============================================================================



                     SECURITIES AND EXCHANGE COMMISSION
                           Washington, D. C. 20549



                                  FORM 10-K



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

              For the fiscal year ended December 31, 1996

              OR

        / /   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
              THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)



                        -----------------------------
                        Commission File Number 1-4393
                        -----------------------------



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

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


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

                                (206) 454-6363
             (Registrant's telephone number, including area code)



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

                                             Name of each exchange
    Title of each class                      on which listed

    Common Stock, without par value,
      $10 stated value                          N. Y. S. E.
    Preference Share Purchase Rights            N. Y. S. E.
    7-7/8% Series Preferred Stock
      (Cumulative $25 Par Value)                N. Y. S. E.
    Adjustable Rate Cumulative Preferred
      Stock, Series B ($25 Par Value)           N. Y. S. E.
    7.45% Series II, Preferred Stock
      (Cumulative, $25 Par Value)               N. Y. S. E.
    8.50% Series III, Preferred Stock
      (Cumulative, $25 Par Value)               N. Y. S. E.

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

    Title of each class

    Preferred Stock (Cumulative; $100 Par Value)
    Preferred Stock (Cumulative; $25 Par Value)


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

                                                   Yes  /X/       No  / /

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

The aggregate market value of the voting stock held by non-affiliates of the
registrant at December 31, 1996 was approximately $1,523,552,000.

The number of shares of the registrant's common stock outstanding at
February 28, 1997 was 84,562,238.
                                      
                                      
                    Documents Incorporated by Reference

The Company's definitive proxy statement for its annual meeting of
shareholders on May 19, 1997, is incorporated by reference in Part III
hereof.
                                     INDEX

            Item                                                        Page
             No.                                                         No.
Part I
           1.   Business................................................  1
                The Company.............................................  1
                Industry Evolution and Merger with Washington Energy
                Company.................................................  2
                Regulation and Rates....................................  3
                Power Resources.........................................  4
                Construction Financing.................................. 10
                Environment............................................. 10
                Operating Statistics.................................... 13
                Executive Officers...................................... 15
           2.   Properties.............................................. 16
           3.   Legal Proceedings....................................... 16
           4.   Submission of Matters to a Vote of Security Holders..... 16
Part II
           5.   Market for Registrant's Common Equity and Related
                Stockholder Matters..................................... 16
           6.   Selected Financial Data................................. 17
           7.   Management's Discussion and Analysis of
                Financial Condition and Results of Operations........... 18
           8.   Financial Statements and Supplementary Data............. 27
           9.   Changes in and Disagreements with Accountants
                on Accounting and Financial Disclosure.................. 27
Part III
                (Incorporated by reference from the Company's
                definitive proxy statement issued in connection
                with the 1997 Annual Meeting of Shareholders)

          10.   Directors and Executive Officers of the Registrant
          11.   Executive Compensation
          12.   Security Ownership of Certain Beneficial
                Owners and Management
          13.   Certain Relationships and Related Transactions
Part IV
          14.   Exhibits, Financial Statement Schedules and
                Reports on Form 8-K..................................... 27
                Signatures.............................................. 28
                Exhibit Index........................................... 63

                           DEFINITIONS


  AFUCE                    Allowance for Funds Used to Conserve Energy

  AFUDC                    Allowance for Funds Used During Construction

  BPA                      Bonneville Power Administration

  CAAA                     Clean Air Act Amendments

  Chelan                   Public Utility District No. 1 of
                           Chelan County, Washington

  EPA                      Environmental Protection Agency

  FERC                     Federal Energy Regulatory Commission

  KW                       Kilowatts

  KWH                      Kilowatt Hours

  MW                       Megawatts (one MW equals one thousand KW)

  MWH                      Megawatt Hours

  Montana Power            The Montana Power Company

  NMFS                     National Marine Fisheries Service

  NWPPC                    Northwest Power Planning Council

  PRAM                     Periodic Rate Adjustment Mechanism

  PRP                      Potentially Responsible Party

  PUDs                     Washington Public Utility Districts

  Washington Commission    Washington Utilities and Transportation
                           Commission

  WECo                     Washington Energy Company

  WNG                      Washington Natural Gas Company

  WPPSS                    Washington Public Power Supply System
                                   PART I
ITEM 1.  BUSINESS

THE COMPANY

     Puget Sound Energy, Inc., formerly Puget Sound Power & Light Company,
("the Company") is an investor-owned public utility incorporated in the
State of Washington furnishing electric, and since February 10, 1997, gas
service in a territory covering approximately 6,000 square miles,
principally in the Puget Sound region of Washington State.  On February 10,
1997, the Company completed a merger ("the Merger") with the Washington
Energy Company ("WECo") and its principal subsidiary, Washington Natural Gas
Company ("WNG").  Seattle-based WNG provided natural gas distribution
service to more than 500,000 customers in an area east of Puget Sound that
included Seattle, Tacoma, Everett, Bellevue and Olympia.  The earnings,
operations and statistical information contained in this report reflect the
results and information for the Company without giving effect to the Merger
unless the text indicates otherwise.  (See Note 18 to the Consolidated
Financial Statements).  The Company changed its name to Puget Sound Energy,
Inc. effective with the Merger.  (See "Merger with Washington Energy Company
and Washington Natural Gas Company" below.)

     In December 1996, the Company had approximately 857,300 electric
customers, consisting of 761,000 residential, 90,500 commercial, 4,100
industrial and 1,400 other customers.  For the year 1996, the Company added
approximately 16,600 customers, an annual growth rate of 2.0%.  Growth in
total kilowatt-hour sales increased 8.0% in 1996 over 1995, due to increased
sales to other utilities, continuing growth in the number of customers and
colder average temperatures in 1996 than experienced in 1995.

     During 1996, the Company's billed revenues were derived 47% from
residential customers, 35% from commercial customers, 14% from industrial
customers and 4% from sales to other utilities and others.  During this
period, the largest single customer accounted for 3.3% of the Company's
operating revenues.  The average number of kilowatt-hours billed per
residential customer served by the Company in 1996 was 12,399 kilowatt-
hours.  At December 31, 1996, the peak power resources of the Company were
approximately 5,203,000 KW.  The Company's historical peak load of
approximately 4,615,000 KW occurred on December 21, 1990.

     The Company is affected by various seasonal weather patterns throughout
the year and, therefore, operating revenues and associated expenses are not
generated evenly during the year.  Variations in energy usage by consumers
occur from season to season and from month to month within a season,
primarily as a result of weather conditions.  The Company normally
experiences its highest energy sales in the first and fourth quarters of the
year.  Sales to other utilities also vary by quarters and years depending
principally upon streamflow conditions for the generation of surplus hydro-
electric power, customer usage and the energy requirements of other
neighboring utilities.  With the implementation of the Periodic Rate
Adjustment Mechanism ("PRAM") by the Washington Utilities and Transportation
Commission (the "Washington Commission") in October 1991, earnings have not
been significantly influenced, up or down, by sales of surplus electricity
to other utilities or by variations in normal seasonal weather or hydro
conditions.  The PRAM however, ended effective September 30, 1996, under a
stipulated negotiated settlement approved by the Washington Commission.
With the discontinuance of the PRAM, the annual regulatory adjustments for
variations in weather and hydro conditions provided for in the PRAM will

1

also be discontinued.  (See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Rate Matters")

     During the period from January 1, 1992 through December 31, 1996, the
Company made gross electric utility plant additions of $915 million and
retirements of $131 million.  Gross electric utility plant at December 31,
1996, was approximately $3.5 billion which consisted of 47% distribution,
27% generation, 15% transmission and 11% general plant and other.

     The Company and its subsidiaries had 2,075 full-time equivalent
employees on December 31, 1996, down from 2,775 at the end of 1992.  This
represents a workforce reduction of 25% over the last four years.

INDUSTRY EVOLUTION

     The U.S. electric utility industry is facing an increasingly competitive
environment, particularly in wholesale electric generation and industrial
customer markets.  The National Energy Policy Act of 1992 ("EPACT")
intensified competition in the wholesale electric market by easing
restrictions on wholesale power producers and by allowing the Federal Energy
Regulatory Commission ("FERC") to order access for wholesale sellers to
deliver power to wholesale buyers over transmission systems owned by others.
In 1996 FERC issued its landmark Orders 888 and 889, which require
jurisdictional utilities, including the Company, to file wholesale
transmission tariffs providing pricing and terms for transmission access for
wholesale purposes.

     The EPACT does not permit the FERC to order transmission access for
retail purposes, but Congress now has pending bills that would require
existing utilities to allow competitors to use utility property, including
transmission and distribution facilities, to provide electric service to
retail customers of the existing utilities.  Several states, including
California, New Hampshire and Rhode Island have enacted legislation to allow
such use by competitors of utility property.  Most other states, including
Washington, are considering legislative or regulatory proposals which would
also allow such use of utility property by competitors to serve the retail
customers of the existing utilities.  In its February 5, 1997 Order approving
the Company's merger with Washington Energy Company described above, the
Washington Commission required the Company to conduct a retail access pilot
program.  Any substantial change in utility regulation in Washington state,
such as requiring utilities to allow use of utility property by competitors
for retail purposes, would require legislative action and would be subject to
court review.  The major credit rating agencies have expressed the general
view that increased competition is likely to increase business risks in the
electric utility industry, with resulting pressures on utility credit quality
and investor returns.  As required by the Public Utility Regulatory Policies
Act of 1978, the Company has contracted to purchase the net electrical output
from a number of non-utility generators.  (See "Power Resources - Contracts
and Agreements with Non-Utilities")  Most of these agreements provide for
power purchases at prices that are now above market prices.  These excess
contract prices could become stranded costs in a deregulated electric
industry environment.
    
     In this environment, the Company seeks to build on the strengths of its
efficient electric distribution and transmission system to become a leading
provider of energy and related services to homes and businesses in the
Pacific Northwest, and to streamline its energy supply operations.  To
prepare for a more competitive business environment, the Company has
committed itself to being a low cost supplier of electricity.  The Company

2

has taken steps to reduce costs, including work force reductions, facility
consolidations and reductions in capital budgets.  The Company intends to
pursue opportunities for improved operating efficiencies and productivity,
including possible restructuring of its power supply resources and
contracts.  The Company is also actively pursuing opportunities to become a
provider of new high value services such as wireless automated meter-based
services and geographic information systems, to utility customers and other
utilities.

MERGER WITH WASHINGTON ENERGY COMPANY AND WASHINGTON NATURAL GAS COMPANY

     As part of the Company's effort to become the leading provider of
energy and related services in the Northwest, the Company, on February 10,
1997, completed the Merger between the Company, WECo and WNG.  This
announcement followed approval by the Washington Commission, on February 5,
1997, of a merger agreement between the Company, WECo, the Staff of the
Washington Commission and the Public Counsel Section of the State Attorney
General's Office. These events marked the culmination of a sixteen month
process that began in October 1995 with the unanimous approval of the
Agreement and Plan of Merger among the Company, WECo and WNG (the "Merger
Agreement") by the Boards of Directors of the Company, WECo and WNG.  On
March 20, 1996, shareholders of the Company and WECo, voting as separate
groups, gave their approval to the Merger.

     The Merger Agreement called for each share of WECo common stock to be
exchanged for 0.86 share of the Company's common stock.  Based on the
capitalization of the Company and WECo on February 10, 1997, holders of the
Company's and WECo's common stock held approximately 75% and 25%
respectively, of the aggregate number of outstanding shares of the merged
company's common stock.  In addition, the Agreement called for the preferred
stock of WNG to be converted into preferred shares of the Company.  The
Merger has been structured as a tax-free exchange of shares and will be
accounted for as a pooling of interests.

     The order approving the Merger, issued by the Washington Commission on
February 5, 1997, contains a rate plan that is designed to provide a five-
year period of rate certainty for customers and provide the Company with an
opportunity to achieve a reasonable return on investment.  As required under
the Merger order, the Company filed tariffs, effective February 8, 1997,
that resulted in an average decrease of 5.6% related to the PRAM, and an
increase in general rates of between 1.0% and 2.5%, depending on rate class.
The net impact was an average decrease of 3.7%, including a decrease in
residential rates of 3.2%.  General rates for residential and industrial
customers will increase by 1.5% on January 1 of each of the four following
years, while those for small commercial customers will increase by 1.0% in
each of the following three years.

REGULATION AND RATES

     The Company is subject to the regulatory authority of (1) the
Washington Commission as to rates, accounting, the issuance of securities
and certain other matters, and (2) the FERC in the transmission of electric
energy in interstate commerce, the sale of electric energy at wholesale for
resale, accounting and certain other matters.  The Washington Commission
consists of three Commissioners, each appointed for a six-year term by the
Governor of the State of Washington.  (See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Rate Matters.")

3

POWER RESOURCES

     During 1996, the Company's total energy production was supplied 21% by
its own resources, 32% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydroelectric projects
on the Columbia River, 34% from other firm purchases and 13% from non-firm
purchases.

     The following table shows the Company's resources at December 31, 1996,
and energy production during the year:

                           Peak Power Resources
                           at December 31, 1996     1996 Energy Production
                         -----------------------    ----------------------
                            Kilowatts     %         Kilowatt-Hours    %
                            ---------    ----       --------------   ----
                                                     (Thousands)
Purchased Resources:
  Columbia River
    PUD Contracts (Hydro)    1,356,000   26.5        8,488,933       32.3
  Other Hydro(a)               570,000   11.2        4,303,931       16.4
  Thermal(a)                 1,399,000   27.4        7,881,061       30.0
-------------------------------------------------------------------------
  Total Purchased            3,325,000   65.1       20,673,925       78.7
-------------------------------------------------------------------------
Company-owned Resources:
  Hydro                        309,950    6.1        1,346,434        5.1
  Coal                         771,900   15.1        4,217,543       16.1
  Natural gas/oil              702,350   13.7           21,618        0.1
-------------------------------------------------------------------------
  Total Company-owned        1,784,200   34.9        5,585,595       21.3
-------------------------------------------------------------------------
      Total                  5,109,200  100.0       26,259,520      100.0
=========================================================================

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


Company Owned Resources
-----------------------

     The Company and other utilities are joint owners of four mine-mouth,
coal-fired, steam-electric generating units at Colstrip, Montana,
approximately 100 miles east of Billings.  The Company owns a 50% interest
(330,000 KW) in Units 1 and 2 and a 25% interest (350,000 KW) in Units 3 and
4.  The owners of the Colstrip Units purchase coal for the units from
Western Energy Company ("Western Energy"), an affiliate of Montana Power -
one of the joint owners, under the terms of long-term coal supply
agreements.

     A contract price reopener for both the base price and adjustment
provisions of the Colstrip 1 and 2 Coal Supply Agreement became effective
July 30, 1996.  Pursuant to a settlement agreement between the Company,

4

Montana Power and Western Energy dated February 21, 1997, the coal price has
been reduced on an interim basis pending a restructuring of the Colstrip
Coal supply arrangements.

     In 1996, under the Colstrip 3 and 4 Coal Supply Agreement, the owners,
other than Montana Power, gave Western Energy written notice of the
existence of an unusual circumstance and gross inequity concerning the coal
price in accordance with contract provisions.  Pursuant to a settlement
agreement between the Company, Montana Power and Western Energy dated
February 21, 1997, the coal price has been reduced on an interim basis
pending a restructuring of the Colstrip coal supply arrangements.  Pursuant
to its settlement agreement, the Company has withdrawn from participation in
and will forego any benefits from the negotiations and a potential
arbitration regarding the notice of an unusual condition and a gross
inequity.

     The Company owns a 7% interest (91,900 KW) in a coal-fired, steam-
electric generating plant near Centralia, Washington, with a net capability
of 1,313,000 KW.  In 1991, the Company and other owners of the Centralia
Project renegotiated a long-term coal supply agreement with Pacific Power &
Light Company.  The Company and other owners of the Centralia project are
reviewing emissions compliance options that will need to be adopted to meet
the Federal and State emission requirements by the year 2001.  Legislation
is pending in the Washington State Legislature which would provide certain
tax relief to the owners of the Centralia Plant in order to help defray
costs associated with emissions compliance.

     The Company also has the following plants with an aggregate net
generating capability of 1,012,300 KW:  Upper Baker River hydro project
(103,000 KW) constructed in 1959; Lower Baker River hydro project (71,400
KW) reconstructed in 1968; White River hydro plant (63,400 KW) constructed
in 1911 with installation of the last unit in 1924; Snoqualmie Falls hydro
plant (44,000 KW), half the capability of which was installed during the
period 1898 to 1910 and half in 1957; two smaller hydro plants, Electron
(26,400 KW) and Nooksack Falls (1,750 KW), constructed during the period
1904 to 1929; a standby internal combustion unit (2,750 KW) installed in
1969; two oil-fired combustion turbine units (28,500 KW and 67,500 KW)
installed in 1972 and 1974, respectively; four dual-fuel combustion turbine
units (89,100 KW each) installed during 1981; and two dual-fuel combustion
turbine units (123,600 KW each) installed during 1984.

     The Company's combustion turbines installed in 1981 and 1984 may be
fueled with either natural gas or distillate oil.  Short-term supplies of
distillate fuel are stored on-site.  These plants are operated from time to
time for peaking purposes and to produce energy for sales to other
utilities, either directly or through 'tolling' arrangements.

     The Company has applied to the FERC for an initial license for its
existing and operating White River project which includes authorization to
install an additional 14,000 KW generating unit.  The initial license for
the existing and operating Snoqualmie Falls project expired in December
1993. The Company is continuing the FERC application process to relicense
this project and expects a license to be issued in 1997. The Company has
also applied for a license to expand its existing 1,750 KW Nooksack Falls
project which is currently unlicensed and not operating because of an
electrical fire.

5

Columbia River Projects
-----------------------
     For the twelve months ended December 31, 1996, approximately 32% of the
Company's energy output was obtained at an average cost of approximately 8.7
mills per KWH through long-term contracts with several of the Washington
public utility districts ("PUDs") owning hydroelectric projects on the
Columbia River.

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

     The Company has contracted to purchase from Chelan County PUD a share
of the output of the original units of the Rock Island Project which equals
57.1% through June 30, 1997.  This share decreases gradually to 50% of the
output until July 1, 1999, and remains unchanged thereafter for the duration
of the contract.  The Company has also contracted to purchase the entire
output of the additional Rock Island units for the duration of the contract,
except that the Company's share of output of the additional units may be
reduced up to 10% per year beginning July 1, 2000, to a minimum of 50% upon
the exercise of rights of withdrawal by Chelan for use in its local service
area.  Chelan has given notice of withdrawal of 5% on July 1, 2000.  The
Company has contracted to purchase from Chelan County PUD a share of the
output of the Rocky Reach Project that remains unchanged for the remainder
of the contract.  Under terms of a settlement agreement concerning
withdrawal of power, the Company's share of the output of the Wells Project
purchased from Douglas County PUD is currently 32.3% and is expected to
decrease to 31.5% by September 1, 1997.  However, the Company's share of the
output can be ultimately reduced to 31.3% upon the additional exercise of
withdrawal rights by Douglas County PUD.  The Company has contracted to
purchase from Grant County PUD a share of the output of the Priest Rapids
and Wanapum projects that remains unchanged for the remainder of the
contracts.

     As of December 31, 1996, the Company was entitled to purchase portions
of the power output of the PUDs' projects as set forth in Note 15 to the
Consolidated Financial Statements.

     In 1964, the Company and fifteen other utilities and agencies in the
Pacific Northwest entered into a long-term coordination agreement extending
until June 30, 2003 (the "Coordination Agreement").  This agreement provides
for the coordinated operation of substantially all of the hydroelectric
power plants and reservoirs in the Pacific Northwest.  Negotiations are
being conducted regarding a possible replacement of the expiring
Coordination Agreement.  Various fishery enhancement measures, including
most recently the 1995 "biological opinion" from the National Marine
Fisheries Service ("NMFS"), have reduced the flexibility provided by the
Coordination Agreement.

     Certain utilities in the northwest United States and Canada are
obtaining the benefits of additional firm power as a result of the

6

ratification of a 1961 treaty between the United States and Canada under
which Canada is providing approximately 15,500,000 acre-feet of reservoir
storage on the upper Columbia River.  As a result of this storage,
streamflow which would otherwise not be usable to serve firm regional load
is stored and later released during periods when it is usable.  Pursuant to
the treaty, one-half of the firm power benefits produced by the additional
storage accrue to Canada.  The Company's benefits from this storage are
based upon its percentage participation in the Columbia River projects and
one half of those benefits must be returned to Canada.  In turn, the Company
has contracted to purchase 17.5% of Canada's share of the power to be
returned resulting from such storage until the beginning of a phased
expiration of the contract in 1998).  The Company has also contracted to
purchase from the Bonneville Power Administration ("BPA") supplemental
capacity in amounts that decrease gradually until the beginning of a phased
expiration of the contract in 1998.  Negotiations are being conducted
regarding replacement of the existing contracts.

See "ENVIRONMENT - Federal Endangered Species Act" for discussion of the
fishery enhancement plan related to these projects.


Contracts and Agreements with Other Utilities
---------------------------------------------

     On September 17, 1985, the Company and BPA entered into a settlement
agreement settling the Company's claims against BPA resulting from BPA's
action in halting construction on Washington Public Power Supply System
("WPPSS") Nuclear Project No. 3 in which the Company has a 5% interest.
Under the settlement agreement, the Company is receiving from BPA for
approximately 30.5 years, beginning January 1, 1987, a certain amount of
electric power during the months of November through April.  Under the
contract, the Company is guaranteed to receive not less than 191,667 MWH in
each contract year until the Company has received total deliveries of
5,833,333 MWH.

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

     On October 27, 1988, the Company executed a 15-year contract for the
purchase of firm power and energy from Pacific Power & Light Company.  Under
the terms of the agreement, the Company receives 120 average MW of energy
and 200 MW of peak capacity.

     On November 23, 1988, the Company executed an agreement to purchase
surplus firm power from BPA.  Under the agreement, the Company receives 150
average MW of energy and 300 MW of peak capacity from BPA between October 1
and March 31 of each contract year.  The contract extends for 20 years,
ending in 2008.  The sale will convert to a power-for-power exchange on June
30, 2001.

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

7

period.  On February 27, 1995, the Company delivered to Montana Power notice
of termination of the contract based on Montana Power's failure to arrange
for firm contractual transmission rights for such energy as required by the
contract.  On February 21, 1997, the Company and Montana Power settled the
dispute as more fully described in the Company's 8-K statement filed on
February 27, 1997.  Pursuant to the settlement, the contract remains in
effect and the price of power purchased by the Company is reduced. On
February 21, 1997, the Company and Montana Power also agreed to settle their
coal supply disputes in return for certain price reductions and
restructuring activities in connection with the Colstrip coal supply
arrangements.  Montana has estimated that these agreements will result in an
annual reduction in Montana Power's revenues between $11 and $13 million,
before anticipated efficiency gains, commencing January 1, 1997.  The
Company will see a reduction in its power supply costs of approximately the
same amount.  In addition, the Company expects reductions in coal taxes and
royalties and anticipates efficiency gains through restructuring.

     On December 11, 1989, the Company executed a conservation transfer
agreement with Snohomish County PUD.  Snohomish County PUD, together with
Mason and Lewis County PUDs, will install conservation measures in their
service areas.  The agreement calls for the Company to receive the power
saved over the expected 20-year life of the measures.  The agreement calls
for BPA to deliver the conservation power to the Company from March 1, 1990
through June 30, 2001, and for Snohomish County PUD to deliver the
conservation power for the remaining term of the agreement.  Power
deliveries gradually increased over the first five years of the agreement
and will remain at six average MW of energy throughout the remaining term of
the agreement.

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

Contracts and Agreements with Non-Utilities
-------------------------------------------

     As required by federal law, Public Utility Regulatory Policies Act of
1978, P.L. 95-617 ("PURPA"), the Company has contracted to purchase the net
electrical output from a number of non-utility generators, of which the most
significant are described below.  Payments by the Company to owners of these
non-utility generating resources are subject to the delivery of power. (See
Note 15 to the Consolidated Financial Statements)  A number of these
agreements have escalation provisions providing for periodic increases in
the cost of power.

     On February 21, 1985, the Company executed a 50-year contract to
purchase 6 average MW of energy and 14 MW of capacity, beginning in December
1990, from Koma Kulshan Associates, which owns and operates a small
hydroelectric project located near the Company's Upper Baker Dam.

     On January 4, 1988, the Company executed a 21-year contract to purchase
15 average MW of energy and 23 MW of capacity, beginning November 1991, from

8

the City of Spokane, which owns and operates a regional solid waste
incineration project located near Spokane, Washington.

     On June 29, 1989, the Company executed a 20-year contract to purchase
70 average MW of energy and 80 MW of capacity, beginning October 11, 1991,
from the March Point Cogeneration Company ("March Point"), which owns and
operates a natural gas-fired cogeneration facility known as March Point
Phase I, located at a Texaco refinery in Anacortes, Washington.  On December
27, 1990, the Company executed a second contract (having a term coextensive
with the first contract) to purchase an additional 53 average MW of energy
and 60 MW of capacity, beginning January 1993, from March Point which owns
and operates another natural gas-fired cogeneration facility known as March
Point Phase II, also located at the Texaco refinery in Anacortes,
Washington.  In November 1995, March 1996 and November 1996, the Company
delivered notices of breach to March Point based on, among other things,
March Point's failure to maintain generation at agreed-upon limits, to
displace generation pursuant to the parties' power purchase agreements, and
to provide information essential to the parties' agreed-upon displacement
arrangements.  On November 29, 1995, March Point commenced litigation
against the Company in federal court for the Western District of Washington
in which March Point requests a declaration of certain obligations of March
Point and the Company under the contracts, injunctive relief preventing the
Company from terminating its contracts with March Point and damages based on
breach of contract.  The Company has answered and counterclaimed in the
action, contending that March Point has breached the contracts.  The Company
seeks declaratory relief regarding the parties' obligations and rights under
the contracts, damages based on the breach and rescission.

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

     On September 26, 1990, the Company executed a 15-year contract to
purchase 141 average MW of energy and 160 MW of capacity, beginning July
1993, from Encogen Northwest L.P. ("Encogen") (a limited partnership having
a general partner that is a subsidiary of Enserch Development Corp.), which
owns and operates a natural-gas fired cogeneration facility located at the
Georgia Pacific mill near Bellingham, Washington.  In June 1995, the Company
delivered notice of breach to Encogen based on, among other things,
Encogen's failure to provide information essential to the parties' agreed-
upon displacement arrangements.  On September 20, 1995, Encogen commenced
litigation against the Company in Whatcom County Superior Court requesting a
declaration of certain obligations of Encogen under the contract, and
seeking further relief.  The Company has answered and counterclaimed in the
action, contending that Encogen has breached the contract and seeking
declaratory relief regarding Encogen's duty to provide certain information.

     On March 20, 1991, the Company executed a 20-year contract to purchase
216 average MW of energy and 245 MW of capacity, beginning April 1994, from
Tenaska Washington Partners, L.P., which owns and operates a natural-gas
fired cogeneration project located near Ferndale, Washington.

Energy Conservation
-------------------

     The Company offers programs designed to help new and existing customers
use electric energy efficiently.  The primary emphasis is to provide

9

information and technical services to enable customers to make energy-
efficient choices with respect to building design, equipment and building
systems, appliance purchases and O&M practices.

     The Company's energy conservation expenditures have historically been
accumulated, included in rate base and amortized to expense over a ten year
period at the direction of the Washington Commission.  In June 1995 the
Company sold approximately $202.5 million of its investment in customer-
owned energy conservation measures to a grantor trust, which, in turn,
issued securities backed by a Washington state statute enacted in 1994.
(See Note 1 to the Consolidated Financial Statements)

Construction Financing
----------------------

     The Company estimates its combined electric and gas construction
expenditures, excluding Allowance for Funds Used During Construction
("AFUDC"), for 1997 through 1999 will be $247 million, $252 million and $226
million, respectively.  The Company expects cash from operations (net of
dividends and AFUDC) during the period 1997 through 1999 will, on average,
be approximately 73% of average estimated construction expenditures
(excluding AFUDC) during the same period.  (See "Management's Discussion and
Analysis of Financial Condition and Results of Operations" for a discussion
of the Company's construction program.)  The Company's ability to finance
its future construction program is dependent upon market conditions and
maintaining a level of earnings sufficient to permit the sale of additional
securities.  In determining the type and amount of future financings, the
Company may be limited by restrictions contained in its Mortgage Indenture,
Articles of Incorporation and certain loan agreements.

     Under the most restrictive tests, at December 31, 1996, the Company
could issue (i) approximately $1.019 billion of additional first mortgage
bonds or (ii) approximately $571 million of additional preferred stock at an
assumed dividend rate of 6.80% or (iii) a combination thereof.

Environment
-----------

     The Company's operations are subject to environmental regulation by
federal, state and local authorities.  Capital expenditures for
environmental controls for Company electric facilities are estimated at $2.3
million for 1997.  Due to the inherent uncertainties surrounding the
development of federal and state environmental and energy laws and
regulations, the Company cannot determine the impact such laws may have on
its existing and future facilities.

Federal Comprehensive Environmental Response, Compensation and
Liability Act, and the Washington State Model Toxics Control Act
----------------------------------------------------------------

     The federal Comprehensive Environmental Response, Compensation and
Liability Act (commonly referred to as the "Superfund Act") subjects certain
parties to liability for remedial action at contaminated disposal sites.

     The Company has been named by the Environmental Protection Agency
("EPA") as a Potentially Responsible Party ("PRP") at four sites in
Washington State.  The Company has reached settlements with the EPA on all
four sites under which the Company has paid approximately $7.7 million.
Estimated future remediation costs at these four sites are expected to be

10

$0.4 million.  To date, the Company has recovered $4.0 million from its
insurance companies in connection with remediation and legal costs and
expects to recover an additional $1.9 million.  These sites represent all
significant superfund sites at which the Company believes it has liability.
There is, however, no assurance that all contaminated sites and contaminants
for which the Company may have a responsibility have been identified or that
remedial actions planned to date at current sites, including actions
pursuant to consent decrees, will be adequate.

     The Company has also commenced a program to test, replace and remediate
certain underground storage tanks as required by federal and state laws.
Remediation and testing of Company vehicle service facilities and storage
yards have also been commenced.  To date, the Company has spent $3.2 million
to remediate underground tank sites and has recovered $1.2 million in
insurance proceeds.  Future expenditures are anticipated to be $1.1 million
and future insurance proceeds are anticipated to be $1.6 million.  Estimated
future remediation costs at other Company-owned sites were $0.7 million at
December 31, 1996.  (See Note 15 to the Consolidated Financial Statements
for further discussion of environmental obligations and the related
regulatory treatment.)  Estimates of future obligations in this section
relate to the Company's electric operations.

Federal Clean Air Act Amendments of 1990
----------------------------------------

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

     The Centralia Project and the Colstrip Projects meet the sulfur dioxide
limits of the CAAA in Phase I (1995).  The Company and other owners of the
Centralia Project, including Pacific Power & Light Company, which operates
the Centralia Project, are reviewing emission compliance options which will
need to be adopted to meet the Phase II limits in the year 2000.

     Montana Power, which operates the Colstrip 3 and 4 Project, is working
to meet the Phase II limits in the year 2000.  Under the CAAA, allowances
may be used to achieve compliance.  It is believed that Units 1 and 2 may
have an excess of allowances above what is currently set for Phase II
requirements and that Units 3 and 4 have sufficient allowances for Phase II
requirements.

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

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

Federal Endangered Species Act
------------------------------

     In November 1991, the National Marine Fisheries Service ("NMFS") listed
the Snake River Sockeye as an endangered species pursuant to the federal
Endangered Species Act.  Since the Sockeye listing, the Snake River fall and
spring/summer Chinook have also been listed as threatened.  In response to
the listings, a team of experts was formed to develop a plan for the

11

recovery needs of these species.  In 1995 the NMFS issued a biological
opinion which has significantly changed the operation of the Federal
Columbia River Power System.

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

     Other species are also proposed for listing as endangered species and
could further restrict regional hydro system flexibility and energy
production.

12


Puget Sound Energy, Inc.
ELECTRIC OPERATING STATISTICS
<TABLE>
<CAPTION>
Year Ended on December 31              1996        1995        1994        1993        1992
--------------------------------------------------------------------------------------------
Operating revenues by classes
(thousands):
--------------------------------------------------------------------------------------------
<S>                              <C>         <C>         <C>         <C>         <C>
  Residential                    $  554,318  $  524,749  $  532,124  $  502,037  $  443,490
  Commercial                        423,139     397,212     375,751     356,586     323,764
  Industrial                        170,596     168,501     163,574     150,063     138,416
  Other consumers                    44,125      38,730      38,759      28,189      35,779
-------------------------------------------------------------------------------------------
    Operating revenues billed
      to consumers (a)            1,192,178   1,129,192   1,110,208   1,036,875     941,449
  Unbilled revenues -
    net increase (decrease)          13,201      (6,382)     (2,522)     14,409      15,080
  PRAM accrual                      (74,326)      3,953      25,835      42,100      42,119
-------------------------------------------------------------------------------------------
    Total operating revenues
      from consumers              1,131,053   1,126,763   1,133,521   1,093,384     998,648
  Other utilities                    67,716      52,567      60,537      19,494      26,322
-------------------------------------------------------------------------------------------
    Total operating revenues     $1,198,769  $1,179,330  $1,194,058  $1,112,878  $1,024,970
-------------------------------------------------------------------------------------------
  Number of customers (average):
  Residential                       754,097     739,173     723,566     708,123     692,100
  Commercial                         89,613      87,404      85,203      82,875      80,963
  Industrial                          3,993       3,908       3,851       3,715       3,659
  Other                               1,371       1,346       1,325       1,289       1,254
-------------------------------------------------------------------------------------------
    Total customers (average)       849,074     831,831     813,945     796,002     777,976
-------------------------------------------------------------------------------------------
KWH generated, purchased
  and interchanged (thousands):
Total Company generated           5,585,595   6,371,416   7,011,932   6,414,311   7,420,058
  Purchased power                20,573,983  17,897,922  16,268,042  14,608,899  13,408,522
  Interchanged power (net)           99,942      48,485     (87,771)    174,478    (118,346)
-------------------------------------------------------------------------------------------
    Total energy output          26,259,520  24,317,823  23,192,203  21,197,688  20,710,234
  Losses and Company use         (1,322,262) (1,235,457) (1,291,322) (1,096,599) (1,202,194)
-------------------------------------------------------------------------------------------
    Total energy sales           24,937,258  23,082,366  21,900,881  20,101,089  19,508,040
-------------------------------------------------------------------------------------------
</TABLE>
(a)  Operating revenues in 1996 and 1995 were reduced by $41.0 million and
$25.1 million, respectfully, as a result of the Company's sale of $202.5
million of its investment in customer-owned energy conservation measures.
(See "Operating revenues" in Management's Discussion and Analysis and Note 1
to the Consolidated Financial Statements.)

13

<TABLE>
<CAPTION>
(Continued from prior page              1996        1995        1994        1993        1992
--------------------------------------------------------------------------------------------
Electric energy sales, KWH
(thousands):
<S>                                <C>         <C>         <C>         <C>         <C>
  Residential                      9,350,292   8,972,498   8,913,903   8,974,787   8,297,293
  Commercial                       6,807,465   6,538,533   6,301,568   6,175,911   5,945,284
  Industrial                       3,793,966   3,720,641   3,724,931   3,690,473   3,704,450
  Other consumers                    205,066     205,232     200,622     196,246     193,563
--------------------------------------------------------------------------------------------
    Total energy billed
      to consumers                20,156,789  19,436,904  19,141,024  19,037,417  18,140,590
  Unbilled energy sales -
    net increase (decrease)          224,412    (158,920)    (72,352)    139,329     209,565
--------------------------------------------------------------------------------------------
    Total energy sales
      to consumers                20,381,201  19,277,984  19,068,672  19,176,746  18,350,155
  Sales to other
    electric utilities             4,556,057   3,804,382   2,832,209     924,343   1,157,885
--------------------------------------------------------------------------------------------
    Total energy sales            24,937,258  23,082,366  21,900,881  20,101,089  19,508,040
--------------------------------------------------------------------------------------------
Per residential customer:
  Annual use (KWH)                    12,399      12,139      12,319      12,674      11,989
  Annual billed revenue              $762.35     $726.95     $735.42     $708.97     $640.79
  Billed revenue per KWH              $.0615      $.0599      $.0597      $.0559      $.0534

Company-owned generation
  capability - kilowatts:
  Hydro                              309,950     309,950     309,950     309,950     309,950
  Steam                              771,900     771,900     771,900     857,700     857,700
  Natural gas/oil                    702,350     702,350     702,350     702,350     702,350
--------------------------------------------------------------------------------------------
    Total                          1,784,200   1,784,200   1,784,200   1,870,000   1,870,000
--------------------------------------------------------------------------------------------
Heating degree days                    4,953       3,994       4,341       4,691       4,090
% of normal of 30 year
  average (4,908)                     100.9%       81.4%       88.4%       95.6%       83.3%

Load factor                            55.5%       56.7%       54.7%       52.5%       57.0%
</TABLE>

14

EXECUTIVE OFFICERS AT DECEMBER 31, 1996:

Name               Age                      Offices
----------------   ---   ---------------------------------------------------

R. R. Sonstelie    51   President and Chief Executive Officer since 1992;
                        President and Chief Operating Officer 1991-1992;
                        President and Chief Financial Officer 1987-1991;
                        Executive Vice President 1985-1987;
                        Senior Vice President Finance 1983-1985;
                        Vice President Engineering and Operations 1980-1983;
                        Director since 1987.

W. S. Weaver       52   Executive Vice President and Chief Financial Officer
                        and Director since 1991.  For more than five years
                        prior to that time, a Partner in the law firm Perkins
                        Coie.

G. B. Swofford     55   Senior Vice President Customer Operations since
                        1994; Vice President Divisions and Customer
                        Services 1991-1994; Vice President Rates and Customer
                        Programs 1986-1991; Director Conservation and
                        Division Services 1980-1986.

S. M. Vortman      51   Senior Vice President Corporate & Regulatory
                        Relations since 1994; Vice President
                        Strategic Planning and Regulatory Affairs
                        February 10, 1994 - May 9, 1994; Vice President
                        Corporate Services 1992-1994; Director Real Estate
                        1990-1992;

R. G. Bailey       57   Vice President Power Systems since 1980.

J. W. Eldredge     46   Chief Accounting Officer since 1994;
                        Corporate Secretary and Controller since 1993;
                        Controller since 1988; Manager Budgets and
                        Performance 1987-1988; Manager General Accounting
                        1984-1987.

G. N. Ferencz      50   Vice President Divisions since 1994; Director
                        Division Services 1992-1994; General Manager Thurston
                        Division 1990-1992; Division Administrator Southern
                        Division 1982-1990.

D. E. Gaines       39   Treasurer since 1994; Director Strategic
                        Planning 1992-1994; Manager Financial Planning 1986 -
                        1992.

J. L. Henry        51   Vice President Engineering and Operating Services
                        since 1994; Vice President Operations
                        Services 1991-1994; Director South Central Division
                        1990-1991; Director Division Operations 1984-1990.


Officers are elected for one-year terms.

15

ITEM  2.  PROPERTIES

      The principal generating plants owned by the Company are described
under Item 1 - "Business - Power Resources."  The Company owns its
transmission and distribution facilities, and various other properties.
Substantially all properties of the Company are subject to the lien of the
Company's Mortgage Indenture.

ITEM  3.  LEGAL PROCEEDINGS

      See Note 15 to the Consolidated Financial Statements.

ITEM  4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - NONE


                                  PART II

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

      The Company's common stock is traded on the New York Stock Exchange
(symbol PSD).  The number of stockholders of record of the Company's common
stock at December 31, 1996, was 56,898.

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

      Certain provisions relating to the Company's senior securities limit
funds available for payment of dividends to net income available for
dividends on common stock (as defined in the Company's Mortgage Indenture)
accumulated after December 31, 1957, plus the sum of $7.5 million.  As of
December 31, 1996, the balance of earnings reinvested in the business that
was not restricted as to dividends on common stock was approximately $254
million.  (See Note 6 to the Consolidated Financial Statements.)

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

                         1996                           1995
                  ---------------------------   ---------------------------
                    Price Range                    Price Range
                  ---------------   Dividends   ---------------   Dividends
Quarter Ended      High       Low     Paid        High      Low     Paid
-------------     ------   ------   ---------   ------   ------   ---------
March 31          25-7/8   23-5/8     $.46      21-1/2   20-1/8     $.46
June 30           25-1/2   23-1/2     $.46      23-3/8   20-3/4     $.46
September 30      24-3/8   22-1/2     $.46      23-3/8   21-1/4     $.46
December 31       24       23-1/8     $.46      24       22-1/4     $.46

16

ITEM  6.  SELECTED FINANCIAL DATA
<TABLE>
Year Ended December 31
(Thousands of Dollars except per share data)
<CAPTION>
                                     1996        1995        1994        1993        1992
----------------------------    ---------  ----------  ----------  ----------  ----------
<S>                            <C>         <C>         <C>         <C>         <C>
Operating Revenue              $1,198,769  $1,179,330  $1,194,058  $1,112,878  $1,024,970
Operating Income               $  200,576  $  214,588  $  193,498  $  210,980  $  214,670
Net Income                     $  135,371  $  135,720  $  120,059  $  138,327  $  135,720
Income for Common Stock        $  120,210  $  120,192  $  104,328  $  121,885  $  121,836
Common Shares Outstanding -
  Weighted Average             63,640,861  63,640,861  63,632,057  60,930,859  56,283,949

Earnings Per Common Share
  (Note 1 to the
  Financial Statements)             $1.89       $1.89       $1.64       $2.00       $2.16
Dividends Per Common Share          $1.84       $1.84       $1.84       $1.83       $1.79
Book Value Per Common Share        $18.53      $18.48      $18.43      $18.65      $17.76
Total Assets at Year End*      $3,187,252  $3,268,995  $3,463,770  $3,341,130  $2,997,721

Long-term Obligations          $  820,664  $  920,439  $  963,298  $1,036,079  $1,044,992
Redeemable Preferred Stock     $   87,839  $   89,039  $   91,242  $   93,176  $   93,822
</TABLE>

*  The Company adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes," effective January 1, 1993, providing deferred
taxes for items which previously had tax benefits flowed through to
ratepayers.  A corresponding regulatory asset was recorded under long-term
assets.  For years prior to 1993, the Company has reclassified as
liabilities deferred taxes previously netted with plant and other property
and investments.

17

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

Financial Condition and Results Of Operations

Net income in 1996 was $135.4 million on operating revenues of $1.199
billion, compared to $135.7 million on operating revenues of $1.179
billion in 1995 and $120.1 million on operating revenues of $1.194
billion in 1994.  Income for common stock was $120.2 million for both
1996 and 1995 and $104.3 million for 1994.

Earnings per share in both 1996 and 1995 were $1.89 on 63.6 million
weighted average common shares outstanding and $1.64 on 63.6 million
weighted average common shares outstanding in 1994.

Return on the average book value of the Company's common equity was
10.3% in 1996 and 1995 and 8.9% in 1994.  The dividend payout ratio was
97.4% in 1996 and 1995 and 112.2% in 1994.

Total kilowatt-hour sales to ultimate consumers in 1996 were 20.4
billion, compared with 19.3 billion in 1995 and 19.1 billion in 1994.
Kilowatt-hour sales to other utilities were 4.6 billion in 1996, 3.8
billion in 1995 and 2.8 billion in 1994.

The preferred stock dividend accrual decreased $0.4 million in 1996
compared to 1995 due to lower dividend rates on the Adjustable Rate
Cumulative Preferred Stock ("ARPS"), Series B ($100 par value).  The
preferred stock dividend accrual decreased $0.2 million in 1995
compared to 1994 due to the redemption of the $40 million Adjustable
Rate Cumulative Preferred Stock ("ARPS"), Series A ($100 par value) in
February 1994.  The preferred stock dividend accrual decreased $0.7
million in 1994 compared to 1993.  This decrease was due to the
redemptions of the $50 million Flexible Dutch Auction Rate Transferable
Securities $100 Par Value Preferred Stock ("FLEX DARTS"), Series B in
July 1993 and the $40 million ARPS, Series A in February 1994.  These
decreases were partially offset by the issuance in February 1994 of the
$50 million ARPS, Series B ($25 par value).

18
  
                 Increase (Decrease) Over Preceding Year
                           Years Ended December 31
                            (Dollars in Millions)


                                                 1996     1995      1994
------------------------------------------------------------------------
Operating revenues
  General rate increase                        $   --    $  --    $ 27.0
  PRAM surcharge billed                          41.2     53.5      29.6
  Accrual of revenue under
    the PRAM - Net                              (78.3)   (21.9)    (16.3)
  BPA Residential Purchase and
    Sale Agreement                              (15.8)   (25.3)      2.3
  Sales to other utilities                       15.1     (8.0)     41.0
  Revenue sold to conservation trust            (15.9)   (25.1)       --
  Load and other changes                         73.1     12.1      (2.4)
------------------------------------------------------------------------
      Total operating revenue changes            19.4    (14.7)     81.2
------------------------------------------------------------------------
Operating expenses
  Purchased and interchanged power               18.6     14.8      77.1
  Fuel                                            5.0    (11.5)     (5.5)
  Other operation expenses                        2.5    (38.7)     26.0
  Maintenance                                    (2.7)     1.8      (2.5)
  Depreciation and amortization                   1.2     (8.2)      0.1
  Taxes other than federal income taxes           7.1      1.7       7.2
  Federal income taxes                            1.7      4.3      (3.7)
------------------------------------------------------------------------
        Total operating expense changes          33.4    (35.8)     98.7
------------------------------------------------------------------------
Allowance for funds used during
  construction ("AFUDC")                         (0.9)     0.8      (0.8)
Other income                                      4.7     (5.3)      1.0
Interest charges                                 (9.9)     0.9       1.0
------------------------------------------------------------------------
Net income changes                             $ (0.3)   $15.7    $(18.3)
========================================================================

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

Operating Revenues

Revenues since October 1, 1995, increased as a result of rates authorized by
the Washington Utilities and Transportation Commission (the "Washington
Commission") under the fifth Periodic Rate Adjustment Mechanism ("PRAM")
filing.  Revenues since October 1, 1994, increased as a result of rates
authorized by the Washington Commission under the fourth PRAM filing.
Revenues since October 1, 1993, increased as a result of rates authorized by
the Washington Commission in its general rate order issued on September 21,
1993. The PRAM was terminated effective September 30, 1996.  (See "Rate
Matters.")

Revenues have been reduced by virtue of the credit that the Company received
through the Residential Purchase and Sale Agreement with the Bonneville
Power Administration ("BPA").  This agreement enables the Company's
residential and small farm customers to receive the benefits of lower-cost
federal power.  A corresponding reduction is included in purchased and

19

interchanged power expenses.  On January 29, 1997, the Company and the BPA
signed a Residential Exchange Termination Agreement.  The Agreement
effectively ends the Company's participation in the Residential Purchase and
Sale Agreement in exchange for settlement payments by the BPA of
approximately $237 million over five years. (See "Other" for a discussion of
the Residential Exchange Termination Agreement.)

Revenues in 1996 and 1995 have been reduced by $41.0 million and $25.1
million as a result of the CompanyOs sale of revenues associated with $202.5
million of its investment in conservation assets to a grantor trust.  The
revenue decrease represents the portion of rate revenues that were sold and
forwarded to the trust.  The impact of this revenue decrease, however, was
offset by related reductions in other operation and interest expenses. (See
OOtherO for a discussion of the sale of conservation assets.)

To meet customer demand, the Company's power supply portfolio includes net
purchases of power under long-term supply contracts.  However, depending
principally upon streamflow available for hydroelectric generation and
weather effects on customer demand, from time to time the Company may have
surplus power available for sale at wholesale to other utilities.  In
addition, the Company intends to increase its wholesale surplus power
business through short and intermediate term purchase, sale, arbitrage and
other trading and marketing techniques.

Operating Expenses

Purchased and interchanged power expenses increased $18.6 million in 1996
when compared to 1995.  Higher payments for firm power purchases from non-
utility generators and secondary power purchases from other utilities
contributed an increase of $34.5 million.  This increase was partially
offset by increased credits associated with the Residential Purchase and
Sale Agreement with BPA of $15.2 million.  (See discussion of the
Residential Purchase and Sale Agreement under "Operating revenues.")

Purchased and interchanged power expenses increased $14.8 million in 1995
when compared to 1994.  Higher payments for firm power purchases from non-
utility generators and secondary power purchases from other utilities
contributed an increase of $35.4 million.  This increase was partially
offset by increased credits associated with the Residential Purchase and
Sale Agreement with BPA of $24.1 million.

Purchased and interchanged power expenses increased $77.1 million in 1994
when compared to 1993.  Higher payments related to new firm power purchase
contracts from non-utility generators contributed an increase of $89.3
million.  Also contributing to the increase was a reduction in credits
associated with the Residential Purchase and Sale Agreement with BPA of $2.2
million.  Partially offsetting these increases were lower secondary power
purchases from other utilities of $15.6 million.

Fuel expense increased $5.0 million in 1996.  The increase was due in part
to an Arbitration PanelOs decision in 1995 of a dispute involving the coal
supply agreement at the CompanyOs fifty percent-owned Colstrip 1 and 2
plants that resulted in a $4.6 million decrease to fuel expense recorded in
the first quarter of 1995.  In addition, the Company recorded a one-time
charge of $1.8 million in the second quarter of 1996 relating to a loss on
the sale of oil stocks at a combustion turbine site.

Fuel expense decreased $11.5 million in 1995 compared to 1994 as the Company
generated less electricity at company-owned coal plants while purchasing

20

more power on the secondary market.  Additionally, an Arbitration PanelOs
decision of a dispute involving the coal supply agreement at the CompanyOs
fifty percent-owned Colstrip 1 and 2 plants resulted in a $4.6 million
decrease to fuel expense in the first quarter of 1995 pertaining to coal
deliveries from August 1, 1991, through March 31, 1995.  Fuel expense
decreased $5.5 million in 1994 as the Company purchased additional power
from cogeneration facilities rather than run Company-owned gas turbines.

Other operation expenses increased $2.5 million in 1996 when compared to
1995.  The increase was due primarily to $7.8 million increase in
transmission and distribution expenses, caused in part by a severe wind
storm in November 1996. In addition, the Company expensed certain merger
integration costs of approximately $4.8 million.  These increases were
partially offset by an $11.6 million decrease in amortization expense
associated with the Company's conservation program.  In June 1995 the
Company sold, to a grantor trust, approximately $202.5 million of its
investment in customer-owned energy conservation measures. (See discussion
of the conservation asset transaction in "Other.")

Other operation expenses decreased $38.7 million in 1995 when compared to
1994.  The decrease was due in part to charges in 1994 totaling $20.9
million associated with the Company's two voluntary early retirement and
separation programs and related business office and service facility
consolidations.  (See Note 10 to the Consolidated Financial Statements.)
Also contributing to the decrease was lower amortization expense of $14.3
million associated with the CompanyOs sale, in June 1995, of $202.5 million
of its investment in customer-owned energy conservation measures.

Other operation expenses increased $26.0 million in 1994 when compared to
1993.  Included in the increase were charges totaling $20.9 million
reflecting costs associated with the Company's two voluntary early
retirement and separation programs and related business office and service
facility consolidations.  Also included was an increase of $4.0 million in
amortization expense associated with the Company's energy conservation
program and an increase of $1.8 million in transmission and distribution
expenses.

Maintenance expense decreased $2.7 million in 1996 as compared to 1995.  The
decrease was primarily the result of lower maintenance expense at the
CompanyOs Colstrip and Centralia coal-fired generation projects.

Maintenance expense increased $1.8 million in 1995 over 1994 due primarily
to higher distribution maintenance expenses in the first and fourth quarters
of 1995 resulting from storm damage to Company transmission and distribution
facilities.  Maintenance expense in 1994 was lower by $2.5 million due
primarily to a $4.4 million decrease in distribution maintenance expense.
This decrease was partially offset by a $1.3 million increase in
administration and general maintenance expense.

Depreciation and amortization expense increased $1.2 million in 1996 from
1995 levels due primarily to the effects of new electric plant placed into
service during 1996.

Depreciation and amortization expense decreased $8.2 million in 1995 from
1994 levels.  A decrease of $12.9 million was attributable to the completion
in September 1994, of the 10 year amortization period related to two
terminated generating projects.  This decrease was partially offset by the
effects of new plant placed into service.

21

Depreciation and amortization expense increased $0.1 million in 1994
compared to the prior year.  Increased depreciation expense related to
additional plant placed into service was offset by the completion of the 10
year amortization period related to two terminated generating projects.

Taxes other than federal income taxes increased $7.1 million in 1996
compared to 1995.  The increase was due primarily to higher Washington state
property tax payments of $2.9 million and higher revenue-based municipal and
state excise tax payments of $3.0 million.

Taxes other than federal income taxes increased $1.7 million in 1995
compared to 1994.  Municipal and state excise tax payments increased $3.5
million and were partially offset by lower property tax payments of $0.8
million and other federal and state taxes of $1.0 million.  Taxes other than
federal income taxes increased $7.2 million in 1994 compared to the prior
year.  Municipal and state excise taxes, which are revenue-based, were
higher by $4.5 million.  Also contributing to the increase were higher
Washington and Montana state property tax payments of $1.4 million.

Federal income taxes on operations increased $1.7 million in 1996 over 1995.
The increase was due primarily to a decrease in energy conservation
expenditures in 1996 which are deducted for federal income taxes.  Federal
income taxes on operations increased $4.3 million in 1995 compared to the
prior year due primarily to higher pre-tax operating income during 1995.
Federal income taxes on operations decreased $3.7 million in 1994 due
primarily to lower pre-tax operating income during 1994.

AFUDC

(See Note 1 to the Consolidated Financial Statements.)

Other Income

Total other income increased $4.7 million in 1996.  The increase was due
primarily to increased earnings of subsidiaries of $6.4 million offset by
lower interest income of $1.0 million.  The increased earnings from
subsidiaries were due to increased profits from property sales of the
Company's real estate subsidiary.  Cash received from these sales, which
totaled $39.0 million, has been paid to the Company and is recorded on the
Statement of Cash Flows as "Cash received from subsidiaries."

Other income decreased $5.3 million in 1995.  The decrease was due in part
to lower energy conservation expenditures resulting in a $2.2 million
decline in Allowance for Funds Used to Conserve Energy ("AFUCE") and a $1.4
million decrease in excess AFUDC over the Federal Energy Regulatory
Commission ("FERC") maximum allowed by the Washington Commission.  Also
contributing to the decrease were higher non-utility expenses of $0.9
million when compared to 1994.

Other income increased $1.0 million in 1994 over 1993.  Included was an
increase in subsidiary earnings of $2.2 million due primarily to an after-
tax gain of $1.9 million resulting from the sale of a small hydroelectric
generating project by the Company's Hydro Energy Development Corporation
subsidiary.  Cash received from the sale, which totaled $30.1 million, is
recorded on the Statement of Cash Flows as "Cash received from subsidiary."

22

Interest Charges

Interest charges, which consist of interest and amortization on long-term
debt and other interest, decreased $9.9 million in 1996 compared to 1995.
Interest and amortization on long-term debt decreased $8.0 million.
Contributing $7.5 million in reduced interest expense were five First
Mortgage Bond retirements or redemptions totaling $151 million over the
previous 17 months.

Other interest expense decreased $1.9 million in 1996 over 1995.  The
decrease was the result of lower weighted average interest rates and lower
average daily short-term borrowings in 1996 as compared to 1995.

Interest charges increased $0.9 million in 1995 compared to 1994.  Interest
and amortization on long-term debt decreased $3.0 million.  Contributing
$4.3 million in reduced interest expense were five First Mortgage Bond
retirements or redemptions totaling $181 million over the previous 23
months.  Partially offsetting this was $1.3 million in new interest expense
associated with two issues of Secured Medium-Term Notes totaling $85 million
that were issued during the same period.  Other interest expense increased
$3.9 million in 1995 over 1994.  The increase was the result of higher
weighted average interest rates and higher average daily short-term
borrowings in 1995 as compared to 1994.

Interest charges increased $1.0 million in 1994.  Interest and amortization
on long-term debt decreased $1.9 million.  Contributing $8.1 million in
reduced interest expense were eight First Mortgage Bond and Secured Medium-
Term Note retirements or redemptions totaling $191 million over the previous
22 months.  Partially offsetting this was $6.4 million in new interest
expense associated with nine issues of Secured Medium-Term Notes totaling
$169 million issued over the previous 23 months.  Other interest expense
increased $2.9 million in 1994 due to higher average daily short-term
borrowings and higher weighted average interest rates in 1994 as compared to
1993.

Construction and Financing Program

Current construction expenditures are primarily transmission and
distribution-related, designed to meet continuing customer growth.
Construction expenditures, which include energy conservation expenditures
and exclude AFUDC and AFUCE, were $115.8 million in 1996.  The Company
expects combined electric and gas construction expenditures for the period
1997 through 1999 will be approximately $247 million, $252 million and $226
million, respectively.  The ratio of cash from operations (net of dividends,
AFUDC and AFUCE) to construction expenditures (excluding AFUDC and AFUCE)
was 144.4% in 1996.  The Company expects cash from operations (net of
dividends and AFUDC) during the period 1997 through 1999 will, on average,
be approximately 73% of average estimated construction expenditures
(excluding AFUDC) during the same period.

In October 1992, the Company filed a shelf registration statement with the
Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to $450 million principal amount of First Mortgage
Bonds.  The First Mortgage Bonds can be issued as Secured Medium-Term Notes,
through underwritten offerings, pursuant to delayed delivery contracts or
any combination thereof.  These Secured Medium-Term Notes were designated
Series B.  As of February 10, 1997, the Company has issued $364 million in
Series B Notes having an average coupon rate of 6.90%.

23

Short-term borrowings from banks and the sale of commercial paper are used
to provide working capital for the construction program.  At December 31,
1996, the Company had in place $176.5 million in lines of credit with
several banks, which provided liquidity support for outstanding commercial
paper of $88.7 million, effectively reducing the available borrowing
capacity under these lines of credit to $87.8 million. (See Note 8 to the
Consolidated Financial Statements.)

Rate Matters

In the Washington Commission's September 21, 1993, general rate case order,
the Company was allowed a 10.5% return on common equity and 8.94% return on
rate base, based on a capital structure of 47% debt, 8% preferred stock and
45% common equity.

On September 22, 1995, the Washington Commission issued a rate order
relating to the Company's fifth annual rate adjustment under the PRAM.  In
addition to approval of the rate adjustment, the Commission also agreed,
pursuant to a negotiated settlement, to discontinue the PRAM on September
30, 1996.  PRAM accrued revenues of $40.5 million, recorded at December 31,
1996, were recovered in the first quarter of 1997.  Over-collection of PRAM
revenues, if any, are expected to be refunded to customers in the second
quarter of 1997.

With the discontinuance of the PRAM, the annual regulatory adjustments for
variations in weather and hydro conditions provided for in the PRAM were
also discontinued.

On September 30, 1996, the Washington Commission issued an order granting a
joint motion by the Company and the Washington Commission Staff to transfer
annual revenues of $165.5 million which were being collected in PRAM rates
to the Company's permanent rate schedules.  As a result of the order, the
Company also wrote off $4.5 million in previously accrued revenues related
to special industrial customer service contracts.

The Merger

On February 7, 1997, the Boards of the Company and Washington Energy Company
(WECo) approved the merger of their respective companies effective
February 10, 1997.  The merged company is called Puget Sound Energy, Inc.
This announcement followed the approval by the Washington Commission, on
February 5, 1997, of a merger agreement between the Company, WECo, the Staff
of the Washington Commission and the Public Counsel Section of the State
Attorney General's Office.  Shareholders of the Company and WECo, voting as
separate groups had, on March 20, 1996, already given their approval to an
Agreement and Plan of Merger ("Merger Agreement") between the two companies.

The order approving the merger contains a rate plan that is designed to 
provide a five-year period of rate certainty for customers and provide the 
Company with an opportunity to achieve a reasonable return on investment.  
As required under the merger order, the Company filed tariffs, effective 
February 8, 1997, that resulted in an average electric rate decrease of 5.6%
related to the PRAM, and an increase in general rates of between 1.0% and 
2.5%, depending on rate class.  The net impact was an average rate decrease 
of 3.7%, including a decrease in residential rates of 3.24%.  General 
electric rates for residential and industrial customers will increase by 
1.5% on January 1 of each of the four following years, while those for small
commercial customers will increase by 1.0% in each of the following three
years.  General rates for all classes of natural gas customers will remain

24

unchanged until January 1, 1999, when they will decrease sufficiently to
reduce utility margin by 1 percent. (See Note 18 to the Consolidated
Financial Statements.)

Other

The U.S. electric utility industry is facing an increasingly competitive
environment, particularly in wholesale generation and industrial customer
markets.  The National Energy Policy Act of 1992 ("EPACT") intensified
competition in the wholesale electric market by easing restrictions on
wholesale power producers and by allowing the Federal Energy Regulatory
Commission ("FERC") to order access for wholesale sellers to deliver power to
wholesale buyers over transmission systems owned by others.  In 1996 FERC
issued its landmark Orders 888 and 889, which require jurisdictional
utilities, including the Company, to file wholesale transmission tariffs
providing pricing and terms for transmission access for wholesale purposes.

The EPACT does not permit the FERC to order transmission access for retail
purposes, but Congress now has pending bills that would require existing
utilities to allow competitors to use utility property, including
transmission and distribution facilities, to provide electric service to
retail customers of the existing utilities.  Several states, including
California, New Hampshire and Rhode Island have enacted legislation to allow
such use by competitors of utility property.  Most other states, including
Washington, are considering legislative or regulatory proposals which would
also allow such use of utility property by competitors to serve the retail
customers of the existing utilities.  In its February 5, 1997 Order approving
the Company's merger with Washington Energy Company described above, the
Washington Commission required the Company to conduct a retail access pilot
program.  Any substantial change in utility regulation in Washington state,
such as requiring utilities to allow use of utility property by competitors
for retail purposes, would require legislative action and would be subject to
court review.  The major credit rating agencies have expressed the general
view that increased competition is likely to increase business risks in the
electric utility industry, with resulting pressures on utility credit quality
and investor returns.

In this environment, the Company seeks to build on the strengths of its
efficient electric distribution and transmission system to become a leading
provider of energy and related services to homes and businesses in the
Pacific Northwest, and to streamline its energy supply operations.  To
prepare for a more competitive business environment, the Company has
committed itself to being a low cost supplier of electricity.  The Company
has taken steps to reduce costs, including work force reductions, facility
consolidations and reductions in capital budgets.  The Company intends to
pursue opportunities for improved operating efficiencies and productivity,
including possible restructuring of its power supply resources and
contracts.  The Company is also actively pursuing opportunities to become a
provider of new high value services such as wireless automated meter-based
services and geographic information systems, to utility customers and other
utilities.

The Company and BPA have entered into a letter of intent, subject to various
conditions, regarding pursuit of construction of a joint transmission
project in Whatcom and Skagit counties in northern Washington state, the
northernmost portion of the Company's service territory.  The joint project
is intended to provide the Company and BPA with certain transfer capacity
with Canadian utilities and is intended to relieve certain transmission
constraints on the respective systems of BPA and the Company.  The joint

25

project, which is expected to be completed in late 1997, will involve a
combination of existing facility upgrades and new construction.

On May 24, 1996, the Company filed a proposal with the Washington Commission
to create an Optional Large Power Sales Rate for its largest customers.
Under the Company's proposal, customers who elect the Optional Large Power
Sales Rate would no longer be considered "core" customers.  Instead, they
would form a new class of "non-core" customers, and the Company would no
longer have an obligation to plan for future resources to serve their needs.
The non-core customers will receive access to electric energy that is priced
at current market cost and will pay a charge for energy delivery (including
a charge for conservation programs) and a transition charge (representing
the difference between the Company's present cost and the current market
cost of electric energy and capacity).  The transition charge will be phased
out before the end of the year 2000.  Non-core customers also would take on
the risk that market costs could become volatile and that electricity could
be unavailable on the open market. On October 9, 1996, the Washington
Commission approved the Company's proposal and ordered the new optional
large power sales tariff into effect November 1, 1996.

On January 29, 1997, the Company and BPA signed a Residential Exchange
Termination Agreement.  The Agreement ends the Company's participation in
the Residential Purchase and Sale Agreement with BPA.  The Residential
Purchase and Sale Agreement enabled the Company's residential and small farm
customers to receive the benefits of lower-cost federal power.  As part of
the Termination Agreement, the Company will receive payments by the BPA of
approximately $237 million over five years.  Under the rate plan approved by
the Washington Commission in its merger order, the Company will continue to
reflect, in customers' bills, the current level of Residential Exchange
benefits.  Over the five year period, it is projected that the Company will
credit customers approximately $250 million more than it will receive from
BPA.  The Company expects the difference will be made up through the general
rate increases approved in the merger order and additional reductions in
operating expenses.

On July 12, 1996, the Company and several other Northwest electric companies
signed a memorandum of understanding to study the creation of an independent
transmission grid operator called "IndeGO."  Participation in IndeGO would
be open to all transmission owners in the Northwest and would include both
investor-owned utilities and certain government-owned power agencies.

The Company's energy conservation expenditures have historically been
accumulated, included in rate base and amortized to expense over a ten year
period at the direction of the Washington Commission.  In June 1995 the
Company sold approximately $202.5 million of its investment in customer-
owned energy conservation measures to a grantor trust, which, in turn,
issued securities backed by a Washington state statute enacted in 1994.  The
statute provides that if certain conditions are met, securities could be
issued, backed by a statutory requirement that a portion of rate revenues be
forwarded to the trust to repay those securities.  The proceeds of the sale
were used to pay down short-term debt.  The Company recognized no gain or
loss on the sale.

The Company is in the process of selectively replacing the High Molecular
Weight ("HMW") underground distribution cable installed during the 1960s and
1970s.  The Company installed about 4,800 miles of standard HMW cable
between 1964 and 1979, but the Company and other utilities have experienced
increasing cable failures in recent years.  The Company is continuing to
analyze cable failure trends to find ways to mitigate the effect of cable

26

failures on customer service.  To minimize the impact on customers of
increasing cable failures, the Company replaces a certain amount of HMW
cable each year and is beginning to use silicone injection to lengthen the
life of potentially problem cables.  The Company so far has replaced 780
miles and injected 20 miles of HMW cable.  The Company expects to spend $49
million on additional cable replacement during the period 1997-2000.  In
1997 the Company is planning either to replace or use silicone injection on
150 miles of HMW cable.

For a discussion of environmental obligations, see Note 15 to the
Consolidated Financial Statements.

ITEM  8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See index on page 32.

ITEM  9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
          FINANCIAL DISCLOSURE  -  NONE.

                                  PART III

     Part III is incorporated by reference from the Company's definitive
proxy statement issued in connection with the 1995 Annual Meeting of
Shareholders.

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


                                  PART IV

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

     (a)  Documents filed as part of this report:

          1) Financial statement schedule - see index on page 32.

          2) Exhibits - see index on page 63.

     (b)  Reports on Form 8-K:

          1)  Form 8-k dated December 12, 1996, Item 5 - Other Events,
             related to stipulated settlement agreement filed with the
             Washington Utilities and Transportation Commission.

27
                                 SIGNATURES

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

                                             PUGET SOUND ENERGY, INC.



                                   By         s/s R. R. Sonstelie
                                        ____________________________________
                                                  R. R. Sonstelie
                                        Chairman and Chief Executive Officer


                                              Date:  March 13, 1997


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

Signature                      Title                                Date
___________________________    ____________________________     _____________


s/s  R. R. Sonstelie           Chairman,
___________________________    Chief Executive Officer
    (R. R. Sonstelie)          and Director


s/s  William S. Weaver         Vice Chairman,
___________________________    Chairman of Unregulated
    (William S. Weaver)        Subsidiaries and Director


s/s  James P. Torgerson        Vice President and
___________________________    Chief Financial Officer        March 13, 1997
    (James P. Torgerson)


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


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


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

28

Signatures, continued



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


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


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


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


s/s  John W. Ellis             Director
___________________________
    (John W. Ellis)


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


                               Director
___________________________
    (Nancy L. Jacob)


s/s  Tomio Moriguchi           Director
___________________________
    (Tomio Moriguchi)


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


s/s  R. Kirk Wilson            Director
___________________________
    (R. Kirk Wilson)

29
                           Puget Sound Energy, Inc.

Report of Management:

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

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

In addition, Coopers & Lybrand L.L.P., the independent auditors, have
performed audit procedures deemed appropriate to obtain reasonable assurance
about whether the financial statements are free of material misstatement.

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




s/s R. R. Sonstelie      s/s William S. Weaver     s/s James W. Eldredge
____________________     _______________________   _______________________
    R. R. Sonstelie          William S. Weaver         James W. Eldredge

Chairman and             Vice Chairman and         Corporate Secretary
Chief Executive Officer  Chairman of Unregulated   and Controller
                         Subsidiaries             (Chief Accounting Officer)

30
                                      
                      REPORT OF INDEPENDENT ACCOUNTANTS



To the Shareholders of
Puget Sound Energy, Inc.

We have audited the consolidated financial statements and the financial
statement schedule of Puget Sound Energy, Inc. (formerly Puget Sound Power &
Light Company) listed on page 32 of this Annual Report on Form 10-K.  These
financial statements and financial statement schedule are the responsibility
of the Company's management.  Our responsibility is to express an opinion on
these financial statements and financial statement schedule based on our
audits.

We conducted our audits in accordance with generally accepted auditing
standards.  Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement.  An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Puget Sound
Energy, Inc. as of December 31, 1996 and 1995, and the consolidated results
of its operations and its cash flows for each of the three years in the
period ended December 31, 1996 in conformity with generally accepted
accounting principles.  In addition, in our opinion, the financial statement
schedule referred to above, when considered in relation to the basic
financial statements taken as a whole, presents fairly, in all material
respects, the information required to be included therein.

Coopers & Lybrand L.L.P.


Seattle, Washington
February 12, 1997

31

PUGET SOUND ENERGY, INC.



CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
  COVERED BY THE FOREGOING REPORT OF INDEPENDENT ACCOUNTANTS


CONSOLIDATED FINANCIAL STATEMENTS:                                     Page


Consolidated Balance Sheets, December 31, 1996 and 1995.................33

Consolidated Statements of Capitalization, December 31, 1996 and 1995...35

Consolidated Statements of Income for the years ended
  December 31, 1996, 1995 and 1994......................................36

Consolidated Statements of Earnings Reinvested in the Business
  for the years ended December 31, 1996, 1995 and 1994..................37

Consolidated Statements of Cash Flows for the years
  ended December 31, 1996, 1995 and 1994................................38

Notes to Consolidated Financial Statements..............................39


SCHEDULE:

II.   Valuation and Qualifying Accounts and Reserves for the
      years ended December 31, 1996, 1995 and 1994......................62

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

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

32

<TABLE>
Consolidated Balance Sheets
Puget Sound Energy, Inc.
----------------------------------------------------------------------------------------
<CAPTION>
Assets
December 31
(Dollars in Thousands)                                                1996          1995
----------------------------------------------------------------------------------------
<S>                                                             <C>           <C>               
Utility Plant:
  Electric plant, at original cost (Notes 2, 7 and 15)          $3,479,652    $3,400,723
  Less: Accumulated depreciation                                 1,188,576     1,118,678
----------------------------------------------------------------------------------------
      Net utility plant                                          2,291,076     2,282,045
----------------------------------------------------------------------------------------
Other Property and Investments:
  Investment in Bonneville Exchange Power Contract                  86,772        94,241
  Investment in and advances to subsidiaries                        73,957        95,459
  Energy conservation loans to customers                               415           783
  Other investments, at cost                                        16,988        11,328
----------------------------------------------------------------------------------------
      Total other property and investments                         178,132       201,811
----------------------------------------------------------------------------------------

Current Assets:
  Cash (Note 9)                                                      3,736        12,498
----------------------------------------------------------------------------------------
  Accounts receivable:
    Customers                                                       96,435        90,345
    Other                                                           41,149        34,627
    Less allowance for doubtful accounts                               770           886
----------------------------------------------------------------------------------------
      Total accounts receivable                                    136,814       124,086
----------------------------------------------------------------------------------------
  Estimated unbilled revenue                                        93,563        80,363
  PRAM accrued revenues                                             40,470        59,123
  Materials and supplies, at average cost                           36,683        46,407
  Prepayments and Other                                              3,911         4,352
----------------------------------------------------------------------------------------
      Total current assets                                         315,177       326,829
----------------------------------------------------------------------------------------
Long-Term Assets:
  Regulatory asset for deferred income taxes (Note 12)             234,095       249,731
  PRAM accrued revenues (net of current portion)                        --        55,673
  Unamortized debt expense                                           9,062        10,264
  Unamortized energy conservation charges                           41,734        37,889
  Other                                                            117,976       104,753
----------------------------------------------------------------------------------------
      Total long-term assets                                       402,867       458,310
----------------------------------------------------------------------------------------
Total Assets                                                    $3,187,252    $3,268,995
========================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
----------------------------------

33

<TABLE>
<CAPTION>
Capitalization and Liabilities
December 31
(Dollars in Thousands)                                                1996          1995
----------------------------------------------------------------------------------------
<S>                                                             <C>           <C>
Capitalization 
(See "Consolidated Statements of Capitalization"):
  Common equity                                                 $1,179,026    $1,175,904
  Preferred stock not subject to mandatory redemption              125,000       125,000
  Preferred stock subject to mandatory redemption                   87,839        89,039
  Long-term debt                                                   820,664       920,439
----------------------------------------------------------------------------------------
      Total capitalization                                       2,212,529     2,310,382
----------------------------------------------------------------------------------------
Current Liabilities:
  Accounts payable                                                  71,690        50,269
  Short-term debt (Notes 8 and 9)                                  120,413       167,049
  Current maturities of long-term debt (Note 7)                     99,922        43,000
  Accrued expenses:
    Taxes                                                           38,335        36,321
    Salaries and wages                                              24,013        22,011
    Interest                                                        21,878        22,921
  Other                                                             28,685        27,356
----------------------------------------------------------------------------------------
      Total current liabilities                                    404,936       368,927
----------------------------------------------------------------------------------------
Deferred Income Taxes:
  Deferred income taxes (Note 12)                                  500,638       528,400
  Investment tax credits                                                --           311
----------------------------------------------------------------------------------------
      Total deferred income taxes                                  500,638       528,711
----------------------------------------------------------------------------------------
Other Deferred Credits:
  Customer advances for construction                                20,405        19,972
  Other                                                             48,744        41,003
----------------------------------------------------------------------------------------
      Total other deferred credits                                  69,149        60,975
----------------------------------------------------------------------------------------
Commitments and Contingencies
  (Notes 1, 11, 12, 13, 14, 15 and 18)                                  --            --
----------------------------------------------------------------------------------------
Total Capitalization and Liabilities                            $3,187,252    $3,268,995
========================================================================================

34

</TABLE>
The accompanying notes are an integral part of the financial statements.
<TABLE>
<CAPTION>
Consolidated Statements of Capitalization
Puget Sound Energy, Inc.
----------------------------------------------------------------------------------------
December 31
(Dollars in Thousands)                                                1996          1995
----------------------------------------------------------------------------------------
<S>                                                             <C>           <C>
Common Equity:
  Common stock - ($10 stated value) - 80,000,000 shares
    authorized, 63,640,861 shares
    outstanding (Notes 3 and 14)                                $  636,409    $  636,409
  Additional paid-in capital (Notes 5 and 14)                      328,963       328,963
  Earnings reinvested in the business (Note 6)                     213,654       210,532
----------------------------------------------------------------------------------------
      Total common equity                                        1,179,026     1,175,904
----------------------------------------------------------------------------------------
Preferred Stock Not Subject to Mandatory
  Redemption - cumulative (Note 3):
  $25 par value:*
    7.875% series - 3,000,000 shares authorized and outstanding     75,000        75,000
    Adjustable Rate, Series B - 2,000,000 shares authorized
      and outstanding                                               50,000        50,000
----------------------------------------------------------------------------------------
      Total preferred stock not subject to mandatory redemption    125,000       125,000
----------------------------------------------------------------------------------------
Preferred Stock Subject To Mandatory Redemption - cumulative
  (Notes 4 and 9):
  $100 par value:*
    4.84% series - 150,000 shares authorized,
       47,956 shares outstanding                                     4,796        4,796
    4.70% series - 150,000 shares authorized,
      56,215 shares outstanding                                      5,621        5,621
    8% series - 150,000 shares authorized,
      24,224 and 36,224 shares outstanding                           2,422        3,622
    7.75% series - 750,000 shares authorized and outstanding        75,000       75,000
----------------------------------------------------------------------------------------
      Total preferred stock subject to mandatory redemption         87,839       89,039
----------------------------------------------------------------------------------------
Long-Term Debt (Notes 7 and 9):
  First mortgage bonds                                             759,000      794,000
  Guaranteed collateralized bonds                                       --        8,000
  Pollution control revenue bonds:
    Revenue refunding 1991 series, due 2021                         50,900       50,900
    Revenue refunding 1992 series, due 2022                         87,500       87,500
    Revenue refunding 1993 series, due 2020                         23,460       23,460
  Other notes                                                           19           21
  Unamortized discount - net of premium                               (293)        (442)
  Long-term debt due within one year                               (99,922)     (43,000)
----------------------------------------------------------------------------------------
      Total long-term debt excluding current maturities            820,664      920,439
----------------------------------------------------------------------------------------
Total Capitalization                                            $2,212,529   $2,310,382
========================================================================================

</TABLE>
* 13,000,000 shares authorized for $25 par value preferred stock
  and 3,000,000 shares authorized for $100 par value preferred stock.

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

35

<TABLE>
<CAPTION>
Consolidated Statements of Income
Puget Sound Energy, Inc.
----------------------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands except per share amounts)         1996          1995         1994
----------------------------------------------------------------------------------------
<S>                                               <C>           <C>          <C>
Operating Revenues                                $1,198,769    $1,179,330   $1,194,058
----------------------------------------------------------------------------------------
Operating Expenses:
  Operation (Note 15):
    Purchased and interchanged power                 428,172       409,541      394,758
    Fuel                                              40,645        35,658       47,166
    Other (Notes 10 and 11)                          167,265       164,735      203,476
  Maintenance                                         50,456        53,148       51,342
  Depreciation and amortization                      108,752       107,582      115,738
  Taxes other than federal income taxes (Note 10)    116,661       109,533      107,821
  Federal income taxes (Note 12)                      86,242        84,545       80,259
----------------------------------------------------------------------------------------
      Total operating expenses                       998,193       964,742    1,000,560
----------------------------------------------------------------------------------------
Operating Income                                     200,576       214,588      193,498
----------------------------------------------------------------------------------------
Other Income:
  Allowance for funds used during
    construction - equity portion                        231           719          530
  Miscellaneous - net of taxes (Notes 10 and 12)      11,629         6,957       12,290
----------------------------------------------------------------------------------------
      Total other income - net                        11,860         7,676       12,820
----------------------------------------------------------------------------------------
Income Before Interest Charges                       212,436       222,264      206,318
----------------------------------------------------------------------------------------
Interest Charges:
  Interest on long-term debt                          69,757        77,224       80,213
  Allowance for funds used during
    construction - debt portion                       (3,919)       (4,292)      (3,667)
  Other interest                                       7,850         9,722        5,782
  Amortization of debt expense,
    net of premium (Note 7)                            3,377         3,890        3,931
----------------------------------------------------------------------------------------
      Total interest charges                          77,065        86,544       86,259
----------------------------------------------------------------------------------------
Net Income                                           135,371       135,720      120,059
----------------------------------------------------------------------------------------
Less Preferred Stock Dividend Accruals                15,161        15,528       15,731
----------------------------------------------------------------------------------------
Income for Common Stock                           $  120,210    $  120,192   $  104,328
----------------------------------------------------------------------------------------

Common shares outstanding weighted average        63,640,861    63,640,861   63,632,057
Earnings per common share                         $     1.89    $     1.89   $     1.64
========================================================================================

</TABLE>
The accompanying notes are an integral part of the financial statements.

36

<TABLE>
<CAPTION>
Consolidated Statements of Earnings Reinvested in the Business
Puget Sound Energy, Inc.
----------------------------------------------------------------------------------------
Year Ended December 31
(Dollars in thousands except per share amounts)         1996          1995          1994
----------------------------------------------------------------------------------------
<S>                                                 <C>           <C>           <C>
Balance at Beginning of Year                        $210,532      $207,567      $220,259
Net Income                                           135,371       135,720       120,059
----------------------------------------------------------------------------------------
    Total                                            345,903       343,287       340,318
----------------------------------------------------------------------------------------
Deductions:
  Dividends Declared:
    Preferred stock:
      $4.84 per share on 4.84% series                    232           232           242
      $4.70 per share on 4.70% series                    265           276           319
      $8.00 per share on 8% series                       218           314           410
      $7.75 per share on 7.75% series                  5,813         5,813         5,813
      $1.97 per share on 7.875% series                 5,906         5,906         5,906
      Adjustable Rate, Series A                           --            --           700
      Adjustable Rate, Series B                        2,716         3,115         2,277
    Common stock                                     117,099       117,099       117,084
----------------------------------------------------------------------------------------
    Total deductions                                 132,249       132,755       132,751
----------------------------------------------------------------------------------------
Balance at End of Year (Note 6)                     $213,654      $210,532      $207,567
----------------------------------------------------------------------------------------
Dividends declared per common share                 $   1.84      $   1.84      $   1.84
========================================================================================

</TABLE>
The accompanying notes are an integral part of the financial statements.

37

<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
Puget Sound Energy, Inc.
----------------------------------------------------------------------------------------
Year Ended December 31                                    1996         1995         1994
(Dollars in Thousands)
----------------------------------------------------------------------------------------
Operating Activities:
<S>                                                   <C>          <C>          <C>
Net income                                            $135,371     $135,720     $120,059
Adjustments to reconcile net income to net
 cash provided by operating activities:
  Depreciation and amortization                        108,752      107,582      115,738
  Deferred income taxes and tax credits - net          (12,437)      12,049       17,762
  PRAM accrued revenues - net                           74,326       (3,955)     (25,835)
  Other                                                (11,915)      17,878       37,283
  Change in certain current assets and
    liabilities (Note 17)                                9,961      (17,564)      (5,979)
----------------------------------------------------------------------------------------
    Net Cash Provided by Operating Activities          304,058      251,710      259,028
----------------------------------------------------------------------------------------
Investing Activities:

Construction expenditures - excluding equity AFUDC    (114,037)    (119,294)    (213,982)
Additions to energy conservation program                (6,683)     (15,156)     (36,648)
Cash received from subsidiaries                         39,000           --       30,136
Cash received from sale of conservation assets - net        --      199,452           --
Other (including advances to subsidiaries)              (7,985)         702       (7,241)
----------------------------------------------------------------------------------------
    Net Cash Provided (Used) by Investing Activities   (89,705)      65,704     (227,735)
----------------------------------------------------------------------------------------

Financing Activities:

Increase (decrease) in short-term debt                 (46,636)     (67,405)      85,148
Dividends paid (net of newly issued shares
  totaling $239,000 in 1994)                          (132,249)    (132,755)    (132,513)
Issuance of common and preferrred stock
  (Notes 3, 4 and 5)                                        --           --       50,000
Issuance of bonds (Note 7)                                  --           --       85,000
Redemption of bonds and notes                          (43,002)    (108,004)     (73,014)
Redemption of preferred stock                           (1,200)      (1,993)     (41,865)
Other                                                      (28)         (43)      (2,210)
----------------------------------------------------------------------------------------
    Net Cash Used by Financing Activities             (223,115)    (310,200)     (29,454)
----------------------------------------------------------------------------------------
Increase (decrease) in Cash                             (8,762)       7,214        1,839

Cash at Beginning of Year                               12,498        5,284        3,445
----------------------------------------------------------------------------------------

Cash at End of Year                                   $  3,736     $ 12,498     $  5,284
======================================================================================== 
</TABLE>
The accompanying notes are an integral part of the financial statements.

38


Puget Sound Energy, Inc.
Notes To Consolidated Financial Statements
----------------------------------------------------------------------------

1)       Summary of Significant Accounting Policies

Significant accounting policies are described below.

Basis of Presentation:

Puget Sound Energy, Inc., formerly Puget Sound Power & Light Company, ("the
Company"), is an investor-owned public utility incorporated in the State of
Washington furnishing electric service in a territory covering approximately
4,500 square miles, principally in the Puget Sound region of Washignton
state.  The earnings, operations and statistical information contained in
this report reflect the results for the Company without giving effect to its
merger in 1997 with Washington Energy Company ("WECo") (See Note 18).  The
change of its name to Puget Sound Energy, Inc. was effective with the
merger.

The consolidated financial statements include the accounts of the Company
and a wholly-owned subsidiary which had issued Guaranteed Collateralized
Bonds, the proceeds of which were advanced to the Company (See Note 7).  The
subsidiary has no independent operations.

Investments in all other subsidiaries are stated on an equity basis inasmuch
as the assets, liabilities, revenues and operating expenses of the
subsidiaries are not material in relation to those of the Company.

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

Utility Plant:

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

Accounting for Regulatory Assets:

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

39

from customers.  In applying Statement No. 71, the Company must give
consideration to changes in the level of demand or competition during the
cost recovery period.  In accordance with Statement No. 71, the Company
capitalizes certain costs in accordance with regulatory authority whereby
those costs will be expensed and recovered in future periods.

Net regulatory assets at December 31, 1996 and 1995 included the following:
----------------------------------------------------------------
(Dollars in Millions)                           1996        1995
-----------------------------------------     ------      ------
Deferred income taxes                         $234.1      $249.7
Investment in BEP Exchange Contract             86.8        94.2
Unamortized energy conservation charges         41.7        37.9
PRAM accrued revenues                           40.5       114.8
Storm damage costs                              39.3        27.3
Various other costs                             66.3        69.5
-----------------------------------------     ------       -----
Total                                         $508.7      $593.4
================================================================

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

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

Operating Revenues:

Operating revenues are recorded on the basis of service rendered, which
include estimated unbilled revenue and revenue accrued under the Periodic
Rate Adjustment Mechanism ("PRAM").

Energy Conservation:

The Company accumulates energy conservation expenditures which are included
in rate base and amortized to expense over a ten-year period when authorized
by the Washington Utilities and Transportation Commission ("Washington
Commission").

In June 1995, the Company sold approximately $202.5 million of its
investment in customer-owned energy conservation measures to a grantor trust
which, in turn, issued securities backed by a Washington state statute

40

enacted in 1994.  The proceeds of the sale were used to pay down short-term
debt.  The Company recognized no gain or loss on the sale.  The Company's
total unamortized conservation balance at December 31, 1996 was $41.7
million.

Self-Insurance:

Prior to October 1, 1993, provision was made for uninsured storm damage,
comprehensive liability, industrial accidents and catastrophic property
losses, with the approval of the Washington Commission, on the basis of the
amount of outside insurance in effect and historical losses.  To the extent
actual costs varied from the provision, the difference was deferred for
incorporation into future rates.

In its September 21, 1993 order, the Washington Commission terminated,
prospectively, the provision for deferral of uninsured storm damage except
for certain losses associated with major storms. At December 31, 1996, the
Company had no insurance coverage for storm damage and is self-insured for a
portion of the risk associated with comprehensive liability, industrial
accidents and catastrophic property losses.  The amount of uninsured storm
damage costs deferred under the regulatory treatment approved by the
Washington Commission at December 31, 1996 was $39.3 million, which includes
$14.7 million of costs deferred as a result of a severe snowstorm in late
December 1996.

Depreciation and Amortization:

For financial statement purposes, the Company provides for depreciation on a
straight-line basis.  The depreciation of automobiles, trucks, power
operated equipment and tools is allocated to asset and expense accounts
based on usage.  The annual depreciation provision stated as a percent of
average original cost of depreciable utility plant was 3.0% in 1996, 1995
and 1994.

The Company's investments in terminated generating projects were amortized
on a straight-line basis over the ten year period ending in 1994 (included
in operating expenses under "Depreciation and amortization").

Amounts recoverable through rates related to investments in terminated
generating projects and the Bonneville Exchange Power Contract were adjusted
to their present value in prior years in accordance with Statement of
Financial Accounting Standards No. 90 ("Statement No. 90").  These
adjustments result in reduced net amortization expense over the recovery
periods, the effect of which is included in miscellaneous income in the
amount, net of federal income tax expense, of $1.1 million, $1.3 million and
$1.8 million for 1996, 1995 and 1994, respectively.

Federal Income Taxes:

The Company normalizes, with the approval of the Washington Commission,
certain items.  Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 109.  (See Note 12.)

Allowance for Funds Used During Construction:

The Allowance for Funds Used During Construction ("AFUDC") represents the
cost of both the debt and equity funds used to finance utility plant
additions during the construction period.  The amount of AFUDC recorded in
each accounting period varies depending principally upon the level of

41

construction work in progress and the AFUDC rate used.  AFUDC is capitalized
as a part of the cost of utility plant and is credited as a non-cash item to
other income and interest charges currently.  Cash inflow related to AFUDC
does not occur until these charges are reflected in rates.

The AFUDC rate allowed by the Washington Commission is the Company's
authorized rate of return, which was 8.94% effective October 1, 1993.  To
the extent amounts calculated using this rate exceed the AFUDC calculated
using the Federal Energy Regulatory Commission ("FERC") formula, the Company
capitalizes the excess as a deferred asset, crediting miscellaneous income.
The amounts included in income were: $2,112,000 for 1996; $1,614,000 for
1995; and $3,016,000 for 1994.  The deferred asset is being amortized over
the average useful life of the Company's non-project utility plant.

Allowance For Funds Used to Conserve Energy:

The Washington Commission has authorized the Company to capitalize, as part
of energy conservation costs, related carrying costs calculated at a rate
established by the Washington Commission.  This Allowance for Funds Used to
Conserve Energy ("AFUCE") has been credited as a non-cash item to
miscellaneous income in the amount of $661,000 in 1996, $1,463,000 in 1995,
and $3,317,000 in 1994.  Cash inflow related to AFUCE occurs when these
charges are reflected in rates, or when the underlying asset is sold to a
third party.  AFUCE was discontinued with the PRAM on September 30, 1996.

Periodic Rate Adjustment Mechanism:

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

Rates established for the PRAM period were subject to future adjustment
based on actual customer growth and variations in certain costs, principally
those affected by hydro and weather conditions.  To the extent revenue
billed to customers varied from amounts allowed under the methodology
established in the PRAM order, the difference was accumulated, without
interest, for rate recovery which was then established in the next PRAM
hearing.  In its September 22, 1995 order, the Washington Commission
approved the Company's last PRAM filing and the recovery of $71.2 million
over the period October 1, 1995 through September 30, 1996.  In addition to
approval of the rate adjustment, the Commission also agreed, pursuant to a
negotiated settlement, to discontinue the PRAM on September 30, 1996, the
end of the last PRAM period.  PRAM accrued revenues of $40.5 million,
recorded at December 31, 1996, were recovered in the first quarter of 1997.
Over-collection of PRAM revenues, if any, are expected to be refunded to
customers in the second quarter of 1997.

Other:

Debt premium, discount and expenses are amortized over the life of the
related debt.

In March 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
("Statement No. 121"). Statement No. 121 requires that long-lived assets and

42

certain intangibles be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of the asset may not be
recoverable.  If impairment has occurred, an impairment loss must be
recognized. Statement No. 121 was implemented in 1996.  Adoption of this
standard has not had a material impact on the financial position, results of
operations, or liquidity of the Company.

In October 1995, the FASB issued Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation" ("Statement No. 123").
Statement No. 123 establishes a fair value based method of accounting for
stock-based compensation plans and encourages entities to adopt that method
in place of the provisions of Accounting Principles Board Opinion No. 25
("APB 25").  The Company intends to continue to apply the provisions of APB
25 in recognizing compensation expense related to its stock-based
compensation plans.  The difference in expense between Statement No. 123 and
APB 25 is not material.

Earnings Per Common Share:

Earnings per common share have been computed based on the weighted average
number of common shares outstanding.

2)       Property Plant and Equipment

---------------------------------------------------------------------------
December 31 (Dollars in Thousands)                        1996         1995
---------------------------------------------------------------------------
Electric utility plant classified by prescribed
accounts at original cost:
  Intangible plant                                  $   50,714   $   38,786
  Production plant                                     926,706      905,047
  Transmission plant                                   535,661      521,810
  Distribution plant                                 1,634,463    1,571,037
  General plant                                        236,972      241,533
  Construction work in progress                         83,085      105,617
  Plant held for future use                             10,802       15,644
  Acquisition adjustments                                1,249        1,249
---------------------------------------------------------------------------
    Total electric utility plant                    $3,479,652   $3,400,723
===========================================================================

43

3)      Capital Stock

                                    Preferred Stock
                              --------------------------------
                                   Not Subject      Subject to
                                       to           Mandatory        Common
                              Mandatory Redemption  Redemption        Stock
--------------------------    --------------------  ----------  -----------
                                                                    Without
                                            $100       $100       Par Value
                                  $25        Par        Par     ($10 Stated
                               Par Value    Value      Value         Value)
--------------------------    ---------   --------  ----------  -----------
Shares outstanding
January 1, 1994                3,000,000   400,000     931,763   63,629,416

  Sold to Public:
    1994                       2,000,000        --          --           --

Issued to shareholders under
the stock purchase and
dividend reinvestment plan:
    1994                              --        --          --       11,445

Acquired for sinking fund:
    1994                              --        --     (19,339)          --
    1995                              --        --     (22,029)          --
    1996                              --        --     (12,000)          --

Called for redemption
and canceled:
    1994                              --  (400,000)         --           --
---------------------------------------------------------------------------

Shares outstanding
December 31, 1996              5,000,000        --     878,395   63,640,861
============================================================================

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

On January 15, 1991, the Board of Directors declared a dividend of one
preference share purchase right (a "Right") on each outstanding common share
of the Company.  The dividend was distributed on January 25, 1991, to
shareholders of record on that date.  The Rights will be exercisable only if
a person or group acquires 10 percent or more of the Company's common stock
or announces a tender offer which, if consummated, would result in ownership
by a person or group of 10 percent or more of the common stock.  Each Right
entitles the registered holder to purchase from the Company one one-
thousandth of a share of Preference Stock, $50 par value per share, at an
exercise price of $45, subject to adjustments.  The description and terms of
the Rights are set forth in a Rights Agreement between the Company and The
Bank of New York, as Rights Agent.  The Rights expire on January 25, 2001,
unless earlier redeemed by the Company.  On October 18, 1995, the Company's
Board of Directors approved an amendment to the Rights Agreement which
precludes the merger with WECo from triggering any rights under the Rights
Agreement.

44

On February 3, 1994, the Company issued $50 million, Adjustable Rate
Cumulative Preferred Stock ("ARPS"), Series B ($25 par value).  The proceeds
were used to retire the $40 million principal amount of its ARPS Series A
($100 par value).  The weighted average dividend rate for the ARPS Series B
was 5.49% for 1996, 6.05% for 1995 and 5.93% for 1994.  The weighted average
dividend rate for the ARPS Series A was 7.00% in the first two months of
1994.

For each quarterly period, dividends on the ARPS Series B, determined in
advance of such period, will be set at 83% of the highest of three interest
rates as defined in the Statement of Relative Rights and Preferences for
ARPS Series B.  The dividend rate for any dividend period will in no event
be less than 4% per annum or greater than 10% per annum.  The Company may
redeem the ARPS Series B at any time on not less than 30 days notice at
$27.50 per share on or prior to February 1, 1999, and at $25 per share
thereafter, plus in each case accrued dividends to the date of redemption;
provided however, that no shares shall be redeemed prior to February 1,
1999, if such redemption is for the purpose or in anticipation of refunding
such share at an effective interest or dividend cost to the Company of less
than 5.37% per annum.

4)      Preferred Stock Subject to Mandatory Redemption

The Company is required to deposit funds annually in a sinking fund
sufficient to redeem the following number of shares of each series of
preferred stock at $100 per share plus accrued dividends:  4.84% Series and
4.70% Series, 3,000 shares each;  8% Series, 6,000 and 1,000 shares through
2003 and 2004, respectively; and 7.75% Series, 37,500 shares on each
February 15, commencing on February 15, 1998.  Previous requirements have
been satisfied by delivery of reacquired shares.  At December 31, 1996,
there were 9,044 shares of the 4.84% Series, 6,785 shares of the 4.70%
Series and 776 shares of the 8% Series acquired by the Company and available
for future sinking fund requirements.  Upon involuntary liquidation, all
preferred shares are entitled to their par value plus accrued dividends.

The preferred stock subject to mandatory redemption may also be redeemed by
the Company at the following redemption prices per share plus accrued
dividends:  4.84% Series, $102; 4.70% Series, $101; and 8% Series, $101.
The 7.75% Series may be redeemed by the Company, subject to certain
restrictions, at $105.17 per share plus accrued dividends through February
15, 1997 and at per share amounts which decline annually to a price of $100
after February 15, 2007.

45

5)      Additional Paid-in Capital

(Dollars in Thousands)                           1996       1995       1994
----------------------------------------------------------------------------
Balance at beginning of year                 $328,963   $328,753   $329,922
Excess of proceeds over stated values of:
  Common stock issued under the
   stock purchase and
   dividend reinvestment plan                      --         --        124
Par value over cost of reacquired
  preferred stock                                  --        210         68
Issue costs of preferred stock                     --         --     (1,361)
---------------------------------------------------------------------------
Balance at end of year                       $328,963   $328,963   $328,753
===========================================================================

6)      Earnings Reinvested in the Business

Earnings reinvested in the business unrestricted as to payment of cash
dividends on common stock approximated $254 million at December 31, 1996,
under the provisions of the most restrictive covenants applicable to
preferred stock and long-term debt contained in the Company's Articles of
Incorporation and indentures.  The adjustments made to the carrying value of
costs associated with the terminated generating projects and Bonneville
Exchange Power as a result of Statement No. 90 and the disallowance of
certain terminated generating project costs by the Washington Commission do
not impact the amount of earnings reinvested in the business for purposes of
payment of dividends on common stock under the terms of the aforementioned
Articles and indentures.  (See Note 1.)

46

7)      Long-Term Debt

First Mortgage Bonds at December 31: (Dollars in Thousands)
Series   Due      1996      1995     Series    Due      1996      1995
----------------------------------------------------------------------
5.25%   1996  $     --  $ 20,000      7.15%   2002  $  5,000  $  5,000
4.85%   1996        --    15,000      7.625%  2002    25,000    25,000
7.875%  1997   100,000   100,000      7.02%   2003    30,000    30,000
6.17%   1998    10,000    10,000      6.20%   2003     3,000     3,000
5.70%   1998     5,000     5,000      6.40%   2003    11,000    11,000
8.83%   1998    25,000    25,000      7.70%   2004    50,000    50,000
6.50%   1999    16,500    16,500      7.80%   2004    30,000    30,000
6.65%   1999    10,000    10,000      8.06%   2006    46,000    46,000
6.41%   1999    20,500    20,500      8.14%   2006    25,000    25,000
7.25%   1999    50,000    50,000      7.75%   2007   100,000   100,000
6.61%   2000    10,000    10,000      8.40%   2007    10,000    10,000
9.14%   2001    30,000    30,000      8.59%   2012     5,000     5,000
7.85%   2002    30,000    30,000      8.20%   2012    30,000    30,000
7.07%   2002    27,000    27,000      7.35%   2024    55,000    55,000
----------------------------------------------------------------------
Total First Mortgage Bonds                          $759,000  $794,000
======================================================================

Guaranteed Collateralized Bonds at December 31: (Dollars in Thousands)
                                     Series    Due      1996      1995
----------------------------------------------------------------------
                                      8.45%   1996   $    --  $  8,000
----------------------------------------------------------------------
Total Guaranteed Collateralized Bonds                $    --  $  8,000
======================================================================

The Company unconditionally guaranteed all payments of principal, premium
and interest on each series of the Guaranteed Collateralized Bonds issued in
1986 by its wholly-owned subsidiary.

Substantially all electric utility properties owned by the Company are
subject to the lien of the First Mortgage Bonds.

Pollution Control Bonds
-----------------------

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

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

47

Long-Term Debt Maturities
-------------------------

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

(Dollars in Thousands)     1997      1998      1999      2000      2001
---------------------  --------   -------   -------   -------   -------

Maturities of
  long-term debt       $100,000  $ 40,000  $ 97,000  $ 10,000   $ 30,000
========================================================================

8)      Short-Term Debt

At December 31, 1996, the Company had short-term borrowing arrangements
which included a $100 million line of credit with four major banks, a $75
million line of credit with five banks and a $1.5 million line with another
two banks.  In February 1997, the Company replaced the $100 million and $75
million credit lines with a new $400 million line of credit with 15 banks.
The agreements provide the Company with the ability to borrow at different
interest rate options.  For the new $400 million line of credit, the options
are:  (1) the higher of the prime rate or the Federal Funds rate plus 1/2 of
1 percent or (2) the Eurodollar rate plus .30 percent.  The new areement
requires an availability fee of .09 percent per annum on the unused loan
commitment.  Borrowings on the $1.5 million credit line are at the prime
rate and compensating balances of 2-1/2% are required.

In addition, the Company has agreements with several banks to borrow on an
uncommitted, as available, basis at money-market rates quoted by the banks.
There are no costs, other than interest, for these arrangements.  The
Company also uses commercial paper to fund its short-term borrowing
requirements.

At December 31: (Dollars in Thousands)         1996        1995        1994
----------------------------------------    -------     -------     -------

Short-term borrowings outstanding:
  Bank notes                               $ 31,700    $ 44,000    $ 94,900
  Commercial paper notes                   $ 88,713    $123,049    $139,554
  Weighted average interest rate               5.69%       6.00%       6.24%
Unused lines of credit (a)                 $176,500    $176,500    $176,500
---------------------------------------------------------------------------
  (a)  Provides liquidity support for outstanding commercial paper in the
      amount of $88.7 million, $123.0 million and $139.6 million  for 1996,
      1995 and 1994, respectively, effectively reducing the available
      borrowing capacity under these credit lines to $87.8 million, $53.5
      million, and $36.9 million, respectively.

48

9)      Estimated Fair Value of Financial Instruments

The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 1996 and 1995.

                                        1996                    1995
                               -------------------     --------------------
                               Carrying       Fair     Carrying        Fair
(Dollars in Millions)            Amount      Value       Amount       Value
----------------------------   --------    -------     --------     -------
Financial Assets:
  Cash                         $    3.7   $    3.7     $   12.5    $   12.5

Financial Liabilities:
  Short-term debt              $  120.4   $  120.4     $  167.0    $  167.0
  Preferred stock subject to
    mandatory redemption       $   87.8   $   88.5     $   89.0    $   91.2
  Long-term debt               $  920.6   $  952.9     $  963.4    $1,012.8
---------------------------------------------------------------------------

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

The preferred stock subject to mandatory redemption is estimated based on
dealer quotes.

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

10)     Supplementary Income Statement Information

(Dollars in Thousands)                           1996       1995       1994
---------------------------------------------------------------------------
Taxes:
  Real estate and personal property          $ 35,181   $ 32,208   $ 33,050
  State business                               44,422     43,541     42,241
  Municipal, occupational and other            29,337     27,280     25,132
  Payroll                                       8,650      8,638      9,514
  Other                                         4,061      3,512      4,194
---------------------------------------------------------------------------
Total taxes                                  $121,651   $115,179   $114,131
---------------------------------------------------------------------------
Charged to:
  Operating expense                          $116,661   $109,533   $107,821
  Other accounts, including
    construction work in progress               4,990      5,646      6,310
---------------------------------------------------------------------------
Total taxes                                  $121,651   $115,179   $114,131
===========================================================================

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

Other operation expenses in 1994 include charges totaling $20.9 million
related to two early separation and retirement programs and associated
facilities consolidations.  Severance packages accepted by employees totaled

49

$18.3 million, including retirement benefits and pension expenses of $6.9
million.  Facility consolidation expenses were $2.6 million.

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

11)     Leases

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

Rental and operating lease expense for the years ended December 31, 1996,
1995 and 1994 were approximately $15,714,000, $15,119,000 and $13,874,000,
respectively.  Payments due for the years ended December 31, 1996, 1995 and
1994 for the sublease of properties were approximately $1,584,000, $554,000
and $529,000, respectively.

At December 31, 1996, future minimum lease payments for noncancelable leases
are $10,111,000 for 1997, $10,044,000 for 1998, $9,386,000 for 1999,
$8,544,000 for 2000, $8,483,000 for 2001, and in the aggregate $18,153,000
thereafter.  Future minimum sublease receipts for noncancelable subleases
are $828,000 for 1997, $822,000 for 1998, $820,000 for 1999, $766,000 for
2000, $500,000 for 2001, and in the aggregate $791,000 thereafter.

12)     Federal Income Taxes
The details of federal income taxes ("FIT") are as follows:

(Dollars in Thousands)                           1996       1995       1994
---------------------------------------------------------------------------
Charged to Operating Expense:

Current                                       $98,679    $72,020    $63,935
Deferred - net                                (12,126)    12,940     16,739
Deferred investment tax credits                  (311)      (415)      (415)
---------------------------------------------------------------------------
Total FIT charged to operations               $86,242    $84,545    $80,259
===========================================================================
Charged to Miscellaneous Income:
Current                                       $(2,037)   $(1,125)   $(1,253)
Deferred - net                                     --       (476)     1,438
---------------------------------------------------------------------------
Total FIT charged to miscellaneous income     $(2,037)   $(1,601)   $   185
===========================================================================
Total FIT                                     $84,205    $82,944    $80,444
===========================================================================

50

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

(Dollars in Thousands)                             1996      1995      1994
---------------------------------------------------------------------------
FIT at the statutory rate                       $76,852   $76,532   $70,177
---------------------------------------------------------------------------
Increase (Decrease):
  Depreciation expense deducted in
    the financial statements in
    excess of tax depreciation, net
    of depreciation treated as a
    temporary difference                          5,538     5,370     4,717
  AFUDC included in income in the financial
    statements but excluded from taxable income  (2,191)   (2,319)   (2,525)
  Investment tax credit amortization               (311)     (415)     (415)
  Energy conservation expenditures - net          3,380       806     5,607
  Other                                             937     2,970     2,883
---------------------------------------------------------------------------
Total FIT                                       $84,205   $82,944   $80,444
===========================================================================
Effective tax rate                                38.3%     37.9%     40.1%
===========================================================================

The following are the principal components of FIT as reported:

(Dollars in Thousands)                             1996      1995      1994
---------------------------------------------------------------------------
Current FIT                                     $96,642   $70,895   $62,682
===========================================================================
Deferred FIT - other:
  Conservation tax settlement                      (759)       (7)      341
  Periodic rate adjustment mechanism (PRAM)     (26,014)    1,384     9,287
  Deferred taxes related to insurance
    reserves                                       (938)     (938)     (938)
  Terminated generating projects                     --        --    (3,345)
  Reversal of Statement No. 90 present
    value adjustments                               552       688       926
  Residential Purchase and Sale
    Agreement - net                              (2,178)   (4,010)     (624)
  Normalized tax benefits of the
    accelerated cost recovery system             18,071    19,435    19,042
  Energy conservation program                    (1,255)   (1,969)   (2,253)
  Other                                             395    (2,119)   (4,259)
---------------------------------------------------------------------------
Total deferred FIT - other                     $(12,126)  $12,464   $18,177
===========================================================================

Deferred investment tax credits -
  net of amortization                              (311)     (415)     (415)
---------------------------------------------------------------------------
Total FIT                                       $84,205   $82,944   $80,444
===========================================================================

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

51

financial statement purposes because they are not allowed for ratemaking
purposes.

Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("Statement No.
109").  Statement No. 109 requires recording deferred tax balances, at the
currently enacted tax rate, for all temporary differences between the book
and tax bases of assets and liabilities, including temporary differences for
which no deferred taxes had been previously provided because of use of flow-
through tax accounting for rate-making purposes.  Because of prior, and
expected future ratemaking treatment for temporary differences for which
flow-through tax accounting has been utilized, a regulatory asset for income
taxes recoverable through future rates related to those differences has also
been established.  At December 31, 1996, the balance of this asset is $234
million.

The deferred tax liability at December 31, 1996 and 1995 is comprised of
amounts related to the following types of temporary differences:

(Dollars in Thousands)                       1996         1995
--------------------------------------------------------------
Utility plant                            $449,031     $442,425
PRAM                                       14,167       40,181
Energy conservation charges                25,636       32,441
Contributions in aid of construction      (27,355)     (25,425)
Bonneville Exchange Power                  11,622       14,217
Other                                      27,537       24,561
--------------------------------------------------------------
  Total                                  $500,638     $528,400
==============================================================
     
The totals of $501 million and $528 million for 1996 and 1995 consist of
deferred tax liabilities of $540 million and $564 million net of deferred
tax assets of $39 million and $36 million, respectively.

13)     Retirement Benefits

The Company has a noncontributory defined benefit pension plan covering
substantially all of its employees.  Benefits are a function of both years
of service and the average of the five highest consecutive years of basic
earnings within the last ten years of employment.  The Company funds pension
cost using the "frozen entry-age" actuarial cost method.

52

Net pension costs for 1996, 1995 and 1994, including $1,564,000 for 1996,
$1,966,000 for 1995 and $2,752,000 for 1994 which were charged to
construction and other asset accounts, were comprised of the following
components:

(Dollars in Thousands)                           1996       1995       1994
---------------------------------------------------------------------------
Service cost (benefits earned
  during the period)                          $ 6,792    $ 6,129    $ 7,244
Interest cost on projected
  benefit obligation                           16,365     15,656     14,895
Actual return on plan assets                  (38,474)   (53,810)     4,392
Net amortization and deferral                  18,064     35,335    (21,539)
---------------------------------------------------------------------------
Net pension costs under
  FASB Statement No. 87                         2,747      3,310      4,992
---------------------------------------------------------------------------
Regulatory adjustment                           1,263      1,263      1,263
---------------------------------------------------------------------------
Net pension costs                             $ 4,010    $ 4,573    $ 6,255
===========================================================================

Funded Status of Plan
At December 31 (Dollars in Thousands)                       1996       1995
---------------------------------------------------------------------------
Actuarial present value of benefit obligations:
  Vested                                               $(182,805) $(181,367)
  Non-vested                                              (3,274)    (1,387)
----------------------------------------------------------------------------
  Accumulated benefit obligation                        (186,079)  (182,754)
Effect of future compensation levels                     (46,411)   (41,566)
----------------------------------------------------------------------------
    Total projected benefit obligation                  (232,490)  (224,320)
Plan assets at market value                              282,886    254,844
----------------------------------------------------------------------------
Plan assets in excess of projected benefit
  obligation                                              50,396     30,524
Unrecognized net gain due to variance
  between assumptions and experience                     (52,250)   (34,584)
Prior service cost                                         7,819      9,606
Transition asset as of January 1, 1986,
  being amortized on a straight-line
  basis over 18 years                                     (2,934)    (3,354)
Regulatory adjustment, cumulative                          3,664      4,927
---------------------------------------------------------------------------
Prepaid pension cost recognized
  in long-term assets on balance sheet                   $ 6,695   $  7,119

===========================================================================

In December 1995, in connection with the proposed merger with WECo, the
Company offered to its employees a Voluntary Separation Plan.  A total of
204 employees elected to participate in the Voluntary Separation Plan
resulting in a curtailment gain for 1996 of $1.6 million under Statement of
Financial Accounting Standards No. 88.

Assumptions used for the above calculations are as follows:  settlement
(discount) rate for 1996 and 1995 - 7.5% and for 1994 - 8.25%;  rate of
annual compensation increase for 1996 and 1995 - 5.0% and for 1994 - 5.5%;

53

and long-term rate of return on assets for 1996 and 1995 - 9.0% and for 1994
- 8.5%.

Plan assets consist primarily of U.S. Government securities, corporate debt
and equity securities.

The Company has supplemental retirement plans for officer and director level
employees.  Expenses for these plans for 1996, 1995 and 1994 were $817,000,
$916,000, and $1,043,000, respectively.

In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees.  These
benefits are provided principally through an insurance company whose
premiums are based on the benefits paid during the year.

Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" ("Statement No. 106") which requires the costs
associated with postretirement benefits to be accrued over the period of
employment.  The Company is recognizing the impact of Statement No. 106 by
amortizing its transition obligation of $24.9 million to expense over 20
years.  The resulting 1996, 1995 and 1994 annual costs under Statement No.
106 were approximately $2.8 million, $3.6 million, and $3.8 million,
respectively.  In addition, a curtailment loss under Statement No. 106 for
1996 of $1.4 million resulted from the 1995 Voluntary Separation Plan
discussed above.

In the rate order issued by the Washington Commission on September 21, 1993,
the Washington Commission approved adoption of accrual accounting for
postretirement benefits.  For rate purposes, the difference between accrual
and pay-as-you-go accounting will be phased in over five years.  The
Washington Commission's calculation of Statement No. 106 costs for rate
purposes differs from the Company's cost by an insignificant amount.  In
1996, 1995 and 1994, the expenses recognized for postretirement benefits
were $3.8 million, $2.5 million and $2.4 million, respectively.

14)     Employee Investment Plan

The Company has a qualified employee Investment Plan under which employee
salary deferrals and after-tax contributions are used to purchase several
different investment fund options.  The Company makes a monthly contribution
equal to 55% of the basic contribution of each participating employee.  The
basic contribution is limited to 6% of the employee's eligible earnings.
All Company contributions are used to purchase Company common stock on the
open market or directly from the Company.

The Company contributions to the plan were $3,057,000, $3,103,000 and
$3,321,000 for the years 1996, 1995 and 1994, respectively.  The
shareholders have authorized the issuance of up to 2,000,000 shares of
common stock under the plan, of which 959,142 were issued through December
31, 1996.  The employee Investment Plan eligibility requirements are set
forth in the plan documents.

54

15)     Commitments and Contingencies

Commitments

For the twelve months ended December 31, 1996, approximately 32% of the
Company's energy output was obtained at an average cost of approximately 8.7
mills per KWH through long-term contracts with several of the Washington
public utility districts ("PUDs") owning hydroelectric projects on the
Columbia River.

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

As of December 31, 1996, the Company was entitled to purchase portions of
the power output of the PUDs' projects as set forth in the following
tabulation:

                                                Company's Annual Amount
                                     Bonds      Purchasable (Approximate)
                Contract License  Outstanding  ---------------------------
                    Exp.    Exp.  12/31/96(a)   % of    Kilowatt  Costs(b)
Project             Date    Date   (Millions)   Output  Capacity (Millions)
--------------------------------------------------------------------------
Rock Island
  Original units    2012    2029    $ 84.5       57.1 )
                                                        )423,000  $ 45.4
  Additional units  2012    2029     320.9      100.0 )
Rocky Reach         2011    2006(c)  200.0       38.9    482,750    19.3
Wells               2018    2012(c)  183.9       32.3    271,320     9.9
Priest Rapids       2005    2005(c)  186.8        8.0     72,320     2.2
Wanapum             2009    2005(c)  209.1       10.8    106,380     2.8
------------------------------------------------------------------------
Total                                                  1,355,770   $79.6
==========================================================================

     (a) The contracts for purchases initially were generally coextensive
with the term of the PUD bonds associated with the project.  Under the terms
of some financings and refinancings, however, long-term bonds were sold to
finance certain assets whose estimated useful lives extend beyond the
expiration date of the power sales contracts.  Of the total outstanding
bonds sold for each project, the percentage of principal amount of bonds
which mature beyond the contract expiration dates are: 70.7% at Rock Island;
31.8% at Rocky Reach; 71.3% at Priest Rapids; and 46.3% at Wanapum.

     (b) The components of 1997 costs associated with the interest portion
of debt service are:  Rock Island, $24.2 million for all units; Rocky Reach,
$5.3 million; Wells, $2.9 million; Priest Rapids, $0.9 million; and Wanapum,
$1.2 million.

55
     (c) The Company is unable to predict whether the licenses under the
Federal Power Act will be renewed to the current licensees.  In the past
twelve months, the FERC has issued orders for Rocky Reach, Wells and Priest
Rapids/Wanapum projects under Section 22 of the Federal Power Act, which
affirm the Company's contractual rights to receive power under existing
terms and conditions even if a new licensee is granted a license prior to
expiration of the contract term.
-----------------------------

The Company's estimated payments for power purchases from the Columbia River
projects are $80 million for 1997, $79 million for 1998, $81 million for
1999, $83 million for 2000, $84 million for 2001 and in the aggregate $1.05
billion thereafter through 2018.

The Company also has numerous long-term firm purchased power contracts with
other utilities and non-utility generators in the region.  The Company is
generally not obligated to make payments under these contracts unless power
is delivered.  The Company's estimated payments for firm power purchases
from other utilities and non-utility generators, excluding the Columbia
River projects, are $422 million for 1997, $441 million for 1998, $464
million for 1999, $481 million for 2000, $509 million for 2001 and in the
aggregate $5 billion thereafter through 2024.  These contracts have varying
terms and may include escalation and termination provisions.

Total purchased power contracts provided the Company with approximately 17.1
million, 16.4 million and 16.0 million MWH of firm energy at a cost of
approximately $485.6 million, $478.7 million and $450.7 million for the
years 1996, 1995 and 1994, respectively.

The following table indicates the Company's percentage ownership and the
extent of the Company's investment in jointly-owned generating plants in
service at December 31, 1996:
                                                  Company's Share
                                          ------------------------------
                  Energy   Company's         Plant in       Accumulated
                  Source   Ownership      Service at cost   Depreciation
Project           (Fuel)   Share (%)        (Millions)       (Millions)
--------------    ------   ---------      --------------    ------------
Centralia          Coal        7              $ 27.4          $ 17.3
Colstrip 1 & 2     Coal       50               184.7            96.4
Colstrip 3 & 4     Coal       25               450.3           154.6
------------------------------------------------------------------------

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

Certain purchase commitments have been made in connection with the Company's
construction program.

Contingencies

The Company is subject to environmental regulation by federal, state and
local authorities.  The Company has been named a Potentially Responsible
Party by the Environmental Protection Agency ("EPA") at four sites.  The
Company has also instituted an ongoing program to test, replace and
remediate certain underground storage tanks as required by federal and state

56

laws.  Remediation and testing of Company vehicle service facilities and
storage yards is also continuing.

On April 1, 1992, the Washington Commission issued an order regarding the
treatment of costs incurred by the Company for certain sites under its
environmental remediation program.  The order authorizes the Company to
accumulate and defer prudently incurred cleanup costs paid to third parties
for recovery in rates established in future rate proceedings.  The Company
believes a significant portion of its past and future environmental
remediation costs are recoverable from either insurance companies, third
parties or under the Washington Commission's order.

The Company has expended approximately $14.3 million related to the
remediation activities covered by the Washington Commission's order, of
which approximately $5.7 million has been recovered from insurance carriers.
At December 31, 1996, approximately $2.1 million has been accrued as a
liability for future remediation costs for these and other remediation
activities.  At December 31, 1996, an asset of approximately $10.0 million
has been recorded related to expected future recoveries.

Other contingencies, arising out of the normal course of the Company's
business, exist at December 31, 1996.  The ultimate resolution of these
issues is not expected to have a material adverse impact on the financial
condition, results of operations or liquidity of the Company.

16)     Supplemental Quarterly Financial Data (Unaudited)

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


1996 Quarter Ended            March 31     June 30    Sept. 30     Dec. 31
--------------------------------------------------------------------------
                            (Dollars in thousands except per share amounts)

Operating revenues            $331,009    $257,317    $252,882    $357,561
Operating income              $ 64,688    $ 39,899    $ 33,004    $ 62,985
Other income                  $  1,119    $    860    $  6,040    $  3,841
Net income                    $ 46,419    $ 21,632    $ 20,121    $ 47,199
Earnings per common share     $   0.67    $   0.28    $   0.26    $   0.68
--------------------------------------------------------------------------

1995 Quarter Ended            March 31     June 30    Sept. 30     Dec. 31
--------------------------------------------------------------------------
                            (Dollars in thousands except per share amounts)

Operating revenues            $338,345    $261,592    $248,584    $330,809
Operating income              $ 70,359    $ 42,938    $ 37,001    $ 64,290
Other income                  $  1,682    $  2,587    $  2,258    $  1,149
Net income                    $ 48,746    $ 22,863    $ 19,019    $ 45,091
Earnings per common share     $   0.70    $   0.30    $   0.24    $   0.65
--------------------------------------------------------------------------

57

17)     Consolidated Statement of Cash Flows

For purposes of the Statement of Cash Flows, the Company considers all
temporary investments to be cash equivalents.  These temporary cash
investments are securities held for cash management purposes, having
maturities of three months or less.  The net change in current assets and
current liabilities for purposes of the Statement of Cash Flows excludes
short-term debt, current maturities of long-term debt and the current
portion of PRAM accrued revenues.

The following provides additional information concerning cash flow
activities:

Year Ended December 31: (Dollars in Thousands)   1996       1995       1994
---------------------------------------------------------------------------
Changes in certain current
  assets and current liabilities:
    Accounts receivable                      $(12,727)  $(16,498)  $(16,725)
    Unbilled revenues                         (13,201)     6,382      2,521
    Materials and supplies                      9,724      3,136      2,840
    Prepayments and Other                         442        908        (75)
    Accounts payable                           21,422     (7,756)     4,576
    Accrued expenses and Other                  4,301     (3,736)       884
---------------------------------------------------------------------------
Net change in certain current assets
  and current liabilities                    $  9,961   $(17,564)  $ (5,979)
===========================================================================
Cash payments:
    Interest (net of capitalized interest)   $ 78,624   $ 90,015   $ 83,959
    Income taxes                             $ 98,609   $ 74,273   $ 63,477
---------------------------------------------------------------------------

18)  Merger with Washington Energy Company

On February 7, 1997, the Boards of the Company and WECo approved the merger
of their respective companies effective February 10, 1997.  The merged
company is called Puget Sound Energy, Inc.  This announcement followed the
approval by the Washington Commission, on February 5, 1997, of a merger
agreement between the Company, WECo, the Staff of the Washington Commission
and the Public Counsel Section of the State Attorney General's Office.
Shareholders of the Company and WECo, voting as separate groups had, on
March 20, 1996, already given their approval to an Agreement and Plan of
Merger ("Merger Agreement") between the two companies.

The Merger Agreement called for each share of WECo common stock to be
exchanged for 0.86 share of the Company's common stock (approximately
20,921,000 shares of Company stock are expected to be issued).  On February
10, 1997, the Company increased the number of authorized shares to
150,000,000.  Based on the capitalization of the Company and WECo on
February 10, 1997, holders of the Company's and WECo's common stock held
approximately 75% and 25% respectively, of the aggregate number of
outstanding shares of the merged company's common stock.  In addition, the
Agreement called for the preferred stock of Washington Natural Gas Company,
a wholly-owned subsidiary of WECo, to be converted into preferred shares of
the merged company.  The merger has been structured as a tax-free exchange
of shares, and is expected to be accounted for as a pooling of interests for
financial statement purposes.

58

The order approving the merger, issued by the 
Washington Commission, contains a rate plan that is designed to provide a
five-year period of rate certainty for customers and provide the Company
with an opportunity to achieve a reasonable return on investment.  As
required under the stipulated settlementmerger order, the Company filed
tariffs, effective February 8, 1997, that resulted in an average electric
rate decrease of 5.6% related to the PRAM, and an increase in general rates
of between 1.0% and 2.5%, depending on rate class.  The net impact was an
average rate decrease of 3.7%, including a decrease in residential rates of
3.24%.  General electric rates for residential and industrial customers will
increase by 1.5% on January 1 of each of the four following years, while
those for small commercial customers will increase by 1.0% in each of the
following three years.  General rates for all classes of natural gas
customers will remain unchanged until January 1, 1999, when they will
decrease sufficiently to reduce utility margin by 1 percent.

In connection with the merger, through December 31, 1996, the Company has
incurred direct merger related costs and indirect costs related to
integration of the operations of the Company and WECo, (including costs
related to a voluntary early separation plan accepted by 204 employees of
the Company - under terms of the plan, certain employees were terminated in
1996 and termination of others was subject to completion of the merger).
Indirect costs of $4.8 million were expensed in the fourth quarter of 1996.
Direct costs of $6.0 million have been deferred and will be expensed in the
first quarter of 1997, as of the merger consummation date.

The Company currently estimates that additional direct and indirect merger
costs of $33 million, including approximately $8 million deferred by WECo
and $25 million of additional costs will be incurred and charged to expense
in 1997.  These estimates are subject to revision as the integration process
proceeds.

Unaudited pro forma information (assuming the merger had been completed as
of December 31, 1996) as of December 31, 1996 and for the three years in the
period ended December 31, 1996, follows.  Information for WECo is as of
September 30, 1996, and for three years in the period ended September 30,
1996 (the fiscal year-end of WECo).

59

Pro Forma Balance Sheet Information
                                                                  Pro Forma
(Thousands except per share amounts)        Puget         WECo        Total
------------------------------------    ---------    ---------    ---------
Total Assets:                          $3,187,252   $1,034,436   $4,221,688
                                        =========    =========    =========
Capitalization:
  Common Equity                        $1,179,026   $  199,351   $1,378,377
  Preferred Stock                         212,839       90,000      302,839
  Long-term debt                          820,664      344,920    1,165,584
Other Liabilities                         974,723      400,165    1,374,888
                                        ---------    ---------    ---------
    Total capitalization and
      liabilities                      $3,187,252   $1,034,436   $4,221,688
===========================================================================

Pro Forma Income Statement Information
                                                             Pro Forma
Year ended December 31, 1996           Puget       WECo          Total
---------------------------------  ---------  ---------      ---------
Revenues                          $1,198,769 $  425,711     $1,624,480
Net Income                        $  135,371 $   23,128     $  165,519(a)
Income available for common stock $  120,210 $   23,128     $  143,338
Earnings per common share         $     1.89 $      .96(b)  $     1.70(a)(b)
Weighted average common
  shares outstanding                  63,641     24,159         84,418(a)

----------------------------------------------------------------------
                                                             Pro Forma
Year ended December 31, 1995           Puget       WECo          Total
---------------------------------  ---------  ---------      ---------
Revenues                          $1,179,330 $  443,611     $1,622,941
Net Income                        $  135,720 $  (41,062)    $  101,784(a)
Income available for common stock $  120,192 $  (41,062)    $   79,130
Earnings per common share         $     1.89 $    (1.72)(b) $     0.94(a)(b)
Weighted average common
  shares outstanding                  63,641     23,893         84,189(a)

----------------------------------------------------------------------
60

                                                             Pro Forma
Year ended December 31, 1994           Puget       WECo          Total
---------------------------------  ---------  ---------      ---------
Revenues                          $1,194,058 $  432,025     $1,626,083
Net Income                        $  120,059 $  (45,646)    $   78,383(a)
Income available for common stock $  104,328 $  (46,328)    $   58,000
Earnings per common share         $     1.64 $    (1.97)(b) $     0.69(a)(b)
Weighted average common
  shares outstanding                  63,632     23,486         83,830(a)

======================================================================

(a)  Pro Forma totals do not add across as a result of adjustments giving
effect to the merger exchange ratio and the effects of the exchange of
Company preferred stock for preferred stock of WECo's wholly-owned
subsidiary.

(b)  WECo and Pro Forma earnings per share include amounts related to
discontinued operations as follows:  1996, $.07 and $.02, respectively;
1995, $1.11 and $.32, respectively; and 1994, $.04 and $.01, respectively.

In connection with the merger, the Company paid, subsequent to year end, a
dividend on the shares issued to WECo shareholders of $.02 per share,
representing a dividend for the period February 11, 1997 through February
15, 1997, the date of payment for the latest Company dividend.

61

<TABLE>
<CAPTION>
Puget Sound Energy, Inc.
Schedule II.  Valuation and Qualifying Accounts and Reserves
-----------------------------------------------------------------------------------
                                           (Dollars in Thousands)
-----------------------------------------------------------------------------------
     Column A                    Column B      Column C      Column D      Column E
-----------------------------------------------------------------------------------

                                              Additions
                               Balance at    Charged to                     Balance
                                Beginning     Costs and                      at End
                                of Period      Expenses    Deductions     of Period
                               ----------    ----------    ----------    ----------
<S>                            <C>           <C>           <C>           <C>
Year Ended December 31, 1996
----------------------------
Accounts deducted from assets
on balance sheet:
  Allowance for doubtful
    accounts receivable            $  886       $4,073         $4,189        $  770
===================================================================================

Year Ended December 31, 1995
----------------------------
Accounts deducted from assets
on balance sheet:
  Allowance for doubtful
    accounts receivable             $ 610       $4,527         $4,251        $  886
===================================================================================

Year Ended December 31, 1994
----------------------------
Accounts deducted from assets
on balance sheet:
  Allowance for doubtful
    accounts receivable             $ 523       $3,537         $3,450        $  610
===================================================================================
</TABLE>

62
                                 EXHIBIT INDEX

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

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

      2.2   Puget Sound Power & Light Company Stock Option Agreement dated as
of October 18, 1995, between Puget Sound Power & Light Company and Washington
Energy Company.  (Exhibit 2.2 to Registration No. 333-617)

      2.3   Washington Energy Company Stock Option Agreement dated as of
October 18, 1995, between Washington Energy Company and Puget Sound Power &
Light Company.  (Exhibit 2.3 to Registration No. 333-617)

       3-a   Restated Articles of Incorporation of the Company.  (Included as
Annex F to the Joint Proxy Statement/Prospectus filed February 1, 1996)

       3-b   Restated Bylaws of the Company.  (Exhibit 4-b to Registration
No. 33-18506)

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

       4.2   Credit Agreement dated as of December 1, 1991, among the Company
and various banks named therein, Seattle-First National Bank as Agent.
(Exhibit (4)-d to Registration No. 33-45916)

       4.3   Credit Agreement dated as of December 1, 1991, among the Company
and various banks named therein, Bank of New York as Agent.  (Exhibit (4)-e
to Registration No. 33-45916)

       4.4   Final form of Indenture dated as of November 1, 1986, among
Puget Energy, the Company, and The First National Bank of Boston, as Trustee.
(Exhibit 4-a to Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1986, Commission File No. 1-4393)

       4.5   Final form of Pledge Agreement dated November 1, 1986, between
the Company and The First National Bank of Boston, as Trustee. (Exhibit 4-c
to Company's Quarterly Report on Form 10-Q for the quarter ended September
30, 1986, Commission File No. 1-4393)

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

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

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

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

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

       4.11  Statement of Relative Rights and Preferences for the Adjustable
Rate Cumulative Preferred Stock, Series B ($25 Par Value).  (Exhibit 1.1 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)

       4.12  Statement of Relative Rights and Preferences for the Series A
Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred
Stock.  (Exhibit 1.3 to Registration Statement on Form 8-A filed February 14,
1994, Commission File No. 1-4393)

       4.13  Statement of Relative Rights and Preferences for the Series B
Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred
Stock.  (Exhibit 1.4 to Registration Statement on Form 8-A filed February 14,
1994, Commission File No. 1-4393)

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

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

       4.16  Statement of Relative Rights and Preferences for the 7 7/8%
Series Preferred Stock Cumulative, $25 Par Value.  (Exhibit 1.7 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)

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

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

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

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

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

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

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

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

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

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

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

      10.8   Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 1 of Douglas County, Washington and
the Company, relating to the Wells Development.  (Exhibit 13-u to
Registration No. 2-24252)
      10.9   Pacific Northwest Coordination Agreement, executed as of
September 15, 1964, among the United States of America, the Company and
most of the other major electrical utilities in the Pacific Northwest.
(Exhibit 13-gg to Registration No. 2-24252)

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

      10.28  Restated Financing Agreement among the Company, lessee,
Chrysler Financial Corporation, owner, Nevada National Bank and Bank of
Montreal (California), trustee, dated December 12, 1974 pertaining to a
combustion turbine generating unit trust.  (Exhibit 5-a-35 to Registration
No. 2-60200)

      10.29  Restated Lease Agreement between the Company, lessee, and the
Bank of California, and National Association, lessor, dated December 12,
1974 for one combustion generating unit.  (Exhibit 5-a-36 to Registration
No. 2-60200)

      10.30  Financing Agreement Supplement and Amendment among the Company,
lessee, Chrysler Financial Corporation, owner, The Bank of California,
National Association, trustee, Pacific Mutual Life Insurance Company,
Bankers Life Company, and The Franklin Life Insurance Company, lenders,
dated as of March 26, 1975, pertaining to a combustion turbine generating
unit trust.  (Exhibit 5-a-37 to Registration No. 2-60200)

      10.31  Lease Agreement Supplement and Amendment between the Company,
lessee, and The Bank of California, National Association, lessor, dated as
of March 26, 1975 for one combustion turbine generating unit.  (Exhibit 5-a-
38 to Registration No. 2-60200)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

      10.78  Power Sales Agreement between The Montana Power Company and the
Company, dated as of October 1, 1989.  (Exhibit (10)-4 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-
4393)
      10.79  Conservation Power Sales Agreement dated as of December 11,
1989, between Public Utility District No. 1 of Snohomish County and the
Company.  (Exhibit (10)-87 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1989, Commission File No. 1-4393)

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

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

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

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

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

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

      10.86  Settlement Agreement dated as of October 1, 1990, among Public
Utility District No. 1 of Douglas County, Washington, the Company, Pacific
Power and Light Company, The Washington Water Power Company, Portland General
Electric Company, the Washington Department of Fisheries, the Washington
Department of Wildlife, the Oregon Department of Fish and Wildlife, the
National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the
Confederated Tribes and Bands of the Yakima Indian Nation, the Confederated

Tribes of the Umatilla Reservation, and the Confederated Tribes of the
Colville Reservation.  (Exhibit (10)-95 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)

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

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

      10.89  Agreement for Firm Power Purchase dated September 26, 1990,
between Encogen Northwest, L.P., A Delaware Corporation and the Company.
(Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended March
31, 1991, Commission File No. 1-4393)

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

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

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

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

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

      10.95  Amendment dated July 11, 1991, to the Agreement for Firm Power
Purchase dated September 26, 1990, between Encogen Northwest, L.P., a
Delaware limited partnership and the Company.  (Exhibit (10)-1 to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1991, Commission File
No. 1-4393)

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

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

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

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

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

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

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

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

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

     10.105  Memorandum of Termination dated August 31, 1992, between Encogen
Northwest, L.P. and the Company.  (Exhibit (10)-115 to Annual Report on Form
10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)

     10.106  Agreement Regarding Security dated August 31, 1992, between
Encogen Northwest, L.P. and the Company.  (Exhibit (10)-116 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)

      10.107  Consent and Agreement dated December 15, 1992, between the
Company, Encogen Northwest, L.P. and The First National Bank of Chicago, as
collateral agent.  (Exhibit (10)-117 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)

      10.108  Subordination Agreement dated December 17, 1992, between the
Company, Encogen Northwest, L.P., Rolls-Royce & Partners Finance Limited and
The First National Bank of Chicago.  (Exhibit (10)-118 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-
4393)

     10.109  Letter Agreement dated December 18, 1992, between Encogen
Northwest, L.P. and the Company regarding arrangements for the application of
insurance proceeds.  (Exhibit (10)-119 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)

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

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

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

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

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

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

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

    *10.117  Power Exchange Agreement dated as of September 27, 1995, between
British Columbia Power Exchange Corporation and the Company.

    *10.118  Contract with W. S. Weaver, Executive Vice President and Chief
Financial Officer, dated October 18, 1996.

    *10.119  Contract with S. M. Vortman, Senior Vice President Corporate and
Regulatory Relations, dated October 18, 1996.

    *10.120  Contract with G. B. Swofford, Senior Vice President Customer
Operations, dated October 18, 1996.

    *12-a    Statement setting forth computation of ratios of earnings to
fixed charges (1992 through 1996).

    *12-b    Statement setting forth computation of ratios of earnings to
combined fixed charges and preferred stock dividends (1992 through 1996).

     *21     List of subsidiaries.

     *23     Consent of accountants.

     *27     Financial Data Schedule

     *99     Pro Forma Statements of Puget Sound Energy, Inc.

_________________________________
*Filed herewith.