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

                                        FORM 10-K

    [X]           ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
                             SECURITIES EXCHANGE ACT OF 1934
                       FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
                                          OR
    [  ]        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                             SECURITIES EXCHANGE ACT OF 1934
           For the Transition period from ________________ to _______________

                            Commission File Number 1-5532-99

                            PORTLAND GENERAL ELECTRIC COMPANY
                 (Exact name of registrant as specified in its charter)

OREGON                                                    93-0256820
(State or other jurisdiction of                           (I.R.S. Employer
incorporation or organization)                            Identification No.)

                                                                        

                 121 SW SALMON STREET, PORTLAND, OREGON 97204
              (Address of principal executive offices) (zip code)

      Registrant's telephone number, including area code: (503) 464-8000

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

                                               
                                              NAME OF EACH EXCHANGE
TITLE OF EACH CLASS                           ON WHICH REGISTERED

  Portland General Electric Company
    8.25% Quarterly Income Debt Securities
    (Junior Subordinated Deferrable 
    Interest Debentures, Series A)             New York Stock Exchange

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

Portland General Electric Company,
    7.75% Series, Cumulative Preferred Stock, 
    no par value                                None

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 ]

State the aggregate market value of  the voting stock held by non-affiliates of
the registrant as of February 28, 1999:  $0.

Indicate the number of shares outstanding  of  each of the registrant's classes
of common stock, as of February 28, 1999: 42,758,877  shares  of  Common Stock,
$3.75 par value. (All shares are owned by Enron Corp.)


<PAGE>
                                  DEFINITIONS

The following abbreviations or acronyms used in the text and notes  are defined
below:

Abbreviations
 OR Acronyms                         Term

AFDC................................Allowance for Funds Used During
                                    Construction
Beaver..............................Beaver Combustion Turbine Plant
Bethel..............................Bethel Combustion Turbine Plant
Boardman............................Boardman Coal Plant
BPA.................................Bonneville Power Administration
Centralia...........................Centralia Coal Plant
Colstrip............................Colstrip Units 3 and 4 Coal Plant
Coyote Springs......................Coyote Springs Generation Plant
CUB.................................Citizens' Utility Board
DEQ.................................Oregon Department of Environmental Quality
Enron...............................Enron Corp.
EFSC................................Energy Facility Siting Council
EPA.................................Environmental Protection Agency
FERC................................Federal Energy Regulatory Commission
Financial Statements................Refers to Financial Statements of Portland
                                    General Electric Company included in 
                                    Part II, Item 8 of this report 
KWh.................................Kilowatt-hour
MW..................................Megawatt
MWa.................................Average megawatts
MWh.................................Megawatt-hour
NRC.................................Nuclear Regulatory Commission
NYMEX...............................New York Mercantile Exchange
OPUC or the Commission..............Oregon Public Utility Commission
PGE or the Company..................Portland General Electric Company
PUD.................................Public Utility District
Regional Power Act..................Pacific Northwest Electric Power Planning
                                    and Conservation Act
SFAS................................Statement of Financial Accounting Standards
                                    issued by the FASB
Trojan..............................Trojan Nuclear Plant
USDOE...............................United States Department of Energy
WAPA................................Western Area Power Authority
WNP-3...............................Washington Public Power Supply System 
                                    Unit 3 Nuclear Project
WSCC................................Western Systems Coordinating Council

<PAGE>

                               TABLE OF CONTENTS
                                                                          PAGE

Definitions................................................................. 2

PART I
      Item 1.  Business....................................................  4

      Item 2.  Properties.................................................. 13

      Item 3.  Legal Proceedings........................................... 15


PART II
      Item 5.  Market for Registrant's Common Equity and
               Related Stockholder Matters................................. 17

      Item 6.  Selected Financial Data..................................... 17

      Item 7.  Management's Discussion and Analysis of Financial
               Condition and Results of Operations......................... 18

      Item 8.  Financial Statements and Supplementary Data................. 34

      Item 9.  Changes in and Disagreements with Accountants on
               Accounting and Financial Disclosure......................... 53

PART III
      Item 10. Directors and Executive Officers of the Registrant.......... 54

      Item 11. Executive Compensation...................................... 57

      Item 12. Security Ownership of Certain Beneficial Owners
               and Management.............................................. 63

      Item 13. Certain Relationships and Related Transactions.............. 63

PART IV
      Item 14. Exhibits, Financial Statement Schedules and
               Reports on Form 8-K......................................... 64

Signatures................................................................. 65

Exhibit Index.............................................................. 66

<PAGE>

                                       Part I

ITEM 1. BUSINESS
                                       
                                    GENERAL

PGE,  incorporated  in  1930, is an electric utility engaged in the generation,
purchase, transmission, distribution,  and  sale of electricity in the State of
Oregon.  PGE also sells energy to wholesale customers  throughout  the  western
United  States.   PGE's  Oregon  service  area is 3,170 square miles, including
54 incorporated cities, of which Portland and  Salem  are the largest, within a
state-approved service area allocation of 4,070 square  miles.   PGE  estimates
that  at  the  end  of  1998  its  service  area  population  was approximately
1.5  million,  constituting  approximately  44% of the state's population.   At
December 31, 1998 PGE served approximately 704,000 customers.

On July 1, 1997 Portland General Corporation  (PGC), the former parent of  PGE,
merged  with  Enron Corp. (Enron) with Enron continuing  in  existence  as  the
surviving corporation.  PGE  is  now  a  wholly  owned  subsidiary of Enron and
subject to control by the Board of Directors of Enron.

As of December 31, 1998, PGE had 2,728 employees.  This compares  to  2,729 and
2,587 PGE employees at December 31, 1997 and 1996, respectively.


                              OPERATING REVENUES

RETAIL
PGE  serves  a  diverse retail customer base.  Residential customers constitute
the largest customer  class  and  account for approximately 48% of total retail
revenues, with Commercial and Industrial  customers accounting for 38% and 14%,
respectively.   Residential  demand  is highly  sensitive  to  the  effects  of
weather,  with  company revenues highest  during  the  winter  heating  season.
Electricity sales to both Commercial and Industrial customers declined somewhat
in 1998 due to the  effects  of  PGE's  Customer  Choice  pilot  program, which
allowed  some  customers  to  buy  their  power  from  competing energy service
providers;  this  program terminated at the end of 1998.   The  commercial  and
industrial classes  are  not  dominated  by  any single industry.  While the 20
largest  customers constitute about 22% of retail  demand,  they  represent  10
different  industrial  groups,  including paper manufacturing, high technology,
metal fabrication, transportation  equipment,  and  health services.  No single
customer represents more than 6% of PGE's total retail load.

In  late 1997 PGE filed a proposal before the OPUC which  would  give  all  its
customers a choice of electricity providers as early as January 1, 1999.  PGE's
Customer Choice proposal included new price tariffs and a new structure for the
company  in  which  PGE  would become a regulated transmission and distribution
company focused on delivering,  but  not selling electricity.  In January 1999,
the OPUC issued an order recommending  that  PGE  offer its customers a limited
set  of options, including the ability to continue to  purchase  rate-regulated
electricity,  with most commercial and industrial customers able to chose their
electricity provider  through  direct  access.   The Commission's order further
requires  PGE  to refile a new rate case should it choose  to  adopt  the  plan
recommended by the order, which is also contingent upon the adoption of certain
statutory changes  by  the Oregon Legislature.  Until such changes are made and
agreed upon among all parties,  PGE  will  not  be implementing its proposal or
accompanying new rate structure.

<PAGE>


WHOLESALE
Wholesale electricity sales comprised about 20% of  total operating revenues in
1998,  down  from  about 35% in 1997.  During the last several  years  PGE  has
actively marketed wholesale  power  throughout  the western United States, with
significant sales growth since 1994; most of such growth has come through sales
to  marketers  and brokers and have been predominantly  short-term.   PGE  will
continue its participation in the wholesale marketplace in order to balance its
supply of power  to  meet  the  needs of its retail customers, manage risk, and
administer  its current long-term  wholesale  contracts.   Long-term  wholesale
trading activities  have  been  transferred to a non-regulated Enron affiliate,
which participates more fully in  a broader market.  PGE expects that its future
revenues from the wholesale marketplace will decline.

The following table summarizes operating  revenues  and MWh sales for the years
ended December 31:

<TABLE>
<CAPTION>
                                                  1998              1997              1996
<S>                                               <C>               <C>               <C>
Operating Revenues (Millions)
     Residential                                   $ 432             $ 391             $ 427
     Commercial (1)                                  345               354               357
     Industrial                                      132               144               149
         Tariff Revenues                             909               889               933
         Accrued (Collected) Revenues                (8)                10              (27)
     Retail                                          901               899               906
     Wholesale                                       234               497               194
     Other                                            41                21                10
         Total Operating Revenues                 $1,176            $1,417            $1,110
Megawatt-Hours Sold (Thousands)
     Residential                                   7,101             6,999             7,073
     Commercial (1)                                6,781             6,973             6,577
     Industrial                                    3,562             4,247             3,909
        Retail                                    17,444            18,219            17,559
        Wholesale                                 10,869            26,934            10,188
           Total MWh Sold                         28,313            45,153            27,747


       Energy Delivered to ESP Customers (2)       1,292                 2                 0

       Total MWh Sold and Delivered               29,605            45,155            27,747



<FN>
(1) Includes Public Street Lighting.
(2) Represents energy delivered to customers of Energy  Service Providers under
PGE's  Customer Choice Pilot Program        (described further  in  "Regulatory
Matters").
</FN>
</TABLE>

For  additional  information  on  year-to-year  revenue  trends,  see  Item  7.
Management's  Discussion  and  Analysis  of  Financial Condition and Results of
Operations.

<PAGE>
                                  REGULATION

The OPUC, a three-member commission appointed  by  the Governor, approves PGE's
retail rates and establishes conditions of utility service.   The  OPUC ensures
that  prices are fair and equitable and provides PGE an opportunity to  earn  a
fair return on its investment.  In addition, the OPUC regulates the issuance of
securities  and  prescribes  the  system  of  accounts  to  be  kept  by Oregon
utilities.

PGE  is  also  subject  to  the  jurisdiction  of  the  FERC with regard to the
transmission and sale of wholesale electric energy, licensing  of hydroelectric
projects and certain other matters.

Construction  of  new generating facilities requires a permit from  the  Energy
Facility Siting Council (EFSC).

The NRC regulates the  licensing  and  decommissioning of nuclear power plants.
In 1993 the NRC issued a possession-only  license  amendment  to  PGE's  Trojan
operating  license  and in early 1996 approved the Trojan Decommissioning Plan.
Approval of the Trojan Decommissioning Plan by the NRC and EFSC has allowed PGE
to begin decommissioning  activities,  which  are proceeding satisfactorily and
within approved cost estimates.  PGE received regulatory  approval  in  1998 to
ship  and dispose of the Trojan reactor vessel as a single package, called  the
Reactor  Vessel And Internals Removal Project (RVAIR).  In 1998 PGE applied for
approval of  the  Independent  Spent Fuel storage Installation (ISFSI) project,
and expects full approval in 1999.   Equipment  removal and disposal activities
will also continue in 1999.  Trojan will be subject  to NRC regulation until it
is fully decommissioned, all nuclear fuel is removed from  the  site,   and the
license  terminated.   The  Oregon  Department  of Energy also monitors Trojan.
(For  further  information,  see  "Nuclear Decommissioning"  in    Item  7.  -
"Management's Discussion and Analysis  of  Financial  Condition  and Results of
Operations").

<PAGE>
                               REGULATORY MATTERS

CUSTOMER CHOICE

PROPOSAL
In late 1997 PGE filed a proposal before the OPUC to give all of its  customers
a  choice  of electricity providers as early as 1999.  Under the proposal,  PGE
would become  a  regulated  transmission  and   distribution company focused on
delivering, but not selling, electricity.  PGE would  continue  to  operate and
maintain  the electricity delivery system and handle outage restoration,  while
other competitive  companies  would market power to customers over that system.
To effect this restructuring, PGE  asked  for  OPUC  approval  to  sell all its
generating assets, power supply and purchase contracts.

In  July  1998,  the  OPUC  staff  issued  its position, disagreeing with PGE's
proposal for full customer choice.  On January  28,  1999,  the  OPUC issued an
order recommending that PGE offer customers a limited set of options, including
the  ability to continue to purchase rate-regulated electricity.  In  addition,
most commercial  and  industrial  customers (those with demand exceeding 30 kW)
would  be  able to choose their electricity  provider  through  direct  access.
Although the  order  would allow PGE to sell its coal- and gas-fired generation
plants, it rejected PGE's  request  to  sell  its  hydroelectric  assets.   The
Commission's  order  further  requires  PGE to refile a new rate case should it
choose to adopt the plan recommended by the  order,  which  is  also contingent
upon  the  adoption  of  certain  statutory  changes by the Oregon Legislature.
Until such changes are made and agreed upon among  all parties, PGE will not be
implementing its proposal or accompanying new rate structure.

The  issue  of  restructuring  will be further addressed  by  the  1999  Oregon
Legislature; PGE is reviewing the  OPUC  order  and  will encourage legislation
that creates a comprehensive approach to the electricity  industry  that  helps
develop a market that is truly competitive.

INTRODUCTORY PROGRAM
PGE  initiated the Customer Choice Introductory Program as a one-year pilot  to
test deregulation  readiness  by  allowing certain customers to buy their power
from competing energy service providers.   The  program,  approved by the OPUC,
was made available to about 50,000 residential, small business  and  commercial
customers  in  four  cities  and  industrial customers throughout PGE's service
territory.  At its peak, over 8,700  -  almost  17  percent  of eligible retail
customers  -  had  selected  from  among  eight  participating  energy  service
providers.    The one-year pilot program terminated on December 31,  1998,  and
all participating customers returned to PGE.

The  Customer Choice Introductory Program provided valuable information to PGE,
the OPUC,  and  legislators on the effects of retail competition on PGE and its
customers.  An extensive  independent  assessment  of the program was completed
and  made  available to interested parties, including  the  State  Legislature.
Such assessment  indicated  wide  satisfaction  by  both  customers  and energy
service   providers,  with  lower  prices  and  the  ability  to  choose  their
electricity supplier cited as primary reasons for customer participation.

LEAST COST ENERGY PLANNING
The OPUC adopted Least Cost Energy Planning for all energy utilities in Oregon,
with the goal  of  selecting the mix of resources that yields a reliable supply
of energy at the least cost to customers.  PGE has filed for formal approval of
its  1998-1999  Integrated  Resource  Plan  (IRP)  with  the  OPUC.   The  plan
recognizes  fundamental   changes   occurring  in  the  electric  industry  and
establishes  a transition strategy for  the  next  two  years.  The  plan  will
maintain PGE's  delivery  capability  and  provides  a  bridge to a competitive
environment  in  which funding for public purposes is provided  from  a  System
Benefit Charge.

RESIDENTIAL EXCHANGE PROGRAM
In 1980, the Regional  Power  Act  (RPA)  was passed by Congress in response to
growing power supply and cost inequities between  customers  of  government and
publicly-owned utilities, who have priority access to low-cost power  from  the
federal  hydroelectric  system,  and  the customers of investor-owned utilities
("IOUs").  The RPA created the Residential  Exchange Program to ensure that all
residential and small farm customers in the region,  the  majority of which are
served by IOUs, receive similar benefits from the publicly funded federal power

<PAGE>

system.  Exchange benefits are passed directly to PGE's customers  in  the form
of  price  adjustments  contained  in  OPUC-approved tariffs.  In January 1998,
rates for PGE's residential and small farm customers increased 11.9% due to the
Bonneville Power Administration's (BPA) elimination of the Residential Exchange
Credit.  PGE contested this decision and in September 1998 signed a Residential
Exchange Termination Agreement with BPA  that  provides  for  a  total of $34.5
million  in  BPA  payments  through  September  2000  and  continues to provide
benefits to PGE's residential and small farm customers through  at  least  June
2001;  the  current  customer  credit  under  the  Residential Exchange Program
amounts to about 1% to 2% on the average monthly electricity  bill.   This  new
agreement  with  BPA  allowed  for a retail rate rollback in late 1998 to a net
increase of 5.7%.

ENERGY EFFICIENCY
PGE has long promoted the efficient  use  of  electricity.  Current Demand Side
Management (DSM) programs provide a range of services  to  all  classes  of PGE
customers and seek to maximize those opportunities in which efficiency measures
are most cost-effective for both PGE ratepayers and customers.  In order to  do
this,  PGE  is focusing on both commercial and  industrial new construction and
industrial process  improvements,  and  continues  to  provide a weatherization
program for eligible low-income families.  PGE is also focusing on developing a
regional solution to funding and delivering energy efficiency  in a competitive
environment.


                           COMPETITION AND MARKETING

GENERAL
As electricity deregulation moves forward nationally, PGE continues to maintain
its  commitment  to  service excellence while assisting in the formation  of  a
competitive electricity  market  in  the  Northwest.  Its Customer Choice Pilot
Program was successfully implemented in 1998  and provided valuable information
on  the  effects  of  retail  competition  on  PGE and  its  customers.   PGE's
deregulation  strategy encompasses five key principles:  bringing  true  market
conditions to the industry, separating the regulated and non-regulated portions
of utility services,  removing  the  incumbent  utility advantage, transferring
commercial customer relationships to the energy service  provider  and allowing
the  market  to  determine  the  cost  of  transitioning from a regulated to  a
deregulated environment.  The outcome of PGE's  efforts  to  help create a more
competitive electricity market will depend in large part on both  statutory and
regulatory changes.

RETAIL COMPETITION AND MARKETING
PGE operates within a state-approved service area and under current  regulation
is  substantially  free  from  direct  retail  competition  with other electric
utilities.  PGE's competitors within its Oregon service territory include other
fuel suppliers, such as the local natural gas company, which  compete  with PGE
for  the  residential  and  commercial  space  and  water  heating  market.  In
addition, there is the potential for the loss of PGE service territory from the
creation of public utility districts or municipal utilities by voters.

WHOLESALE COMPETITION AND MARKETING
The  FERC  has taken steps to provide a framework for increased competition  in
the  electric   industry.    In  1996,  it  issued  Order  888  requiring  non-
discriminatory  open access transmission  by  all  public  utilities  that  own
interstate transmission,  requiring utilities to file tariffs that offer others
the same transmission services  they  provide themselves under comparable terms
and conditions.  It also requires reciprocity  from  municipals,  cooperatives,
and  federal  power  marketers  receiving  service under the tariff and  allows
public  utilities  to  recover stranded costs in  accordance  with  the  terms,
conditions and procedures set forth in the order.

The Company's transmission  system  connects  winter-peaking  utilities  in the
Northwest  and  Canada, which have access to low-cost hydroelectric generation,
with summer-peaking  wholesale customers in California and the Southwest, which
have higher-cost fossil  fuel generation.  PGE has used this system to purchase
and sell in both markets depending  upon the relative price and availability of
power, water conditions, and seasonal demand from each market.


<PAGE>
                                 POWER SUPPLY

Growth  within  PGE's service territory,  as  well  as  its  wholesale  trading
activities, has underscored  the  Company's  need for sources of reliable, low-
cost energy supplies.  The demand for energy within PGE's service territory has
experienced an average annual growth rate of approximately  2.5%  over the last
10  years.   Although  wholesale  activity has recently declined, PGE's  retail
demand is expected to continue its  upward  trend.  PGE has relied increasingly
on short-term purchases to supplement its existing  base of generating resource
and long-term power contracts to meet its energy needs.   Short-term  purchases
include both secondary as well as firm purchases for periods less than one year
in duration.  The availability of short-term firm purchase agreements and PGE's
ability to renew these contracts on a month-by-month basis have enabled  PGE to
minimize  risk  and enhance its ability to provide reliable low-cost energy  to
retail customers.   Increased  competition  has placed pressure on the price of
short-term  power  as  well  as  enhanced  its availability.   Northwest  hydro
conditions also have a significant impact on  regional power supply.  Plentiful
water conditions can lead to surplus power and  the  economic  displacement  of
more expensive thermal generation.

GENERATING CAPABILITY
PGE's  existing  hydroelectric,  coal-fired  and gas-fired plants are important
resources for the Company, providing 2,023 MW  of  generating  capability  (see
Item  2. Properties, for a full listing of PGE's generating facilities).  PGE's
lowest-cost  producers  are  its eight hydroelectric projects on the Clackamas,
Sandy, Deschutes, and Willamette  rivers  in  Oregon.  These facilities operate
under federal licenses, which will be up for renewal between the years 2001 and
2006.

On November 1, 1998, PGE signed a definitive agreement to  sell  its 20 percent
interest  in  coal-fired generating units 3 and 4 of the Colstrip power  plant,
located in eastern  Montana.   The agreement, subject to both state and federal
approval, would transfer ownership  of PGE's 322 megawatt interest in the plant
to PP&L Global, a subsidiary of PP&L Resources, for $230.5 million.  Regulatory
approval of this agreement is expected  to  take  about  one  year.   It is not
anticipated  that  the  sale  will  have  an  adverse  impact on the results of
operations.

PURCHASED POWER
PGE has long-term power contracts with four hydro projects  on the mid-Columbia
River  which  provide  PGE  with  650 MW of firm capacity.  PGE also  has  firm
contracts, ranging in term from 1 to  30  years,  to purchase 519 MW, primarily
hydro-generated, from other Pacific Northwest utilities.   In addition, PGE has
a long-term exchange contract with a summer-peaking Southwest  utility  to help
meet  its  winter-peaking requirements.  These resources, along with short-term
contracts, provide PGE with sufficient firm capacity to serve its peak loads.

SYSTEM RELIABILITY AND THE WSCC
PGE relies on  wholesale  market  purchases within the WSCC in conjunction with
its base of generating resources to  supply  its  resource  needs  and maintain
system  reliability.   The  WSCC  is  the  largest  and most diverse of the  10
regional electric reliability councils.  The WSCC performs an essential role in
developing   and  monitoring  established  reliability  criteria   guides   and
procedures to  ensure continued reliability of the electric system.  During the
last few years,  the  area covered by WSCC has become a dynamic marketplace for
the trading of electricity.  This area, which extends from Canada to Mexico and
includes 14 Western states,  is very  diverse in climates.  Peak loads occur at
different times of the year in  the  different  regions  within  the WSCC area.
Energy loads in the Southwest peak in summer due to air conditioning;  northern
loads peak during winter heating months.  Further, according to WSCC forecasts,
the  nearly  80 electric organizations participating in the WSCC, which include
utilities,  independent   power  producers  and  transmission  utilities,  have
sufficient generating capacity  to meet forecast demand and energy requirements
until the year 2006. 



January Reserve Margin WSCC Region

(Megawatts)
                WSCC Reserve Margin             % Margin
1993                 22,997                       0.217
1994                 31,033                       0.31
1995                 28,693                       0.288
1996                 24,500                       0.221
1997                 36,246                       0.325
1998                 37,145                       0.326
1999                 33,240                       0.286
2000                 34,309                       0.29
2001                 34,056                       0.284
2002                 30,842                       0.253

<PAGE>

Favorable water conditions  also  contribute to increased energy supplies.


During 1998, PGE's peak load was 4,073 MW, of which 14% was  met through short-
term  purchases.   PGE's firm resource capacity, including short-term  purchase
agreements, totaled approximately 4,492 MW as of December 31, 1998.

RESTORATION OF SALMON RUNS

The populations of many  salmon  species  in  the  Pacific Northwest have shown
significant decline over the last several decades.   A  significant  number  of
these  species  have  either been granted or are being evaluated for protection
under the federal Endangered Species Act (ESA).  While long term recovery plans
for  these  species may include  major  operational  changes  to  the  region's
hydroelectric projects, including PGE's, the impacts to date have been minimal.
The biggest change  has  been  modifying  the  timing  of the releases of water
stored  behind  the  dams  in the upper part of the Columbia  and  Snake  River
basins.   This  change in water  releases  has  resulted  in  decreased  energy
generation in the  fall and winter.  Favorable hydro conditions helped mitigate
the effect of these actions in 1997 and 1998.

PGE continues to evaluate  the  impact  of  these  listings on the operation of
hydroelectric  projects  on  the  Deschutes, Sandy, Clackamas,  and  Willamette
Rivers.   We  foresee  no  further operational  changes  to  our  hydroelectric
projects during 1999 as a result of recovery measures for endangered salmon.

<PAGE>
                                  FUEL SUPPLY

Fuel  supply  contracts  are  negotiated   to   support  annual  planned  plant
operations.  Flexibility in contract terms is sought  to  allow  for  the  most
economic  dispatch  of  PGE's thermal resources in conjunction with the current
market price of wholesale power.

COAL

BOARDMAN
PGE has agreements to purchase  coal for Boardman that cover a portion of total
requirements through the year 2000.   Coal  purchases in 1998, totaling about 2
million tons, contained less than 0.4% of sulfur  by  weight  and  emitted less
than  the  EPA  allowable limit of 1.2 pounds of sulfur dioxide per MMBtu  when
burned.  The coal,  from  surface  mining operations in Wyoming, was subject to
federal, state and local regulations.   Coal  is  delivered to Boardman by rail
under a contract which expires in 2003.

COLSTRIP
Coal for Colstrip Units 3 and 4, located in southeastern  Montana,  is provided
under  contract  with  Western  Energy  Company,  a wholly owned subsidiary  of
Montana Power Company.  The contract provides that  the coal delivered will not
exceed  a  maximum sulfur content of 1.5% by weight.  The  Colstrip  plant  has
sulfur dioxide  removal  equipment  to allow operation in compliance with EPA's
source-performance emission standards.   PGE  has  reached an agreement to sell
its 20 percent interest in Colstrip Units 3 and 4 (for  additional information,
see "Power Supply").

CENTRALIA
Coal  for  Centralia  Units  1  and 2, located in Southwestern  Washington,  is
provided under contract with PacifiCorp,  doing business as PacifiCorp Electric
Operations.  Most of Centralia's coal requirements  are expected to be provided
under this contract for the foreseeable future.


                           SULFUR            TYPE OF POLLUTION
PLANT                      CONTENT           CONTROL EQUIPMENT
Boardman, OR               0.4%              Electrostatic precipitators
Centralia, WA              0.7%              Electrostatic precipitators
Colstrip, MT               0.7%              Scrubbers and precipitators

NATURAL GAS

In  addition to the agreements discussed below, the Company utilizes short-term
and spot  market  purchases  to secure transportation capacity and gas supplies
sufficient to fuel plant operations.

BEAVER
PGE owns 90% of the Kelso-Beaver  Pipeline,  which directly connects its Beaver
generating station to Northwest Pipeline, an interstate  gas pipeline operating
between British Columbia and New Mexico.  During 1998, PGE had access to 76,000
MMBtu/day of firm transportation capacity, enough to operate  Beaver  at  a 70%
load factor.

COYOTE SPRINGS
The  Coyote  Springs  generating  station  utilizes  41,000  MMBtu/day  of firm
transportation capacity on three interconnecting pipeline systems accessing the
gas  fields  in  Alberta,  Canada.   Firm  gas  supplies for Coyote Springs are
purchased at market based prices up to two years prior to delivery based on the
anticipated  operation  of  the plant.  PGE believes  that  sufficient  gas  is
available in the marketplace  to  meet the full fuel requirements of the plant.
PGE remarkets any natural gas and transportation  capacity  that  are excess to
its needs.

<PAGE>

                             ENVIRONMENTAL MATTERS

PGE  operates  in  a  state  recognized  for  environmental  leadership.  PGE's
environmental stewardship policy emphasizes minimizing waste in its operations,
minimizing environmental risk, and promoting the wise use of energy.

REGULATION
PGE's  current  and  historical  operations  are  subject  to a wide  range  of
environmental  protection  laws covering  air and water quality,  noise,  waste
disposal, and other environmental  issues.   The  EPA regulates the proper use,
transportation,  cleanup  and  disposal  of polychlorinated  biphenyls  (PCBs).
State agencies or departments which have direct jurisdiction over environmental
matters  include the Environmental Quality  Commission,  the  DEQ,  the  Oregon
Office of  Energy  and EFSC.  Environmental matters regulated by these agencies
include the siting and operation of generating facilities and the accumulation,
cleanup, and disposal of toxic and hazardous wastes.

CLEANUP
PGE is involved with others in the environmental cleanup of PCB contaminants at
various sites as a potentially  responsible party (PRP).  The cleanup effort is
considered complete at several sites which are awaiting consent orders from the
appropriate regulatory agencies.   These  and  future  cleanup  costs  are  not
expected to be material.

AIR/WATER QUALITY
The  Clean Air Act (Act) requires significant reductions in emissions of sulfur
dioxide,  nitrogen  oxide  and other contaminants.  Coal-fired plant operations
will be affected by these emission  limitations.   State  governments  are also
charged  with  monitoring and administering certain portions of the Act.   Each
state is required to set guidelines that at least equal federal standards.

Boardman was assigned  sufficient  sulfur  emission  allowances  by  the EPA to
operate  after the year 2000 at a 60% to 67% capacity factor without having  to
further reduce  emissions.   If needed, PGE will purchase additional allowances
to meet excess capacity needs.   Centralia will be required to reduce emissions
by the year 2001, with the owner-operator  utility considering the installation
of scrubbers.  As it already utilizes scrubbers,  it  is  not  anticipated that
Colstrip will be required to reduce emissions.  However, future legislation, if
adopted, could affect plant operations and increase operating costs  or  reduce
coal-fired capacity.

Federal  operating  permits,  issued  by the DEQ, have been obtained for all of
PGE's fossil fuel generating facilities.

<PAGE>

ITEM 2.           PROPERTIES



PGE's  principal  plants  and appurtenant  generating  facilities  and  storage
reservoirs are situated on  land  owned by PGE in fee or land under the control
of PGE pursuant to valid existing leases, federal or state licenses, easements,
or other agreements.  In some cases  meters  and  transformers are located upon
the premises of customers.  The Indenture securing  PGE's  first mortgage bonds
constitutes a direct first mortgage lien on substantially all  utility property
and  franchises, other than expressly excepted property.  The map  below  shows
PGE's Oregon service territory and location of generating facilities:

                                    OREGON
<PAGE>

Generating facilities owned by PGE are set forth in the following table:
<TABLE>
<CAPTION>

                                                                       PGE Net MW
                                                                       Capability
FACILITY                 Location                      Fuel
<S>                      <C>                           <C>             <C>           <C>
WHOLLY OWNED:
  Faraday                Clackamas River               Hydro              44
  North Fork             Clackamas River               Hydro              54
  Oak Grove              Clackamas River               Hydro              44
  River Mill             Clackamas River               Hydro              25
  Pelton                 Deschutes River               Hydro             108
  Round Butte            Deschutes River               Hydro             300
  Bull Run               Sandy River                   Hydro              22
  Sullivan               Willamette River              Hydro              16
  Beaver                 Clatskanie, OR                Gas/Oil           500
  Coyote Springs         Boardman, OR                  Gas/Oil           241

                                                                                     PGE
JOINTLY OWNED:                                                                       INTEREST
  Boardman               Boardman, OR                  Coal              348  @      65.8%
  Centralia              Centralia, WA                 Coal               33  @      2.5%
  Colstrip 3 & 4         Colstrip, MT                  Coal              288  @      20.0%
        Total                                                          2,023
</TABLE>


PGE holds licenses under the Federal Power Act for its hydroelectric generating
plants.   All  of  its  licenses  expire  during  the years 2001 to 2006.  FERC
requires  that  a  notice  of  intent  to  relicense these  projects  be  filed
approximately five years prior to expiration  of  the  license.   PGE filed for
relicensing of the Pelton Round Butte Project in December 1998 and  is actively
pursuing  the  renewal  of  all  other  licenses. The State of Oregon also  has
licensed all or portions of five hydro plants.  For further information see the
Hydro Relicensing discussion in Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations.

Following the 1993 Trojan closure, PGE was  granted  a  possession-only license
amendment by the NRC.  In early 1996 PGE received NRC approval  of  its  Trojan
decommissioning  plan.  See Note 11, Trojan Nuclear Plant, in the Notes to  the
Financial Statements for further information.

LEASED PROPERTIES
Combustion  turbine   generators  at  Beaver  operate  under  a  25-year  lease
agreement.   In February  1999,  PGE  exercised  its  option  to  purchase  the
generators for  $37  million  at the August 1999 termination of the lease.  The
lease of combustion turbine generators at Bethel terminated at the end of 1998.
PGE leases its headquarters complex  in downtown Portland and the coal-handling
facilities and certain railroad cars for Boardman.

<PAGE>

ITEM 3. LEGAL PROCEEDINGS



                                    UTILITY

UTILITY REFORM PROJECT V. OPUC, MULTNOMAH COUNTY CIRCUIT COURT

On February 18, 1992 the Utility Reform  Project  (URP)  filed  a  complaint in
Multnomah County Oregon Circuit Court asking the court to set aside and rescind
OPUC Order No. 91-1781 that authorized PGE a temporary rate increase to recover
a portion (approximately $22 million) of the excess power costs incurred during
the  1991 Trojan outage.  URP's challenge was stayed pending the outcome  of  a
similar  jurisdictional  issue  in  another case already on appeal.  That other
case was decided, the stay lifted, and  the URP challenge proceeded.  PGE filed
a motion, which was granted, to intervene  as  a  participant  in the case, and
both PGE and the OPUC moved to have the case dismissed.  The case was dismissed
in December 1998 by the Multnomah County Circuit Court Judge.

CITIZENS'  UTILITY BOARD OF OREGON V. PUBLIC UTILITY COMMISSION OF  OREGON  AND
UTILITY REFORM  PROJECT  AND  COLLEEN  O'NEILL  V. PUBLIC UTILITY COMMISSION OF
OREGON, MARION COUNTY OREGON CIRCUIT COURT

The Citizens' Utility Board (CUB) appealed a 1994 ruling from the Marion County
Circuit  Court which upheld the order of the OPUC  in  its  Declaratory  Ruling
proceeding (DR-10).  In the DR-10 proceeding, PGE filed an Application with the
OPUC  requesting   a  Declaratory  Ruling  regarding  recovery  of  the  Trojan
investment and decommissioning  costs.   On  August 9, 1993 the OPUC issued the
declaratory ruling.  In its ruling, the OPUC agreed  with  an opinion issued by
the Oregon Department of Justice (Attorney General) stating  that under current
law,  the  OPUC  has  authority  to  allow recovery of and a return  on  Trojan
investment and future decommissioning costs.

In PGE's 1995 general rate case, the OPUC  issued  an  order  granting PGE full
recovery of Trojan decommissioning costs and 87% of its remaining investment in
the plant.  The URP filed an appeal of the OPUC's order.  URP alleged  that the
OPUC  lacked  authority to allow PGE to recover Trojan costs through its rates.
The complaint sought  to  remand  the  case back to the OPUC and have all costs
related to Trojan immediately removed from PGE's rates.

The CUB also filed an appeal challenging the portion of the OPUC's order issued
in PGE's 1995 general rate case that authorized  PGE to recover a return on its
remaining investment in Trojan.  CUB alleged that  the  OPUC's decision was not
based upon evidence received in the rate case, is not supported  by substantial
evidence in the record of the case, was based on an erroneous interpretation of
law  and is outside the scope of the OPUC's discretion, and otherwise  violates
constitutional or statutory provisions.  CUB sought to have the order modified,
vacated, set aside or reversed.

On April  4,  1996,  a  circuit court judge in Marion County, Oregon rendered a
decision that contradicted  a  November  1994  ruling from the same court.  The
1996 decision found that the OPUC could not authorize  PGE  to collect a return
on its undepreciated investment in Trojan currently in PGE's  rate  base.   The
1994  and  1996  circuit  court decisions were consolidated and appealed to the
Oregon Court of Appeals.

On June 24, 1998, the Court  of  Appeals  of the State of Oregon ruled that the
OPUC does not have the authority to allow PGE  to  recover  a rate of return on
its   undepreciated  investment  in  Trojan.   The  court  upheld  the   OPUC's
authorization  of PGE's recovery of its undepreciated  investment in Trojan and
its costs to decommission Trojan.

On August 26, 1998,  PGE  filed  a  Petition for Review with the Oregon Supreme
Court, supported by amicus briefs filed  by three other major utilities seeking
review of that portion of the Oregon Court  of  Appeals  decision  relating  to
PGE's  return  on  its  undepreciated  investment in Trojan.  The OPUC has also
filed such a petition for review.  If the  Supreme  Court  declines to hear the
case, it would be referred back to the OPUC.

<PAGE>

Also on August 26. 1998, the Utility Reform Project filed a Petition for Review
with  the  Oregon Supreme Court seeking review of that portion  of  the  Oregon
Court of Appeals  decision  relating  to  PGE's  recovery  of its undepreciated
investment in Trojan.

LLOYD K. MARBET AND LAURENCE TUTTLE V OREGON WATER RESOURCES  DEPT  AND  OREGON
PUC

On  November  9,  1998,  two individuals filed suit in Multnomah County, Oregon
Circuit Court against two  agencies  of  the  State of Oregon (the Oregon Water
Resources Dept and the OPUC) seeking a declaration  that  the  State  of Oregon
possesses  certain  contractual  rights  to  current  or  future  ownership  of
hydroelectric  generating facilities licensed by the State of Oregon.  The suit
alleges certain  state statutes, which were repealed in 1995, were incorporated
into state licenses  for some hydroelectric facilities licensed or permitted by
the state prior to that  date,  and  that the State of Oregon therefore has the
right to assume ownership of such hydroelectric  facilities when they have been
fully  depreciated.  The relief requested includes  an  order  that  the  state
agencies  perform  an  accounting  to  determine the depreciation status of the
various projects.  The complaint alleges  that  PGE's  Round  Butte  generating
facility  is  one of the projects that incorporated such statutes into a  state
license; the complaint  does  not  allege specifically what other hydroelectric
facilities in Oregon, owned by PGE or  otherwise,  would  be  affected.   PGE's
motion  to  intervene  in  this proceeding was granted.  PGE cannot predict the
outcome of this matter at this time.

COLUMBIA RIVER PEOPLE'S UTILITY DISTRICT V PORTLAND GENERAL ELECTRIC COMPANY

On December 1, 1998, the Columbia River People's Utility District (CRPUD) filed
an anti-trust complaint in Federal  District  Court  which  seeks to overturn a
1984 Judgment and Acquisition Agreement that confirmed PGE's exclusive right to
serve Boise Cascade Corporation ("Boise").  The complaint seeks  a  declaration
that  the  provision  of  such agreement establishing the amount to be paid  by
CRPUD to PGE if CRPUD condemns  PGE's  facilities  necessary  to serve Boise be
declared  invalid  and unenforceable; it also seeks an injunction  barring  PGE
from enforcing such  agreement  and  judgment related to this matter.  Attorney
fees and costs are sought but no claim has been made for monetary damages.  PGE
cannot predict the outcome of this matter at this time.

<PAGE>


                                       PART II


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



PGE is a wholly owned subsidiary of Enron.   PGE's common stock is not publicly
traded.  Aggregate cash dividends declared on  common  stock  were  as  follows
(millions of dollars):

                  QUARTER             1998      1997
                  First               $  -      $ 14
                  Second                16        16
                  Third                 16        17
                  Fourth                17         -

PGE  is  restricted,  without  prior  OPUC  approval,  from making any dividend
distributions to Enron that would reduce PGE's common equity  capital below 48%
of total capitalization.


ITEM 6.   SELECTED FINANCIAL DATA


                                   For the Years Ended December 31
                              1998     1997      1996       1995      1994
                                      (millions of dollars)

Operating Revenues          $1,176   $1,416    $1,110       $982      $959
Net Operating Income           200      208       230        201       159
Net Income                     137      126       156        93{1}     106

Total Assets                $3,162   $3,256    $3,398     $3,246    $3,354
Long-Term Obligations{2}       981    1,038       963        931       856

NOTES TO THE TABLE ABOVE:
1 Includes a loss of $50 million from regulatory disallowances.
2 Includes  long-term  debt,  preferred stock subject to mandatory  redemption
  requirements, long-term capital lease obligations, and commercial paper to
  be refinanced.

<PAGE>

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


RESULTS OF OPERATIONS

                                    GENERAL

1998 COMPARED TO 1997
Portland General Electric's net income  for  1998  was $137 million compared to
$126 million for 1997.  Net income in 1997 included the effect of a $14 million
non-recurring  loss  provision  associated  with  non-utility  property.  PGE's
operating performance reflected the addition of over  19,000  new  customers in
one of the faster growing service territories in the U.S.

Retail  revenues increased $2 million, as the effects of warmer winter  weather
and the move  of  about 8,700 customers to other energy service providers under
PGE's Customer Choice  pilot  program  largely offset the increase in customers
served.   Revenues from power delivery services  to  energy  service  providers
totaled $21  million  for  the  year and caused the increase in Other operating
revenues.

NET INCOME
$ Millions

1994          106
1995           93
1996          156
1997          126
1998          137

Wholesale revenues decreased $263 million, or 53%, reflecting PGE's decision to
limit wholesale activities to transactions  related to the management of system
power supplies and generation.

OPERATING REVENUES
$Millions

        RETAIL          WHOLESALE
1994     845              106
1995     877               95
1996     906              194
1997     899              497
1998     901              234


Purchased  power and fuel costs decreased $234  million,  or  35%,  due  almost
entirely to  reduced  wholesale  trading  activity.   A  52% decrease in energy
purchases  was offset somewhat by higher average prices (16.2  mills  in  1997,
18.0 mills in  1998),  caused  largely by increased winter gas prices and tight
market  conditions  in  the southwestern  United  States.   Company  generation
provided 37% of total power  needs,  up from 16% in 1997;  coal and gas powered
generation almost tripled, with average  production  costs  significantly  less
than the cost to purchase.

RETAIL ENERGY SALES
Million MWhs

1994    16.802
1995    17.065
1996    17.559
1997    18.221
1998    18.736

1997/1998 include energy delivered to ESP customers

<PAGE>

<TABLE>
<CAPTION>
                                                  MEGAWATT-HOURS/VARIABLE POWER COSTS
<S>                         <C>               <C>                            <C>           <C>
                                 Megawatt-Hours                                Average Variable
                                  (thousands)                                Power Cost (Mills/KWh)
                              1998              1997                            1998         1997
Generation                  10,854             7,326                             8.6          6.3
Firm Purchases              16,595            36,014                            17.3         16.5
Spot Purchases               2,180             2,958                            23.6         12.2
  Total Send-Out            29,629            46,298                          * 15.6       * 15.1
                                                                             (* includes wheeling costs)
</TABLE>


Operating expenses (excluding purchased power and fuel, depreciation and taxes)
increased  $9  million,  or 4%.  The increase was due largely to the payment of
$12 million in Enron overhead costs and a $2 million increase in production and
distribution expenses; these  were partially offset by a $5 million decrease in
customer support, marketing, and sales expenses.

Depreciation and amortization expense  decreased  $6  million,  or  4%.   A $13
million  decrease caused by the amortization of regulatory credits and the gain
on the sale  of  land  formerly  occupied by PGE's Western Division offices was
partially  offset  by a $7 million increase  in  depreciation  expense  due  to
capital additions to PGE's distribution system.

OPERATING EXPENSES
($ Millions)

            Depreciation            Operating Costs         Variable Power
1994            128                       334                     338
1995            140                       356                     285
1996            162                       410                     308
1997            155                       378                     675
1998            149                       386                     441


Other Income increased $20 million, due largely to a $14 million after tax loss
provision recorded in  1997  for  the  future  removal of non-utility property.
Also contributing to the 1998 increase were gains  on sales of non-utility land
and timber.

1997 COMPARED TO 1996
Portland General Electric's net income for 1997 was  $126  million, including a
$14 million non-recurring loss provision associated with non-utility  property.
Excluding this provision, 1997 net income would have been $140 million compared
to  $156  million  in  1996.  PGE's strong operating performance reflected  the
addition of over 17,000  new  customers  in  one  of the faster growing service
territories in the U.S.  Continued customer growth  helped  mitigate the impact
of a December 1996 rate settlement which resulted in a $70 million  annual rate
reduction for PGE's regulated retail customers.

Retail  revenues  decreased  $8 million primarily due to the decrease in  rates
mentioned above.

Wholesale revenues totaled $497 million in 1997, an all-time record for PGE and
an increase of over $300 million from 1996 levels.  Favorable market conditions
prompted  PGE  to  increase  its  participation  in  the  short-term  wholesale
marketplace.

Purchased power and fuel costs rose  $367  million,  or  119%,  due  largely to
increased  wholesales sales volume.  Energy purchases were up 79%, with  prices
averaging 16.2  mills  compared  to  13.8 mills for 1996.  Increased winter gas
prices followed by tight market conditions  in  the  southwestern United States
were the major contributors to the price increase.  Company generation provided
16% of total power needs.

Operating  expense  (excluding purchased power, fuel, depreciation  and  taxes)
were comparable to 1996.

<PAGE>

Depreciation expense increased $6 million or 5% due to recent capital additions
to PGE's distribution system.

Amortization expense  decreased  $13  million,  due  largely to the $17 million
amortization of the gain associated with termination of a power sales agreement
in 1996; this was partially offset by the amortization of bondable conservation
investments.

Other Income decreased due to loss provisions recorded  for  the future removal
of non-utility property.


                                   CASH FLOW

CASH  PROVIDED BY OPERATIONS is used to meet the day-to-day  cash  requirements
of PGE.  Supplemental cash is obtained from external borrowings as needed.

PGE maintains  varying  levels  of  short-term  debt,  primarily in the form of
commercial paper, which serves as the primary form of daily liquidity. In 1998,
monthly balances ranged from $96 million to $167 million.   PGE  has  committed
borrowing facilities through July 2000 totaling $200 million, which are used as
backup for PGE's commercial paper facility.

A  significant  portion  of cash provided by operations comes from depreciation
and amortization of utility  plant,  charges  which  are  recovered in customer
revenues  but  require  no  current  period cash outlay.  Changes  in  accounts
receivable and accounts payable can also  be  significant contributors or users
of cash.

CAPITAL EXPENDITURES
($ Millions) 

1994      246
1995      234
1996      200
1997      180
1998      144

Decreased  cash  flow in 1998 was due to a significant  reduction  in  accounts
payable.  In addition,  1997  includes a non-cash loss provision of $24 million
related to future costs associated  with  non-utility  property (in "Other non-
cash  expenses") and deferred income taxes of $48 million  on  a  capital  gain
associated  with the termination of the SCE Power Sales Agreement (in "Deferred
income taxes").   "Other  -  net" includes a $35 million net change in deferred
charges and credits.

INVESTING ACTIVITIES consist primarily  of  improvements to PGE's distribution,
transmission, and generation facilities, as well as continued energy efficiency
program  expenditures.   Capital expenditures of  $144  million  in  1998  were
primarily for the expansion  and upgrade of PGE's distribution system.  Capital
expenditures are expected to approximate  $200  million  in 1999, including the
$37 million purchase of previously-leased combustion turbines  at Beaver.  Over
the  next  few  years,  anticipated  expenditures  are  expected to approximate
current levels, with the majority of expenditures comprised  of improvements to
the  Company's  expanding  distribution system to support the addition  of  new
customers.

FINANCING ACTIVITIES provide  supplemental  cash  for day-to-day operations and
capital requirements as needed.  PGE relies on commercial  paper borrowings and
cash from operations to manage its day-to-day financing requirements.  In 1998,
PGE  issued  long  term  debt maturing through 2033 and in turn  redeemed  $142
million of its variable rate  pollution control bonds.  In addition, PGE repaid
$72 million in other long term  debt, funded primarily through commercial paper
borrowings.  In April 1999, PGE plans to file a $200 million shelf registration
statement  with the Securities and  Exchange  Commission  for  the  purpose  of
issuing new long-term debt.

During 1998,  PGE's dividend payments totaled $51 million, consisting of common
stock dividends  of  $49 million paid to its parent and $2 million in preferred
stock  dividends.   In 1997,  PGE's  dividend  payments  totaled  $65  million,
consisting of common  stock dividends of $46 million to public shareholders and
$17 million to its parent, and $2 million in preferred stock dividends.

<PAGE>

In September 1998, Moody's  Investor  Services  reaffirmed  PGE's debt ratings,
with senior secured debt rated A2, and commercial paper rated  P1.  In November
1998, Standard & Poor's reaffirmed PGE's debt ratings, with senior secured debt
rated  A  and commercial paper rated A-1.  These ratings enable PGE  to  access
public debt markets at favorable borrowing costs.

The issuance  of  additional  First Mortgage Bonds and preferred stock requires
PGE to meet earnings coverage and security provisions set forth in the Articles
of Incorporation and the Indenture  securing  its  First Mortgage Bonds.  As of
December  31,  1998,  PGE  had  the  capability  to issue preferred  stock  and
additional  First  Mortgage Bonds in amounts sufficient  to  meet  its  capital
requirements.

<PAGE>

FINANCIAL AND OPERATING OUTLOOK

PORTLAND GENERAL ELECTRIC COMPANY - ELECTRIC UTILITY

REGULATION AND COMPETITION

State
Since the passage of  the  federal  Energy  Policy  Act  of 1992, various state
utility commissions and legislatures have considered allowing  retail customers
direct  access  to  generation suppliers, marketers, brokers and other  service
providers in a competitive  marketplace  for energy services (retail wheeling).
A statement of principles for restructuring  the  electric utility industry was
issued by Oregon's governor in 1996 that included access to electricity service
at  a  reasonable  price, the option of customers to choose  their  electricity
provider, and the opportunity  for  utilities  to recover the costs of previous
commitments, including stranded costs.

In  late  1997,  PGE  filed  its "Customer Choice" proposal  before  the  OPUC,
designed to give all of its customers  a  choice  of  electricity  providers as
early  as  1999.  Under the proposal, PGE would become a regulated transmission
and  distribution  company focused on delivering, but not selling, electricity.
PGE would continue to  operate and maintain the electricity delivery system and
handle outage restoration, while other competitive companies would market power
to customers over that system. To effect this restructuring, PGE asked for OPUC
approval  to  sell  all  its  generating  assets,  power  supply  and  purchase
contracts.

In  conjunction  with  its  proposal,   PGE   initiated   the  Customer  Choice
Introductory  Program  as  a one-year pilot to test deregulation  readiness  by
allowing certain PGE customers to buy their power from competing energy service
providers.  The program, approved  by  the  OPUC,  was  made available to about
50,000 residential, small business and commercial customers  in four cities and
industrial  customers  throughout PGE's service territory.  At its  peak,  over
8,700 - almost 17 percent  of  eligible  retail  customers  - had selected from
among eight participating energy service providers.  The program  terminated as
scheduled  on  December  31, 1998, and all participating customers returned  to
PGE.

The Customer Choice Introductory  Program provided valuable information to PGE,
the OPUC, and legislators on the effects  of  retail competition on PGE and its
customers.  An extensive independent assessment  of  the  program was completed
and  made  available  to  interested parties, including the State  Legislature.
Such  assessment indicated wide  satisfaction  by  both  customers  and  energy
service   providers,  with  lower  prices  and  the  ability  to  choose  their
electricity supplier cited as primary reasons for customer participation.

In July 1998,  the  OPUC  staff  issued  its  position on PGE's Customer Choice
proposal, disagreeing with PGE's proposal for full  implementation.  On January
28,  1999, the OPUC issued an order recommending that  PGE  offer  customers  a
limited  set  of  options,  including the ability to continue to purchase rate-
regulated electricity; most commercial  and  industrial  customers  (those with
demand  exceeding  30  kW)  would  be able to choose their electricity provider
through direct access.  Although the  order  would  allow PGE to sell its coal-
and  gas-fired  generation  plants,  it  rejected  PGE's request  to  sell  its
hydroelectric assets.  The Commission's order further  requires PGE to refile a
new  rate  case should it choose to adopt the plan recommended  by  the  order,
which is also  contingent upon the adoption of certain statutory changes by the
Oregon Legislature.   Until  such  changes  are  made and agreed upon among all
parties, PGE will not seek to implement either its  Customer Choice proposal or
the recent Commission order.

The  issue  of  restructuring  will be further addressed  by  the  1999  Oregon
Legislature.  PGE is reviewing the  OPUC  order and will support a deregulation
plan that includes the following: 1) creation  of  a  comprehensive approach to
restructuring  the  electricity  industry  that  benefits  all   customers;  2)
development  of  a  truly competitive market; 3) avoidance of cost shifts  that
benefit one group at  the  expense  of  another;  4)  assurance  that customers
continue to receive benefits of federal hydropower; and, 5) implementation of a
Systems  Benefit  Charge  (SBC)  to  ensure  adequate  funds for public purpose
investments (renewable energy projects, low-income weatherization, etc).

<PAGE>

Federal
The Energy Policy Act of 1992 (Energy Act) set the stage  for change in federal
regulations aimed at increasing wholesale competition in the electric industry.
The Energy Act eased restrictions on independent power production  and  granted
authority to the FERC to mandate open access for the wholesale transmission  of
electricity.

The  FERC  has  taken steps to provide a framework for increased competition in
the electric industry.   In  1996  the  FERC  issued  Order  888 requiring non-
discriminatory  open  access  transmission  by  all public utilities  that  own
interstate transmission.  The final rule requires  utilities  to  file  tariffs
that offer others the same transmission services they provide themselves  under
comparable  terms  and  conditions.   This rule also allows public utilities to
recover stranded costs in accordance with  the terms, conditions and procedures
set  forth  in  Order 888.  The ruling requires  reciprocity  from  municipals,
cooperatives and  federal  power  marketers receiving service under the tariff.
The new rules became effective in July  1996  and  have  resulted  in increased
competition, lower prices and more choices to wholesale energy customers.

Further  legislation  to  restructure  the electric industry, including  retail
choice,  is under active consideration at  the  federal  level.   Congressional
committee  hearings  on  electricity  restructuring  are  anticipated  in 1999,
although  there  remains  considerable  uncertainty  regarding  their  ultimate
outcome.

On July 16, 1998,  PGE filed an application with the FERC to increase its rates
for  transmission  service,  in  accordance  with  the  terms of FERC Order 888
requiring  open-access transmission by public utilities.   Revised  rates  were
implemented  on February 11, 1999, with final settlement and filing on March 1,
1999.

RETAIL CUSTOMER GROWTH AND ENERGY SALES
During 1998, weather  adjusted  retail  energy  sales grew 3.0%. Commercial and
industrial  sales  increased  by 3.8% and 2.7% respectively  due  to  continued
growth  in  most industry segments.  The  addition  of  over  19,000  customers
resulted in residential  sales  growth  of  2.4%.   PGE forecasts retail energy
sales growth of approximately 3% in 1999 and comparable  growth in the next few
years.

In January 1998, rates for PGE's residential and small farm customers increased
11.9%  due  to the Bonneville Power Administration's (BPA) elimination  of  the
Residential Exchange  Credit.   PGE  contested  this decision and reached a new
agreement with BPA in September 1998 that provides  for  a retail rate rollback
to  a  net  increase of 5.7%.  Exchange benefits are passed directly  to  PGE's
customers in the form of price decreases.

WHOLESALE SALES
The availability  of  electric  generating  capability in the Western U.S., the
entrance of numerous wholesale marketers and  brokers into the market, and open
access transmission are contributing to increasing  competitive pressure on the
price of power.  In addition, the development of financial  markets  and  NYMEX
electricity contract trading has led to enhanced price discovery available  for
market  participants,  further  adding  to  the  downward pressure on wholesale
prices and margins.  During 1998, PGE's wholesale sales accounted for about 19%
of  total  revenues  and  38% of total energy sales.   PGE  will  continue  its
participation in the wholesale  marketplace  in  order to balance its supply of
power to meet the needs of its retail customers, manage  risk,  and  administer
its   current  long-term  wholesale  contracts.   Long-term  wholesale  trading
activities  have  been  transferred  to  a non-regulated Enron affiliate, which
participates  more fully in a broader market.   PGE  expects  that  its  future
revenues from wholesale activities will continue to decline.

POWER & FUEL SUPPLY
PGE's base of hydro  and  thermal  generating  capacity,  supplemented  by  its
existing  firm  power  contracts  and  the availability of competitively-priced
wholesale energy within the region, provide  the  Company  with the flexibility
needed to respond to seasonal fluctuations in the demand for electricity within
its service territory.

PGE has long-term power contracts with four hydro projects on  the mid-Columbia
River  providing  capability  of 650 MW, and has also relied increasingly  upon
short-term purchases to meet its energy needs.  The Company anticipates that an
active wholesale market and a surplus  of  generating  capacity within the WSCC
should 

<PAGE>

provide sufficient wholesale energy available at  competitive  prices to
supplement its generation and purchases under existing firm power contracts.

Though  early  forecasts  indicate  above-average  water  conditions  for 1999,
efforts  to  restore  salmon runs on the Columbia and Snake rivers may somewhat
reduce the amount of water  available  for  generation,  which could affect the
availability and price of purchased power. Additional factors that could affect
the availability and price of purchased power include weather conditions in the
Northwest during winter months and in the Southwest during  summer  months,  as
well  as  the  performance  of  major  generating facilities in both regions.

During 1998, PGE generated approximately  37%  of  its  total load requirement,
compared to approximately 16% in 1997; short-term purchases  were  utilized  to
meet  the  remaining load.  Purchases, which are expected to decline further in
1999, were also used to support PGE's wholesale sales activity.

On November  1,  1998, PGE signed a definitive agreement to sell its 20 percent
interest in coal-fired  generating  units  3 and 4 of the Colstrip power plant,
located in eastern Montana.  The agreement,  subject  to both state and federal
approval, would transfer ownership of PGE's 322 megawatt  interest in the plant
to PP&L Global, a subsidiary of PP&L Resources, for $230.5 million.  Regulatory
approval  of  this  agreement is expected to take about one year.   It  is  not
anticipated that the  sale  will  have  an  adverse  impact  on  the results of
operations.

In  February  1999,  PGE  elected  to  exercise its option to purchase the  six
combustion turbine generators at Beaver  for  their  $37  million  fair  market
value.   The  generators,  operated  under terms of a 25-year lease expiring in
August 1999, produce a net output of approximately  500  MW  in  combined-cycle
configuration.

The lease of combustion turbine generators at Bethel terminated at  the  end of
1998.

RESTORATION  OF  SALMON  RUNS  -  The populations of many salmon species in the
Pacific Northwest have shown significant decline over the last several decades.
A significant number of these species  have  either  been  granted or are being
evaluated for protection under the federal Endangered Species Act (ESA).  While
long  term  recovery  plans  for  these  species may include major  operational
changes to the region's hydroelectric projects, including PGE's, the impacts to
date have been minimal.  The biggest change  to  date  has  been  modifying the
timing of the releases of water stored behind the dams in the upper part of the
Columbia and Snake River basins.  This change in water releases has resulted in
decreased energy generation in the fall and winter.  Favorable hydro conditions
helped mitigate the effect of these actions in 1997 and 1998.

PGE  continues  to  evaluate  the impact of these listings on the operation  of
hydroelectric  projects  on the Deschutes,  Sandy,  Clackamas,  and  Willamette
Rivers.   The  company  foresees   no   further   operational  changes  to  its
hydroelectric  projects  during  1999  as  a  result of recovery  measures  for
endangered salmon.

HYDRO RELICENSING
PGE HYDRO - PGE's eight hydroelectric plants provide  economical generation and
flexible load following capabilities; in 1998, they produced 2.6 million MWh of
renewable  energy,  about  9%  of PGE's total load.  The plants  operate  under
federal licenses, which will be up for renewal between the years 2001 and 2006.
PGE continued the relicensing process for its 408-MW Pelton Round Butte Project
throughout 1998, culminating with  issuance  of  a draft license application in
December.  The Confederated Tribes of Warm Springs,  currently the licensee for
a  powerhouse  located at the reregulating dam (one of three  dams  within  the
Pelton Round-Butte  Project),  also  proceeded with their competing relicensing
process  for  the entire project.  Several  meetings  with  federal  and  state
agencies, as well  as members of the public and non-governmental organizations,
were conducted during  the  year  in support of relicensing PGE's hydroelectric
projects on the Clackamas, Sandy, and  Willamette  rivers;  licenses  on  these
plants,  with  combined generating capacity of 203 MW, expire in 2004 and 2006.
Should relicensing  not  be  completed  prior to the expiration of the original
license,  it  is  anticipated  that  PGE will  be  issued  annual  licenses  at
substantially   identical  terms  and  conditions  until  such  time  as  final
relicensing has been completed.

The relicensing process includes the involvement of numerous interested parties
such as governmental agencies, public interest  groups  and  communities,  with
much  of  the  focus on environmental concerns.  PGE has already 

<PAGE>

performed many
pre-filing activities,  including  numerous  public  meetings with such groups.
The cost of relicensing includes legal and filing fees  as  well as the cost of
environmental  studies,  possible  fish passage measures, and wildlife  habitat
enhancements.  Relicensing cost may  be  a  significant  factor  in determining
whether  a  project  remains  cost-effective  after  a new license is obtained,
especially  for  smaller  projects.   Although the FERC has  rarely  denied  an
application and has never issued a license  to  anyone other than the incumbent
licensee, there is no assurance that new licenses will be granted to PGE.

Refer to Item 3. Legal Proceedings for additional information.

MID-COLUMBIA  HYDRO -  PGE's long-term power purchase  contracts  with  certain
public utility  districts  in  the  state of Washington expire between 2005 and
2018.  Certain Idaho Electric Utility  Co-operatives have initiated proceedings
with the FERC seeking to change the allocation  of  generation  from the Priest
Rapids  and  Wanapum  dams  between  electric  utilities  in  the  region  upon
expiration  of  the  current contracts. In early 1998, the FERC ruled that  the
portion of the output  from these dams made available to purchasers such as PGE
be reduced to 30%, and that such purchases be at market-based rather than cost-
based prices. This decision  could  change  both PGE's percentage share and the
price  of  power  from these facilities, although  such  changes  are  not  yet
determinable.  This matter is now on appeal to the Circuit Court of Appeals.

For further information  regarding  the  power  purchase  contracts on the mid-
Columbia dams, including Priest Rapids and Wanapum, see Note 7, Commitments, in
the Notes to Financial Statements.

NUCLEAR DECOMMISSIONING
PGE currently estimates the total cost to decommission Trojan  at  $339 million
(nominal  dollars),  with approximately $73 million expended through 1998.  The
total estimate assumes  that the majority of decommissioning activities will be
completed by 2002, after the spent fuel has been transferred to a temporary dry
spent fuel storage facility.   The  plan  anticipates  final  site  restoration
activities will begin in 2018 after PGE completes shipment of spent fuel  to  a
USDOE  facility  (see  Note 11, Trojan Nuclear Plant, for further discussion of
the decommissioning plan and other Trojan issues).

In 1998 PGE continued to  make  progress  in  decommissioning  Trojan.  Over 68
thousand  cubic  feet  of  contaminated  equipment  and material were  removed,
packaged,  and  shipped to the disposal site.  Also in  1998,  Trojan  received
regulatory approval  to  ship  and  dispose  of  the Trojan reactor vessel as a
single package, called the Reactor Vessel And Internals  Removal Project.  This
precedent-setting project will save millions of dollars from  the  conventional
segmentation  approach.   In  1999,  PGE  will continue moving forward on  this
project.

PGE expects remaining transition activities to be completed in 1999, with total
costs estimated at $8 million paid from current  operating  funds.   Transition
activities  are comprised of operating and maintaining the spent fuel pool  and
securing the  plant  until  fuel  is  transferred to dry storage as part of the
Independent Spent Fuel Storage Installation (ISFSI) project.  Equipment removal
and  disposal  activities  will  also continue.   PGE  anticipates  total  1999
decommissioning costs of approximately  $59  million,  compared  to  about  $30
million in 1998.

These efforts position PGE to safely dispose of all radiological hazards, other
than  spent  nuclear fuel, on the Trojan site and to initiate a final radiation
survey to prove  these  hazards  are  no  longer  present.   Decommissioning is
proceeding  on  schedule and within approved cost estimates.  PGE  expects  the
final site survey to be completed by the end of 2002.

YEAR 2000
The Year 2000 problem results from the use in computer hardware and software of
two digits rather  than  four digits to define the applicable year.  The use of
two  digits  was  a common practice  for  decades  when  computer  storage  and
processing was much  more  expensive  than  today.   When computer systems must
process  dates both before and after January 1, 2000, two-digit  year  "fields"
may create  processing  ambiguities  that can cause errors and system failures.
For example, computer programs that have  date-sensitive features may recognize
a date represented by "00" as the year 1900,  instead of 2000.  These errors or
failures may have limited effects, or the effects  may be widespread, depending
on the computer chip, system or software, and its location and function.

The  effects  of  the  Year  2000  problem  are  exacerbated   because  of  the
interdependence of computer and telecommunications systems in the United States
and throughout the world.  This interdependence certainly is true  for  PGE and
PGE's suppliers, trading partners, and customers.

<PAGE>

STATE OF READINESS

PGE's  Board  of  Directors  has  adopted  the  Enron Year 2000 plan (the
"Plan"),  which  covers  all  of  PGE's  and  other Enron  subsidiaries'
activities.  The aim of the plan is to take reasonable steps to prevent Enron's
mission-critical functions from being impaired  due  to  the Year 2000 problem.
"Mission-critical"  functions  are those critical functions  whose  loss  would
cause an immediate stoppage of or  significant  impairment  to  major  business
areas  (a  major  business  area  is  one  of  material  importance  to Enron's
business).

PGE's  Year  2000  plan  has  been  assigned  to  a centralized staff under the
direction of a Year 2000 Project Manager, who coordinates the implementation of
the  Plan  within  all affected areas of the company.   PGE  has  also  engaged
outside consultants,  technicians  and  other  external  resources  to  aid  in
implementing the Plan.

PGE  is implementing the Plan, which will be modified as events warrant.  Under
the Plan, PGE will continue to inventory its mission-critical computer hardware
and software  systems  and  embedded  chips  (computer  chips with date-related
functions, contained in a wide variety of devices); assess  the effects of Year
2000  problems  on  the  mission-critical  functions of PGE's business;  remedy
systems, software and embedded chips in an effort to avoid material disruptions
or other material adverse effects on mission-critical  functions, processes and
systems;  verify  and  test the mission-critical systems to  which  remediation
efforts have been applied;  and  attempt  to  mitigate  those  mission-critical
aspects  of the Year 2000 problem that are not remediated by January  1,  2000,
including  the  development  of  contingency  plans  to  cope with the mission-
critical consequences of Year 2000 problems that have not  been  identified  or
remediated by that date.

The  Plan  recognizes  that the computer, telecommunications, and other systems
("Outside Systems") of outside entities ("Outside Entities") have the potential
for major, mission-critical,  adverse effects on the conduct of PGE's business.
PGE  does  not  have control of these  Outside  Entities  or  Outside  Systems.
However, the Plan  includes  an  ongoing  process of identifying and contacting
Outside  Entities  whose  systems  in  PGE's judgment  have,  or  may  have,  a
substantial effect on PGE's ability to continue to conduct the mission-critical
aspects of its business without disruption  from  Year 2000 problems.  The Plan
envisions PGE's attempting to inventory and assess  the  extent  to which these
Outside  Systems  may not be "Year 2000 ready" or "Year 2000 compatible."   PGE
will attempt reasonably to coordinate with these Outside Entities in an ongoing
effort to obtain assurance  that  the Outside Systems that are mission-critical
to PGE will be Year 2000 compatible well before January 1, 2000.  Consequently,
PGE  will work prudently with Outside  Entities  in  a  reasonable  attempt  to
inventory,  assess,  analyze,  convert  (where  necessary),  test,  and develop
contingency  plans  for  PGE's  connections  to  these mission-critical Outside
Systems and to ascertain the extent to which they  are,  or  can be made to be,
Year 2000 ready and compatible with PGE's mission-critical systems.

It  is  important  to recognize that the processes of inventorying,  assessing,
analyzing, converting  (where  necessary),  testing, and developing contingency
plans for mission-critical items in anticipation  of  the  Year  2000 event are
necessarily iterative processes.  That is, the steps are repeated as PGE learns
more about the Year 2000 problem and its effects on PGE's internal  systems and
on Outside Systems, and about the effects that embedded chips may have on PGE's
systems and Outside Systems.  As the steps are repeated, it is likely  that new
problems  will  be  identified  and  addressed.   PGE  anticipates that it will
continue with these processes through January 1, 2000 and,  if  necessary based
on  experience,  into  the Year 2000 in order to assess and remediate  problems
that reasonably can be identified only after the start of the new century.

As of March 1999, PGE is  at  various  stages in implementation of the Plan, as
shown in the following table, which lists  the  status of both mission-critical
internal systems (including embedded chips) and Outside  Systems.  Any notation
of "complete" or reference to a "completion date" conveys  the  fact  only that
the initial iteration of this phase has been substantially completed. PGE  will
continue  closely  to  monitor  work  under  the  Plan  and to revise estimated
completion dates for the initial iteration of each listed process.

<PAGE>

<TABLE>
<CAPTION>
                                                              YEAR 2000 READINESS PLAN
<S>                      <C>                  <C>                      <C>                    <C>
                           MISSION-CRITICAL INTERNAL ITEMS               MISSION-CRITICAL OUTSIDE ENTITIES
                          STATUS             COMPLETION DATE            STATUS              COMPLETION DATE*
Inventory                Complete             December 1997            Complete               October 1998
Assessment               Complete             October 1998             Complete               November 1998
Analysis                 Complete             October 1998             Complete               November 1998
Conversion               In Process           June 1999                In Process             June 1999
Testing                  In Process           June 1999                In Process             June 1999
Y2K-Ready                In Process           June 1999                In Process             June 1999
Contingency Plan         In Process           June 1999                In Process             June 1999

</TABLE>

* The June 1999 completion date for Mission-Critical Outside  Entities  conveys
only  the  date  when  PGE   anticipates it will have evaluated the progress of
Outside  Entities  with  respect   to   Conversion,   Testing,  Y2K-Ready,  and
Contingency Plans.

COSTS TO ADDRESS YEAR 2000 ISSUES

Under the Plan, PGE currently estimates that it will spend approximately $20-25
million relating to Year 2000 issues, about one-third of  which  has been spent
to  date;  1999  expenditures  are  currently  estimated  at approximately  $15
million.   Most costs incurred to address the Year 2000 issue  are  charged  to
operating expenses  as  incurred and are expected to be funded by cash provided
by operations.  PGE anticipates  that  its  costs  relating to Year 2000 issues
will not have a material adverse effect on its financial  condition  or results
of operations.

Although management believes that its estimates are reasonable, there can be no
assurance,  for  the  reasons stated in the "Outlook" section, below, that  the
actual costs of implementing  the  plan  will  not  differ  materially from the
estimated costs or that PGE will not be materially adversely  affected  by Year
2000 issues.

YEAR 2000 RISK FACTORS

REGULATORY   REQUIREMENTS  -   PGE  expects  to  satisfy  all  requirements  of
regulatory authorities  for  achieving  Year 2000 readiness.  If its reasonable
expectations in this regard are in error,  the  adverse  effect on PGE could be
material.  Outside Entities could force temporary cessation  of operations that
materially adversely affect PGE.

SHORTAGE  OF  RESOURCES  -   Between  now  and  2000  there  will  be increased
competition for people skilled in the technical and managerial skills necessary
to  deal  with  the  Year  2000  problem.   While  PGE  is  taking  substantial
precautions to recruit and retain sufficient people skilled in dealing with the
Year 2000 problem and has hired consultants who bring additional skilled people
to deal with the Year 2000 problem as it affects PGE, PGE could face  shortages
of  skilled  personnel  or  other  resources,  such as Year 2000 ready computer
chips, and these shortages might delay or otherwise  impair  PGE's  ability  to
assure that its mission-critical systems are Year 2000 ready.  Outside Entities
could  force temporary cessation of operations that materially adversely affect
PGE.  PGE  believes  that the possible import of the shortage of skilled people
is not, and will not be, unique to PGE.

POTENTIAL SHORTCOMING  -   PGE estimates that its mission-critical systems will
be Year 2000-ready substantially  before January 1, 2000.  However, there is no
assurance that the Plan will succeed  in  accomplishing  its  purposes  or that
unforeseen circumstances will not arise during implementation of the Plan  that
would materially and adversely affect PGE.

CASCADING  EFFECT  -   PGE  is taking reasonable steps to identify, assess, and
where appropriate, replace devices  that contain embedded chips.  Despite these
reasonable efforts, there is no assurance  that  PGE  will  be able to find and
remediate all embedded chips in its systems.  Further, there  is  no  assurance
that  Outside  Entities on 

<PAGE>

which PGE depends will be able to find and remediate
all embedded chips  in  their systems.  Some of the embedded chips that fail to
operate or that produce anomalous  results  may  create  system  disruptions or
failures.  Some of these disruptions or failures may spread from the systems in
which they are located to other systems in a cascade.  These cascading failures
may have adverse effects upon PGE's ability to maintain safe operations and may
also  have  adverse  effects  upon  PGE's  ability  to serve its customers  and
otherwise  to  fulfill  certain contractual and other legal  obligations.   The
embedded chip problem is widely recognized as one of the more difficult aspects
of the Year 2000 problem  across  industries  and  throughout  the  world.  PGE
believes that the possible adverse impact of the embedded chip problem  is not,
and will not be, unique to PGE.

THIRD  PARTIES  -   PGE  cannot assure that suppliers upon which it depends for
essential goods and services  will  convert  and  test  their  mission-critical
systems and processes in a timely manner.  Failure or delay by all  or  some of
these  entities,  including  U.S.  federal,  state  or local governments, could
create  substantial  disruptions  having  a material adverse  effect  on  PGE's
business.

CONTINGENCY PLANS

As part of the Plan, PGE is developing contingency  plans  that  deal  with two
aspects  of  the  Year  2000  problem:  (1)  that  PGE, despite its good-faith,
reasonable efforts, may not have satisfactorily remediated  all of its internal
mission-critical  systems; and (2) that Outside Systems may not  be  Year  2000
ready, despite PGE's  good-faith,  reasonable  efforts  to  work  with  Outside
Entities.    PGE's  contingency  plans  are  being  designed  to  minimize  the
disruptions or other adverse effects resulting from Year 2000 incompatibilities
regarding these  mission-critical  functions  or systems, and to facilitate the
early  identification and remediation of mission-critical  Year  2000  problems
that first manifest themselves after January 1, 2000.

PGE's contingency  plans  will  contemplate  an  assessment of all its mission-
critical internal information technology systems and  its  internal operational
systems that use computer-based controls.  This process will  commence  in  the
early  minutes  of  January  1, 2000, and continue for hours, days, or weeks as
circumstances require.  Further,  PGE  will  in  that  time  frame  assess  any
mission-critical  disruptions  due  to  Year  2000-related  failures  that  are
external  to  PGE.   The  assessment  process  will cover, for example, loss of
electrical  power  from  other  utilities;  telecommunications   services  from
carriers;  or  building  access,  security,  or  elevator service in facilities
occupied by PGE.

PGE plans to file with the Western Systems Coordinating  Council  by  June  15,
1999   its  contingency  plan  related  to  Mission-Critical  Internal  Systems
(including   embedded  chips)  and  Outside  Systems.   PGE  plans  to  perform
additional contingency planning relating to other systems both before and after
its June 15, 1999 filing.

PGE's contingency  plans  will  include  the  creation  of  teams  that will be
standing  by on the eve of the new millennium, prepared to respond rapidly  and
otherwise as  necessary  to mission-critical Year 2000-related problems as soon
as they become known.  The  composition of teams that are assigned to deal with
Year 2000 problems will vary  according to the nature, mission-criticality, and
location of the problem.

WORST CASE SCENARIO

The Securities and Exchange Commission  requires  that  companies must forecast
the most reasonably likely worst case Year 2000 scenario.  Analysis of the most
reasonably  likely  worst  case  Year  2000  scenarios PGE may  face  leads  to
contemplation of the following possibilities which,  though unlikely in some or
many  cases, must be included in any consideration of worst  cases:  widespread
failure  of  electrical,  gas,  and  similar supplies by utilities serving PGE;
widespread  disruption  of  the services  of  communications  common  carriers;
similar  disruption to means and  modes  of  transportation  for  PGE  and  its
employees,  contractors,  suppliers,  and  customers; significant disruption to
PGE's ability to gain access to, and remain  working  in,  office buildings and
other facilities; the failure of substantial numbers of PGE's  mission-critical
information (computer) hardware and software systems, including  both  internal
business  systems  and  systems (such as those with embedded chips) controlling
operational  facilities  such   as  electrical  generation,  transmission,  and
distribution systems; and the failure  of Outside Systems, the effects of which
would  have  a cumulative material adverse  impact  on  PGE's  mission-critical
systems.  Among other things, PGE could face substantial claims by customers or
loss of revenues due to service interruptions, inability to fulfill contractual
obligations, inability  to  account  for  

<PAGE>

certain revenues or obligations or to
bill  customers  accurately  and  on  a timely basis,  and  increased  expenses
associated  with litigation, stabilization  of  operations  following  mission-
critical failures,  and  the  execution  of  contingency plans.  PGE could also
experience an inability by customers, traders,  and  others to pay, on a timely
basis  or  at  all,  obligations owed to PGE.  Under these  circumstances,  the
adverse effect on PGE, and the diminution of PGE's revenues, would be material,
although  not quantifiable  at  this  time.   Further  in  this  scenario,  the
cumulative  effect of these failures could have a substantial adverse effect on
the economy,  domestically and internationally.  The adverse effect on PGE, and
the diminution  of  its  revenues,  from  a  domestic  or  global  recession or
depression  also  is likely to be material, although not quantifiable  at  this
time.

PGE will continue to  monitor business conditions with the aim of assessing and
quantifying material adverse  effects,  if  any, that result from the Year 2000
problem.

SUMMARY

PGE has a Plan to deal with the Year 2000 challenge  and  believes that it will
be able to achieve substantial Year 2000 readiness with respect  to the mission
critical  systems  that  it controls.  From a forward-looking perspective,  the
extent and magnitude of the  Year  2000  problem  as  it  will affect PGE, both
before and for some period after January 1, 2000, are difficult  to  predict or
quantify for a number of reasons.  Among these are: the difficulty of  locating
"embedded"  chips  that  may be in a great variety of mission-critical hardware
used  for  process  or  flow control,  environmental,  transportation,  access,
communications and other  systems;  the  difficulty of inventorying, assessing,
remediating, verifying and testing Outside  Systems; the difficulty in locating
all mission-critical software (computer code)  internal to PGE that is not Year
2000  compatible;  and  the  unavailability of certain  necessary  internal  or
external resources, including  but not limited to trained hardware and software
engineers, technicians and other  personnel  to  perform  adequate remediation,
verification and testing of PGE systems or Outside Systems.  Accordingly, there
can be no assurance that all of PGE's systems and all Outside  Systems  will be
adequately  remediated so that they are Year 2000 ready by January 1, 2000,  or
by some earlier  date,  so  as  not  to  create  a material disruption to PGE's
business.   If,  despite PGE's reasonable efforts under  the  Plan,  there  are
mission-critical Year 2000-related failures that create substantial disruptions
to PGE's business,  the  adverse  impact  on  PGE's business could be material.
Additionally, Year 2000 costs are difficult to  estimate  accurately because of
unanticipated  vendor delays, technical difficulties, the impact  of  tests  of
Outside  Systems   and  similar  events.   Moreover,  the  estimated  costs  of
implementing the Plan do not take into account the costs, if any, that might be
incurred as a result  of  Year  2000-related  failures that occur despite PGE's
implementation of the Plan.

NEW ACCOUNTING STANDARDS
In 1998, the AICPA issued Statement of Position  98-1  (SOP  98-1), "Accounting
for the Costs of Computer Software Developed or Obtained for Internal Use", and
Statement  of  Position  98-5 (SOP 98-5), "Reporting on the Costs  of  Start-Up
Activities".  Also in 1998,  the  Financial  Accounting  Standards Board issued
SFAS  No. 133, "Accounting for Derivative Instruments and Hedging  Activities",
and the  Emerging  Issues  Task  Force  reached a consensus on Issue No. 98-10,
"Accounting  for  Contracts  involved in Energy  Trading  and  Risk  Management
Activities".  PGE has analyzed  the potential effects of the application of SOP
98-1 and SOP 98-5 in 1999 and has  determined  that  their application will not
have a material effect on its financial position or results  of  operations for
the year.

SFAS  No.  133,  to  be  effective January 1, 2000, establishes accounting  and
reporting  standards requiring  that  every  derivative  instrument  (including
certain derivative  instruments embedded in other contracts) be recorded on the
balance sheet as either  an asset or liability measured at its fair value.  The
Statement requires that changes  in  the  derivative's fair value be recognized
currently  in  earnings  unless specific hedge  accounting  criteria  are  met.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results  on  the  hedged  item  in  the income statement, and
requires  that  a  company  must formally document, designate  and  assess  the
effectiveness of transactions  that  receive hedge accounting.  PGE has not yet
quantified the impacts of adopting SFAS No. 133 on its financial statements and
has not determined the method of its adoption of SFAS No. 133 nor the effect on
the accounting for its hedging activities or physical contracts.

<PAGE>

EITF 98-10 is effective for fiscal years  beginning after December 15, 1998 and
requires energy trading contracts to be recorded  at  fair value on the balance
sheet,  with  any changes in fair value included in earnings.   The  effect  of
initial application  of EITF 98-10 will be reported as a cumulative effect of a
change in accounting principle.   Because  an  insignificant  portion  of PGE's
electricity trades are entered into for trading purposes, PGE believes that the
adoption  of  EITF  98-10  will  not  have  a  materially adverse impact on its
financial position or results of operations.

INFORMATION REGARDING FORWARD LOOKING STATEMENTS
This Annual Report on Form 10-K includes forward  looking statements within the
meaning of Section 27A of the Securities Act of 1933  and  Section  21E  of the
Securities  Exchange  Act of 1934.  Although PGE believes that its expectations
are based on reasonable  assumptions,  it  can give no assurance that its goals
will be achieved. Important factors that could  cause  actual results to differ
materially  from  those  in  the  forward  looking  statements  herein  include
political  developments  affecting federal and state regulatory  agencies,  the
pace of electric industry  deregulation  in  Oregon  and  in the United States,
environmental  regulations,  changes  in  the  cost  of power, adverse  weather
conditions,  and the effects of the Year 2000 date change  during  the  periods
covered by the forward looking statements.

<PAGE>
              
              MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING


The following  financial  statements  of  Portland General Electric Company and
subsidiaries  (collectively,  PGE)  were  prepared   by  management,  which  is
responsible  for  their integrity and objectivity.  The  statements  have  been
prepared  in conformity  with  generally  accepted  accounting  principles  and
necessarily  include  some  amounts  that  are  based on the best estimates and
judgments of management.

The  system  of  internal  controls of PGE is designed  to  provide  reasonable
assurance as to the reliability  of  financial statements and the protection of
assets from unauthorized acquisition,  use  or  disposition.   This  system  is
augmented  by  written  policies  and  guidelines and the careful selection and
training of qualified personnel.  It should  be recognized, however, that there
are  inherent  limitations  in the effectiveness  of  any  system  of  internal
control.  Accordingly, even an  effective  internal  control system can provide
only reasonable assurance with respect to the preparation of reliable financial
statements  and  safeguarding  of  assets.   Further,  because  of  changes  in
conditions, internal control system effectiveness may vary over time.

PGE  assessed its internal control system as of December  31,  1998,  1997  and
1996,  relative  to  current  standards  of  control criteria.  Based upon this
assessment,  management  believes  that its system  of  internal  controls  was
adequate  during  the  periods  to  provide  reasonable  assurance  as  to  the
reliability  of  financial statements and  the  protection  of  assets  against
unauthorized acquisition, use or disposition.

Arthur Andersen LLP  was  engaged  to audit the financial statements of PGE and
issue  reports  thereon.   Their  audits   included   developing   an   overall
understanding of PGE's accounting systems, procedures and internal controls and
conducting  tests  and  other  auditing  procedures sufficient to support their
opinion on the financial statements.  Arthur  Andersen  LLP was also engaged to
examine and report on management's assertion about the effectiveness  of  PGE's
system  of  internal  controls  over financial reporting and the protection  of
assets against unauthorized acquisition,  use  or  disposition.  The Reports of
Independent Public Accountants appear in this Annual Report.

The adequacy of PGE's financial controls and the accounting principles employed
in financial reporting are under the general oversight  of  the Audit Committee
of Enron's Board of Directors.  No member of this committee is  an  officer  or
employee  of  Enron  or  PGE.   The  independent public accountants have direct
access to the Audit Committee, and they  meet  with  the committee from time to
time,  with  and without financial management present, to  discuss  accounting,
auditing and financial reporting matters.

<PAGE>
                   
                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Shareholder of
  Portland General Electric Company:

We have examined  management's assertion that the system of internal control of
Portland General Electric  Company  and  its  subsidiaries  as of
December  31,  1998,  was  adequate  to provide reasonable assurance as  to  the
reliability  of  financial statements and  the  protection  of  assets  against
unauthorized acquisition,  use  or  disposition,  included  in the accompanying
report on Management's Responsibility for Financial Reporting.

Our  examination  was  made  in  accordance with standards established  by  the
American Institute of Certified Public  Accountants  and, accordingly, included
obtaining  an  understanding of the system of internal control  over  financial
reporting and the protection of assets against unauthorized acquisition, use or
disposition, testing  and  evaluating the design and operating effectiveness of
the system of internal control  and  such  other  procedures  as  we considered
necessary  in  the  circumstances.  We believe that our examination provides  a
reasonable basis for our opinion.

Because of inherent limitations in any  system  of  internal control, errors or
irregularities  may  occur  and  not  be  detected.  Also, projections  of  any
evaluation of the system of internal control to future  periods  are subject to
the risk that the system of internal control may become inadequate  because  of
changes  in  conditions,  or that the degree of compliance with the policies or
procedures may deteriorate.

In our opinion, management's  assertion  that the system of internal control of
Portland  General Electric Company and its  subsidiaries  as of
December 31,  1998,  was  adequate  to  provide  reasonable  assurance as to the
reliability  of  financial  statements  and  the  protection of assets  against
unauthorized acquisition, use or disposition is fairly  stated, in all material
respects, based upon current standards of control criteria.
                                                                               

                                                           Arthur Andersen LLP

Portland, Oregon
March 5, 1999

<PAGE>
                   
                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Shareholder of
  Portland General Electric Company:

We  have  audited  the  accompanying  consolidated balance sheets  of  Portland
General  Electric  Company  (an Oregon corporation),  and  subsidiaries  as  of
December 31, 1998 and 1997, and  the related consolidated statements of income,
retained earnings and cash flows for  each  of  the  three  years in the period
ended December 31, 1998.  These financial statements are the  responsibility of
the Company's management.  Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion, the financial statements referred  to  above present fairly, in
all  material  respects,  the financial position of Portland  General  Electric
Company and subsidiaries as  of  December 31, 1998 and 1997, and the results of
their operations and their cash flows for each of the three years in the period
ended  December  31,  1998 in conformity  with  generally  accepted  accounting
principles.

                                                           Arthur Andersen LLP

Portland, Oregon,
March 5, 1999

<PAGE>

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA              
              
              PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF INCOME


<TABLE>
<CAPTION>
For the Years Ended December 31                                      1998           1997          1996
<S>                                                                  <C>           <C>            <C>       
                                                                             (MILLIONS  OF DOLLARS)
 Operating Revenues                                                  $ 1,176       $ 1,416        $ 1,110
 Operating Expenses
  Purchased power and fuel                                               441           675            308
  Production and distribution                                            134           132            138
  Administrative and other                                               114           107            104
  Depreciation and amortization                                          149           155            162
  Taxes other than income taxes                                           57            56             52
  Income taxes                                                            81            83            116
                                                                         976         1,208            880
Net Operating Income                                                     200           208            230
Other Income (Deductions)
  Miscellaneous                                                          13            (21)           (3)
  Income taxes                                                           (1)            13             5
                                                                         12             (8)            2
Interest Charges
  Interest on long-term debt and other                                   68             69            67
  Interest on short-term borrowings                                       7              5             9
                                                                         75             74            76
Net Income                                                              137            126           156
Preferred Dividend Requirement                                            2              2             3
Income Available for Common Stock                                    $  135          $ 124        $  153

                                 Portland General Electric Company and Subsidiaries
                                    Consolidated Statements of Retained Earnings
For the Years Ended December 31
                                                                     1998            1997        1996
                                                                               (MILLIONS OF DOLLARS)
Balance at Beginning of Year                                         $ 270           $  292       $  246
Net Income                                                             137              126          156
Miscellaneous                                                            0               (2)          (2)
                                                                       407              416          400
Dividends Declared
  Common stock - cash                                                   49               47          105
  Common stock - property                                                0               97            0
  Preferred stock                                                        2                2            3
                                                                        51              146          108
Balance at End of Year                                               $ 356           $  270       $  292
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>

<PAGE>

              PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
                          CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
AT DECEMBER 31

                                                                   1998                  1997

<S>                                                              <C>                     <C>

                                                                      (MILLIONS OF DOLLARS)

        ASSETS
        ELECTRIC UTILITY PLANT - ORIGINAL COST
            Utility plant (includes Construction Work in
        Progress of
            $35 and $27)                                          $ 3,182                 $ 3,078
            Accumulated depreciation                               (1,363)                 (1,260)
                                                                    1,819                   1,818
        OTHER PROPERTY AND INVESTMENTS
            Contract termination receivable                            95                     104
            Receivable from parent                                     97                     106
            Nuclear decommissioning trust, at market value             72                      84
            Corporate Owned Life Insurance, less loans of              63                      58
        $32 and $30
            Miscellaneous                                              15                      17
                                                                      342                     369
        CURRENT ASSETS
            Cash and cash equivalents                                   4                       3
            Accounts and notes receivable                             135                     125
            Unbilled and accrued revenues                              45                      46
            Inventories, at average cost                               28                      30
            Prepayments and other                                      31                      21
                                                                      243                     225
        DEFERRED CHARGES
          Unamortized regulatory assets                               731                     819
          Miscellaneous                                                27                      25
                                                                      758                     844
                                                                  $ 3,162                 $ 3,256



        CAPITALIZATION AND LIABILITIES
        CAPITALIZATION
            Common stock equity
               Common stock, $3.75 par value per share,
        100,000,000 shares authorized,
                 42,758,877 shares outstanding                    $  160                   $ 160
               Other paid-in capital - net                           480                     480
               Retained earnings                                     356                     270
            Cumulative preferred stock
               Subject to mandatory redemption                        30                      30
            Long-term obligations                                    951                   1,008
                                                                   1,977                   1,948
        CURRENT LIABILITIES
            Accounts payable and other accruals                      145                     167
            Accrued interest                                          11                      11
            Dividends payable                                          1                       1
            Accrued taxes                                             35                      63
                                                                     192                     242
        OTHER
            Deferred income taxes                                    351                     363
            Deferred investment tax credits                           39                      43
            Trojan decommissioning and transition costs              274                     313
            Unamortized regulatory liabilities                       237                     258
            Miscellaneous                                             92                      89
                                                                     993                   1,066
                                                                 $ 3,162                 $ 3,256
        The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>

<PAGE>

              PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOW


<TABLE>
<CAPTION>
For the Years Ended December 31                             1998            1997              1996
<S>                                                        <C>             <C>               <C>        
                                                                    
                                                                       (MILLIONS OF DOLLARS)
Cash flows from Operating Activities:
Reconciliation of net income to net cash provided by
  (used in) operating activities
    
      Net Income                                             $ 137           $ 126             $ 156
      Non-cash items included in net income:
          Depreciation and amortization                        149             155               162
          Deferred income taxes                                (5)             (58)               (9)
          Other non-cash expenses                                0              24                 0
     Changes in working capital:
         (Increase) Decrease in receivables                     (8)             27               (32)
         Increase (Decrease) in payables                       (47)             51                38
         Other working capital items - net                      (4)             (1)                4
     Other -  net                                               43              35                50
Net Cash Provided by Operating Activities                      265             359               369
Cash flows from Investing Activities:
     Capital expenditures                                     (144)           (180)             (200)
     Other - net                                                (4)            (28)              (21)
Net Cash Used in Investing Activities                         (148)           (208)             (221)
Cash Flows from Financing Activities:
     Repayment of long-term debt                              (214)           (115)             (176)
     Issuance of long-term debt                                148               8               171
     Retirement of preferred stock                               0               0               (20)
     Dividends paid                                            (51)            (65)             (106)
     Other - net                                                 1               5                 0
Net Cash Used in Financing Activities                         (116)           (167)             (131)
Increase (Decrease) in Cash and Cash Equivalents                 1             (16)               17
Cash and Cash Equivalents, the Beginning of Year                 3              19                 2
Cash and Cash Equivalents, End of Year                       $   4             $ 3              $ 19
Supplemental disclosures of cash flow information
   Cash paid during the year:
      Interest, net of amounts capitalized                   $  63            $ 71              $ 73
      Income taxes                                             133              96               108
The accompanying notes are an integral part of these consolidated financial statements.

</TABLE>

<PAGE>

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES NOTES TO FINANCIAL
STATEMENTS


NATURE OF OPERATIONS
On July 1, 1997 Portland  General Corporation (PGC), the former parent of  PGE,
merged with Enron Corp. (Enron)  with  Enron  continuing  in  existence  as the
surviving  corporation.  PGE  is  now  a  wholly  owned subsidiary of Enron and
subject to control by the Board of Directors of Enron.   PGE  is engaged in the
generation,  purchase,  transmission, distribution, and sale of electricity  in
the  State  of  Oregon.   PGE   also   sells  energy  to  wholesale  customers,
predominately utilities, marketers and brokers  throughout  the  western United
States.   PGE's  Oregon  service  area  is  3,170  square  miles, including  54
incorporated  cities,  of  which Portland and Salem are the largest,  within  a
state-approved service area  allocation  of  4,070 square miles.  At the end of
1998, PGE's service area population was approximately 1.5 million, constituting
approximately 44% of the state's population and  serving  approximately 704,000
customers.


NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

CONSOLIDATION PRINCIPLES
The  consolidated  financial statements include the accounts  of  PGE  and  its
majority-owned subsidiaries.   Intercompany balances and transactions have been
eliminated.

BASIS OF ACCOUNTING
PGE and its subsidiaries' financial  statements  conform  to generally accepted
accounting  principles.   In  addition,  PGE's  accounting  policies   are   in
accordance  with  the  requirements and the rate making practices of regulatory
authorities having jurisdiction.   PGE's  consolidated  financial statements do
not reflect an allocation of the purchase price that was recorded by Enron as a
result of the PGC merger.

USE OF ESTIMATES
The preparation of financial statements requires management  to  make estimates
and  assumptions that affect the reported amounts of 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.

RECLASSIFICATIONS
Certain amounts in prior years have been reclassified for comparative purposes.

REVENUES
PGE accrues estimated unbilled  revenues  for  services provided from the meter
read date to month-end.

PURCHASED POWER
PGE credits purchased power costs for the benefits  received  through  a  power
purchase  and  sale contract with the BPA.  Reductions in purchased power costs
that result from  this  exchange  are  passed directly to PGE's residential and
small farm customers in the form of lower  prices.   PGE  and the BPA reached a
new  agreement  in September 1998 which will  continue to provide  benefits  to
PGE's residential and small farm customers through at least June 30, 2001.

DEPRECIATION
PGE's depreciation  is  computed  on  the  straight-line  method  based  on the
estimated  average  service  lives  of the various classes of plant in service.
Depreciation expense as a percent of  the  related average depreciable plant in
service was approximately 4.3% in 1998, 1997 and 1996.

The cost of renewal and replacement of property  units  is  charged  to  plant,
while  repairs  and  maintenance costs are charged to expense as incurred.  The
cost  of utility property  units  retired,  other  than  land,  is  charged  to
accumulated depreciation.

<PAGE>

PGE's capital  leases  are amortized over the life of the lease. As of December
31, 1998 and 1997, accumulated  amortization  for  capital  leases  totaled $28
million and $33 million, respectively.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC)
AFDC  represents  the  pre  tax  cost  of  borrowed funds used for construction
purposes and a reasonable rate for equity funds.   AFDC  is capitalized as part
of the cost of plant and is credited to income but does not  represent  current
cash earnings.  The average rate used by PGE was 5.5%.

INCOME TAXES
PGE's  federal  income  taxes  are  a part of its parent company's consolidated
federal income tax return.  PGE pays  for its tax liabilities when it generates
taxable income and is reimbursed for its  tax benefits by the parent company on
a  stand-alone  basis.  Deferred  income  taxes   are  provided  for  temporary
differences between financial and income tax reporting.   Amounts  recorded for
Investment  Tax  Credits  (ITC)  have been deferred and are being amortized  to
income over the approximate lives  of  the  related  properties,  not to exceed
25 years.  See Note 3, Income Taxes, for more details.

CASH AND CASH EQUIVALENTS
Highly liquid investments with original maturities of three months  or less are
classified as cash equivalents.

DERIVATIVE FINANCIAL INSTRUMENTS
PGE  uses  financial  instruments  to  hedge against exposure to interest  rate
risks.  The objective of PGE's hedging program  is  to  mitigate  risks  due to
market  fluctuations associated with external financings.  Gains and losses  on
financial  instruments  that reduce interest rate risk of future debt issuances
are deferred and amortized  over  the life of the related debt as an adjustment
to interest expense.

REGULATORY ASSETS AND LIABILITIES
The Company is subject to the provisions  of  Statement of Financial Accounting
Standards  (SFAS)  No. 71,  "Accounting for the Effects  of  Certain  Types  of
Regulation".  When the  requirements of SFAS No. 71 are met, PGE defers certain
costs which would otherwise be charged to expense if it is probable that future
prices will permit recovery  of  such  costs.   In addition, PGE defers certain
revenues, gains, or cost reductions which would normally be reflected in income
but through the rate making process ultimately will be refunded to customers.
Regulatory  assets  and  liabilities reflected as deferred  charges  and  other
liabilities in the financial  statements are amortized over the period in which
they are included in billings to customers.

Amounts in the Consolidated Balance Sheets as of December 31 relate to the
following:

<TABLE>
<CAPTION>
                                                  1998                     1997
<S>                                                <C>                      <C>
                                                       (millions of dollars)
Regulatory Assets
  Trojan-related                                  $438                     $488
  Income taxes recoverable                         165                      174
  Debt reacquisition and other                      44                       47
  Conservation investments - secured                64                       72
  Energy efficiency programs                        21                       19
  Regional Power Act                                (1)                      19
              Total Regulatory Assets             $731                     $819
Regulatory Liabilities
  Deferred gain on SCE termination                 $92                     $103
  Merger payment obligation                         96                      103
  Miscellaneous                                     49                       52
               Total Regulatory Liabilities        237                    $ 258
</TABLE>

<PAGE>

As of December 31, 1998, a majority  of  the  Company's  regulatory  assets and
liabilities are being reflected in rates charged to customers.  Based  on rates
in  place  at  year-end  1998,  the  Company  estimates  that  it  will collect
substantially all of its regulatory assets within the next 13 years.

CONSERVATION  INVESTMENTS  -  SECURED  -  In  1996, $81 million of PGE's energy
efficiency investment was designated as Bondable  Conservation  Investment upon
PGE's  issuance  of  10-year 6.91% Conservation Bonds collateralized  by  OPUC-
assured future revenues.   These  bonds  provide  savings  to  customers  while
granting  PGE  immediate  recovery  of  its  prior  energy  efficiency  program
expenditures.    Revenues  collected  from  customers  fund  the  debt  service
obligation on the  conservation  bonds.   At December 31, 1998, the outstanding
balance on the bonds was $68 million.

DEFERRED  GAIN  ON  SCE TERMINATION - In 1996,  PGE  and  SCE  entered  into  a
termination agreement  for the Power Sales Agreement between the two companies.
The agreement requires that  SCE pay PGE $141 million over 6 years ($15 million
per year in 1997 through 1999  and  $32 million per year in 2000 through 2002).
The gain is being recognized in income consistent with current rate making 
treatment.

MERGER  PAYMENT  OBLIGATION - Pursuant to the Enron/PGC merger agreement,   PGE
customers are guaranteed  $105  million  in  compensation and benefits, payable
over an eight-year period, in the form of reduced  prices.  These  benefits are
being paid by Enron, received by PGE, and passed on to PGE's retail customers.

TRANSACTIONS WITH RELATED PARTIES
As part of its ongoing operations, PGE receives management services  from Enron
and  provides incidental services to Enron and its affiliated companies.
In 1998, approximately  $12  million  was  paid to Enron for allocated overhead
costs, including PGE's $5 million share of the Employee Stock Option Plan.

<PAGE>

NOTE 2 - EMPLOYEE BENEFITS

PENSION PLAN
PGE participates in a non-contributory defined benefit pension plan (the Plan)
with other affiliated companies. Substantially all of the plan members are
current or former PGE employees.  The Plan's     assets are held in a trust.
The following tables provide a reconciliation of the changes in the plan's
benefit obligation, fair value of plan assets, a statement of the funded
status, and components of net periodic pension expense (in millions):

<TABLE>
<CAPTION>
                                                    1998                    1997
<S>                                                  <C>                     <C>
 Reconciliation of benefit obligation:
 Obligation at January 1                           $ 240                  $  222
 Service cost                                          7                       6
 Interest cost                                        17                      17
 Actuarial loss                                       17                       5
 Benefit payments                                    (12)                    (10)
 Obligation at December 31                        $  269                   $ 240
 
 Reconciliation of fair value of plan assets  
 Fair value of plan assets at January 1            $ 375                   $ 315
 Actual return on plan assets                         38                      71
 Benefit payments                                    (12)                    (11)
 Fair value of plan assets at December 31          $ 401                   $ 375
 
 Funded status
 Funded status at December 31                      $ 132                   $ 135
 Unrecognized transition (asset)                     (12)                    (14)
 Unrecognized prior service cost                       9                      11
 Unrecognized (gain)                                (117)                   (128)
 Prepaid Pension Cost                              $  12                    $  4
</TABLE>


<TABLE>
<CAPTION>
                                                     1998                   1997
<S>                                                  <C>                    <C>
ASSUMPTIONS:
Discount rate used to calculate PBO                  6.75%                  7.25%
Rate of increase in future compensation levels       5.25                   5.25
Long-term rate of return on assets                   9.00                   9.00
</TABLE>
<TABLE>
<CAPTION>
COMPONENTS OF NET PERIODIC PENSION EXPENSE:
<S>                                                <C>                    <C>
 Service cost                                      $   7                  $   6
 Interest cost on PBO                                 17                     17
 Expected return on plan assets                      (28)                   (25)
 Amortization of Transition Asset                     (2)                    (2)
 Amortization of Prior Service Cost                    1                      1
 Recognized (gain)                                    (3)                    (2)
 Net periodic pension (benefit)                    $  (8)                 $  (5)
</TABLE>

<PAGE>

OTHER POST-RETIREMENT BENEFIT PLANS
PGE accrues for health, medical and life insurance  costs during the employees'
service years, in accordance with SFAS No. 106 ("Employers' Accounting for Post
Retirement  Benefits  Other  than Pensions"). Employees  are  covered  under  a
Defined  Dollar  Medical  Benefit   Plan   which  limits  PGE's  obligation  by
establishing  a  maximum contribution per employee.   The  accumulated  benefit
obligation  for  post-retirement   health   and   life  insurance  benefits  at
December 31, 1998, was $29 million, for which there  were $33 million of assets
held in trust.

PGE also provides senior officers with additional benefits  under  an  unfunded
Supplemental  Executive  Retirement Plan (SERP).  Projected benefit obligations
for the SERP are $13 million  and  $12  million  at December 31, 1998 and 1997,
respectively.

DEFERRED COMPENSATION
PGE  provides  certain  employees with benefits under  an  unfunded  Management
Deferred Compensation Plan  (MDCP).   Obligations for the MDCP were $30 million
and $26 million at December 31, 1998 and 1997, respectively.

EMPLOYEE STOCK OWNERSHIP PLAN
PGE participates in an Employee Stock Ownership  Plan (ESOP) which is a part of
its 401(k) retirement savings plan.  One-half of employee  contributions  up to
6% of base pay are matched by employer contributions in the form of ESOP common
stock.   Shares  of  common  stock  to  be  used  to match contributions by PGE
employees are purchased from Enron at current market prices.

ALL EMPLOYEE STOCK OPTION PLAN
Enron granted stock options to PGE employees on December 31, 1997.  The options
were granted at the fair value of the stock at the  date  of  the  grant.  One-
third of the options vested in 1998 and one-third of the options will  vest  in
1999  and  in  2000.   PGE pays Enron the estimated value of the shares vesting
each year.  The fair value  of shares that vested in 1998 was $5 million and is
estimated to be $5 million in  both  1999  and  2000.   The value is calculated
using the Black-Scholes option-pricing model.

<PAGE>


NOTE 3 - INCOME TAXES

The following table shows the detail of taxes on income and  the  items used in
computing  the  differences between the statutory federal income tax  rate  and
PGE's effective tax rate (millions of dollars):

<TABLE>
<CAPTION>
                                          1998            1997                  1996
<S>                                       <C>             <C>                   <C>
Income Tax Expense
Currently payable
    Federal                               $ 75             $  114              $  98
    State and local                         13                 14                 22
                                            88                128                120
Deferred income taxes
    Federal                                 (1)               (45)                (4)
    State and local                         (1)                (9)                (1)
                                            (2)               (54)                (5)
Investment tax credit adjustments           (4)                (4)                (4)
                                          $ 82              $  70              $ 111
Provision Allocated to:
   Operations                              $ 81             $  83              $ 112
   Other income and deductions                1               (13)                (1)
                                           $ 82             $  70              $ 111

Effective Tax Rate Computation:
Computed tax based on statutory
federal income tax rates applied           $ 77             $  69              $  93
Flow through depreciation                     4                 6                  9
State and local taxes - net                   7                13                 12
State of Oregon refund                        -                (9)                 -
Investment tax credits                       (4)               (4)                (3)
Excess deferred tax                          (1)               (1)                (1)
Other                                        (1)               (4)                 1
                                           $ 82             $  70              $ 111
Effective tax rate                         37.5%             35.7%              41.6%
</TABLE>


<PAGE>

As of December 31,  1998 and 1997, the significant components of PGE's deferred
income tax assets and liabilities were as follows (millions of dollars):
<TABLE>
<CAPTION>
                                          1998                    1997
<S>                                       <C>                     <C>
DEFERRED TAX ASSETS
Depreciation and amortization             $   27                  $   31
SCE termination payment                       42                      49
Other regulatory liabilities                  14                      12
Employee fringe benefits                      15                      15
Other                                          4                      12
                                             102                     119
DEFERRED TAX LIABILITIES
Depreciation and amortization             $ (378)                 $ (393)
Price risk management                         (9)                    (10)
Trojan abandonment                           (56)                    (63)
Other regulatory assets                       (3)                     (4)
Other                                         (7)                    (12)
                                            (453)                   (482)
Total                                     $ (351)                 $ (363)
</TABLE>
PGE  has  recorded deferred  tax  assets  and  liabilities  for  all  temporary
differences  between  the financial statement basis and tax basis of assets and
liabilities.

<PAGE>


NOTE 4 - COMMON AND PREFERRED STOCK


<TABLE>
<CAPTION>
                                    COMMON STOCK      CUMULATIVE PREFERRED    Other
                                Number     $3.75 Par    Number    $100 Par    No-Par    Paid-in    Unearned
                                OF SHARES   VALUE      OF SHARES   VALUE      VALUE     CAPITAL    COMPENSATION
<S>                             <C>         <C>         <C>        <C>         <C>       <C>       <C>

 (millions of dollars
  except share amounts)

December 31, 1995              42,758,877   $160       500,000   $  20        $30       $473      $  (7)
Redemption of preferred stock          -      -       (200,000)    (20)         -          2          -
Repayment of ESOP loan
and other                              -      -              -       -          -          2          5

December 31, 1996              42,758,877   $160       300,000       -        $30       $477      $  (2)
Repayment of ESOP loan
and other                               -      -             -       -          -          3          2
                                                    
December 31, 1997              42,758,877   $160       300,000   $   -        $30       $480          -

December 31, 1998              42,758,877   $160       300,000   $   -        $30       $480      $   -

</TABLE>

CUMULATIVE PREFERRED STOCK
PGE has authorized 30 million  shares  of  cumulative  preferred  stock, no par
value;  there  are  300,000 shares of the 7.75% series outstanding.  The  7.75%
series preferred stock  has  an  annual sinking fund requirement which requires
the redemption of 15,000 shares at  $100  per  share  beginning in 2002. At its
option, PGE may redeem, through the sinking fund, an additional  15,000  shares
each  year.  All remaining shares shall be mandatorily redeemed by sinking fund
in 2007. This series is only redeemable by operation of the sinking fund.

No dividends may  be  paid on common stock or any class of stock over which the
preferred stock has priority  unless  all  amounts  required  to  be  paid  for
dividends and sinking fund payments have been paid or set aside, respectively.

COMMON DIVIDEND RESTRICTION OF SUBSIDIARY
Enron  is  the  sole shareholder of PGE common stock.  PGE is restricted
from paying dividends or  making  other  distributions  to  Enron without
prior  OPUC  approval to the extent such payment or distribution  would  reduce
PGE's common stock equity capital below 48% of its total capitalization.

<PAGE>

NOTE 5 - CREDIT FACILITIES AND DEBT

At December 31,  1998, PGE had committed lines of credit totaling $200 million,
expiring in July 2000. These lines of credit have an annual fee of 0.10% and do
not require compensating  cash  balances.   These  lines  of  credit  are  used
primarily  as  backup  for both commercial paper and borrowings from commercial
banks under uncommitted  lines  of credit.  At December 31, 1998, there were no
outstanding borrowings under the committed lines of credit.

PGE has a $200 million commercial  paper  facility.  Unused  committed lines of
credit  must  be  at  least  equal  to  the  amount  of PGE's commercial  paper
outstanding.   Commercial  paper and lines of credit borrowings  are  at  rates
reflecting current market conditions.

PGE sells commercial paper to provide financing for various corporate purposes.
As of December 31, 1998, commercial  paper borrowings of $105 million have been
classified as long-term debt based upon  the  availability  of committed credit
facilities with expiration dates exceeding one year and management's  intent to
maintain such amounts in excess of one year.  Similarly, at December 31,  1998,
$102 million of long-term debt due within one year is classified as long-term.

Short-term borrowings and related interest rates were as follows:

<TABLE>
<CAPTION>
                                                    1998                    1997
<S>                                                  <C>                     <C>
AS OF YEAR-END:                                         (millions of dollars)
   Aggregate short-term debt outstanding
    Commercial paper                                 $105                    $100
  Weighted average interest rate*
    Commercial paper                                  5.2%                    6.0%
    Committed lines of credit                        $200                    $200
FOR THE YEAR ENDED:
    Average daily amounts of short-term
    debt outstanding
    Commercial paper                                 $113                    $ 89
    Weighted daily average interest rate*
     Commercial paper                                 5.4%                    5.6%
    Maximum amount outstanding
     during the year                                 $144                    $115
</TABLE>

             *  Interest  rates exclude the effect of commitment fees, facility
fees and other financing fees.

<PAGE>


The Indenture securing PGE's  First  Mortgage  Bonds constitutes a direct first
mortgage lien on substantially all utility property  and franchises, other than
expressly excepted property.

<TABLE>
<CAPTION>
                                                                           1998           1997
<S>                                                                        <C>            <C>

Schedule of long-term debt at December 31                                             

                                                                          (millions of dollars)
First Mortgage Bonds
  Maturing 1998 through 2003 5.65% - 8.88%                              $   219       $   241
  Maturing 2004 - 2007 7.15% - 9.07%                                        113           153
  Maturing 2021 - 2023  7.75% - 9.46%                                       170           170
                                                                            502           564
Pollution Control Bonds
  Port of Morrow, Oregon, variable rate, due 2013
&  2031
     (Average rate 3.5% for 1998)                                             6            29
  Port of Morrow, Oregon, variable rate, due 2031                            23             -
& 2033
     (4.60% fixed rate to 2033)
  City of Forsyth, Montana, variable rate, due                                -           119
2013 & 2016
  Amount held by trustee                                                      -            (8)
  City of Forsyth, Montana, variable rate, due
2033
     (4.60% - 4.75% fixed rate to 2003)                                     119             -
  Port of St. Helens, Oregon, 4.80% - 7 1/8%, due                            52            52
2010 &
                                                                            200           192
Other
  8.25% Junior Subordinated Deferrable Interest
     due December 31, 2035                                                   75            75
  6.91% Conservation Bonds maturing monthly to                               68            73
2006
  Capital lease obligations                                                   1             4
  Commercial Paper                                                          105           100
                                                                            249           252
 Total long-term debt                                                     $ 951       $ 1,008
</TABLE>


The following principal amounts of long-term debt (excluding  Commercial Paper)
become due through regular maturities (millions of dollars):

<TABLE>
<CAPTION>
                       1999             2000             2001             2002             2003
<S>                    <C>              <C>              <C>              <C>              <C>
    Maturities:
    PGE               $102              $32              $53              $23              $49
</TABLE>


<PAGE>

NOTE 6 - OTHER FINANCIAL INSTRUMENTS

FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the  fair  value of
each  class of financial instrument for which it is practical to estimate  that
value.

CASH AND  CASH  EQUIVALENTS  - The carrying amount of cash and cash equivalents
approximates fair value because of the short maturity of those instruments.

OTHER INVESTMENTS - Other investments approximate market value.

REDEEMABLE PREFERRED STOCK - The  fair  value  of redeemable preferred stock is
based on quoted market prices.

LONG-TERM DEBT - The fair value of long-term debt  is  estimated  based  on the
quoted  market  prices  for  the same or similar issues or on the current rates
offered to PGE for debt of similar remaining maturities.

INTEREST RATE SWAPS - At December  31, 1998, PGE had entered into interest rate
swap agreements with a notional principal  amount  of  $142  million  to manage
interest  rate  exposure.  In  March  1999  PGE  unwound these agreements.  The
estimated  fair value of these agreements is based  on  the  amount  PGE  would
receive if the agreements were terminated.

The estimated  fair  values  of  debt  and  equity  instruments  are as follows
(millions of dollars):

<TABLE>
<CAPTION>

                              1998                                    1997
<S>                           <C>                        <C>          <C>                    <C>
                              Carrying                   Fair         Carrying               Fair
                              Amount                     Value        Amount                 Value
Preferred stock subject to
mandatory redemption           $ 30                      $ 35          $ 30                   $ 34
Long-term debt                 $777                      $822          $831                   $861
Interest rate swaps in net
receivable position            $  -                      $  1          $  -                   $  -
</TABLE>

<PAGE>

NOTE 7 - COMMITMENTS

NATURAL GAS AGREEMENTS
PGE has long-term agreements for transmission of natural gas from  domestic and
Canadian  sources  to  natural gas-fired generating facilities.  The agreements
provide firm pipeline capacity.   Under  the  terms of these agreements, PGE is
committed to paying capacity charges of approximately  $15  million annually in
1999 through 2003 and $122 million over the remaining years of  the  contracts.
PGE's  capacity  payments  amounted  to  $16 million in 1998 and 1997, and  $15
million in 1996.  These contracts expire at  varying  dates  from 2001 to 2015.
PGE has the right to assign unused capacity to other parties.

PURCHASE COMMITMENTS
Purchase  commitments  outstanding,  which  include  construction,   coal,  and
railroad service agreements, totaled approximately $51 million at December  31,
1998.   Cancellation  of these purchase agreements could result in cancellation
charges.

FUEL CONTRACTS
PGE has coal and transportation contracts with take-or-pay obligations totaling
$7  million  for  1999  and   $1   million  for  2000.   Coal  purchases  under
unconditional purchase obligations in  1998,  1997, and 1996 respectively, were
$5 million, $2 million, and $3 million.

PURCHASED POWER
PGE  has  long-term  power  purchase  contracts  with  certain  public  utility
districts in the state of Washington and with the  City  of  Portland,  Oregon.
PGE  is  required  to  pay  its  proportionate  share of the operating and debt
service costs of the hydro projects whether or not they are operable.

Selected information is summarized as follows (millions of dollars):

<TABLE>
<CAPTION>
                                                ROCKY          PRIEST                                      PORTLAND
                                                REACH          RAPIDS         WANAPUM          WELLS          HYDRO
<S>                                            <C>             <C>             <C>             <C>            <C>
Revenue bonds outstanding at
December 31, 1998                                $238         $   171         $   157           $173           $ 34
PGE's current share of:
   Output                                        12.0%           13.9%           18.7%          20.3%           100%
   Net capability (megawatts)                     154             131             194             171            36
Annual cost, including debt service:
   1998                                             6               4               6               6              4
   1997                                             7               3               4               6              4
   1996                                             5               4               5               6              4
Contract expiration date                         2011            2005            2009            2018           2017
</TABLE>

PGE's share of debt service costs, excluding interest, will be approximately $5
million for 1999, $7 million  for 2000 thru 2002, and $8 million for 2003.  The
minimum payments through the remainder of the contracts  are estimated to total
$70 million.

PGE has entered into long-term contracts to purchase power from other utilities
in the region.  These contracts will require fixed payments  of up to $23 
million
in 1999, $20 million in 2000, and $19 million in 2001 through 2003.  After that
date, capacity contract charges will average $19 million annually  until  2016.
Long-term  contract  payments  amounted  to $22 million in 1998, $23 million in
1997, and $28 million in 1996.

LEASES
PGE  has  operating  and  capital  leasing arrangements  for  its  headquarters
complex,  combustion  turbines and the  coal-handling  facilities  and  certain
railroad cars for Boardman.  PGE's aggregate rental payments charged to 

<PAGE>

expense
totaled $23 million in 1998, $24 million in 1997, and $22 million in 1996.  PGE
has  capitalized its combustion  turbine  leases;  however,  these  leases  are
considered operating leases for rate making purposes.
Future  minimum  lease  payments  under  non-cancelable  leases  are as follows
(millions of dollars):


<TABLE>
<CAPTION>
         YEAR ENDING                                        OPERATING LEASES
         DECEMBER 31             CAPITAL LEASES         (NET OF SUBLEASE RENTALS)             TOTAL
<S>                               <C>                    <C>                                  <C>
          1999                         $1                          $  21                       $ 22
          2000                          -                             22                         22
          2001                          -                             21                         21
          2002                          -                             11                         11
          2003                          -                             11                         11
      Remainder                         -                            162                        162  
      Total                            $1                           $248                       $249
      Imputed Interest                  -                      
      Present Value of
      Minimum Future
      Net Lease Payments               $1
</TABLE>


Included  in  the  future  minimum  operating lease payments schedule above  is
approximately $114 million for  PGE's headquarters complex.

The lease of combustion turbine generators  at  Bethel terminated at the end of
1998.  In February 1999, PGE exercised its option  to  purchase  the combustion
turbine generators at Beaver for $37 million at the August 1999 termination  of
the lease.


NOTE 8 - WNP-3 SETTLEMENT EXCHANGE AGREEMENT

During 1997, PGE transferred its rights and certain obligations under the WNP-3
Settlement Exchange Agreement (WSA) and the long-term power sale agreement with
the  Western Area Power Administration (WAPA) to Enron in the form of a special
non-cash dividend.


NOTE 9 - JOINTLY OWNED PLANT

At December  31,  1998,  PGE  had  the  following  investments in jointly owned
generating plants (millions of dollars):

<TABLE>
<CAPTION>
                                                             MW               PGE %            PLANT          ACCUMULATED
     FACILITY           LOCATION            FUEL          CAPACITY          INTEREST        IN SERVICE       DEPRECIATION
<S>                    <C>                 <C>            <C>               <C>              <C>              <C>
  Boardman           Boardman, OR           Coal             529              65.8             $380              $208
  Colstrip 3&4       Colstrip, MT           Coal           1,440              20.0              454               235
  Centralia          Centralia, WA          Coal           1,310               2.5               10                 6
</TABLE>


The dollar amounts in the table above represent PGE's  share  of  each  jointly
owned plant.  Each participant in the above generating plants has provided  its
own  financing.  PGE's share of the direct expenses of these plants is included
in  the   corresponding   operating   expenses  on  PGE's  consolidated  income
statements.

<PAGE>

NOTE 10 - LEGAL MATTERS

TROJAN INVESTMENT RECOVERY - On June 24,  1998,  the  Oregon  Court  of Appeals
ruled  that  the  OPUC  does  not have the authority to allow PGE to recover  a
return on its undepreciated investment  in the Trojan generating facility.  The
court upheld the OPUC's authorization of  PGE's  recovery  of its undepreciated
investment in Trojan.

The  Court  of Appeals decision was a result of combined appeals  from  earlier
circuit court  rulings.   In  April  1996,  a Marion County Circuit Court judge
ruled  that  the  OPUC  could not authorize PGE to  collect  a  return  on  its
undepreciated investment  in  Trojan, contradicting a November 1994 ruling from
the same court upholding the OPUC's  authority.  The 1996 ruling was the result
of an appeal of PGE's 1995 general rate  order  which  granted PGE recovery of,
and a return on, 87 percent of its remaining investment in Trojan.

On  August  26,  1998, PGE and the OPUC filed a Petition for  Review  with  the
Oregon Supreme Court,  supported  by  amicus  briefs filed by three other major
utilities  seeking  review  of  that portion of the  Oregon  Court  of  Appeals
decision relating to PGE's return  on  its  undepreciated investment in Trojan.
If the Supreme Court declines to hear the case,  it  would  be referred back to
the  OPUC.   Due to uncertainties in the regulatory process, management  cannot
predict, with  certainty,  what  ultimate rate making action the OPUC will take
regarding PGE's recovery of a rate of return on its Trojan investment.

Also on August 26, 1998, the Utility Reform Project filed a Petition for Review
with the Oregon Supreme Court seeking  review  of  that  portion  of the Oregon
Court  of  Appeals  decision  relating  to  PGE's recovery of its undepreciated
investment in Trojan.

At December 31, 1998, PGE's after-tax Trojan plant investment was $170 Million.
PGE  is  presently  collecting annual revenues of  approximately  $21  million,
representing the return  on  its  undepreciated  investment.   Revenue  amounts
reflecting a recovery of a return on the Trojan investment decline through  the
recovery period which ends in the year 2011.

Management  believes that the ultimate outcome will not have a material adverse
impact on the  financial  position  of  the  Company.   However,  it may have a
material impact on the results of operations for future reporting periods.

OTHER  LEGAL MATTERS - PGE is party to various other claims, legal actions  and
complaints  arising  in  the ordinary course of business.  These claims are not
considered material.

<PAGE>


NOTE 11 - TROJAN NUCLEAR PLANT

PLANT SHUTDOWN AND TRANSITION COSTS - PGE is a 67.5% owner of Trojan.  In early
1993, PGE ceased commercial  operation  of  the  nuclear  plant.   Since  plant
closure, PGE has committed itself to a safe and economical transition toward  a
decommissioned  plant.   Remaining  transition costs associated with  operating
and  maintaining the spent fuel pool and  securing  the  plant  until  fuel  is
transferred to dry storage in 1999 are estimated at $8 million and will be paid
from current operating funds.

DECOMMISSIONING  -  In December 1997, PGE filed an updated decommissioning plan
estimate with the OPUC.   The  plan estimates PGE's cost to decommission Trojan
at $339 million, reflected in nominal  dollars  (actual  dollars expected to be
spent  in  each  year).   The primary reason for the reduction  from  the  $351
million estimated  in  1994  is  a  lower  inflation  rate,  coupled  with  the
acceleration of certain decommissioning activities and partially offset by cost
increases  related  to  the  spent  fuel storage project.  The current estimate
assumes that the majority of decommissioning activities will occur between 1998
and  2002, while fuel management costs  extend  through  the  year  2018.   The
original plan represents a site-specific decommissioning estimate performed for
Trojan   by   an  engineering  firm  experienced  in  estimating  the  cost  of
decommissioning  nuclear  plants.  Updates to the plan's original estimate have
been prepared by PGE.  Final  site  restoration  activities  are anticipated to
begin  in 2018 after PGE completes shipment of spent fuel to a  USDOE  facility
(see the  Nuclear Fuel Disposal discussion below).  Stated in 1998 dollars, the
decommissioning cost estimate is $290 million.

TROJAN DECOMMISSIONING LIABILITY
(millions of dollars)

Estimated - 12/31/94                    $351
Updates filed with NRC - 11/16/95          7
Updates filed with OPUC - 12/01/97       (19)
                                         339

Expenditures through 12/31/98            (73)              
Liability - 12/31/98                     266

Transition costs                           8
Total Trojan obligation                 $274


PGE  is collecting  $14  million  annually  through  2011  from  customers  for
decommissioning  costs.   These amounts are deposited in an external trust fund
which   is  limited to reimbursing  PGE  for  activities  covered  in  Trojan's
decommissioning  plan.   Funds were withdrawn during 1998 to cover the costs of
planning and licensing activities  in  support  of  the  independent spent fuel
storage  installation  and  the reactor vessel and internals  removal  project.
Decommissioning funds are invested  primarily  in  investment-grade, tax-exempt
and U.S. Treasury bonds.  Year-end  balances are valued at market.

Earnings  on  the trust fund are used to reduce the amount  of  decommissioning
costs to be collected  from  customers.   PGE  expects  any  future  changes in
estimated  decommissioning  costs to be incorporated in future revenues  to  be
collected from customers.

DECOMMISSIONING TRUST ACTIVITY
(Millions of dollars)

                                1998            1997
Beginnning Balance              $84             $78
 Activity
  Contributions                  14              14
  Gain                            4               6
Disbursements                   (30)            (14)

  Ending Balance                $72             $84


NUCLEAR FUEL DISPOSAL AND CLEANUP  OF  FEDERAL PLANTS - PGE contracted with the
USDOE for permanent disposal of its spent nuclear fuel in federal facilities at
a cost of 0.1<cent> per net kilowatt-hour sold at Trojan which the Company paid
during the period the plant operated.  Significant  delays  are expected in the
USDOE acceptance schedule of spent fuel from domestic utilities.   The  federal
repository, which was originally 

<PAGE>

scheduled to begin operations in 1998, is  now
estimated  to  commence  operations  no  earlier  than  2010.   This may create
difficulties for PGE in disposing of its high-level radioactive waste  by 2018.
However,  federal  legislation  has  been  introduced  which,  if passed, would
require USDOE to provide interim storage for high-level waste until a permanent
site  is  established.   PGE  intends  to build an interim storage facility  at
Trojan to house the nuclear fuel until a federal site is available.

The Energy Policy Act of 1992 provided for  the  creation  of a Decontamination
and Decommissioning Fund to finance the cleanup of USDOE gas  diffusion plants.
Funding comes from domestic nuclear utilities and the federal government.  Each
utility contributes based on the ratio of the amount of enrichment services the
utility purchased to the total amount of enrichment services purchased  by  all
domestic  utilities  prior  to  the  enactment  of  the  legislation.  Based on
Trojan's 1.1% usage of total industry enrichment services, PGE's portion of the
funding requirement is approximately $17 million.  Amounts  are  funded over 15
years  beginning with the USDOE's fiscal year 1993.  Since enactment,  PGE  has
made the  first  seven of the 15 annual payments with the first payment made in
September 1993.

NUCLEAR  INSURANCE  -  The  Price-Anderson  Amendment  of  1988  limits  public
liability claims that could arise from a nuclear incident and provides for loss
sharing among  all owners of nuclear reactor licenses.  Because Trojan has been
permanently defueled,  the  NRC  has  exempted  PGE  from  participation in the
secondary financial protection pool covering losses in excess  of  $200 million
at other nuclear plants.  In addition, the NRC has reduced the required primary
nuclear  insurance  coverage  for  Trojan  from  $200  million  to $100 million
following a 3 year cool-down period of the nuclear fuel that is still  on-site.
The  NRC  has  allowed  PGE  to  self-insure  for on-site decontamination.  PGE
continues to carry non-contamination property insurance  on the Trojan plant at
the $158 million level.

<PAGE>

                  QUARTERLY COMPARISON FOR 1998 AND 1997 (UNAUDITED)



<TABLE>
<CAPTION>
                            MARCH 31    JUNE 30   SEPTEMBER 30   DECEMBER 31      TOTAL
                                                     (MILLIONS OF DOLLARS)
<S>                         <C>         <C>        <C>            <C>            <C>
1998
Operating revenues           $314        $260         $274          $328         $ 1,176
Net operating income           52          42           41            65             200
Net income                     37          24           26            50             137
Income available for
  common stock                 36          25           25            49             135

1997
Operating revenues           $368        $308         $391          $349         $ 1,416
Net operating income           65          46           46            51             208
Net income                     48          28           15            35             126
Income available for
  common stock                 47          28           14            35             124

</TABLE>



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


None.

<PAGE>


ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT


DIRECTORS OF THE REGISTRANT (*)


JAMES V. DERRICK, JR., age 54
Director since 1997
  Mr. Derrick has served as Senior Vice President and General  Counsel of Enron
  since June 1991.  Prior to joining Enron  in 1991, Mr. Derrick  was a partner
  at the law firm of Vinson & Elkins L.L.P. for over 13 years.

PEGGY Y. FOWLER, age 47
Director since 1998
  Ms. Fowler has served as President of Portland General Electric Company since
  1997.   Ms.  Fowler  served  as  Executive Vice President and Chief Operating
  Officer of Portland General Electric  from  November  1996 until appointed to
  current  position.   Ms  Fowler  also  serves  on the boards  of  George  Fox
  University,  Goodwill  Industries,  Legacy  Health System,  and  Lifewise,  a
  Premera Health Plan Inc.

KEN L. HARRISON, age 56
Director since 1987
  Mr. Harrison serves as a Director and Vice Chairman  of Enron  and has served
  as Chairman and Chief Executive Officer of Portland General  Electric Company
  since  1987.   Mr.  Harrison  is also a Director of Enron Oil & Gas  Company,
  Enron Communications Inc, and Rythyms Net Connections.

JOSEPH M. HIRKO, age 42
Director since 1997
  Mr. Hirko serves as Senior Vice  President  of  Enron   and  also  serves  as
  President  and Chief Executive Officer of Enron Communications.  From 1991 to
  1998 he served  as  Vice  President-Finance,  Chief  Financial Officer, Chief
  Accounting Officer and Treasurer of Portland General Electric Company.

KENNETH L. LAY, age 56
Director since 1997
  Mr. Lay has served as Chairman of the Board and Chief  Executive  Officer  of
  Enron   since  February  1986.    Mr. Lay is also a Director of Eli Lilly and
  Company, Compaq Computer Corporation,  Enron  Oil  & Gas Company, EOTT Energy
  Corp. (the general partner of EOTT Energy Partners,  L.P.)  and Trust Company
  of the West.

JEFFREY K. SKILLING, age 45
Director since 1997
  Since  January  1,  1997,  Mr  Skilling  has  served  as President and  Chief
  Operating Officer of Enron   From June 1995 until December  1996 he served as
  Chief  Executive  Officer  and  Managing  Director of Enron Capital  &  Trade
  Resources Corp. ("ECT").  From August 1990  until  June  1995,  Mr.  Skilling
  served ECT in a variety of senior managerial positions.


(*)Directors  of  PGE hold office until the next annual meeting of shareholders
   or until their respective successors are duly elected and qualified.

<PAGE>

              PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF CASH FLOW

EXECUTIVE OFFICERS OF THE REGISTRANT (*)


<TABLE>
<CAPTION>

NAME                           AGE  BUSINESS EXPERIENCE
<S>                            <C>  <C>

Ken L. Harrison                56   Appointed to current position of Chairman 
  Chairman and Chief                and Chief Executive Officer on December 1,
  Executive Officer                 1988.
                


Peggy Y. Fowler                47   Appointed to current position on June 24, 
 President and Chief                1997.  Served as Executive Vice President 
 Operating Officer                  and Chief Operating Officer, PGE from 
                                    November 1996 until appointed to current
                                    position.  Served as Senior Vice President, 
                                    Energy Services from September 1995 until 
                                    November 1996. Served as Vice President, 
                                    Distribution and Power Production from 
                                    January 1990 to September 1995.



Alvin L. Alexanderson          51   Appointed to current position on December
 Senior Vice President              12, 1995.  Served as Vice President, 
 General Counsel and                Rates and Regulatory Affairs from 
 Secretary                          February 1991 until appointed to current
                                    position.


Frederick D. Miller            56   Appointed to current position on June 24, 
 Senior Vice President              1997.  Served as Senior Vice President, 
 Public Policy and                  Public Affairs and Corporate Services
 Administrative Services            from November 1996 until appointed to
                                    current position. Served as Director of
                                    Executive Department, State of Oregon,
                                    from 1987 until appointed to Vice
                                    President, Public Affairs and Corporate
                                    Services in October 1992.
 

Walter E. Pollock              56   Appointed to current position  on October 
 Senior Vice President              14, 1997.  Served as Vice President, Enron 
 Power Supply                       Capital and Trade and Senior Vice 
                                    President, First Point Utility Solutions
                                    from November 1996  until  appointed  to 
                                    current position.  Served  as  Group
                                    Vice  President,  Marketing Conservation
                                    and Production at Bonneville Power
                                    Administration (BPA) from April 1994
                                    to November 1996.  Served as Assistant
                                    Administrator at BPA, Office of Power
                                    Sales from January 1988 until March 1994.


Arleen N. Barnett              46   Appointed to current position on February
 Vice President                     1, 1998.   Served  as  Manager, Human 
 Human Resources                    Resources from 1989 until appointed to
                                    current position.


David K. Carboneau             52   Appointed to current position in October
 Vice President                     1998. Served as President of  First 
 Products and Services              Point Utility Solutions  until  appointed
                                    to  current  position.  Served  as Vice
                                    President, Utility  Service and
                                    Telecommunications from January 1997
                                    until July 1997.  Served as Vice
                                    President, Information Technology from
                                    January  1996 until January 1997.
                                    Served as Vice President, Thermal and
                                    Power Operations from September 1995 to
                                    January 1996.  Served as Vice President,
                                    PGE Administration from October 1992 to
                                    September 1995.


Stephen R. Hawke               49   Appointed to current position on July 1,
 Vice President                     1997.  Served as General Manager, System
 Delivery System                    Planning and Engineering until appointed to
 Planning and                       current position.  Served as Manager,
 Engineering                        Response and Restoration from May 1993
                                    until May 1995.  Served as Manager,
                                    Western Region from August 1990 until
                                    May 1993.


<PAGE>

EXECUTIVE OFFICERS OF THE REGISTRANT (*) - CONTINUED.


                                                      
                                
NAME                          AGE   BUSINESS EXPERIENCE
          
Pamela G. Lesh                 42   Appointed to current position on December 
 Vice President                     31, 1998.  Served as Vice President,
 Rates and Regulatory               Strategy and Product Management with
 Affairs                            ConneXt Corp. of Seattle since June 1997. 
                                    Previously served at Portland General
                                    Electric as Vice President, Rates and 
                                    Regulatory Affairs from November 1996 to
                                    June 1997.  Served as Director of
                                    Marketing Strategy from May 1996 to June
                                    1997. Served as Director of Rates and
                                    Regulatory Affairs from 1992 to 1996.


Joe A. McArthur                51   Appointed to current position on July 1, 
 Vice President                     1997.  Served as Manager of Western
 Substation and Line                Region from May 1996 until appointed to
 Operations                         current position.  Served as Manager,
                                    System Planning from May 1995 to May 
                                    1996.  Served as Commercial and 
                                    Industrial Market Manager from 1993 to
                                    1995.  Served as Substation Maintenance 
                                    and Metering Manager from 1980 to 1993.


James J. Piro                  46   Appointed  to  current  position on
 Vice President                     February 23, 1998.  Served as General
 Business Development               Manager, Planning Support and Analysis
                                    from November 1992 until appointed to
                                    current position.
  


Stephen M. Quennoz             51   Appointed to current position  in  October,
 Vice President                     1998.  Joined PGE in 1991 and held the
 Nuclear and Thermal                position of Trojan Site Executive and
 Operations                         Plant General Manager since 1993.



Christopher D. Ryder           49   Appointed to current position on July 1,
 Vice President                     1997.  Served as General Manager, Customer
 Distribution and                   Services and Southern Region Operations from
 Customer Service                   1996 until appointed to current position.
                                    Served as General Manager,  Customer
                                    Services  and  Marketing  from 1992 to 
                                    1996.


Mary K. Turina                 31   Appointed  to  current  position  on  March 
 Treasurer, Controller              10,  1999.  Served as Controller, Chief 
 and Chief Accounting               Accounting Officer and Assistant Treasurer
 Officer                            until appointed to current position.
                                    Served as Manager of Risk Management,
                                    Reporting and Control from March 1996
                                    to July 1998.  Served as Senior Business
                                    Analyst from 1991 to 1996.

</TABLE>

(*)   Officers  are  listed as of March 10, 1999; they are elected for one-year
terms or until their successors are elected and qualified.


<PAGE>


ITEM 11.  EXECUTIVE COMPENSATION


                          Summary Compensation Table

The following indicates  total compensation earned for the years ended December
31, 1998, 1997, 1996 by the  Chief  Executive  Officer and the four most highly
compensated executive officers of PGE.

<TABLE>
<CAPTION>
                                                                                              Long-Term
                                                         Annual Compensation                Compensation            All Other
<S>                                   <C>            <C>               <C>                <C>                      <C>
                                                     Salary                               Restricted Stock        Compensation
Name and Principal Position           Year              (1)               Bonus              Awards (2)                 (3)
Ken L. Harrison (5)                   1998          $206,799            $183,200             $  705,483              $12,050
  Chairman                            1997           243,570             236,592                204,755               68,051
  Chief Executive Officer             1996           399,510             252,193                251,410               40,480

Peggy Y. Fowler                       1998           246,664             300,000                200,004               17,443
  President, Chief Operating          1997           230,000             160,000                230,185               29,406
  Officer                             1996           202,504             106,379                150,500               24,045

Walter E. Pollock (4)                 1998           176,191             140,000                 75,037                5,664
   Senior Vice President,             1997            37,500              24,000                      0                  826
   Power Supply                       1996                 0                   0                      0                    0

Frederick D. Miller                   1998           181,684             150,000                 68,760               10,233
   Senior Vice President, Public      1997           175,020             105,000                      0               48,906
   Policy and Administrative          1996           161,259              73,811                 75,250               36,400
   Services

James J. Piro                         1998           157,535              128,063                50,043                5,081
 Vice President, Business             1997           131,352              140,000                     0                7,743
    Development                       1996           104,304               36,226                     0                6,210
</TABLE>

(1)   Amounts  shown  include  cash compensation earned  and  received  by  the
      executive officer, as well as amounts earned but deferred at the election
      of the officer.

(2)   Restricted stock awards are  valued  at the closing price of $41.4375 per
      share of Enron  common stock for the July 1, 1997, grant which vested 20%
      on July 1, 1998, and 20% on each of the  following  four anniversaries of
      the  date  of grant.  Dividend equivalents for the July  1,  1997,  grant
      accrue from  the  date  of  grant  and are paid upon vesting.  Restricted
      stock awards are valued at the closing  price of $37.625 per share of PGC
      common stock for the September 10, 1996 grant,  which  converted to Enron
      shares on the effective date of the merger.  Dividends on  this grant are
      paid  as declared.  Restricted stock awarded to Mr. Harrison  on  October
      12, 1998,  is  valued  at  the  $50.9375 per share closing price of Enron
      common stock on that date; one-third  of the shares vest on January 31 of
      each  of  the  next three years, beginning  in  1999.   Restricted  stock
      awarded to other officers was granted December 31, 1998, and is valued at
      the $57.0625 per share closing price of Enron  common stock on that date.
      Aggregate restricted  stock  holdings listed below are valued at $57.0625
      per share, the closing price of  the  Enron  common stock on December 31,
      1998.

                                           AGGREGATE RESTRICTED STOCK HOLDINGS

                                           AGGREGATE SHARES (#)     VALUE 
      Ken L. Harrison                           58,743             $3,352,022
      Peggy Y. Fowler                           11,879                677,845
      Walter E. Pollock                          1,315                 75,037
      Frederick D. Miller                        3,170                180,888
      James J. Piro                                877                 50,044

<PAGE>

(3)   Other  compensation  includes: (i) company-paid  split  dollar  insurance
      premiums; (ii) the dollar  value of life insurance benefits as determined
      under  the Commission's methodology  for  valuing  such  benefits;  (iii)
      company  contributions  to  the  RSP  and  the MDCP; and (iv) earnings on
      amounts in the MDCP which are greater than 120  percent  of  the  federal
      long-term  rate  which  was  in effect at the time the rate was set.  The
      following are amounts for 1998:
<TABLE>
<CAPTION>

                                                    
                                 Split Dollar       Dollar Value of   Contributions to    Above Market
                              Insurance Premiums    Life Insurance    401 (k) and MDCP    Interest on MDCP       Total
<S>                          <C>                     <C>              <C>                 <C>                   <C>
Ken L. Harrison                    $   403             $1,130             $ 4,103             $ 6,414           $12,050

Peggy Y. Fowler                        450              7,430               8,109               1,454            17,443

Walter E. Pollock                        0                  0               5,331                 333             5,664

Frederick D. Miller                    610                  0               6,885               2,738            10,233

James J. Piro                            0                  0               4,859                 222             5,081
</TABLE>

(4)   Mr. Pollock was hired November  1, 1996, and was not a PGE employee until
      October, 1997.

(5)   Mr.  Harrison  also  serves  as  an  executive  officer  of  Enron.   The
      compensation shown represents the amount allocated to PGE.


The following  lists information concerning   options  to  purchase  shares  of
Enron   common  stock  that  were  granted  to PGE's five highest paid officers
during 1998.  No stock appreciation rights were granted during 1998.


                        OPTIONS/SAR GRANTS IN LAST FISCAL YEAR

<TABLE>
<CAPTION>
                            Number of        
                            Securities       % of Total                                            Potential Realized Value   
                            Underlying       Options/                                              at Assumed Annual Rates of 
                            Options/         SARs Granted to    Exercise or                        Stock Price Appreciation for  
                            SARs{(1)}        Employees in       Base Price      Expiration         Option Term 
Name                        Granted          Fiscal Year        ($/SH)          Date                   5%                10%
<S>                        <C>               <C>                <C>             <C>                <C>                <C>
Ken L. Harrison                14,320{(2)}       0.18%           $40.1250         01/19/05        $    233,916      $   545,123
                              140,285{(3)}       1.80%            50.9375         10/12/08           4,493,935       11,388,513
                              117,925{(4)}       1.50%            50.9375         10/12/08           3,777,647        9,573,300

Peggy Y. Fowler                15,210{(5)}       0.19%            57.0625         12/31/05             353,331          823,411

Walter E. Pollock               5,705{(5)}       0.07%            57.0625         12/31/05             132,528          308,847

James J. Piro                   3,805{(5)}       0.05%            57.0625         12/31/05              88,391          205,988

Frederick D. Miller             5,230{(5)}       0.07%            57.0625         12/31/05             121,494          283,132

</TABLE>

<PAGE>

(1)   If a "Change of  Control" (as defined in the Enron  1991 Stock Plan) were
      to occur before the  options  became  exercisable  and are exercised, the
      vesting  described  below  will be accelerated and all  such  outstanding
      options shall be surrendered  and  the  optionee  shall  receive  a  cash
      payment  by  Enron  in  an  amount  equal to the value of the surrendered
      options (as defined in the 1991 Stock Plan).
(2)   Represents stock options awarded January 19, 1998 which were fully vested
      on the date of grant.
(3)   Represents stock options awarded on October 12, 1998, which vested 25% at
      grant and 25% each on June 30 thereafter.
(4)   Represents stock options awarded on October  12,  1998,  which cliff vest
      100% on the 5th anniversary date of the grant.
(5)   Represents  stock  options awarded under the Long-Term Incentive  Program
      for 1999.  Stock options  awarded  on December 31, 1998 became 25% vested
      on the date of grant with an additional  25% vested on the anniversary of
      the date of grant until 100% vested December 31, 2001.


The following lists information concerning options  to purchase shares of Enron
common stock that were exercised by the officers named  above  during 1998, and
the total options and their value held by each at December 31, 1998.


                        Aggregate Stock Options/SAR Exercised During 1998
                        AND STOCK OPTIONS/SAR VALUES AT  DECEMBER  31, 1998

<TABLE>
<CAPTION>
                          Shares Acquired       Value         Exercisable      Unexercisable      Exercisable      Unexercisable
     NAME                 ON EXERCISE          REALIZED         SHARES            SHARES            AMOUNT            AMOUNT
<S>                      <C>                  <C>              <C>              <C>                <C>              <C>
Ken L. Harrison               20,900           $788,338          190,202           320,093        $4,611,889         $2,878,513

Peggy Y. Fowler               18,137            221,786            5,855            34,733            31,806            363,428

Walter E. Pollock                  0                  0            4,186            28,424            42,780            325,950

Frederick D. Miller            7,000            115,500            9,175            20,385           122,626            256,739

James J. Piro                      0                  0           27,170            21,037           684,680            343,097
</TABLE>


LONG-TERM INCENTIVE PLAN - AWARDS IN 1998

The following table provides information concerning awards of performance units
under  the  Performance  Unit  Plan  of  Enron  for the 1998 - 2001 performance
period.  Grants are made at the beginning of each  fiscal year and each unit is
assigned a value of $1.00.  The units are subject to  a  four-year  performance
period,  at  the  end of which Enron's total shareholder return is compared  to
that of the 11 peer  companies  included  in  the  Current Peer Group.  At that
time, the units are assigned a value ranging from $0 to $2.00 based on the rank
of Enron's shareholder return within the Current Peer  Group.   To be valued at
the maximum of $2.00, Enron must rank first, and to be valued at  the target of
$1.00, Enron must rank third.  Regardless of Enron's rank, Enron's shareholder
return  must  be above the return on 90-day U.S. Treasury Bills over  the  same
performance period in order for any value to be assigned.
<TABLE>
<CAPTION>

                                Number          Performance
                                of Shares       or Other                  Estimated Future Payouts
                                Units or        Period Unit            UNDER NON-STOCK PRICE-BASED PLANS
                                Other           Maturation        Threshold         Target          Maximum
     NAME                       RIGHTS (#)      PAYOUT              ($)              ($)              ($)
<S>                            <C>              <C>               <C>               <C>                <C>               

Ken L. Harrison                  325,000           4 years            0            $325,000         $650,000

Peggy Y. Fowler                  100,000           4 years            0             100,000          200,000

Walter E. Pollock                 50,000           4 years            0              50,000          100,000

Frederick D. Miller               37,500           4 years            0              37,500           75,000

</TABLE>

<PAGE>

Estimated annual  retirement  benefits payable upon normal retirement at age 65
for the named executive officers  are shown in the table below.  Amounts in the
table reflect payments from the Portland  General  Holdings,  Inc. Pension Plan
and Supplemental Executive Retirement Plan ("SERP") combined.

<TABLE>
<CAPTION>
                                     Pension Plan Table
                            Estimated Annual Retirement Benefit
                               Straight-Life Annuity, Age 65
<S>                            <C>                 <C>                <C>

                                                    Years of Service
Final Average
  EARNINGS:                       15                  20                25+
 $ 175,000                     $78,750             $91,875            $105,000
   200,000                      90,000             105,000             120,000
   225,000                     101,250             118,125             135,000
   250,000                     112,500             131,250             150,000
   300,000                     135,000             157,500             180,000
   400,000                     180,000             210,000             240,000
   500,000                     225,000             262,500             300,000
   600,000                     270,000             315,000             360,000
 1,000,000                     450,000             525,000             600,000

</TABLE>

Compensation  used  to calculate benefits under the combined Pension  Plan  and
SERP is based on a three-year  average  of base salary and bonus amounts earned
(the highest 36 consecutive months within  the  last  10 years), as reported in
the Summary Compensation Table.  SERP participants may retire without age-based
reductions  in  benefits  when  their  age  plus  years of service  equals  85.
Surviving spouses receive one half the participant's  retirement  benefit  from
the  SERP,  plus the joint and survivor benefit, if any, from the Pension Plan.
In addition to  the  aforementioned  annual  retirement benefits, an additional
temporary Social Security Supplement is paid until  the participant is eligible
for social security retirement benefits.  Retirement  benefits  are not subject
to any deduction for social security.

The  following executive officers named in the table are participants  in  both
plans  and have had the following number of service years with the Company: Ken
L. Harrison,  23;  Peggy  Y. Fowler, 24; Frederick D. Miller, 6.  James J. Piro
and Walter E. Pollock are not  participants  in  the SERP but do participate in
the Pension Plan.  Under the Company's SERP, the named  executives are eligible
to  retire  without a reduction in benefits upon attainment  of  the  following
ages: Ken L.  Harrison,  59; Peggy Y. Fowler, 55; Frederick D. Miller, 62.  Mr.
Pollock and Mr. Piro are not participants in the SERP.

EMPLOYMENT CONTRACTS

Mr. Harrison entered into  a  new  employment agreement effective July 1, 1998,
which superseded his July 20, 1996,  employment  agreement.   The new agreement
extends  from  the effective date through June 30, 2002, and provides  for  the
following:

1.  A base pay of not less than $550,000.

2.  Participation in the Enron  Annual Incentive Plan.

<PAGE>

3. A grant of 300,000  options  under the Enron Communications, Inc. 1998 Stock
   Option Plan effective January  1,  1998,  at  a purchase price of one dollar
   ($1.00) per share that will vest 25% on the first anniversary of the date of
   grant and an additional 6.25% for each completed three month period.

4. A grant of 140,285 options under the Enron  1991  Stock  Plan that will vest
   25% at grant and 25% on each June 30 of 1999, 2000 and 2001.

5. A  grant  of 12,800 shares of restricted stock under the Enron   1991  Stock
   Plan that will vest 33 1/3 % each January 31 of 1999, 2000 and 2001.

6.  Eligibility  for  $2.5  million  long  term  value over a four year term as
    follows:

   i.   50% of such value to be delivered in a 25,000  share  performance based
        restricted stock grant with 33.3% vesting conditioned on  meeting Enron
        after tax net income and/or cash flow targets for 1999, 2000  and 2001.
        Targets  are cumulative over the three year period beginning with  1999
        so that missed  vesting  due to missed targets can vest on a cumulative
        basis if the cumulative performance target is met.

   ii.  50% of such value to be delivered  in  a  117,925  share  Enron   stock
        option  grant  with  full 100% cliff vesting on 10/12/03, provided that
        the grant of options may accelerate vesting in 33.3% increments on each
        of 1/31/00, 1/31/01 and  1/31/02  conditioned  on  meeting Enron;
        performance targets to be established for 1999, 2000 and 2001.

Additionally,  following  termination  of  Mr.  Harrison's employment  for  any
reason, he will receive the aggregate benefits he  would have received pursuant
to the Pension Plan and the SERP, as in effect on the  effective  date  of  his
employment  agreement,  as  if  he  had  retired  on  the effective date of his
employment agreement having attained the "unreduced benefit  date"  (as defined
in  the  SERP),  and 25 years of service and as if his "final average earnings"
(as defined in the SERP) had equaled $1,050,000.

In partial consideration  of  rescinding  Mr. Harrison's previous agreement and
executing  his  new employment agreement effective  July  1,  1998,  Enron   is
obligated to pay  Mr.  Harrison the lessor of $2,835,000 or 2.99 times his base
amount, accruing the later of June 30, 2002, or the date Mr. Harrison ceases to
be employed by a participating employer in the Management Deferred Compensation
Plan.

Ms. Fowler and Mr. Miller  entered  into  employment agreements on July 1, 1997,
the effective date of the merger between Enron  and  PGC,  the former parent of
PGE.   The  employment  agreements  generally  provide as follows:   (i)   each
agreement will have a term of three years and expires  on  June  30, 2000; (ii)
each  agreement  provides  for  severance  pay  in  the  event  of  involuntary
termination  by PGE based on the greater of two years or the remainder  of  the
term; (iii) the  minimum  salary  for  Ms.  Fowler  is $230,000 and the minimum
salary for Mr. Miller is $175,000 per year; the minimum  guaranteed annual cash
incentive per year under such agreements is $115,000 for Ms. Fowler and $52,500
for Mr. Miller; (iv) Mr. Miller's agreement provides for the  grant  of  25,000
options  to  purchase  shares of Enron Common Stock while Ms. Fowler's provides
for 30,000 options;  (v)  Ms.  Fowler's  agreement  provides for the grant of a
number of restricted shares of Enron Common Stock having  a  market value equal
to  such  employee's annual base pay which will vest over a five  year  period;
(vi) Ms. Fowler's  and  Mr. Miller's agreements provide that the failure of PGE
and the employee to extend  or enter into a new agreement for two years will be
treated  as  involuntary termination;  (vii)  each  agreement  provides  for  a
supplemental retirement  benefit;  (viii)  each  agreement provides that in the
event  that the severance or other payments payable  under  the  agreement  for
involuntary  termination  constitute  "excess  parachute  payments"  within the
meaning of Section 280G of the code and the employee becomes liable for any tax
penalties,  PGE  will  pay in cash to the employee an amount equal to such  tax
penalties until the amount  of  the  last  gross  up  is  less than one hundred
dollars; and (x) each agreement includes a noncompetition covenant.

Mr. Pollock entered into an employment agreement effective  November  1,  1996.
The  agreement  extends  from  the  effective  date until November 1, 1999, and
provides for the following:

1.  An initial base pay of $150,000.

2. A guaranteed bonus of 33% of base pay paid in  1996  and  1997,  and a bonus
   opportunity of 75% in 1998.

<PAGE>

3. A grant of 20,000 shares of PGC stock under the Portland General Corporation
   amended  and  restated  1990 Long-Term Master Plan which converted to  Enron
   Common Stock upon the merger and will vest 100% on November 4, 1999.

4. Remedy for breach clause  which  provides  for  a  payment  of one times Mr.
   Pollock's salary plus target incentive award if his employment is terminated
   plus  equivalent medical and dental coverage for 12 months for  Mr.  Pollock
   and his dependents.

5. Noncompete and confidentiality clauses.

Mr. Piro entered  into  a  retention  agreement effective January 7, 1997.  The
agreement extends two years from the date  of  the merger between PGC and Enron
and provides for the following:

1.  No reduction of base pay during the agreement.

2.  12 months written notification prior to involuntary termination.

3.   $10,000 plus one times Mr. Piro's base pay and  target  incentive  in  the
   event of a breach of the agreement, where a breach is defined as involuntary
   termination,  diminishment of status, base pay or bonus opportunity position
   and/or responsibilities  or a requirement that Mr. Piro relocate outside the
   Portland, Oregon geographic  area  without his written consent.  In addition
   to the payment, the company will provide  Mr.  Piro  and his dependents with
   equivalent medical and dental coverage for up to 12 months.

4. Noncompete and confidentiality clauses.


COMPENSATIONS OF DIRECTORS
There are no compensation arrangements for or fees paid to Directors of PGE.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
None

<PAGE>

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                MANAGEMENT


PGE is a wholly-owned subsidiary of Enron.



ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS


There  are  no  relationships  or  transactions involving PGE's  directors  and
executive officers.

<PAGE>

                                PART IV


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


(A) INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

   FINANCIAL STATEMENTS
   Report of Independent Public Accountants
   Consolidated Statements of Income for each of the three years
     in the period ended December 31, 1998
   Consolidated Statements of Retained Earnings for each of
     the three years in the period ended December 31, 1998
   Consolidated Balance Sheets at December 31, 1998 and 1997
   Consolidated Statement of Cash Flows for each of the three
     years in the period ended December 31, 1998
   Notes to Financial Statements

   FINANCIAL STATEMENT SCHEDULES
   Schedules are omitted because of  the absence of conditions under which they
   are required or because the required  information  is given in the financial
   statements or notes thereto.

   EXHIBITS
   See Exhibit Index on Page 66 of this report.

(B) REPORT ON FORM 8-K
   None

<PAGE>

                                        SIGNATURES

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

                              Portland General Electric Company



March 19, 1999                By     /S/ KEN L. HARRISON
                                         Ken L. Harrison

                                   Chairman and
                                   Chief Executive Officer


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.


                                Chairman and
/S/ KEN L. HARRISON             Chief Executive Officer         March 19, 1999
    Ken L. Harrison


                                 Treasurer, Controller and
                                 Chief Accounting Officer
/S/ MARY K. TURINA               (Principal financial officer    March 19, 1999
    Mary K. Turina               and principal accounting 
                                 officer)




    *James V. Derrick
    *Peggy Y. Fowler
    *Ken L. Harrison
    *Joseph M. Hirko                 Directors                March 19, 1999
    *Kenneth L. Lay
    *Jeffrey K. Skilling


     *By              /S/ MARY K. TURINA
              (Mary K. Turina, Attorney-in-Fact)

<PAGE>


                                        SIGNATURES

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

                                     Portland General Electric Company



March 19, 1999                       By

                                                       Ken L. Harrison

                                           Chairman  and
                                           Chief Executive Officer


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.


                                 Chairman and
                                 Chief Executive Officer   March 19, 1999

     Ken L. Harrison


                                 Treasurer, Controller and
                                 Chief Accounting Officer
                                 (Principal financial officer   March 19, 1999
     Mary K. Turina              and principal accounting 
                                 officer)






    *James V. Derrick
    *Peggy Y. Fowler
    *Ken L. Harrison
    *Joseph M. Hirko                 Directors                 March 19, 1999
    *Kenneth L. Lay
    *Jeffrey K. Skilling


     *By
              (Mary K. Turina, Attorney-in-Fact)


<PAGE>


           PORTLAND GENERAL ELECTRIC COMPANY AND
           SUBSIDIARIES

                                    EXHIBIT INDEX

  NUMBER                            EXHIBIT

  (2)          PLAN OF ACQUISITION, REORGANIZATION, ARRANGEMENT, LIQUIDATION OR
               SUCCESSION

           *   Amended  and Restated Agreement and Plan of Merger, dated as  of
               July 20, 1996  and amended and restated as of September 24, 1996
               among  Enron  Corp,  Enron  Oregon  Corp  and  Portland  General
               Corporation [Amendment  1  to S4 Registration Nos. 333-13791 and
               333-13791-1, dated October 10, 1996, Exhibit No. 2.1].

  (3)          ARTICLES OF INCORPORATION AND BYLAWS

           *   Copy of Articles of Incorporation  of  Portland General Electric
               Company [Registration No. 2-85001,  Exhibit (4)].

           *   Certificate of Amendment, dated July 2, 1987, to the Articles of
               Incorporation limiting the personal liability  of  directors  of
               Portland General Electric Company [Form 10-K for the fiscal year
               ended December 31, 1987, Exhibit (3)].

           *   Form  of  Articles  of  Amendment  of the New Preferred Stock of
               Portland  General Electric Company [Registration  No.  33-21257,
               Exhibit (4)].

           *   Bylaws  of Portland  General  Electric  Company  as  amended  on
               October 1,  1991  [Form  10-K for the fiscal year ended December
               31, 1991, Exhibit (3)].

               Bylaws of Portland General Electric Company as amended on May 1,
               1998,(Filed herewith).

  (4)          INSTRUMENTS DEFINING THE RIGHTS  OF  SECURITY HOLDERS, INCLUDING
               INDENTURES

           *   Portland General Electric Company Indenture of Mortgage and Deed
               of Trust dated July 1, 1945.

           *   Fortieth Supplemental Indenture, dated October 1, 1990 [Form 10-
               K for the fiscal year ended December 31, 1990, Exhibit (4)].

           *   Forty-First Supplemental Indenture dated  December 1, 1991 [Form
               10-K for the fiscal year ended December 31, 1991, Exhibit (4)].

           *   Forty-Second Supplemental Indenture dated April  1,  1993  [Form
               10-Q for the quarter ended March 31,1993, Exhibit (4)].

           *   Forty-Third Supplemental Indenture dated July 1, 1993 [Form 10-Q
               for the quarter ended September 30, 1993, Exhibit (4)].

           *   Forty-Fourth  Supplemental  Indenture dated August 1, 1994 [Form
               10-Q for the quarter ended September 30, 1994, Exhibit (4)].

           *   Forty-Fifth Supplemental Indenture  dated May 1, 1995 [Form 10-Q
               for the quarter ended June 30, 1995, Exhibit (4)].

<PAGE>

           PORTLAND GENERAL ELECTRIC COMPANY AND
           SUBSIDIARIES

                                    EXHIBIT INDEX

  NUMBER                                                                EXHIBIT

  (4)      *   Forty-Sixth  Supplemental  Indenture  dated August 1, 1996 [Form
  CONT         10-K for the fiscal year ended December 31, 1997, Exhibit (4)].

               Other  instruments  which  define  the  rights   of  holders  of
               long-term debt not required to be filed herein will be furnished
               upon  written request.


  (10)         MATERIAL CONTRACTS

           *   Residential  Purchase  and  Sale  Agreement  with the Bonneville
               Power  Administration  [Form  10-K  for  the fiscal  year  ended
               December 31, 1981, Exhibit (10)].

           *   Power Sales Contract and Amendatory Agreement  Nos. 1 and 2 with
               Bonneville Power Administration [Form 10-K for the  fiscal  year
               ended December 31, 1982, Exhibit (10)].

           The  following  12  exhibits were filed in conjunction with the 1985
           Boardman/Intertie Sale:

           *   Long-term Power Sale  Agreement,  dated  November  5, 1985 [Form
               10-K for the fiscal year ended December 31, 1985, Exhibit (10)].

           *   Long-term Transmission Service Agreement, dated November 5, 1985
               [Form 10-K for the fiscal year ended December 31, 1985,  Exhibit
               (10)].

           *   Participation Agreement, dated December 30, 1985 [Form 10-K  for
               the fiscal year ended December 31, 1985, Exhibit (10)].

           *   Lease  Agreement,  dated  December  30,  1985 [Form 10-K for the
               fiscal year ended December 31,1985, Exhibit (10)].

           *   PGE-Lessee Agreement, dated December 30, 1985 [Form 10-K for the
               fiscal year ended December 31, 1985, Exhibit (10)].

           *   Asset Sales Agreement, dated December 30,  1985  [Form  10-K for
               the fiscal year ended December 31, 1985, Exhibit (10)].

           *   Bargain  and Sale Deed, Bill of Sale and Grant of Easements  and
               Licenses, dated December 30, 1985 [Form 10-K for the fiscal year
               ended December 31, 1985, Exhibit (10)].

           *   Supplemental  Bill  of  Sale, dated December 30, 1985 [Form 10-K
               for the fiscal year ended December 31, 1985, Exhibit (10)].

           *   Trust Agreement, dated December  30,  1985  [Form  10-K  for the
               fiscal year ended December 31, 1985, Exhibit (10)].

           *   Tax   Indemnification   Agreement,   dated   December  30,  1985
               [Form 10-K for the fiscal year ended December  31, 1985, Exhibit
               (10)].

<PAGE>
      
           PORTLAND GENERAL ELECTRIC COMPANY AND
           SUBSIDIARIES

                                    EXHIBIT INDEX

  NUMBER                                                                EXHIBIT

  (10)     *   Trust   Indenture,   Mortgage   and  Security  Agreement,  dated
  CONT         December 30, 1985 [Form 10-K for the
               fiscal year ended December 31, 1985, Exhibit (10)].

           *   Restated  and  Amended Trust Indenture,  Mortgage  and  Security
               Agreement, dated  February  27,  1986  [Form 10-K for the fiscal
               year ended December 31, 1997, Exhibit (10)].

           *   Portland  General  Holdings,  Inc. Outside  Directors'  Deferred
               Compensation Plan, 1997 Restatement  dated  June  25, 1997 [Form
               10-K for fiscal year ended December 31, 1997, Exhibit 10].

           *   Portland  General  Holdings,  Inc.  Retirement Plan for  Outside
               Directors, 1997 Restatement dated June  25,  1997 [Form 10-K for
               fiscal year ended December 31, 1997, Exhibit 10].

           *   Portland   General   Holdings,  Inc.  Outside  Directors'   Life
               Insurance Benefit Plan, 1997 Restatement
               dated June 25, 1997 [Form  10-K  for  fiscal year ended 
               December 31, 1997, Exhibit 10].

                EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS

           *   Portland General Holdings, Inc. Management Deferred Compensation
               Plan,  1997  Restatement  dated June 25, 1997   [Form  10-K  for
               fiscal year ended December 31, 1997, Exhibit 10].

           *   Portland General Holdings,  Inc.  Senior Officers Life Insurance
               Benefit Plan, 1997 Restatement Amendment  No.  1  dated June 25,
               1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit
               10].

           *   Portland  General  Electric Company Annual Incentive  MasterPlan
               [Form 10-K for the fiscal  year ended December 31, 1987, Exhibit
               (10)].

           *   Portland General Electric Company  Annual Incentive Master Plan,
               Amendments No. 1 and No. 2 dated March  5,  1990  [Form 10-K for
               the fiscal year ended December 31, 1989, Exhibit (10)].

           *   Portland   General   Holdings,   Inc.   Supplemental   Executive
               Retirement Plan, 1997 Restatement dated June 25, 1997 [Form 10-K
               for fiscal year ended December 31, 1997, Exhibit 10].

<PAGE>

           PORTLAND GENERAL ELECTRIC COMPANY AND
           SUBSIDIARIES

                                    EXHIBIT INDEX

  NUMBER                                                                EXHIBIT


  (24)         POWER OF ATTORNEY

               Portland  General  Electric  Company  Power  of  Attorney (filed
               herewith).



  * Incorporated by reference as indicated.



  Note:    Although  the  Exhibits  furnished  to  the Securities and  Exchange
           Commission with the Form 10-K have  been  omitted  herein, they will
           be supplied upon written request and payment of a reasonable fee for
           reproduction costs.  Requests should be sent to:

                   Mary K Turina
                   Treasurer, Controller, and Chief Accounting Officer


                   Portland General Electric Company
                   121 SW Salmon Street
                   Portland, OR 97204