which included a $375 million line of credit with thirteen banks.  The agreement
provides  the Company  with the  ability to borrow at  different  interest  rate
options and includes variable fee levels. The options are: (1) the higher of the
prime rate or the Federal Funds rate plus 1/2 of 1 percent or (2) the Eurodollar
rate plus .25 percent.  The current availability fee is .08 percent per annum on
the unused loan commitment.

       In addition,  the Company has agreements  with several banks to borrow on
an uncommitted,  as available,  basis at money-market rates quoted by the banks.
There are no costs,  other than interest,  for these  arrangements.  The Company
also uses commercial paper to fund its short-term borrowing requirements.
<TABLE>
<CAPTION>
  at December 31: (dollars in thousands)      1999         1998          1997
 ----------------------------------------------------------------------------
<S>                                       <C>          <C>           <C>
 Short-term borrowings outstanding:
    Commercial paper notes                $105,712     $142,105      $124,538
    Bank line of credit borrowing               --      $25,000      $215,000
    Uncommitted bank borrowings           $499,000     $283,800       $33,000
    Weighted average interest rate           6.59%        5.90%         6.88%
    Credit availability (1)               $375,000     $375,000      $375,000
</TABLE>

       The Company has, on occasion,  entered into interest rate swap agreements
to  reduce  the  impact  of  changes  in  interest  rates  on  portions  of  its
floating-rate debt. One agreement outstanding at December 31, 1999,  effectively
changes the Company's interest rate on outstanding  commercial paper to 9.64% on
a notional  principal amount of $16.5 million expiring March 31, 2000. Two other
agreements  outstanding at December 31, 1999,  effectively  change the Company's
interest rate on outstanding  commercial paper to 7.39% on a notional  principal
amount of $53.0 million expiring June 29, 2007.


___________________________
     (1)  Provides  liquidity  support  for  outstanding  commercial  paper  and
borrowing from credit line banks in the amount of $105.7 million, $167.1 million
and $339.5 million for 1999, 1998 and 1997  respectively,  effectively  reducing
the available  borrowing  capacity  under these credit lines to $269.3  million,
$207.9 million and $35.5 million, respectively.


                                       56
<PAGE>


NOTE 10.
         ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

       The following  table  presents the carrying  amounts and  estimated  fair
values of the Company's financial instruments at December 31, 1999 and 1998:
<TABLE>
<CAPTION>
                                                      1999         1999         1998        1998
                                                  CARRYING         FAIR     CARRYING        FAIR
  (DOLLARS IN MILLIONS)                             AMOUNT        VALUE       AMOUNT       VALUE
--------------------------------------------- ------------- ------------ ------------ -----------
<S>                                                 <C>          <C>          <C>         <C>
  Financial Assets:
    Cash                                            $ 65.7       $ 65.7       $ 28.2      $ 28.2
    Cabot preferred stock                           $ 51.6       $ 51.6       $ 51.6      $ 51.6
    Equity securities (1)                           $ 13.7       $ 13.7        $40.0       $40.0
    Notes receivable                                $ 31.1       $ 31.1           --          --
  Financial Liabilities:
    Short-term debt                                 $604.7       $604.7       $450.9      $450.9
    Preferred stock subject to
      mandatory redemption                          $ 65.7       $ 65.2       $ 73.2      $ 75.8
    Corporation obligated, mandatorily
      redeemable preferred securities of
       subsidiary trust holding solely
       junior subordinated debentures of
       the corporation                              $100.0       $ 91.8       $100.0      $109.3
    Long-term debt                                $1,724.8     $1,618.3     $1,582.1    $1,686.4
    Project debt                                    $106.0       $109.4           --          --
  Unrecognized Financial Instruments:
    Interest rate swaps                                 --       $ (0.6)          --       $(1.3)
--------------------------------------------- ------------- ------------ ------------ -----------
</TABLE>

     The  fair  value of  outstanding  bonds  including  current  maturities  is
estimated based on quoted market prices.

     The  preferred  stock  subject  to  mandatory  redemption  and  corporation
obligated,  mandatorily  redeemable  preferred  securities of  subsidiary  trust
holding solely junior  subordinated  debentures of the  corporation is estimated
based on dealer quotes.

     The carrying  value of  short-term  debt is  considered  to be a reasonable
estimate of fair value.  The carrying amount of cash,  which includes  temporary
investments with original  maturities of 3 months or less, is also considered to
be a reasonable estimate of fair value.

       The fair value of interest rate swaps (used for hedging  purposes) is the
estimated  amount that the Company would  receive or pay to terminate  each swap
agreement at the reporting date,  taking into account current interest rates and
the current credit-worthiness of all the parties to each swap.

       Derivative  instruments have been used by the Company on a limited basis.
The  Company  has a policy  that  financial  derivatives  are to be used only to
mitigate business risk and not for speculative purposes.


_______________________________
     (1) 1999 carrying  amount includes an adjustment of $13.5 million to report
the available-for-sale securities at market value. This amount has been included
as a  component  of other  comprehensive  income net of  deferred  taxes of $4.7
million.


                                       57
<PAGE>

NOTE 11.
         SUPPLEMENTARY INCOME STATEMENT INFORMATION
<TABLE>
<CAPTION>
  (dollars in thousands)                        1999          1998         1997
--------------------------------------------------------------------------------
 <S>                                         <C>           <C>          <C>
 Taxes:
    Real estate and personal property       $ 48,036      $ 40,422     $ 46,252
    State business                            70,047        62,855       58,466
    Municipal, occupational and other         52,739        48,090       45,252
    Other                                     19,445        20,010       21,242
--------------------------------------------------------------------------------
  Total taxes                               $190,267      $171,377     $171,212
--------------------------------------------------------------------------------
  Charged to:
    Operating expense                       $180,141      $160,472     $159,310
    Other accounts, including
      construction work in progress           10,126        10,905       11,902
--------------------------------------------------------------------------------
  Total taxes                               $190,267      $171,377     $171,212
--------------------------------------------------------------------------------
</TABLE>

       See "Consolidated  Statements of Income" for maintenance and depreciation
expense.

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

NOTE 12.
         LEASES

       The Company treats all leases as operating leases for ratemaking purposes
as  required by the  Washington  Commission.  Certain  leases  contain  purchase
options, renewal and escalation provisions. Capitalized leases are not material.

       Rental and operating lease expense for the years ended December 31, 1999,
1998 and 1997, were  approximately  $19,179,000,  $ 17,798,000 and  $19,428,000,
respectively. Payments due for the years ended December 31, 1999, 1998 and 1997,
for the sublease of properties were approximately  $2,321,000,  $1,242,000,  and
$962,000, respectively.

       Future minimum lease payments for noncancelable  leases are approximately
$16,459,000 for 2000,  $14,621,000 for 2001,  $14,210,000 for 2002,  $12,019,000
for  2003,  $7,854,000  for 2004 and in the  aggregate,  $9,252,000  thereafter.
Future minimum sublease receipts for noncancelable  subleases are $2,025,000 for
2000,  $2,025,000 for 2001, $2,025,000 for 2002, $2,025,000 for 2003, $3,000 for
2004 and in the aggregate, $3,000 thereafter.


                                       58
<PAGE>

NOTE 13.
         FEDERAL INCOME TAXES

       The details of federal income taxes ("FIT") are as follows:
<TABLE>
<CAPTION>
  (dollars in thousands)                           1999        1998        1997
--------------------------------------------------------------------------------
  Charged to Operating Expense:
<S>                                             <C>         <C>        <C>
  Current                                       $94,516     $88,606    $ 28,863
  Deferred - net                                 15,373      17,948      16,677
  Deferred investment tax credits                  (725)       (740)       (624)
--------------------------------------------------------------------------------
  Total FIT charged to operations               109,164     105,814      44,916
--------------------------------------------------------------------------------
  Charged to Miscellaneous Income:
  Current                                        (1,665)      4,634      16,709
  Deferred - net                                  4,574        (648)     (1,902)
--------------------------------------------------------------------------------
  Total FIT charged to miscellaneous income       2,909       3,986      14,807
--------------------------------------------------------------------------------
  Credited to discontinued operations                --          --      (1,412)
--------------------------------------------------------------------------------
  Total FIT                                    $112,073    $109,800    $ 58,311
--------------------------------------------------------------------------------
</TABLE>

       The following is a reconciliation of the difference between the amount of
FIT computed by  multiplying  pre-tax book income by the statutory tax rate, and
the amount of FIT in the Consolidated Statements of Income:
<TABLE>
<CAPTION>
  (dollars in thousands)                               1999       1998     1997
--------------------------------------------------------------------------------
<S>                                                <C>         <C>      <C>
  FIT at the statutory rate                        $104,174    $97,794  $63,485
--------------------------------------------------------------------------------
  Increase (Decrease):
    Depreciation expense deducted in the
      financial statements in excess of tax
      depreciation, net of depreciation
      treated as a temporary difference               8,678      7,756    7,019
    AFUDC included in income in the financial
      statements but excluded from taxable income    (4,345)    (3,953)  (2,774)
    Accelerated benefit on early retirement
      of depreciable assets                            (812)    (1,241)    (805)
    Investment tax credit amortization                 (725)      (740)    (624)
    Energy conservation expenditures - net           13,434     12,754   11,028
    Conservation Settlement                              --         --  (26,197)
    Prior period adjustment/Audit adjustment             --         --      (37)
    Other - net                                      (8,331)    (2,570)   7,216
--------------------------------------------------------------------------------
  Total FIT                                        $112,073   $109,800  $58,311
--------------------------------------------------------------------------------
  Effective tax rate                                  37.7%      39.3%    32.1%
--------------------------------------------------------------------------------
</TABLE>


                                       59
<PAGE>

       The following are the principal components of FIT as reported:
<TABLE>
<CAPTION>
  (dollars in thousands)                             1999       1998       1997
--------------------------------------------------------------------------------
<S>                                               <C>        <C>        <C>
  Current FIT                                     $92,851    $93,240    $45,572
--------------------------------------------------------------------------------
  Deferred FIT - other:

    Conservation tax settlement                     2,927      3,257     14,404
    Periodic rate adjustment mechanism (PRAM)          --        107     (14,272)
    Deferred taxes related to insurance reserves   (1,225)    (1,224)     (2,768)
    Reversal of Statement No. 90 present
      value adjustments                                92        255        408
    Residential Purchase and Sale Agreement - net      --      3,441      (6,047)
    Normalized tax benefits of the
      accelerated cost recovery system             14,452     20,118     22,575
    Energy conservation program                      (983)    (2,437)     5,101
    Environmental remediation                         947     (2,946)     (3,092)
    WNP 3 tax settlement                             (826)      (826)    21,360
    Merger costs                                      409         42      (7,322)
    Demand charges                                     14      3,273      (3,558)
    Other                                           4,140     (5,760)    (12,014)
---------------------------------------------------------------------------------
  Total deferred FIT - other                       19,947     17,300     14,775
--------------------------------------------------------------------------------
  Deferred investment tax credits -
    net of amortization                              (725)      (740)       (624)
  Credited to discontinued operations                             --      (1,412)
--------------------------------------------------------------------------------
  Total FIT                                      $112,073   $109,800    $58,311
--------------------------------------------------------------------------------
</TABLE>

       Deferred tax amounts shown above result from  temporary  differences  for
tax and financial statement  purposes.  Deferred tax provisions are not recorded
in the income  statement  for  certain  temporary  differences  between  tax and
financial  statement  purposes  because  they  are not  allowed  for  ratemaking
purposes.

       The Company  calculates  its  deferred tax assets and  liabilities  under
Statement of Financial  Accounting  Standards  No. 109,  "Accounting  for Income
Taxes" ("Statement No. 109").  Statement No. 109 requires recording deferred tax
balances,  at the  currently  enacted tax rate,  for all  temporary  differences
between the book and tax bases of assets and  liabilities,  including  temporary
differences for which no deferred taxes had been previously  provided because of
use of flow-through  tax accounting for rate making  purposes.  Because of prior
and expected  future rate making  treatment for temporary  differences for which
flow-through  tax accounting has been  utilized,  a regulatory  asset for income
taxes  recoverable  through future rates related to those  differences  has also
been  established.  At December  31,  1999,  the balance of this asset is $228.5
million.


                                       60
<PAGE>

       The deferred tax liability at December 31, 1999 and 1998, is comprised of
amounts related to the following types of temporary differences

<TABLE>
<CAPTION>
  (dollars in thousands)                          1999           1998
----------------------------------------------------------------------
<S>                                           <C>            <C>
  Utility plant                               $574,064       $567,642
  Investment in Cabot stock                     10,635         13,435
  Energy conservation charges                   41,833         57,919
  Contributions in aid of construction         (33,927)        (31,874)
  Bonneville Exchange Power                     22,618         26,513
  Cabot Gas Contract Purchase                    4,200             --
  Other                                         17,312          (5,081)
----------------------------------------------------------------------
  Total                                       $636,735       $628,554
----------------------------------------------------------------------
</TABLE>

       The totals of $636.7 million and $628.6 million for 1999 and 1998 consist
of deferred tax liabilities of $719.7 million and $712.2 million net of deferred
tax assets of $83.0 million and $83.6 million, respectively.

NOTE 14.
         RETIREMENT BENEFITS

       The Company has a defined benefit pension plan covering substantially all
of its employees.  Benefits are a function of both age and salary. Additionally,
the Company maintains a non-qualified  supplemental retirement plan for officers
and certain director-level employees.

       In addition to providing pension  benefits,  the Company provides certain
health care and life insurance  benefits for retired  employees.  These benefits
are provided  principally  through an insurance company whose premiums are based
on the benefits paid during the year.
<TABLE>
<CAPTION>
                                                        PENSION BENEFITS           OTHER BENEFITS
       (dollars in thousands)                              1999         1998        1999         1998
                                                     ------------------------  -----------------------
       <S>                                             <C>          <C>          <C>          <C>
       Change in benefit obligation:
       Benefit obligation at beginning of year         $352,422     $325,063     $29,438      $27,433
       Service cost                                       9,259        8,550         245          229
       Interest cost                                     24,181       22,862       1,868        1,985
       Amendments                                           500        2,540          --           --
       Actuarial (gain)/loss                            (14,548)      15,272      (3,600)       1,896
       Benefits paid                                    (22,654)     (21,865)     (1,948)      (2,105)
-----------------------------------------------------------------------------  -----------------------
       Benefit obligation at end of year               $349,160     $352,422     $26,003      $29,438
-----------------------------------------------------------------------------  -----------------------
       Change in plan assets:
       Fair value of plan assets at beginning of year  $464,195     $415,270     $14,132      $14,445
       Actual return on plan assets                      82,300       67,544         740          570
       Employer contribution                                986        3,246       1,814        1,222
       Benefits paid                                    (22,654)     (21,865)     (1,948)      (2,105)
-----------------------------------------------------------------------------  -----------------------
       Fair value of plan assets at end of year        $524,827     $464,195     $14,738      $14,132
-----------------------------------------------------------------------------  -----------------------
</TABLE>

                                       61
<PAGE>

(continued from previous page)
<TABLE>
<CAPTION>
                                                          PENSION BENEFITS            OTHER BENEFITS
       (dollars in thousands)                              1999         1998        1999          1998
                                                     ------------------------    ----------------------
<S>                                                    <C>          <C>          <C>          <C>
       Funded status                                   $175,667     $111,773     $(11,265)    $(15,306)
       Unrecognized actuarial gain                     (189,609)    (133,189)      (4,870)      (1,532)
       Unrecognized prior service cost                   22,218       25,510         (429)        (463)
       Unrecognized net initial (asset)/obligation       (6,333)      (7,563)      8,148         8,775
------------------------------------------------------------------------------   -----------------------
       Net amount recognized                              $1,943     $(3,469)     $(8,416)     $(8,526)
------------------------------------------------------------------------------   -----------------------
       Amounts recognized on statement of
         financial position consist of:
       Prepaid benefit cost                             $17,698       $8,900      $(8,416)     $(8,526)
       Accrued benefit liability                        (23,670)     (22,988)         --            --
       Intangible asset                                   7,915       10,619          --            --
------------------------------------------------------------------------------   -----------------------
       Net amount recognized                             $1,943      $(3,469)     $(8,416)     $(8,526)
------------------------------------------------------------------------------   -----------------------
</TABLE>

       In accounting for pension and other  benefits costs under the plans,  the
following weighted average actuarial assumptions were used:
<TABLE>
<CAPTION>
                                                   PENSION BENEFITS                       OTHER BENEFITS
                                                1999       1998        1997           1999         1998         1997
                                         ------------ ---------- -----------      --------- ------------ ------------
<S>                                             <C>        <C>    <C>                 <C>        <C>          <C>
  Discount rate                                 7.5%         7%   7.25-7.5%           7.5%           7%        7.25%
  Return on plan assets                        9.75%      9.75%          9%         6-8.5%       6-8.5%       6-8.5%
  Rate of compensation increase                   5%         5%          5%             --           --           --
  Medical trend rate                              --         --          --             7%         7.5%         7.5%
---------------------------------------- ------------ ---------- -----------      --------- ------------ ------------
</TABLE>
<TABLE>
<CAPTION>
                                                   PENSION BENEFITS                       OTHER BENEFITS
                                                1999        1998       1997           1999         1998      1997
                                         ------------ ----------- ----------      --------- ------------ ---------
  <S>                                          <C>         <C>        <C>               <C>          <C>       <C>
Components of net periodic
   benefit cost:
  (dollars in thousands)
  Service cost                                $9,259      $8,550     $8,268           $245         $229      $216
  Interest cost                               24,180      22,862     21,412          1,868        1,985     1,895
  Expected return on plan assets             (37,310)    (33,744)   (27,997)          (857)        (867)     (821)
  Amortization of prior service cost           3,330       3,330      2,247            (34)         (34)      (34)
  Recognized net actuarial gain               (3,117)     (3,180)    (1,144)          (145)         (97)     (204)
  Amortization of transition                  (1,230)     (1,230)    (1,095)           627          627       627
  (asset)/obligation
  Special recognition of prior service           462            --       --             --           --        --
  costs
  Plan curtailments, mergers                      --            --    5,138             --           --     4,712
---------------------------------------- ------------ ------------- ----------    --------- ------------ ---------
  Net pension benefit cost                    (4,426)     (3,412)     6,829          1,704        1,843     6,391
  Regulatory adjustment                          932       1,263      1,263             --           --        --
---------------------------------------- ------------- ------------ --------      --------- ------------ ---------
  Net periodic benefit cost                  $(3,494)    $(2,149)    $8,092         $1,704       $1,843    $6,391
---------------------------------------- ------------- ------------ --------      --------- ------------ ---------
</TABLE>


                                       62
<PAGE>

       The projected benefit obligation,  accumulated  benefit  obligation,  and
fair  value of plan  assets  for the  pension  plans  with  accumulated  benefit
obligations in excess of plan assets were $29 million,  $23.7  million,  and $0,
respectively, as of December 31, 1999.

       The assumed  medical  inflation  rate is 7% in 1999  decreasing  to 6% in
2003. A 1% change in the assumed medical inflation rate would have the following
effects:
<TABLE>
<CAPTION>
                                                           1999                            1998
                                                  1%              1%             1%             1%
  (DOLLARS IN THOUSANDS)                       INCREASE        DECREASE         INCREASE     DECREASE
                                             ------------------------------- -----------------------------
<S>                                                   <C>             <C>             <C>           <C>
  Effect on service and interest cost                 $596            $(579)          $690          $(671)
  components

  Effect on postretirement benefit obligation         $ 40            $ (39)          $ 45           $(44)
</TABLE>

       In December 1995, in connection  with the proposed  merger with WECo, the
Company  offered to its  employees a Voluntary  Separation  Plan. A total of 204
employees elected to participate in the Voluntary Separation Plan resulting in a
curtailment  loss  under  Statement  No. 106 for 1997 of $4.7  million.  Also in
connection  with the  merger  was a  curtailment  loss of $5.1  million  in 1997
related to the supplemental retirement plans.

NOTE 15.
         EMPLOYEE INVESTMENT PLAN & EMPLOYEE STOCK PURCHASE PLAN

       The Company has qualified Employee  Investment Plans under which employee
salary  deferrals  and  after-tax  contributions  are used to  purchase  several
different  investment  fund options.  The Company  makes a monthly  contribution
equal to 100% on up to 4% of participant contributions and 50% on the next 4% of
participant  contributions  which  equates  to a maximum  contribution  of 6% of
eligible earnings. In addition, the Company contributes an amount equal to 1% of
each participant's base pay at the end of the plan year.

       The  Company   contributions   to  the  Employee   Investment  Plan  were
$7,123,400,  $6,532,400  and  $5,000,200  for the  years  1999,  1998 and  1997,
respectively.  The shareholders  have authorized the issuance of up to 2,000,000
shares of common  stock under the plan,  of which  959,142  were issued  through
December 31, 1999. The Employee Investment Plan eligibility requirements are set
forth in the plan documents.

       The Company also has an Employee  Stock  Purchase Plan which was approved
by shareholders on May 19, 1997, and commenced July 1, 1997, under which options
are  granted  to  eligible  employees  who elect to  participate  in the plan on
January  1st and July 1st of each year.  Participants  are  allowed to  exercise
those  options  six months  later to the extent of  payroll  deductions  or cash
payments  accumulated  during that six-month period.  The option price under the
plan during 1999 was 90% of either the fair market  value of the common stock at
the grant date or the fair market value at the exercise date, whichever is less.
Effective with the beginning of the next offering period on January 1, 2000, the
option  price will be 85% of either the fair market value of the common stock at
the grant date or the fair market value at the exercise date, whichever is less.
The  Company  contributions  to the Plan were  $88,900,  $98,200 and $97,600 for
1999, 1998 and 1997, respectively.

       On February 1, 1998, the Company  granted 50 performance  shares to 2,800
eligible  employees in  recognition  of their efforts to implement the Company's
strategies.   On  February  1,  2000,  those  performance  shares  and  dividend
equivalents were converted to common stock.  Total cost of the performance share
grant program was $4,053,400.


                                       63
<PAGE>

NOTE 16.
         OTHER INVESTMENTS

       In May  1994,  the  Company  merged  its  oil  and  gas  exploration  and
production subsidiary, Washington Energy Resources Company ("Resources"), with a
wholly-owned subsidiary of Cabot Oil and Gas Corporation ("Cabot") in a tax-free
exchange.  At December 31, 1998, the Company owned 15.4% of Cabot's  outstanding
voting  securities  consisting of 2,133,000 shares of common stock and 1,134,000
shares of 6% convertible voting preferred stock, stated value $50. For 1998, the
investment  in  Cabot  common  stock  was  classified  as an  available-for-sale
security and was reported at its fair value of $31,995,000.  The unrealized gain
of $8,802,000  (net of deferred taxes of $4,739,000)  was included as a separate
component of common equity.  In May 1999, the Company sold the 2,133,000  shares
of common stock and recorded an after-tax gain of $12.3 million.  At the time of
the sale, the fair value of the stock was $37,350,000,  resulting in an increase
of  $3,483,000  in the  unrealized  gain.  This  amount has been  included  as a
component of other  comprehensive  income,  net of deferred taxes of $1,875,000.
The  $12.3  million  realized  gain on the  sale has  been  reclassified  out of
accumulated other  comprehensive  income. No fair value is readily available for
the Cabot preferred stock as it is not publicly traded;  however, its cost basis
of  $51,619,000  is believed to be a reasonable  approximation  of fair value at
December 31, 1999. The Company has an agreement  that Cabot,  subject to certain
conditions,  will  repurchase  all shares of the preferred  stock by November 1,
2000.  Prior to October 1, 1997, the Company's  interest in Cabot's common stock
was  accounted  for using the equity  method  because the  Company,  through its
representation  on Cabot's  board of  directors,  had the  ability  to  exercise
significant influence over operating and financial policies of Cabot.  Effective
October 1, 1997, the Company discontinued equity-method accounting for Cabot and
records its interest as an investment in stock because the Company no longer has
representation on Cabot's board of directors.  Equity in earnings from Cabot was
$948,000 for 1997. See Note 17 regarding certain gas transportation, storage and
other  contractual  arrangements  of Resources that were excluded from the Cabot
merger and retained by a subsidiary of the Company.

       In March 1998,  the Company  entered into an agreement  with CellNet Data
Services Inc.  ("CellNet")  under which the Company would lend CellNet up to $35
million in the form of multiple  draws so that  CellNet can finance an Automated
Meter  Reading  (AMR)  network  system to be deployed in the  Company's  service
territory.  In September  1999,  the Company  announced it was expanding its AMR
network system from 800,000 meters to 1,325,000 meters and as a result increased
the  authorized  loan amount to $72 million.  On June 30, 1999, the Company made
the first loan under the loan agreement and as of December 31, 1999,  there were
loans outstanding of $31.1 million.

NOTE 17.
         COMMITMENTS AND CONTINGENCIES

COMMITMENTS - ELECTRIC

       For the twelve months ended December 31, 1999, approximately 23.2% of the
Company's  energy  output was obtained at an average cost of  approximately  9.4
mills per KWH through long-term  contracts with several of the Washington public
utility districts ("PUDs") owning hydro-electric projects on the Columbia River.

       The purchase of power from the Columbia  River projects is generally on a
"cost-of-service"  basis under which the Company pays a  proportionate  share of
the  annual  cost of each  project in direct  proportion  to the amount of power
annually  purchased  by the Company  from such  project.  Such  payments are not
contingent upon the projects being operable. These projects are financed through
substantially  level debt  service  payments,  and their annual costs should not
vary significantly over the term of the contracts unless additional financing is
required  to meet the costs of major  maintenance,  repairs or  replacements  or
license  requirements.  The  Company's  share of the costs and the output of the
projects is subject to reduction  due to various  withdrawal  rights of the PUDs
and others over the lives of the contracts.

       As of December 31, 1999, the Company was entitled to purchase portions of
the power output of the PUDs' projects as set forth in the following tabulation:


                                       64
<PAGE>
<TABLE>
<CAPTION>
                                                              BONDS                    COMPANY'S ANNUAL AMOUNT
                                                           OUTSTANDING                PURCHASABLE (APPROXIMATE)
                                                                          -------------------------------------------------
                              CONTRACT      LICENSE (1)    12/31/99 (2)         % OF            MEGAWATT        COSTS (3)
  PROJECT                    EXP. DATE      EXP. DATE       (MILLIONS)         OUTPUT           CAPACITY       (MILLIONS)
------------------------- --------------- ------------- ----------------- ---------------- ----------------- --------------
 <S>                                 <C>           <C>              <C>               <C>                <C>           <C>
 Rock Island
     Original units                 2012          2029              83.5             52.4               478          $40.7
     Additional units               2012          2029             331.7            100.0                --             --
  Rocky Reach                       2011          2006             265.6             38.9               505           22.6
  Wells                             2018          2012             182.9             31.3               261            9.6
  Priest Rapids                     2005          2005             169.1              8.0                72            2.0
  Wanapum                           2009          2005             186.3             10.8                98            3.4
                                                                                           ----------------- --------------
  Total                                                                                               1,414          $78.3
</TABLE>

       The Company's  estimated  payments for power  purchases from the Columbia
River  projects are $81 million for 2000,  $80 million for 2001, $80 million for
2002,  $78 million for 2003,  $76  million for 2004 and in the  aggregate,  $605
million thereafter through 2018.

       The Company also has numerous  long-term firm purchased  power  contracts
with other  utilities in the region.  The Company is generally  not obligated to
make payments  under these  contracts  unless power is delivered.  The Company's
estimated payments for firm power purchases from other utilities,  excluding the
Columbia River projects,  are $155 million for 2000, $150 million for 2001, $141
million  for 2002,  $130  million  for  2003,  $77  million  for 2004 and in the
aggregate,  $707 million  thereafter  through 2037. These contracts have varying
terms and may include escalation and termination provisions.

       As  required  by the  federal  Public  Utility  Regulatory  Policies  Act
("PURPA"),  the Company  entered into long-term firm purchased  power  contracts
with non-utility generators.  The Company purchases the net electrical output of
four  significant  projects at fixed and annually  escalating  prices which were
intended to approximate the Company's  avoided cost of new generation  projected
at the time these  agreements  were made.  Principally,  as a result of dramatic
changes in natural  gas price  levels,  the power  purchase  prices  under these
agreements are significantly  above the current market price of power and, based
upon  projections  of future  market  prices,  are expected to remain well above
market for the duration of the contracts.  The Company's estimated payment under
these four  contracts  are $181 million for 2000,  $204  million for 2001,  $206
million  for 2002,  $207  million  for 2003,  $213  million  for 2004 and in the
aggregate,  $1.5 billion  thereafter  through  2012. If retail  electric  energy
prices move to market levels as a result of electric industry restructuring, the
Company plans to seek to continue to recover in rates the  above-market  portion
of these contract costs.


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

     (2) The contracts for purchases  initially were generally  coextensive with
the term of the PUD bonds  associated with the project.  Under the terms of some
financings  and  refinancings,  however,  long-term  bonds  were sold to finance
certain assets whose estimated useful lives extend beyond the expiration date of
the power sales contracts. Of the total outstanding bonds sold for each project,
the  percentage  of principal  amount of bonds which mature  beyond the contract
expiration date are: 40.8% at Rock Island; 45.7% at Rocky Reach; 81.3% at Priest
Rapids; and 49.7% at Wanapum; and 5.1% at Wells.

     (3) The components of 1999 costs  associated  with the interest  portion of
debt service are: Rock Island,  $23.2 million for all units;  Rocky Reach,  $5.3
million;  Wells, $2.7 million;  Priest Rapids, $0.8 million;  and Wanapum,  $1.1
million.

                                       65
<PAGE>

       The following table summarizes the Company's obligations for future power
purchases.
<TABLE>
<CAPTION>
                                                                                               2005 &
                                                                                               THERE-
(In Millions)                      2000        2001         2002         2003         2004      AFTER      TOTAL
------------------------------ --------- ----------- ------------ ------------ ------------ ---------- ----------
<S>                                 <C>         <C>          <C>          <C>          <C>       <C>      <C>
  Columbia River Projects           $81         $80          $80          $78          $76       $605     $1,000
  Other utilities                   155         150          141          130           77        707      1,360
  Non-Utility Generators            181         204          206          207          213      1,494      2,505
------------------------------ --------- ----------- ------------ ------------ ------------ ---------- ----------
      Total                        $417        $434         $427         $415         $366     $2,806     $4,865
------------------------------ --------- ----------- ------------ ------------ ------------ ---------- ----------
</TABLE>

       Total purchased power contracts  provided the Company with  approximately
16.1  million,  15.8  million  and 15.6  million MWH of firm energy at a cost of
approximately  $487.4  million,  $481.6 million and $464.5 million for the years
1999, 1998 and 1997, respectively.

       As part of its  electric  operations  and in  connection  with  the  1997
restructuring  of the Tenaska Power Purchase  Agreement the Company is obligated
to deliver to Tenaska up to 48,000 MMBtu per day of natural gas for operation of
Tenaska's  cogeneration  facility.  This obligation  continues for the remaining
term of the agreement, provided that no deliveries are required during the month
of May. The price paid by Tenaska for this gas is  reflective of the daily price
of gas at the U.S./Canada border near Sumas, Washington.

       As part of its  electric  operations  and in  connection  with  the  1999
buy-out of the Cabot gas supply contract, the Company is obligated to deliver to
Encogen up to 21,800  MMBtu per day of natural gas for  operation of the Encogen
cogeneration  facility.  This obligation continues for the remaining term of the
original Cabot  agreement.  The price paid by Encogen for this gas is reflective
of the price paid under the Cabot  agreement.  The difference  between the price
paid by Encogen and the  replacement  cost of gas at current  market prices will
reduce the  Company's  cost of power.  The Company  entered  into two  financial
arrangements to hedge future gas supply costs  associated with this  obligation,
hedging  20,000  MMBtu  per day  for  2000,  and  10,000  MMBtu  per day for the
remaining term of the agreement. Encogen has two remaining gas supply agreements
that comprise 40% of the plant's requirements with remaining terms of 8.5 years.
Not included in the table above are Encogen's  obligations under these contracts
of $11,821,000 in 2000, $12,414,000 in 2001, $13,047,000 in 2002, $13,690,000 in
2003, $14,375,000 in 2004 and $65,098,000 in the aggregate thereafter.

       The following table indicates the Company's  percentage ownership and the
extent of the Company's investment in jointly-owned generating plants in service
at December 31, 1999:
<TABLE>
<CAPTION>

                                                                                   COMPANY'S SHARE
                                                                  ------------------------------------------------
                            ENERGY               COMPANY'S           PLANT IN SERVICE           ACCUMULATED
       PROJECT           SOURCE (FUEL)      OWNERSHIP SHARE (%)     AT COST (MILLIONS)    DEPRECIATION (MILLIONS)
--------------------- ------------------ ------------------------ --------------------- --------------------------
<S>                     <C>                                  <C>               <C>                        <C>
  Centralia             Coal                                  7%                $ 27.3                     $ 19.2
  Colstrip 1 & 2        Coal                                 50%                 188.7                      112.0
  Colstrip 3 & 4        Coal                                 25%                 451.2                      191.5
</TABLE>

     Financing for a  participant's  ownership share in the projects is provided
for  by  such  participant.   The  Company's  share  of  related  operating  and
maintenance  expenses is included in corresponding  accounts in the Consolidated
Statements of Income.

                                       66
<PAGE>

       On November 2, 1998, the Company announced that it signed an agreement to
sell the Company's  735-megawatt interest in the four-unit,  coal-fired Colstrip
generation  plant  in  eastern  Montana,  as  well  as  associated  transmission
facilities. The Company signed the agreement with PP&L Global, Inc., of Fairfax,
Virginia,  a subsidiary  of PP&L  Resources,  Inc.  Included in the sale are the
Company's 50% interest in Colstrip Units 1 and 2; 25% interest in Units 3 and 4;
and associated Colstrip transmission capacity across Montana.  Completion of the
sale is  contingent  on  acceptable  regulatory  treatment  from the  Washington
Commission.  On September  30, 1999,  the  Washington  Commission  conditionally
approved the Colstrip  sale,  which at that time was fixed at $556 million.  The
net book value of these assets and related  regulatory  assets is  approximately
$464  million.  After taxes and other costs,  the Company  expected to realize a
gain of approximately  $37.6 million.  However,  the terms and conditions of the
Washington  Commission  order  made the sale  economically  unattractive  to the
Company. The Company appealed the Washington  Commission's  decision in December
1999.  Pending the outcome of the appeal,  the Company is working  with  various
parties to obtain other terms and conditions so the sale can proceed.

       In May 1999, the eight partners,  including the Company, in the Centralia
coal fired generating plant project announced the sale of the plant to TransAlta
Corporation of Calgary, Canada. The purchase price of the plant and the adjacent
mine (owned and operated by PacifiCorp)  is $554 million.  The Company owns a 7%
interest  in the  plant.  The  transaction  is  currently  under  review  by the
Washington Commission.

GAS

       The Company has also entered into various firm supply, transportation and
storage service contracts in order to assure adequate availability of gas supply
for its firm customers. Many of these contracts, which have remaining terms from
one to 24 years,  provide that the Company  must pay a fixed demand  charge each
month,  regardless  of actual usage.  Certain of the  Company's  firm gas supply
agreements  also obligate the Company to purchase a minimum  annual  quantity at
market-based  contract  prices.  Generally,  if  the  minimum  volumes  are  not
purchased and taken during the year, the Company is obligated to pay either:  1)
a monthly or annual gas  inventory  charge  calculated  as a  percentage  of the
then-current  contract  commodity price times the minimum quantity not taken; or
2) pay  for gas not  taken.  Alternatively,  under  some of the  contracts,  the
supplier may  exercise a right to reduce its  subsequent  obligation  to provide
firm gas to the Company.  The Company  incurred  demand charges in 1999 for firm
gas supply, firm transportation  service and firm storage and peaking service of
$31,012,000, $52,190,000 and $8,799,000, respectively.

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

  DEMAND CHARGE OBLIGATIONS
<TABLE>
<CAPTION>

                                                                                                    2005 &
                                                                                                    THERE-
(In Thousands)                        2000         2001        2002        2003         2004         AFTER          TOTAL
------------------------------- ----------- ------------ ----------- ----------- ------------ ------------- --------------
<S>                                <C>          <C>         <C>         <C>          <C>           <C>           <C>
  Firm gas supply                  $28,114      $28,114     $27,358     $21,863      $11,482       $ 5,291       $122,222
  Firm transportation service       51,248       51,196      51,196      51,196       45,020        91,209        341,065
  Firm storage service               8,885        8,885       8,885       8,885        8,680        78,851        123,071
------------------------------- ----------- ------------ ----------- ----------- ------------ ------------- --------------
      Total                        $88,247      $88,195     $87,439     $81,944      $65,182      $175,351       $586,358
------------------------------- ----------- ------------ ----------- ----------- ------------ ------------- --------------
</TABLE>

  MINIMUM ANNUAL TAKE OBLIGATIONS
<TABLE>
<CAPTION>

                                                                                                       2005 &
                                                                                                       THERE-
(In thousands of therms)                     2000         2001        2002        2003        2004      AFTER          TOTAL
-------------------------------------- ----------- ------------ ----------- ----------- ----------- ---------- --------------
<S>                                       <C>          <C>         <C>         <C>         <C>            <C>      <C>
  Firm gas supply                         588,967      444,726     403,026     318,515     144,849        685      1,900,768
</TABLE>

       The Company believes that all demand charges will be recoverable in rates
charged to its customers.  Further, pursuant to implementation of FERC Order No.
636,  the  Company  has the  right to  resell or  release  to others  any of its
unutilized gas supply or transportation and storage capacity.

                                       67
<PAGE>

       The Company does not  anticipate  any difficulty in achieving the minimum
annual  take  obligations  shown,  as such  volumes  represent  less than 65% of
expected annual sales for 2000 and less than 49% of expected sales in subsequent
years.

       The Company's current firm gas supply contracts obligate the suppliers to
provide, in the aggregate, annual volumes up to those shown below:

  MAXIMUM SUPPLY AVAILABLE UNDER CURRENT FIRM SUPPLY CONTRACTS
<TABLE>
<CAPTION>

                                                                                            2005 &
                                                                                            THERE-
(In thousands of therms)         2000         2001        2002        2003         2004      AFTER         TOTAL
-------------------------- ----------- ------------ ----------- ----------- ------------ ---------- -------------
<S>                           <C>          <C>         <C>         <C>          <C>         <C>        <C>
  Firm gas supply             745,201      600,960     556,860     456,524      246,199     42,734     2,648,478
</TABLE>

       Washington  Energy  Gas  Marketing   Company  ("WEGM"),   a  wholly-owned
subsidiary,  holds firm rights to transport  natural gas on the Nova Corporation
of Alberta  ("Nova"),  and Alberta Natural Gas Company  ("ANG"),  pipelines from
Alberta, Canada, to the northern border of Idaho, as well as certain gas storage
rights at the Alberta Energy  Company  ("AECO") field in Alberta and the Jackson
Prairie  field in western  Washington.  These  rights  were  formerly  held by a
wholly-owned  subsidiary of Washington  Energy  Resources but were excluded from
the merger of Resources and Cabot  completed in May 1994.  Following the merger,
WEGM entered into a five-year contract with IGI Resources ("IGI"), Boise, Idaho,
to manage these  rights.  The  management  contract  terminated on September 30,
1999.  WEGM's annual  obligations  for future demand charges through the primary
term of WEGM's gas  transportation  and storage contracts are as follows:  2000,
$778,200;  2001, $778,200;  2002, $778,200;  2003, $634,900;  2004, $553,000 and
thereafter, $1,924,000.

       Through October of 1999, WEGM also held firm rights to transport  natural
gas on the PG&E Gas Transmission - Northwest  ("PGT") pipeline from the northern
Idaho border to the northern California border. Effective November 1, 1999, WEGM
sold its remaining interests in the PGT pipeline capacity.

       As of December 31, 1999, WEGM has a reserve for future losses  associated
with the remaining contractual  obligations of $1,779,800.  In the third quarter
of 1999, WEGM recorded a $4,888,400  ($3,177,500  after tax) charge based on the
sale of its interest in the PGT pipeline capacity and actual mitigation  results
in 1999. In the fourth quarter of 1999, WEGM recorded a $709,000 ($461,000 after
tax) charge to adjust the remaining  reserve for expected future losses.  During
1999,  1998  and  1997,  pre-tax  losses  totaling  $8,429,000,  $1,916,000  and
$2,235,000, respectively, were charged against the reserve.

CONTINGENCIES

       The Company is subject to environmental  regulation by federal, state and
local authorities. The Company has been named a Potentially Responsible Party by
the Environmental  Protection Agency ("EPA") at several  contaminated  sites and
manufactured  gas plant sites. The Company has implemented an ongoing program to
test,  replace and remediate  certain  underground  storage tanks as required by
federal and state laws and this process is nearing  completion.  Remediation and
testing  of  Company  vehicle  service  facilities  and  storage  yards  is also
continuing.

       During 1992,  the  Washington  Commission  issued  orders  regarding  the
treatment  of  costs  incurred  by the  Company  for  certain  sites  under  its
environmental   remediation   program.  The  orders  authorize  the  Company  to
accumulate and defer prudently  incurred cleanup costs paid to third parties for
recovery in rates established in future rate proceedings. The Company believes a
significant portion of its past and future  environmental  remediation costs are
recoverable  from  either  insurance  companies,  third  parties  or  under  the
Washington Commission's order.

       The  information  presented  here as it  relates to  estimates  of future
liability is as of December 31, 1999.

ELECTRIC SITES

       The Company  has  expended  approximately  $15.1  million  related to the
remediation  activities covered by the Washington  Commission's  order, of which
approximately  $7.5  million has been  recovered  from  insurance  carriers.  At
December  31, 1999,  approximately  $2.6 million has been accrued as a liability
for future remediation costs for these and other remediation activities.

                                       68
<PAGE>

GAS SITES

       Five former WNG or predecessor  companies  manufactured gas plant ("MGP")
sites are currently  undergoing  investigation,  remedial  actions or monitoring
actions relating to environmental contamination: 1) Everett, Washington; 2) "Gas
Works Park" in Seattle,  Washington;  3) "Tacoma 22nd and A St." Site in Tacoma,
Washington;  4) Chehalis,  Washington;  and 5) the  "Tideflats"  area of Tacoma,
Washington.  Legal and remedial costs incurred to date total approximately $51.8
million and currently  estimated future remediation costs are approximately $6.9
million.  Work at  both  the  Chehalis  and  Tideflats  sites  is  substantially
completed and the remediation  construction activity at Everett is completed. To
date,  the Company has  recovered  approximately  $57.5  million from  insurance
carriers and other third parties.

       Based on all known facts and  analyses,  the  Company  believes it is not
likely that the identified  environmental  liabilities will result in a material
adverse impact on the Company's  financial  position,  operating results or cash
flow trends.

LITIGATION

       Other  contingencies,  arising out of the normal  course of the Company's
business, exist at December 31, 1999. The ultimate resolution of these issues is
not  expected  to have a material  adverse  impact on the  financial  condition,
results of operations or liquidity of the Company.

NOTE 18.
         DISCONTINUED OPERATIONS

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


                                       69
<PAGE>

NOTE 19.
         SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)

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

  (unaudited; dollars in thousands except per-share amounts)
<TABLE>
<CAPTION>
------------------------------- ----------------- ------------------ ------------------- ----------------
  1999 Quarter                             First             Second               Third           Fourth
------------------------------- ----------------- ------------------ ------------------- ----------------
<S>                                     <C>                <C>                 <C>              <C>
  Operating revenues                    $575,332           $435,439            $411,035         $644,824
  Operating income                      $101,930           $ 54,897            $ 51,448         $101,857
  Other income                            $3,747           $ 13,102              $9,801           $ (831)
  Net income                            $ 69,755           $ 31,065            $ 24,912         $ 59,835
  Basic and diluted earnings
    per common share                      $ 0.79             $ 0.33              $ 0.26           $ 0.68
------------------------------- ----------------- ------------------ ------------------- ----------------
</TABLE>
<TABLE>
<CAPTION>

  (unaudited; dollars in thousands except per-share amounts)
------------------------------ ----------------- ------------------ ------------------- ----------------
  1998 Quarter (1)                        First             Second               Third           Fourth
------------------------------ ----------------- ------------------ ------------------- ----------------
<S>                                    <C>                <C>                 <C>              <C>
  Operating revenues                   $524,514           $370,227            $428,510         $600,605
  Operating income                     $ 98,681           $ 49,689            $ 50,834         $ 95,894
  Other income                           $1,764             $3,862             $ 4,184           $3,372
  Net income                           $ 66,003           $ 19,542            $ 21,091         $ 62,976
  Basic and diluted earnings
    per common share                     $ 0.74             $ 0.19              $ 0.21           $ 0.71
------------------------------ ----------------- ------------------ ------------------- ----------------
</TABLE>


_____________________________________
     (1) Results for 1998 include certain reclassifications to present financial
results on a consistent basis with 1999.

                                       70

<PAGE>

NOTE 20.
         CONSOLIDATED STATEMENT OF CASH FLOWS

       For purposes of the  Statement of Cash Flows,  the Company  considers all
temporary  investments to be cash equivalents.  These temporary cash investments
are securities held for cash  management  purposes,  having  maturities of three
months or less.  The net change in current  assets and current  liabilities  for
purposes  of the  Statement  of Cash Flows  excludes  short-term  debt,  current
maturities of long-term debt and the current  portion of PRAM accrued  revenues.
At December 31, 1999 and 1998,  book  overdrafts of $22,245,000  and $15,710,000
were included in accounts  payable.  Non-cash  transactions in 1999 included the
issuance  of  $6,682,000  of Company  common  stock for the  Company's  Dividend
Reinvestment  Plan and the  assumption of $109 million in long-term debt as part
of the purchase of the Encogen partnership.

       The  following  provides  additional  information  concerning  cash  flow
activities:
<TABLE>
<CAPTION>
--------------------------------------------------------------- ------------ ------------ ------------
  (year ended December 31; dollars in thousands)                       1999         1998         1997
--------------------------------------------------------------- ------------ ------------ ------------
  Changes in certain current assets and current liabilities:
<S>                                                                <C>           <C>          <C>
      Accounts receivable                                          $(23,382)     $(29,042)     $ (4,488)
      Unbilled revenue                                                5,437        (3,909)        4,591
      Materials and supplies                                        (10,707)       (4,111)        3,316
      Prepayments and other                                          (1,832)       (2,175)        5,670
      Purchased gas liability                                       (28,208)       (6,368)      (34,966)
      Accounts payable                                               15,077        25,650        3,003
      Accrued expenses and other                                     18,169        (3,151)      (38,490)
 -------------------------------------------------------------- ------------ ------------ ------------
  Net change in certain current assets
    and current liabilities                                        $(25,446)     $(23,106)     $(61,364)
--------------------------------------------------------------- ------------ ------------ ------------
  Cash payments:
      Interest (net of capitalized interest)                       $153,093      $131,567     $119,810
      Income taxes                                                  $99,959      $119,664     $104,161
--------------------------------------------------------------- ------------ ------------ ------------
</TABLE>

NOTE 21.
         MERGER OF PUGET POWER AND WECO

       Included in  consolidated  results of operations for the month of January
1997 are the following  results of the  previously  separate  companies for that
period (Dollars in Thousands):
<TABLE>
<CAPTION>
                                                    MONTH ENDED
                                                  JANUARY 31, 1997
                                           PUGET POWER          WECO
                                       ---------------- -------------
<S>                                           <C>            <C>
  Revenues                                    $123,051       $60,486
  Net Income                                   $19,671        $9,378
  Common Dividends Declared                    $29,244            --
</TABLE>

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

                                       71
<PAGE>

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

NOTE 22.
         SEGMENT INFORMATION

       The Company primarily operates in one business segment, Regulated Utility
Operations.  The Company's regulated utility operation generates,  purchases and
sells electricity and purchases, transports and sells natural gas. The Company's
service  territory  covers  approximately  6,000  square  miles in the  state of
Washington.

       Principal  non-utility  lines of business include computer billing system
software,  real  estate  investment  and  development  and small  hydro-electric
project development. Reconciling items between segments are not material.

       In the third  quarter of 1999,  the Company sold the assets,  liabilities
and trade name of Homeguard  Security  Services,  Inc.,  its  wholly-owned  home
security  services  subsidiary  and  recorded a net gain of  approximately  $7.6
million.

       Financial data for business segments are as follows:
<TABLE>

  (dollars in thousands)
<CAPTION>
                                        Regulated
                       1999                Utility               Other                   Total
-----------------------------------------------------------------------------------------------
<S>                                     <C>                    <C>                  <C>
  Revenues                              $2,043,500             $23,130              $2,066,630
  Depreciation & Amortization              175,610                 100                 175,710
  Federal Income Tax                       110,026                (862)                109,164
  Operating Income                         309,005               1,127                 310,132
  Interest Charges, net of AFUDC           150,384                  --                 150,384
  Net Income                               174,914              10,653                 185,567
  Total Assets                           4,999,020             146,586               5,145,606
</TABLE>
<TABLE>
<CAPTION>

                                         Regulated
                       1998                Utility               Other                   Total
-----------------------------------------------------------------------------------------------
<S>                                     <C>                    <C>                  <C>
  Revenues                              $1,891,759             $32,097              $1,923,856
  Depreciation & Amortization              165,491                  96                 165,587
  Federal Income Tax                       106,967              (1,153)                105,814
  Operating Income                         292,337               2,761                 295,098
  Interest Charges, net of AFUDC           138,561                 107                 138,668
  Net Income                               170,435                (823)                169,612
  Total Assets                           4,596,893             112,794               4,709,687
-----------------------------------------------------------------------------------------------
</TABLE>


                                       72
<PAGE>
<TABLE>
<CAPTION>
                                         Regulated
                       1997                Utility               Other                   Total
-----------------------------------------------------------------------------------------------
<S>                                     <C>                    <C>                  <C>
  Revenues                              $1,640,871             $40,657              $1,681,528
  Depreciation & Amortization              161,402                 463                 161,865
  Federal Income Tax                        34,230              10,686                  44,916
  Operating Income                         215,126              (4,488)                210,638
  Interest Charges, net of AFUDC           117,258               1,080                 118,338
  Net Income                               123,872                (796)                123,076
  Total Assets                           4,396,832              96,474               4,493,306
-----------------------------------------------------------------------------------------------
</TABLE>

SCHEDULE II.
         VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<TABLE>
<CAPTION>

  (dollars in thousands)
                                                                    ADDITIONS
                                                 BALANCE AT         CHARGED TO                          BALANCE
                                                 BEGINNING          COSTS AND                           AT END
                                                 OF PERIOD          EXPENSES          DEDUCTIONS        OF PERIOD
                                               ------------------ ----------------- ----------------- ----------------
----------------------------------------------
  YEAR ENDED DECEMBER 31, 1999
----------------------------------------------
  <S>                                                       <C>               <C>               <C>              <C>
Accounts deducted from assets on balance sheet:
    Allowance for doubtful
      accounts receivable                                 $1,020            $6,885            $6,402           $1,503
    Gas transportation contracts reserve                  $4,611            $5,598            $8,429           $1,780

---------------------------------------------- ------------------ ----------------- ----------------- ----------------
  YEAR ENDED DECEMBER 31, 1998
----------------------------------------------
  Accounts deducted from assets on balance sheet:
    Allowance for doubtful
      accounts receivable                                  $ 971            $5,905            $5,856           $1,020
    Gas transportation contracts reserve                  $6,527                --            $1,916           $4,611
---------------------------------------------- ------------------ ----------------- ----------------- ----------------
  YEAR ENDED DECEMBER 31, 1997
----------------------------------------------
  Accounts deducted from assets on balance sheet:
    Allowance for doubtful
      accounts receivable (1)                             $1,700            $5,080            $5,809            $ 971
    Gas transportation contracts reserve                  $8,762                --            $2,235           $6,527
</TABLE>


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


                                       73
<PAGE>

EXHIBIT INDEX

     Certain of the following exhibits are filed herewith.  Certain other of the
following  exhibits  have  heretofore  been  filed with the  Commission  and are
incorporated herein by reference.

     2.1 Agreement and Plan of Merger dated as of October 18, 1995, among the
Registrant,  Washington  Energy  Company and  Washington  Natural  Gas  Company.
(Exhibit 2.1 to Registration No. 333-617)

     3-a Restated Articles of Incorporation of the Company. (Included as Annex F
to the Joint Proxy Statement/Prospectus filed February 1, 1996, Registration No.
333-617)

     3-b  Restated  Bylaws of the  Company.  (Exhibit 3 to  Company's  Quarterly
Report on Form 10-Q for the quarter  ended June 30,  1997,  Commission  File No.
1-4393)

     4.1 Fortieth through  Seventy-seventh  Supplemental Indentures defining the
rights of the holders of the Company's  First  Mortgage  Bonds.  (Exhibit 2-d to
Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347;  Exhibits 2-e
through  and  including  2-k  to  Registration  No.  2-60200;   Exhibit  4-h  to
Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No. 2-60200;
Exhibits 2-m to Registration No. 2-37645;  Exhibit 2-o through and including 2-s
to Registration No. 2-60200;  Exhibit 5-b to Registration  No. 2-62883;  Exhibit
2-h to Registration  No. 2-65831;  Exhibit (4)-j-1 to Registration  No. 2-72061;
Exhibit (4)-a to  Registration  No.  2-91516;  Exhibit (4)-b to Annual Report on
Form 10-K for the fiscal  year ended  December  31,  1985,  Commission  File No.
1-4393;  Exhibits  (4)(a) and (4)(b) to  Company's  Current  Report on Form 8-K,
dated April 22,  1986;  Exhibit (4)a to  Company's  Current  Report on Form 8-K,
dated  September 5, 1986;  Exhibit (4)-b to Company's  Quarterly  Report on Form
10-Q for the quarter  ended  September  30, 1986,  Commission  File No.  1-4393;
Exhibit (4)-c to Registration  No.  33-18506;  Exhibit (4)-b to Annual Report on
Form 10-K for the fiscal  year ended  December  31,  1989,  Commission  File No.
1-4393;  Exhibit  (4)-b to Annual  Report on Form 10-K for the fiscal year ended
December 31,  1990,  Commission  File No.  1-4393;  Exhibits  (4)-b and (4)-c to
Registration No. 33-45916;  Exhibit (4)-c to Registration No. 33-50788;  Exhibit
(4)-a to Registration  No.  33-53056;  Exhibit 4.3 to Registration No. 33-63278;
Exhibit 4.25 to Registration No.  333-41181;  and Exhibit 4.27 to Current Report
on Form 8-K dated March 5, 1999.)

     4.2 Rights Agreement, dated as of January 15, 1991, between the Company and
The Chase  Manhattan Bank,  N.A., as Rights Agent.  (Exhibit 2.1 to Registration
Statement on Form 8-A filed on January 17, 1991, Commission File No. 1-4393)

     4.3 Amendment  No. 1 dated as of August 30, 1991,  to the Rights  Agreement
dated as of January 15, 1991,  between the  Registrant  and the Bank of New York
(as successor to The Chase Manhattan Bank, N.A.), as Rights Agent.  (Exhibit 2.1
to Registration Statement on Form 8 filed on August 30, 1991)

     4.4 Amendment  No. 2 dated as of October 18, 1995, to the Rights  Agreement
dated as of January 15, 1991,  between the  Registrant  and The Bank of New York
(as successor to The Chase Manhattan Bank, N.A.), as Rights Agent. (Exhibit 1 to
Registration Statement on Form 8-A/A filed on October 27, 1995)

     4.5 Pledge  Agreement  dated  August 1, 1991,  between  the Company and The
First National Bank of Chicago, as Trustee. (Exhibit
(4)-j to Registration No. 33-45916)

     4.6 Loan  Agreement  dated  August 1, 1991,  between  the City of  Forsyth,
Rosebud  County,  Montana and the Company.  (Exhibit (4)-k to  Registration  No.
33-45916)

     4.7 Statement of Relative Rights and Preferences for the Preference  Stock,
Series R, $50 Par Value.  (Exhibit  1.5 to  Registration  Statement  on Form 8-A
filed February 14, 1994, Commission File No. 1-4393)

     4.8  Statement  of Relative  Rights and  Preferences  for the 7 3/4% Series
Preferred  Stock  Cumulative,  $100  Par  Value.  (Exhibit  1.6 to  Registration
Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)

     4.9 Pledge Agreement, dated as of March 1, 1992, by and between the Company
and Chemical Bank relating to a series of first mortgage bonds. (Exhibit 4.15 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1993,
Commission File No. 1-4393)

     4.10  Pledge  Agreement,  dated as of April 1,  1993,  by and  between  the
Company and The First  National  Bank of Chicago,  relating to a series of first
mortgage bonds.  (Exhibit 4.16 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, Commission File No. 1-4393)

     4.11 Form of Statement of Relative Rights and Preferences for the Series II
Cumulative  Preferred  Stock,  $25 Par Value  (included  as Annex F to the Joint
Proxy Statement/Prospectus filed February 1, 1996).

     4.12  Indenture of First  Mortgage  dated as of April 1, 1957 (Exhibit 4-B,
Registration No. 2-14307).

     4.13 First Supplemental  Indenture dated as of October 1, 1959 (Exhibit 4-D
to Registration No. 2-17876).

     4.14 Sixth  Supplemental  Indenture  dated as of August 1, 1966 (Exhibit to
Form 8-K for month of August 1966, File No. 0-951).

     4.15  Sixteenth  Supplemental  Indenture  dated as of June 1, 1977 (Exhibit
6-05 to Registration No. 2-60352).

     4.16 Seventeenth Supplemental Indenture dated as of August 9, 1978 (Exhibit
5-K.18 to Registration No. 2-64428).

     4.17  Twenty-second  Supplemental  Indenture  dated  as of  July  15,  1986
(Exhibit  4-B.20 to Form 10-K for the year ended  September  30, 1986,  File No.
0-951).

     4.18  Twenty-sixth  Supplemental  Indenture  dated as of  September 1, 1990
(Exhibit  4-B.19,  Form 10-K for the year ended  September  30,  1990,  File No.
0-951).


     4.19  Twenty-seventh  Supplemental  Indenture dated as of September 1, 1990
(Exhibit  4-B.20,  Form 10-K for the year ended  September  30,  1988,  File No.
0-951).

     4.20 Twenty-eighth Supplemental Indenture dated as of July 31, 1991
(Exhibit 4-A, Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).

     4.21 Twenty-ninth  Supplemental Indenture dated as of June 1, 1993 (Exhibit
4-A to Registration No. 33-49599).

     4.22  Thirtieth   Supplemental  Indenture  dated  as  of  August  15,  1995
(incorporated  herein by  reference  to Exhibit  4-A of  Washington  Natural Gas
Company's S-3 Registration Statement, Registration No. 33-61859).

     10.1 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 1 of Chelan County, Washington and the Company, relating to
the Rock Island Project. (Exhibit 13-b to Registration No. 2-24262)

     10.2 First Amendment,  dated as of October 4, 1961, to Power Sales Contract
between  Public  Utility  District No. 1 of Chelan  County,  Washington  and the
Company,  relating to the Rocky Reach Project. (Exhibit 13-d to Registration No.
2-24252)

     10.3 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 1 of Chelan County, Washington and the Company, relating to
the Rocky Reach Project. (Exhibit 13-e to Registration No. 2-24252)

     10.4 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 2 of Grant County,  Washington and the Company, relating to
the Priest Rapids Development. (Exhibit 13-j to Registration No. 2-24252)

     10.5 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 2 of Grant County,  Washington and the Company, relating to
the Wanapum Development. (Exhibit 13-n to Registration No. 2-24252)

     10.6 First  Amendment,  dated  February 9, 1965,  to Power  Sales  Contract
between  Public  Utility  District No. 1 of Douglas  County,  Washington and the
Company,  relating to the Wells  Development.  (Exhibit 13-p to Registration No.
2-24252)

     10.7 First  Amendment,  executed as of February 9, 1965, to Reserved  Share
Power Sales Contract  between Public Utility  District No. 1 of Douglas  County,
Washington and the Company, relating to the Wells Development.  (Exhibit 13-r to
Registration No. 2-24252)

     10.8 Assignment and Agreement,  dated as of August 13, 1964, between Public
Utility District No. 1 of Douglas County,  Washington and the Company,  relating
to the Wells Development. (Exhibit 13-u to Registration No. 2-24252)

     10.9 Pacific Northwest Coordination Agreement, executed as of September 15,
1964,  among the United  States of  America,  the  Company and most of the other
major  electrical  utilities  in  the  Pacific  Northwest.   (Exhibit  13-gg  to
Registration No. 2-24252)

     10.10 Contract dated November 14, 1957, between Public Utility District No.
1 of Chelan  County,  Washington  and the  Company,  relating to the Rocky Reach
Project. (Exhibit 4-1-a to Registration No. 2-13979)

     10.11 Power Sales Contract,  dated as of November 14, 1957,  between Public
Utility District No. 1 of Chelan County, Washington and the Company, relating to
the Rocky Reach Project. (Exhibit 4-c-1 to Registration No. 2-13979)

     10.12 Power Sales  Contract,  dated May 21, 1956,  between  Public  Utility
District No. 2 of Grant  County,  Washington  and the  Company,  relating to the
Priest Rapids Project. (Exhibit 4-d to Registration No. 2-13347)

     10.13 First  Amendment to Power Sales  Contract dated as of August 5, 1958,
between  the  Company  and  Public  Utility  District  No.  2 of  Grant  County,
Washington,  relating  to  the  Priest  Rapids  Development.  (Exhibit  13-h  to
Registration No. 2-15618)

     10.14 Power Sales  Contract  dated June 22, 1959,  between  Public  Utility
District No. 2 of Grant  County,  Washington  and the  Company,  relating to the
Wanapum Development. (Exhibit 13-j to Registration No. 2-15618)

     10.15  Reserve  Share Power Sales  Contract  dated June 22,  1959,  between
Public  Utility  District  No. 2 of Grant  County,  Washington  and the Company,
relating  to the  Priest  Rapids  Project.  (Exhibit  13-k to  Registration  No.
2-15618)

     10.16 Agreement to Amend Power Sales Contracts dated July 30, 1963, between
Public  Utility  District  No. 2 of Grant  County,  Washington  and the Company,
relating to the Wanapum Development. (Exhibit 13-1 to Registration No. 2-21824)

     10.17 Power Sales  Contract  executed as of  September  18,  1963,  between
Public  Utility  District No. 1 of Douglas  County,  Washington and the Company,
relating to the Wells Development (Exhibit 13-r to Registration No. 2-21824)

     10.18  Reserved  Share Power Sales  Contract  executed as of September  18,
1963,  between Public Utility  District No. 1 of Douglas County,  Washington and
the Company,  relating to the Wells  Development.  (Exhibit 13-s to Registration
No. 2-21824)

     10.19 Exchange Agreement dated April 12, 1963, between the United States of
America,  Department  of the  Interior,  acting  through  the  Bonneville  Power
Administration  and  Washington  Public  Power  Supply  System and the  Company,
relating to the Hanford Project. (Exhibit 13-u to Registration 2-21824)

     10.20 Replacement Power Sales Contract dated April 12, 1963, between the
United  States of  America,  Department  of the  Interior,  acting  through  the
Bonneville Power Administrator and the Company, relating to the Hanford Project.
(Exhibit 13-v to Registration No. 2-21824)

     10.21 Contract  covering  undivided  interest in ownership and operation of
Centralia  Thermal Plant,  dated May 15, 1969.  (Exhibit 5-b to Registration No.
2-3765)

     10.22  Construction  and  Ownership  Agreement  dated as of July 30,  1971,
between The Montana Power Company and the Company.  (Exhibit 5-b to Registration
No. 2-45702)

     10.23  Operation  and  Maintenance  Agreement  dated as of July  30,  1971,
between The Montana Power Company and the Company.  (Exhibit 5-c to Registration
No. 2-45702)

     10.24 Coal Supply  Agreement,  dated as of July 30, 1971, among The Montana
Power  Company,  the  Company  and  Western  Energy  Company.  (Exhibit  5-d  to
Registration No. 2-45702)

     10.25 Power Purchase  Agreement with Washington  Public Power Supply System
and the Bonneville Power  Administration dated February 6, 1973. (Exhibit 5-e to
Registration No. 2-49029)

     10.26 Ownership Agreement among the Company, Washington Public Power Supply
System and others dated September 17, 1973.  (Exhibit 5-a-29 to Registration No.
2-60200)

     10.27 Contract dated June 19, 1974,  between the Company and P.U.D No. 1 of
Chelan County. (Exhibit D to Form 8-K dated July 5, 1974)

     10.28  Exchange  Agreement  executed  August 13,  1964,  between the United
States of America,  Columbia Storage Power Exchange and the Company, relating to
Canadian Entitlement. (Exhibit 13-ff to Registration No. 2-24252)

     10.29 Loan  Agreement  dated as of December  1, 1980 and related  documents
pertaining to Whitehorn turbine construction trust financing.  (Exhibit 10.52 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1980,
Commission File No. 1-4393)

     10.30  Letter  Agreement  dated  March 31,  1980,  between  the Company and
Manufacturers  Hanover Leasing  Corporation.  (Exhibit b-8 to  Registration  No.
2-68498)

     10.31 Coal Supply Agreement for Colstrip 3 and 4, dated as of July 2, 1980;
Amendment No. 1 to Coal Supply  Agreement,  dated as of July 10, 1981,  and Coal
Transportation  Agreement dated as of July 10, 1981.  (Exhibit 20-a to Quarterly
Report on Form 10-Q for the quarter ended  September 30, 1981,  Commission  File
No. 1-4393)

     10.32  Residential  Purchase and Sale Agreement between the Company and the
Bonneville Power Administration,  effective as of October 1, 1981. (Exhibit 20-b
to  Quarterly  Report on Form 10-Q for the quarter  ended  September  30,  1981,
Commission File No. 1-4393)

     10.33 Letter of Agreement to Participate in Licensing of Creston Generating
Station,  dated  September 30, 1981.  (Exhibit 20-c to Quarterly  Report on Form
10-Q for the quarter ended September 30, 1981, Commission File No. 1-4393)

     10.34 Power sales  contract  dated  August 27, 1982 between the Company and
Bonneville Power Administration.  (Exhibit 10-a to Quarterly Report on Form 10-Q
for the quarter ended September 30, 1982, Commission File No. 1-4393)

     10.35 Agreement executed as of April 17, 1984, between the United States of
America,  Department  of the  Interior,  acting  through  the  Bonneville  Power
Administration,  and wholesale  customers  relating to extension energy from the
Hanford Atomic Power Plant No. 1. (Exhibit (10)-47 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1984, Commission File No. 1-4393)

     10.36  Agreement for the  Assignment  of Output from the Centralia  Thermal
Project,  dated as of April 14,  1983,  between the  Company and Public  Utility
District No. 1 of Grays Harbor.  (Exhibit  (10)-48 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1984, Commission File No. 1-4393)

     10.37  Settlement  Agreement and Covenant Not to Sue executed by the United
States  Department  of  Energy  acting  by  and  through  the  Bonneville  Power
Administration  and the Company dated  September 17, 1985.  (Exhibit  (10)-49 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1985,
Commission File No. 1-4393)

     10.38  Agreement to Dismiss Claims and Covenant Not to Sue dated  September
17, 1985 between Washington Public Power Supply System and the Company. (Exhibit
(10)-50 to Annual  Report on Form 10-K for the fiscal  year ended  December  31,
1985, Commission File No. 1-4393)

     10.39  Irrevocable  Offer of Washington  Public Power Supply System Nuclear
Project  No.  3  Capability  for  Acquisition  executed  by the  Company,  dated
September 17, 1985.  (Exhibit A of Exhibit (10)-50 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1985, Commission File No. 1-4393)

     10.40 Settlement Exchange Agreement  ("Bonneville Exchange Power Contract")
executed  by the United  States of America  Department  of Energy  acting by and
through the Bonneville Power Administration and the Company, dated September 17,
1985. (Exhibit B of Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1985, Commission File No. 1-4393)

     10.41 Settlement  Agreement and Covenant Not to Sue between the Company and
Northern  Wasco  County  People's  Utility  District,  dated  October 16,  1985.
(Exhibit  (10)-53  to  Annual  Report  on Form 10-K for the  fiscal  year  ended
December 31, 1985, Commission File No. 1-4393)

     10.42 Settlement  Agreement and Covenant Not to Sue between the Company and
Tillamook People's Utility District, dated October 16, 1985. (Exhibit (10)-54 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1985,
Commission File No. 1-4393)

     10.43 Settlement  Agreement and Covenent Not to Sue between the Company and
Clatskanie People's Utility District, dated September 30, 1985. (Exhibit (10)-55
to Annual  Report on Form 10-K for the fiscal  year  ended  December  31,  1985,
Commission File No.1-4393)

     10.44  Stipulation  and  Settlement   Agreement  between  the  Company  and
Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October 31, 1986.
(Exhibit  (10)-55  to  Annual  Report  on Form 10-K for the  fiscal  year  ended
December 31, 1986, Commission File No. 1-4393)

     10.45  Transmission  Agreement dated April 17, 1981, between the Bonneville
Power  Administration  and the Company (Colstrip  Project).  (Exhibit (10)-55 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1987,
Commission File No. 1-4393)

     10.46  Transmission  Agreement dated April 17, 1981, between the Bonneville
Power  Administration  and Montana Intertie Users (Colstrip  Project).  (Exhibit
(10)-56 to Annual  Report on Form 10-K for the fiscal  year ended  December  31,
1987, Commission File No.1-4393)

     10.47 Ownership and Operation  Agreement  dated as of May 6, 1981,  between
the  Company  and  other  Owners of the  Colstrip  Project  (Colstrip  3 and 4).
(Exhibit  (10)-57  to  Annual  Report  on Form 10-K for the  fiscal  year  ended
December 31, 1987, Commission File No. 1-4393)

     10.48  Colstrip  Project  Transmission  Agreement  dated as of May 6, 1981,
between the  Company and Owners of the  Colstrip  Project.  (Exhibit  (10)-58 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1987,
Commission File No. 1-4393)

     10.49  Common  Facilities  Agreement  dated as of May 6, 1981,  between the
Company and Owners of Colstrip 1 and 2, and 3 and 4. (Exhibit  (10)-59 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File
No. 1-4393)

     10.50  Agreement  for the  Purchase of Power dated as of October 29,  1984,
between  South  Fork  II,  Inc.  and the  Company  (Weeks  Falls  Hydro-electric
Project).  (Exhibit  (10)-60 to Annual  Report on Form 10-K for the fiscal  year
ended December 31, 1987, Commission File No. 1-4393)

     10.51  Agreement  for the  Purchase of Power dated as of October 29,  1984,
between South Fork  Resources,  Inc. and the Company (Twin Falls  Hydro-electric
Project).  (Exhibit  (10)-61 to Annual  Report on Form 10-K for the fiscal  year
ended December 31, 1987, Commission File No. 1-4393)

     10.52  Agreement  for Firm  Purchase  Power  dated as of  January  4, 1988,
between  the  City  of  Spokane,  Washington  and  the  Company  (Spokane  Waste
Combustion  Project).  (Exhibit  (10)-62  to Annual  Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)

     10.53 Agreement for Evaluating, Planning and Licensing dated as of February
21, 1985 and  Agreement  for  Purchase  of Power  dated as of February  21, 1985
between   Pacific   Hydropower   Associates   and  the  Company   (Koma  Kulshan
Hydro-electric Project).  (Exhibit (10)-63 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)

     10.54 Power Sales  Agreement  dated as of August 1, 1986,  between  Pacific
Power & Light Company  ("PacifiCorp")and the Company. (Exhibit (10)-64 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File
No. 1-4393)

     10.55  Agreement for Purchase and Sale of Firm Capacity and Energy dated as
of August 1, 1986 between The Washington Water Power Company  ("Avista") and the
Company.  (Exhibit  (10)-65 to Annual  Report on Form 10-K for the  fiscal  year
ended December 31, 1987, Commission File No. 1-4393)

     10.56 Amendment  dated as of June 1, 1968, to Power Sales Contract  between
Public  Utility  District  No. 1 of Chelan  County,  Washington  and the Company
(Rocky Reach  Project).  (Exhibit  (10)-66 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)

     10.57 Coal  Supply  Agreement  dated as of October  30,  1970,  between the
Washington  Irrigation & Development Company and the Company and other Owners of
the Centralia Thermal Project (Centralia Generating Plant).  (Exhibit (10)-67 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1987,
Commission File No. 1-4393)

     10.58 Interruptible Natural Gas Service Agreement dated as of May 14, 1980,
between Cascade Natural Gas  Corporation and the Company  (Whitehorn  Combustion
Turbine).  (Exhibit  (10)-68 to Annual  Report on Form 10-K for the fiscal  year
ended December 31, 1987, Commission File No. 1-4393)

     10.59  Interruptible  Natural Gas Service Agreement dated as of January 31,
1983,  between  Cascade  Natural  Gas  Corporation  and  the  Company  (Fredonia
Generating  Station).  (Exhibit  (10)-69  to Annual  Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)

     10.60  Interruptible  Gas Service  Agreement  dated May 14,  1981,  between
Washington Natural Gas Company and the Company (Fredrickson Generating Station).
(Exhibit  (10)-70  to  Annual  Report  on Form 10-K for the  fiscal  year  ended
December 31, 1987, Commission File No. 1-4393)

     10.61  Settlement  Agreement  dated April 24, 1987,  between Public Utility
District No. 1 of Chelan County,  the National  Marine  Fisheries  Service,  the
State of Washington,  the State of Oregon, the Confederated  Tribes and Bands of
the  Yakima  Indian  Nation,   Colville  Indian  Reservation,   Umatilla  Indian
Reservation,  the  National  Wildlife  Federation  and the Company  (Rock Island
Project).  (Exhibit  (10)-71 to Annual  Report on Form 10-K for the fiscal  year
ended December 31, 1987, Commission File No. 1-4393)

     10.62  Amendment  No. 2 dated as of September 1, 1981,  and Amendment No. 3
dated  September  14, 1987,  to Coal Supply  Agreement  between  Western  Energy
Company  and the  Company  and the other  Owners of  Colstrip 3 and 4.  (Exhibit
(10)-72 to Annual  Report on Form 10-K for the fiscal  year ended  December  31,
1987, Commission File No. 1-4393)

     10.63  Amendatory  Agreement  No. 1 dated August 27, 1982,  and  Amendatory
Agreement No. 2 dated August 27, 1982, to the Power Sales  Contract  between the
Company and the Bonneville Power  Administration dated August 27, 1982. (Exhibit
(10)-73 to Annual  Report on Form 10-K for the fiscal  year ended  December  31,
1987, Commission File No. 1-4393)

     10.64  Transmission  Agreement  dated as of December 30, 1987,  between the
Bonneville Power Administration and the Company (Rock Island Project).  (Exhibit
(10)-74 to Annual  Report on Form 10-K for the fiscal  year ended  December  31,
1988, Commission File No.1-4393)

     10.65  Agreement for Purchase and Sale of Firm Capacity and Energy  between
The Washington  Water Power Company and the Company dated as of January 1, 1988.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31,
1988, Commission File No. 1-4393)

     10.66 Amendment dated as of August 10, 1988, to Agreement for Firm Purchase
Power dated as of January 4, 1988,  between the City of Spokane,  Washington and
the Company (Spokane Waste Combustion Project).(Exhibit (10)-76 to Annual Report
on Form 10-K for the fiscal year ended  December 31, 1988,  Commission  File No.
1-4393)

     10.67  Agreement for Firm Power  Purchase  dated October 24, 1988,  between
Northern Wasco People's  Utility  District and the Company (The Dalles Dam North
Fishway).  (Exhibit  (10)-77 to Annual  Report on Form 10-K for the fiscal  year
ended December 31, 1988, Commission File No. 1-4393)

     10.68  Agreement  for the  Purchase of Power dated as of October 27,  1988,
between  Pacific Power & Light Company  (PacifiCorp)  and the Company.  (Exhibit
(10)-78 to Annual  Report on Form 10-K for the fiscal  year ended  December  31,
1988, Commission File No. 1-4393)

     10.69  Agreement  for Sale and  Exchange of Firm Power dated as of November
23, 1988, between the Bonneville Power Administration and the Company.  (Exhibit
(10)-79 to Annual  Report on Form 10-K for the fiscal  year ended  December  31,
1988, Commission File No.1-4393)

     10.70  Agreement  for Firm Power  Purchase,  dated as of February 24, 1989,
between Sumas Energy, Inc. and the Company.  (Exhibit (10)-1 to Quarterly Report
on Form 10-Q for the quarter ended March 31, 1989, Commission File No. 1-4393)

     10.71  Settlement  Agreement,  dated as of April 27, 1989,  between  Public
Utility District No. 1 of Douglas County, Washington,  Portland General Electric
Company ("Enron"), PacifiCorp, The Washington Water Power Company ("Avista") and
the  Company.  (Exhibit  (10)-1 to Quarterly  Report on Form 10-Q quarter  ended
September 30, 1989, Commission File No. 1-4393)

     10.72 Agreement for Firm Power Purchase (Thermal Project), dated as of June
29, 1989,  between San Juan Energy Company and the Company.  (Exhibit  (10)-2 to
Quarterly  Report  on Form  10-Q  for the  quarter  ended  September  30,  1989,
Commission File No. 1-4393)

     10.73 Agreement for  Verification  of Transfer,  Assignment and Assumption,
dated as of September  15, 1989,  between San Juan Energy  Company,  March Point
Cogeneration  Company and the Company.  (Exhibit  (10)-3 to Quarterly  Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)

     10.74 Power Sales  Agreement  between  The  Montana  Power  Company and the
Company,  dated as of October 1, 1989.  (Exhibit  (10)-4 to Quarterly  Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)

     10.75  Conservation  Power Sales  Agreement  dated as of December 11, 1989,
between  Public  Utility  District  No. 1 of  Snohomish  County and the Company.
(Exhibit  (10)-87  to  Annual  Report  on Form 10-K for the  fiscal  year  ended
December 31, 1989, Commission File No. 1-4393)

     10.76 Memorandum of Understanding dated as of January 24, 1990, between the
Bonneville Power  Administration  and The Washington Public Power Supply System,
Portland  General  Electric  Company  ("Enron"),  Pacific  Power & Light Company
("PacifiCorp"),  The Montana Power Company, and the Company. (Exhibit (10)-88 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1989,
Commission File No. 1-4393)

     10.77  Amendment  No. 1 to Agreement  for the  Assignment of Power from the
Centralia  Thermal  Project dated as of January 1, 1990,  between Public Utility
District  No. 1 of Grays Harbor  County,  Washington  and the Company.  (Exhibit
(10)-89 to Annual  Report on Form 10-K for the fiscal  year ended  December  31,
1990, Commission File No. 1-4393)

     10.78 Preliminary Materials and Equipment Acquisition Agreement dated as of
February  9, 1990,  between  Northwest  Pipeline  Corporation  and the  Company.
(Exhibit  (10)-90  to  Annual  Report  on Form 10-K for the  fiscal  year  ended
December 31, 1990, Commission File No. 1-4393)

     10.79 Amendment No. 1 to the Colstrip Project Transmission  Agreement dated
as of February 14, 1990,  among the Montana Power Company,  The Washington Water
Power  Company   ("Avista"),   Portland  General  Electric  Company   ("Enron"),
PacifiCorp and the Company.  (Exhibit  (10)-91 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1990, Commission File No. 1-4393)

     10.80  Settlement  Agreement  dated as of February 27,  1990,  among United
States of America  Department  of Energy  acting by and through  the  Bonneville
Power  Administration,  the  Washington  Public  Power  Supply  System,  and the
Company.  (Exhibit  (10)-92 to Annual  Report on Form 10-K for the  fiscal  year
ended December 31, 1990, Commission File No. 1-4393)

     10.81 Amendment No. 1 to the Fifteen-Year Power Sales Agreement dated as of
April 18, 1990, between  Pacificorp and the Company.  (Exhibit (10)-93 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File
No. 1-4393)

     10.82  Settlement  Agreement  dated as of  October 1,  1990,  among  Public
Utility District No. 1 of Douglas County, Washington, the Company, Pacific Power
and Light Company ("PacifiCorp"), The Washington Water Power Company ("Avista"),
Portland  General  Electric  Company  ("Enron"),  the  Washington  Department of
Fisheries,  the Washington Department of Wildlife, the Oregon Department of Fish
and Wildlife,  the National Marine Fisheries Service, the U.S. Fish and Wildlife
Service,  the  Confederated  Tribes and Bands of the Yakima Indian  Nation,  the
Confederated Tribes of the Umatilla Reservation,  and the Confederated Tribes of
the Colville Reservation. (Exhibit (10)-95 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)

     10.83  Agreement  for Firm  Power  Purchase  dated July 23,  1990,  between
Trans-Pacific  Geothermal  Corporation,  a Nevada corporation,  and the Company.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31,
1991, Commission File No. 1-4393)

     10.84  Agreement  for Firm  Power  Purchase  dated July 18,  1990,  between
Wheelabrator Pierce,  Inc., a Delaware  corporation,  and the Company.  (Exhibit
(10)-2 to  Quarterly  Report on Form 10-Q for the quarter  ended March 31, 1991,
Commission File No. 1-4393)

     10.85  Agreement for Firm Power Purchase  (Thermal  Project) dated December
27,  1990,  among  March  Point  Cogeneration   Company,  a  California  general
partnership  comprising  San Juan  Energy  Company,  a  California  corporation;
Texas-Anacortes  Cogeneration Company, a Delaware corporation;  and the Company.
(Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended March 31,
1991, Commission File No. 1-4393)

     10.86  Agreement  for Firm Power  Purchase  dated March 20,  1991,  between
Tenaska  Washington,  Inc., a Delaware  corporation,  and the Company.  (Exhibit
(10)-1 to  Quarterly  Report on Form 10-Q for the quarter  ended June 30,  1991,
Commission File No. 1-4393)

     10.87 Letter Agreement dated April 25, 1991, between Sumas Energy, Inc. and
the Company, to amend the Agreement for Firm Power Purchase dated as of February
24, 1989. (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended
June 30, 1991, Commission File No. 1-4393)

     10.88  Amendment  dated June 7, 1991, to Letter  Agreement  dated April 25,
1991, between Sumas Energy,  Inc. and the Company.  (Exhibit (10)-3 to Quarterly
Report on Form 10-Q for the quarter  ended June 30,  1991,  Commission  File No.
1-4393)

     10.89  Amendatory  Agreement  No. 3, dated  August 1, 1991,  to the Pacific
Northwest Coordination Agreement,  executed September 15, 1964, among the United
States of America,  the Company and most of the other major electrical utilities
in the Pacific  Northwest.  (Exhibit (10)-4 to Quarterly Report on Form 10-Q for
the quarter ended June 30, 1991, Commission File No. 1-4393)

     10.90  Agreement  between the 40 parties to the Western  Systems Power Pool
(the Company being one party) dated July 27, 1991.  (Exhibit (10)-2 to Quarterly
Report on Form 10-Q for the quarter ended  September 30, 1991,  Commission  File
No. 1-4393)

     10.91  Memorandum of  Understanding  between the Company and the Bonneville
Power  Administration  dated  September 18, 1991.  (Exhibit  (10)-3 to Quarterly
Report on Form 10-Q for the quarter ended  September 30, 1991,  Commission  File
No. 1-4393)

     10.92  Amendment of Seasonal  Exchange  Agreement,  dated December 4, 1991,
between Pacific Gas and Electric Company and the Company.  (Exhibit  (10)-107 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1991,
Commission File No. 1-4393)

     10.93 Capacity and Energy Exchange Agreement,  dated as of October 4, 1991,
between Pacific Gas and Electric Company and the Company.  (Exhibit  (10)-108 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1991,
Commission File No. 1-4393)

     10.94 Intertie and Network Transmission  Agreement,  dated as of October 4,
1991, between Bonneville Power Administration and the Company. (Exhibit (10)-109
to Annual  Report on Form 10-K for the fiscal  year  ended  December  31,  1991,
Commission File No. 1-4393)

     10.95  Amendatory  Agreement  No. 4,  executed  June 17, 1991, to the Power
Sales   Agreement   dated  August  27,  1982,   between  the  Bonneville   Power
Administration and the Company.  (Exhibit (10)-110 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1991, Commission File No. 1-4393)

     10.96 Amendment to Agreement for Firm Power Purchase, dated as of September
30, 1991,  between  Sumas  Energy,  Inc. and the Company.  (Exhibit  (10)-112 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1991,
Commission File No. 1-4393)

     10.97 Centralia Fuel Supply Agreement, dated as of January 1, 1991, between
Pacificorp Electric Operations and the Company and other Owners of the Centralia
Steam-Electric Power Plant.  (Exhibit (10)-113 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1991, Commission File No. 1-4393)

     10.98  Agreement  for Firm Power  Purchase  dated August 10, 1992,  between
Pyrowaste  Corporation,  Puget Sound  Pyroenergy  Corporation  and the  Company.
(Exhibit  (10)-114  to  Annual  Report on Form 10-K for the  fiscal  year  ended
December 31, 1992, Commission File No. 1-4393)

     10.99  Guaranty  of  Ensearch  Corporation  in favor of the  Company  dated
December  15,  1992.  (Exhibit  (10)-120  to Annual  Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)

     10.100 Letter Agreement dated October 12, 1992,  between Tenaska Washington
Partners,  L.P.  and the Company  regarding  clarification  of issues  under the
Agreement for Firm Power  Purchase.  (Exhibit  (10)-121 to Annual Report on Form
10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)

     10.101  Consent and Agreement  dated October 12, 1992,  between the Company
and The Chase Manhattan Bank, N.A., as agent. (Exhibit (10)-122 to Annual Report
on Form 10-K for the fiscal year ended  December 31, 1992,  Commission  File No.
1-4393)

     10.102  Settlement  Agreement dated December 29, 1992,  between the Company
and the Bonneville  Power  Administration  (BPA) providing for power purchase by
BPA.  (Exhibit  (10)-123 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, Commission File No. 1-4393)

     10.103  Contract  with W.  S.  Weaver,  Executive  Vice  President  & Chief
Financial  Officer,  dated April 24, 1991.  (Exhibit  10.114 to Annual Report on
Form 10-K for the fiscal  year ended  December  31,  1993,  Commission  File No.
1-4393)

     10.104 General Transmission Agreement dated as of December 1, 1994, between
the  Bonneville  Power   Administration   and  the  Company  (BPA  Contract  No.
DE-MS79-94BP93947)  (Exhibit 10.115 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1994, Commission File No. 1-4393)

     10.105 PNW AC Intertie Capacity Ownership Agreement dated as of October 11,
1994 between the Bonneville Power  Administration  and the Company (BPA Contract
No.  DE-MS79-94BP94521)  (Exhibit  10.116 to Annual  Report on Form 10-K for the
fiscal year ended December 31, 1994, Commission File No. 1-4393)

     10.106 Power  Exchange  Agreement  dated as of September 27, 1995,  between
British Columbia Power Exchange Corporation and the Company.  (Exhibit 10.117 to
Annual  Report  on Form  10-K for the  fiscal  year  ended  December  31,  1996,
Commission File No. 1-4393)

     10.107  Contract  with W. S. Weaver,  Executive  Vice  President  and Chief
Financial Officer,  dated October 18, 1996.  (Exhibit 10.118 to Annual Report on
Form 10-K for the fiscal  year ended  December  31,  1996,  Commission  File No.
1-4393)

     10.108  Contract  with G.  B.  Swofford,  Senior  Vice  President  Customer
Operations,  dated  October 18, 1996.  (Exhibit  10.120 to Annual Report on Form
10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393)

     10.109 Service Agreement dated September 1, 1987 between Northwest Pipeline
Corporation and Washington Natural Gas Company for SGS-1 firm storage service at
Jackson  Prairie  (Exhibit 10-A Form 10-K for the year ended September 30, 1994,
File No. 11271).

     10.110  Service  Agreement  dated April 14, 1993 between  Questar  Pipeline
Corporation and Washington Natural Gas Company for FSS-1 firm storage service at
Clay Basin (Exhibit 10-B Form 10-K for the year ended  September 30, 1994,  File
No. 11271).

     10.111 Service  Agreement dated November 1, 1989,  with Northwest  Pipeline
Corporation covering  liquefaction storage gas service filed under cover of Form
SE dated December 27, 1989.

     10.112 Firm Transportation Service Agreement dated October 1, 1990, between
Northwest Pipeline  Corporation and Washington Natural Gas Company (Exhibit 10-D
Form 10-K for the year ended September 30, 1994, File No. 11271).

     10.113 Gas  Transportation  Service  Contract dated June 29, 1990,  between
Washington Natural Gas Company and Northwest Pipeline  Corporation  (Exhibit 4-A
Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).

     10.114 Gas  Transportation  Service  Contract dated July 31, 1991,  between
Washington Natural Gas Company and Northwest Pipeline  Corporation  (Exhibit 4-A
Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).

     10.115  Amendment to Gas  Transportation  Service  Contract  dated July 31,
1991, between Washington Natural Gas Company and Northwest Pipeline Corporation.
(Exhibit  10-E.2  Form 10-K for the year  ended  September  30,  1995,  File No.
11271).

     10.116 Gas  Transportation  Service  Contract dated July 15, 1994,  between
Washington  Natural Gas Company and  Northwest  Pipeline  Corporation.  (Exhibit
10-E.3 Form 10-K for the year ended September 30, 1995, File No. 11271).  10.117
Amendment to Gas Transportation  Service Contract dated August 15, 1994, between
Washington  Natural Gas Company and  Northwest  Pipeline  Corporation.  (Exhibit
10-E.4 Form 10-K for the year ended September 30, 1995, File No. 11271).  10.118
Interest Rate Swap Agreement dated September 27, 1989 between Thermal Resources,
Inc. and the First National Bank of Chicago,  filed under cover of Form SE dated
December 27, 1989,  (Exhibit  10-N,  Form 10-K for the year ended  September 30,
1994, File No. 1-11271).

     10.119 Firm  Transportation  Service  Agreement dated March 1, 1992 between
Northwest Pipeline Corporation and Washington Natural Gas Company (Exhibit 10-O,
Form 10-K for the year ended September 30, 1994, File No. 1-11271).

     10.120 Firm Transportation Service Agreement dated January 12, 1994 between
Northwest  Pipeline  Corporation  and  Washington  Natural  Gas Company for firm
transportation  service from Jackson  Prairie  (Exhibit 10-P,  Form 10-K for the
year ended September 30, 1994, File No. 1-11271).

     10.121 Firm Transportation Service Agreement dated January 12, 1994 between
Northwest  Pipeline  Corporation  and  Washington  Natural  Gas Company for firm
transportation  service from Jackson  Prairie  (Exhibit 10-Q,  Form 10-K for the
year ended September 30, 1994, File No. 1-11271).

     10.122 Firm Transportation Service Agreement dated January 12, 1994 between
Northwest  Pipeline  Corporation  and  Washington  Natural  Gas Company for firm
transportation  service from Plymouth, LNG (Exhibit 10-R, Form 10-K for the year
ended September 30, 1994, File No. 1-11271).

     10.123  Service  Agreement  dated  July 9,  1991  with  Northwest  Pipeline
Corporation  for  SGS-2F  Storage  Service  filed  under  cover of Form SE dated
December 23, 1991  (Exhibit  10-S,  Form 10-K for the year ended  September  30,
1994, File No. 1-11271).

     10.124 Firm Transportation Agreement dated October 27, 1993 between Pacific
Gas   Transmission   Company  and  Washington   Natural  Gas  Company  for  firm
transportation  service from  Kingsgate  (Exhibit  10-T,  Form 10-K for the year
ended September 30, 1994, File No. 1-11271).

     10.125 Firm Storage  Service  Agreement and Amendment  dated April 30, 1991
between  Questar  Pipeline  Company and Washington  Natural Gas Company for firm
storage  service at Clay Basin filed under cover of Form SE dated  December  23,
1991.

     10.126  Employment  agreement with R. R. Sonstelie,  Chairman of the Board,
dated  January 13, 1998.  (Exhibit  10.150 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1997, Commission File No. 1-4393)

     10.127 Change in control agreement with T. J. Hogan, dated August 17, 1995.
(Exhibit 10.152 to Annual Report on Form 10-K for the fiscal year ended December
31, 1997, Commission File No. 1-4393)

     10.128 Asset Purchase Agreement between PP&L Global,  Inc. and the Company.
(Exhibit 2a to Current Report on Form 8-K dated November 13, 1998)

     10.129 Employment  agreement with S. A. McKeon,  Vice President and General
Counsel,  dated May 27, 1997.  (Exhibit 10.152 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1998, Commission File No. 1-4393)

     10.130  Employment  agreement  with R. L. Hawley,  Vice President and Chief
Financial  Officer,  dated March 16, 1998.  (Exhibit  10.153 to Annual Report on
Form 10-K for the fiscal  year ended  December  31,  1998,  Commission  File No.
1-4393)

     *10.131  Separation agreement  with J. Quintana,  Vice  President  External
Affairs, dated December 29, 1999.

     *12-a  Statement  setting forth  computation of ratios of earnings to fixed
charges (1995 through 1999).

     *12-b Statement setting forth computation of ratios of earnings to combined
fixed charges and preferred stock dividends (1995 through 1999).

     *21 Subsidiaries of the Registrant.

     *23.1 Consent of PricewaterhouseCoopers LLP.

     *27 Financial Data Schedules.

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