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.)

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

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

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.

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:

1998 1997 1996

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>

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

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").

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

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.

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

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.

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.

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.

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

Generating facilities owned by PGE are set forth in the following table:

PGE Net MW
Capability
FACILITY Location Fuel

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

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.

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.

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.

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.

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

MEGAWATT-HOURS/VARIABLE POWER COSTS

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)

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.

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.

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.

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.

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).

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

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.

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

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.

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.

YEAR 2000 READINESS PLAN

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

* 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

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

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.

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.

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.

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

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31 1998 1997 1996

(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.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

AT DECEMBER 31

1998 1997

(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.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW

For the Years Ended December 31 1998 1997 1996

(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.

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.

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:

1998 1997

(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

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.

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):

1998 1997

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

1998 1997

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

COMPONENTS OF NET PERIODIC PENSION EXPENSE:

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)

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.

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):

1998 1997 1996

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%

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):

1998 1997

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)

PGE has recorded deferred tax assets and liabilities for all temporary
differences between the financial statement basis and tax basis of assets and
liabilities.

NOTE 4 - COMMON AND PREFERRED STOCK

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

(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 $ -

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.

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:

1998 1997

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

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

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.

1998 1997

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

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

1999 2000 2001 2002 2003

Maturities:
PGE $102 $32 $53 $23 $49

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):

1998 1997

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 $ - $ -

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):

ROCKY PRIEST PORTLAND
REACH RAPIDS WANAPUM WELLS HYDRO

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

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

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):

YEAR ENDING OPERATING LEASES
DECEMBER 31 CAPITAL LEASES (NET OF SUBLEASE RENTALS) TOTAL

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

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):

MW PGE % PLANT ACCUMULATED
FACILITY LOCATION FUEL CAPACITY INTEREST IN SERVICE DEPRECIATION

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

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.

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.

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

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.

QUARTERLY COMPARISON FOR 1998 AND 1997 (UNAUDITED)

MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 TOTAL
(MILLIONS OF DOLLARS)

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

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

None.

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.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW

EXECUTIVE OFFICERS OF THE REGISTRANT (*)

NAME AGE BUSINESS EXPERIENCE

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.

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.

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

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.

Long-Term
Annual Compensation Compensation All Other

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

(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

(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:

Split Dollar Dollar Value of Contributions to Above Market
Insurance Premiums Life Insurance 401 (k) and MDCP Interest on MDCP Total

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

(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

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%

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

(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

Shares Acquired Value Exercisable Unexercisable Exercisable Unexercisable
NAME ON EXERCISE REALIZED SHARES SHARES AMOUNT AMOUNT

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

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.

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 ($) ($) ($)

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

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.

Pension Plan Table
Estimated Annual Retirement Benefit
Straight-Life Annuity, Age 65

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

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.

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.

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

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.

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

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)

SIGNATURES

Portland General Electric Company

March 19, 1999 By

Ken L. Harrison

Chairman and
Chief Executive Officer

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)

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)].

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)].

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].

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