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, 1997
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, 1998: $0.

Indicate the number of shares outstanding of each of the registrant's classes
of common stock, as of February 28, 1998: 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

Beaver..............................Beaver Combustion Turbine Plant
Bethel..............................Bethel Combustion Turbine Plant
Boardman............................Boardman Coal Plant
BPA.................................Bonneville Power Administration
Centralia...........................Centralia Coal Plant
COB.................................California/Oregon Border
Colstrip............................Colstrip Units 3 and 4 Coal Plant
Coyote Springs......................Coyote Springs Generation Plant
CUB.................................Citizens' Utility Board
DEQ.................................Oregon Department of Environmental Quality
EFSC................................Oregon Energy Facility Siting Council
Enron...............................Enron Corp
EPA.................................Environmental Protection Agency
FASB................................Financial Accounting Standards Board
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.
Intertie............................Pacific Northwest Intertie Transmission
Line
IOUs................................Investor-Owned Utilities
IRS.................................Internal Revenue Service
kWh.................................Kilowatt-Hour
MMBtu...............................Million British thermal units
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
Portland General or PGC.............Portland General Corporation
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
WPPSS or Supply System..............Washington Public Power Supply System
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.................................................. 12

Item 3. Legal Proceedings........................................... 14

PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters................................. 16

Item 6. Selected Financial Data..................................... 16

Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations......................... 17

Item 8. Financial Statements and Supplementary Data................. 27

Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure......................... 44

PART III
Item 10. Directors and Executive Officers of the Registrant.......... 45

Item 11. Executive Compensation...................................... 48

Item 12. Security Ownership of Certain Beneficial Owners
and Management.............................................. 54

Item 13. Certain Relationships and Related Transactions............. 55

PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K......................................... 56

Signatures................................................................. 57

Exhibit Index.............................................................. 58

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 1997 its service area population was approximately
1.5 million, constituting approximately 44% of the state's population. At
December 31, 1997 PGE served approximately 685,000 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, 1997, PGE had 2,729 employees. This compares to 2,587 and
2,533 PGE employees at December 31, 1996 and 1995, respectively.

OPERATING REVENUES

RETAIL
PGE serves a diverse retail customer base. Residential customers constitute
the largest customer class and account for 44% of retail revenues.
Residential demand is highly sensitive to the effects of weather. Commercial
customers consume 40% and industrial customers 16% of retail revenues. Since
1995 commercial demand has grown by 9%, making this the Company's most rapidly
growing retail customer class. Sales to industrial customers rebounded in 1997
after a 4% decline in 1996. The commercial and industrial classes are not
dominated by any single industry. While the 20 largest customers constitute
21% 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 10% of
PGE's retail load. PGE's retail revenues peak during the winter season.

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 Implementation Proposal includes new price tariffs and a new
structure for the company. If the proposal is approved by the OPUC, PGE
would become a regulated transmission and distribution company focused on
delivering, but not selling electricity.

WHOLESALE
Wholesale revenues continued to make a significant contribution to overall
revenues, providing over 35% of total operating revenues for 1997. During the
last several years PGE has actively marketed wholesale power throughout the
western United States and has experienced record sales growth since 1994. Most
of the Company's wholesale growth has come through sales to marketers and
brokers. These sales are predominantly of a short-term nature. Due to
increasing volatility and reduced margins resulting from increased competition,
long-term wholesale marketing activities have been transferred to PGE's non-
regulated affiliates. 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:

1997 1996 1995

Operating Revenues (Millions)
Residential $ 391 $ 427 $ 380
Commercial 343 346 336
Industrial 143 149 153
Public Street Lighting 11 11 11
Tariff Revenues 888 933 880
Accrued (Collected) Revenues 10 (27) (3)
Retail 898 906 877
Wholesale 497 194 95
Other 21 10 10
Total Operating Revenues $ 1,416 $ 1,110 $ 982
Megawatt-Hours Sold (Thousands)
Residential 6,999 7,073 6,622
Commercial 6,873 6,475 6,285
Industrial 4,247 3,909 4,056
Public Street Lighting 100 102 102
Retail 18,219 17,559 17,065
Wholesale 26,934 10,188 3,383
Total MWh Sold 45,153 27,747 20,448

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 commence decommissioning activities. Trojan will be subject to NRC
regulation until Trojan is fully decommissioned, all nuclear fuel is removed
from the site and the license is terminated. The Oregon Department of Energy
also monitors Trojan.

OREGON REGULATORY MATTERS

CUSTOMER CHOICE

Proposal
In late 1997 PGE filed a proposal before the OPUC which would give all of its
customers a choice of electricity providers and provide a price decrease of
about 10% as early as January 1, 1999. PGE's Customer Choice Implementation
Proposal includes new tariffs and a new structure for the company. If the
proposal is approved by the OPUC, 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 is asking for OPUC approval to sell all its generating
assets, which represent approximately 27% of PGE's total assets, and power
supply and purchase contracts. A sale of PGE's supply portfolio would allow
the OPUC to put a dollar value on "transition costs," the costs that a
regulated utility company would be unable to recover in a competitive market.
PGE is seeking full recovery of these transition costs.

PGE is dependent upon the regulatory process to ensure that future revenues
will be provided for the recovery of regulatory assets, including the
transition costs mentioned above. In the event that the regulatory process does
not provide revenues for recovery of transition costs, PGE could be required
to write off all or a portion of such amounts from its balance sheet.

INTRODUCTORY PROGRAM
In a move to prepare for future retail competition, PGE initiated an
introductory Customer Choice Plan to allow 50,000 PGE customers in four cities
to buy their power from competing energy service providers. This program allows
certain customers in Oregon to experience a competitive electricity market. The
program, which received OPUC approval, is available to residential, small
business and commercial customers in the four cities, and industrial customers
throughout PGE's service territory. Since October 1997 PGE's large industrial
customers throughout its service territory have had the opportunity to purchase
up to 50 percent of their electricity from competing electricity providers.
Residential, small business and commercial customers were given the option of
receiving electricity from a company of their choice in December 1997. Under
this program, customers in the four cities can pool or aggregate their electric
load in order to negotiate a cheaper rate from energy suppliers. To date over
7,000 retail customers have selected alternative energy service providers. This
program, which terminates on December 31, 1998, is being undertaken to provide
information to PGE and the OPUC on the effects of future retail competition on
PGE and its customers. PGE does not expect that this program will have a
materially adverse impact on operating margins.

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. In September 1997 PGE submitted its
1998-1999 Integrated Resource Plan (IRP) to the OPUC. This plan recognizes the
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
The Regional Power Act (RPA), passed in 1980, attempted to resolve growing
power supply and cost inequities between customers of government and publicly
owned utilities, who have priority access to the low-cost power from the
federal hydroelectric system, and the customers of IOUs. The RPA created the
residential exchange program to ensure that all residential and farm customers
in the region, the vast majority of which are served by IOUs, receive similar
benefits from the publicly funded federal power system. Exchange benefits, and
any related changes in the amount of benefits, have generally passed directly
to PGE's customers in the form of price increases or decreases. Effective
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 has contested this decision and is working
with the BPA to resolve the issue.

ENERGY EFFICIENCY
PGE has promoted the efficient use of electricity for over two decades.
Current Demand Side Management (DSM) programs provide a range of services
to all classes of PGE
customers. DSM programs seek to capitalize on windows of opportunity in which
efficiency measures are most cost-effective both for PGE's ratepayers and the
specific customers. In order to do this PGE is focusing on commercial or
industrial new construction and industrial process improvements. PGE 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
At the onset of nationwide electricity deregulation PGE is maintaining its
commitment to service excellence while assisting with the formation of a
competitive electricity market in the Northwest. Its Customer Choice
Implementation Proposal was filed with the OPUC in December 1997 and an
introductory program has been put in place. The proposal addresses 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 proposal, if
approved by the OPUC, will create one of the nation's first regulated
electricity transmission and distribution companies focused on delivering, but
not selling, power. In the new environment, PGE would continue to operate and
maintain the electricity delivery system and handle outages, while other
competitive companies would market power to customers over that system.

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 of a loss of PGE service territory to the
creation of public utility districts or municipal utilities by voters. In the
future PGE will focus on transitioning to a regulated transmission and
distribution company.

WHOLESALE COMPETITION AND MARKETING
During the last few years, the western United States has become a vibrant
marketplace for the trading of electricity and PGE has been an active
participant. During 1997 PGE's wholesale revenues increased 156% over 1996
levels with wholesale activities accounting for 35% of total revenues and
60% of total megawatt-hour sales. However, due to increasing volatility and
reduced margins resulting from increased competition, long-term wholesale
marketing activities have been transferred to PGE's non-regulated affiliates.

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 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. Wholesale demand has experienced significant increases. In 1996 and
1997 PGE's wholesale sales increased approximately 200% annually. Although
wholesale activity is expected to decline, PGE's retail demand should 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 spot market,
or secondary, purchases 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 competitive
pressures 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 2,120 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.

PURCHASED POWER
PGE has long-term power contracts with four hydro projects on the mid-Columbia
River which provide PGE with 590 MW of firm capacity. PGE also has firm
contracts, ranging in term from one to 30 years, to purchase 512 MW, primarily
hydro-generated, from other Pacific Northwest utilities. In addition, PGE has
long-term exchange contracts with summer-peaking Southwest utilities 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
during the next 10 years. Favorable water conditions have the ability to
further increase energy supplies.

JANUARY RESERVE MARGIN WSCC REGION

MEGAWATTS PERCENT
1993 22,997 0.217
1994 31,033 0.310
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 33,735 0.286
2001 32,680 0.273
2002 30,842 0.253

During 1997, PGE's peak load was 3,448 MW, of which 52% was met through
economical short-term purchases. PGE's firm resource capacity, including
short-term purchase agreements, totaled approximately 4,714 MW as of December
31, 1997.

RESTORATION OF SALMON RUNS
Several species of salmon found in the Snake River and the Columbia rivers, have
been granted protection under the federal Endangered Species Act (ESA). In an
effort to help restore these fish, the federal government has reduced the
amount of water allowed to flow through the turbines at the hydroelectric dams
on the Snake and Columbia rivers while the young salmon are migrating to the
ocean. This has resulted in reduced amounts of electricity generated at the
dams. Favorable hydro conditions helped mitigate the effect of these actions
in 1996 and 1997. If this practice is continued in future years it could mean
less water available in the fall and winter for generation when demand for
electricity in the Pacific Northwest is highest. Although PGE does not own any
hydroelectric facilities on the Columbia and Snake rivers, it does buy energy
from both utilities and federal agencies which do.

In early 1997, the State of Oregon proposed an aggressive recovery plan for the
Oregon coastal Coho salmon. The National Marine Fisheries Service (NMFS)
accepted this recovery plan and as a result this run of salmon was not listed
for federal protection. PGE has no hydroelectric projects that will be
impacted by this action.

Also in 1997, a petition to protect winter steelhead trout under the federal
Endangered Species Act was reviewed by NMFS. In early 1998 NMFS listed this
species as threatened. The affected areas include the lower Columbia River
tributaries in Oregon and Washington. PGE is currently evaluating what impact
this listing will have on the operation of its hydroelectric projects on the
Willamette, Clackamas and Sandy rivers.

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 an agreement to purchase coal for Boardman through the year 2000. The
agreement does not require a minimum amount of coal to be purchased, allowing
PGE to obtain coal from other sources. During 1997 PGE did not take deliveries
under this contract but purchased coal under favorable short-term agreements.
Coal purchases in 1997 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 Montana and Wyoming,
was subject to federal, state and local regulations. Coal is delivered to
Boardman by rail under a contract which expires in 2002.

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.

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 1997, 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 on three interconnected pipeline systems accessing the gas
fields in Alberta, Canada. Coyote Springs' one and two-year gas supply
contracts expire in November 1998 and November 1999. Gas supplies and
transportation capacity are sufficient to fully fuel Coyote Springs. Minimum
purchase requirements represent 50% of the plant's capacity.

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 energy efficiency.

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. PGE is also subject to the Federal
Rivers and Harbors Act of 1899 and similar Oregon laws under which it must
obtain permits from the U.S. Army Corps of Engineers or the Oregon Division of
State Lands to construct facilities or perform activities in navigable waters
of the State. 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 Department 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 over the next several years.
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 the federal standards.

Boardman was assigned sufficient 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 2000. The owner-operator utility is considering the installation of
scrubbers. It is not anticipated that Colstrip will be required to reduce
emissions because it utilizes scrubbers. However, future legislation, if
adopted, could affect plant operations and increase operating costs or reduce
coal-fired capacity.

Air contaminant discharge permits or federal operating permits, issued by the
DEQ, have been obtained for all of PGE's fossil fuel generating facilities with
only one limitation, at the Bethel plant, on power production. DEQ limits
night operations of Bethel to one unit due to noise considerations. Maximum
plant operations are allowed during the day.

The water pollution control facilities permit for Boardman expired in May 1991.
The DEQ is processing the permit application and renewal is expected. In the
interim, Boardman is permitted to continue operating under the terms of the
original permit.

PGE is no longer accepting oil shipments by river for its Beaver plant in order
to eliminate the risk of an oil spill into the Columbia River. Instead, the
rail off-loading facility has been upgraded. This plant is normally fired by
natural gas, and only small amounts of oil are used.

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
Facility Location Fuel Capability

WHOLLY OWNED:
Faraday Clackamas River Hydro 44
North Fork Clackamas River Hydro 54
Oak Grove Clackamas River Hydro 44
River Mill Clackamas River Hydro 23
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
Bethel Salem, OR Gas/Oil 116
Coyote Springs Boardman, OR Gas/Oil 241
PGE
JOINTLY OWNED: INTEREST
Boardman Boardman, OR Coal 331 @ 65.0%
Centralia Centralia, WA Coal 33 @ 2.5%
Colstrip 3 & 4 Colstrip, MT Coal 288 @ 20.0%
Trojan Rainier, OR Nuclear - @ 67.5%
2,120

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 is actively
pursuing the renewal of these 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 Bethel and Beaver are leased by PGE. These
leases expire in 1998 and 1999. PGE is currently evaluating its renewal
options. 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 OPUC Order
No. 91-1781 which authorized deferred accounting, suspended certain rate
schedules and opened an investigation on PGE's request for 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 has been decided, and the URP challenge will now
proceed. PGE plans to intervene in this case shortly.

COLUMBIA STEEL CASTING CO., INC. V. PGE, PACIFICORP, AND MYRON KATZ, NANCY
RYLES AND RONALD EACHUS, NINTH CIRCUIT COURT OF APPEALS

On June 19, 1990 Columbia Steel filed a complaint for declaratory judgment,
injunctive relief and damages in U.S. District Court for the District of Oregon
contending that a 1972 territory allocation agreement between PGE and
PacifiCorp, dba Pacific Power & Light Company (PP&L), which was subsequently
approved by the OPUC and the City of Portland, does not give PGE the exclusive
right to serve them nor does it allow PP&L to deny service to them. Columbia
Steel is seeking an unspecified amount in damages amounting to three times the
excess power costs paid over a 10-year period.

On July 3, 1991 the Court ruled that the Agreement did not allocate customers
for the provision of exclusive services and that the 1972 order of the OPUC
approving the Agreement did not order the allocation of territories and
customers. Subsequently, on August 19, 1993 the Court ruled that Columbia
Steel was entitled to receive from PGE approximately $1.4 million in damages
which represented the additional costs incurred by Columbia Steel for electric
service from July 1990 to July 1991, trebled, plus costs and attorney's fees.

PGE appealed to the U.S. Court of Appeals for the Ninth Circuit which, on July
20, 1995, issued an opinion in favor of PGE, reversing the judgment and
ordering judgment to be entered in favor of PGE. Columbia Steel filed a
petition for reconsideration and on December 27, 1996 , the Ninth Circuit Court
of Appeals reversed its earlier decision, ruling in favor of Columbia Steel and
remanding the case to the U.S. District Court for a new determination of damages
for service rendered from early 1987 to July 1991. In early 1997 PGE's request
for reconsideration by the Ninth Circuit was denied. On July 2, 1997 PGE filed
a request for certiorari with the U.S. Supreme Court. A response is expected in
1998. On August 2, 1997 the U.S. District Court entered a new judgment in favor
of Columbia Steel for approximately $3.7 million.

CITIZENS' UTILITY BOARD OF OREGON V. PUBLIC UTILITY COMMISSION OF OREGON AND
UTILITY REFORM PROJECT AND COLLEEN O'NEIL 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 alleges that the
OPUC lacks authority to allow PGE to recover Trojan costs through its rates.
The complaint seeks 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 alleges that the OPUC's decision is not
based upon evidence received in the rate case, is not supported by substantial
evidence in the record of the case, is 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 seeks 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. Both
the 1994 and 1996 circuit court decisions have been appealed to the Oregon
Court of Appeals where they have been consolidated. PGE expects a ruling in
1998.

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 1997 1996
First $14 $15
Second 16 18
Third 17 56
Fourth - 16

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
1997 1996 1995 1994 1993
(millions of dollars)

Operating Revenues $1,416 $1,110 $ 982 $ 959 $ 945
Net Operating Income 208 230 201 159 160
Net Income 126 156 93{1} 106 100

Total Assets $3,256 $3,398 $3,246 $3,354 $3,227
Long-Term Obligations{2} 1,038 963 931 856 873

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 short-term debt intended
to be refinanced.

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

RESULTS OF OPERATIONS

GENERAL

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 fastest 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 price decrease
mentioned above.

OPERATING REVENUE AND NET INCOME (LOSS) GRAPH:
($ MILLIONS):

OPERATING NET
REVENUE INCOME
1993 945 100
1994 959 106
1995 982 93
1996 1110 156
1997 1416 126

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 wholesale marketplace.

PGE ELECTRICITY SALES GRAPH:
(BILLIONS OF KWH)

1993 Residential 6.8
Commercial 6.0
Industrial 3.8
Wholesale 2.7

1994 Residential 6.7
Commercial 6.2
Industrial 3.9
Wholesale 2.7

1995 Residential 6.6
Commercial 6.4
Industrial 4.1
Wholesale 3.4

1996 Residential 7.1
Commercial 6.5
Industrial 3.9
Wholesale 10.2

1997 Residential 7.0
Commercial 7.0
Industrial 4.2
Wholesale 26.9

MEGAWATT-HOURS SOLD
(THOUSANDS)

1997 1996
Retail 18,219 17,559
Wholesale 26,934 10,188

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

MEGAWATT-HOURS/VARIABLE POWER COSTS

Megawatt-Hours Average Variable
(thousands) Power Cost (Mills/KWh)
1997 1996 1997 1996

Generation 7,326 7,223 6.3 6.6
Firm Purchases 36,014 18,099 16.5 14.5
Secondary Purchases 2,958 3,714 12.2 10.4
Total 46,298 29,036 14.6 12.0

Operating expenses (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 primarily due to the amortization of
regulatory credits. These items were 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.

OPERATING EXPENSES GRAPH:
($ MILLIONS)

1993 Depreciation 125
Operating Costs 357
Variable Power 303

1994 Depreciation 128
Operating Costs 334
Variable Power 338

1995 Depreciation 140
Operating Costs 356
Variable Power 285

1996 Depreciation 162
Operating Costs 410
Variable Power 308

1997 Depreciation 155
Operating Costs 378
Variable Power 675

1996 COMPARED TO 1995
PGE reported 1996 net income of $156 million compared to $93 million for 1995.
1995 net income included a $50 million after-tax charge to income related to
the OPUC's rate orders disallowing certain deferred power costs and 13% of
PGE's remaining investment in Trojan.

Excluding the effect of regulatory disallowances, net income in 1995 would have
been $143 million.

Strong operating earnings reflected the benefits of low variable power costs
due to optimal hydro conditions and a competitive wholesale market. Sales
growth due to a growing retail customer base, along with favorable weather
conditions, contributed to new record peak loads for both the summer and winter
periods.

Retail revenues exceeded the prior year by $29 million, largely due to rate
increases accompanied by 3% higher energy sales. These increases were partially
offset by revenue refund provisions for SAVE adjustments and certain state tax
benefits.

Wholesale revenues exceeded 1995 levels by $99 million due to increased trading
activities.

The price of purchased power and fuel dropped 25% in 1996, averaging 12 mills
versus 15.9 mills last year. Total costs increased only $23 million or 8%,
despite a 36% rise in total Company energy requirements. Optimal hydro
conditions brought steep reductions in the cost of secondary power, as well as
the cost of firm power purchased from the mid-Columbia projects. Power
purchases amounted to 75% of total PGE load in 1996 at an average cost of
13.8 mills compared to 18.3 mills in 1995.

PGE hydro projects generated 9% of the Company's energy needs, an 11% increase
in production levels. PGE's thermal plants operated efficiently, and with the
addition of Coyote Springs, average overall costs dropped to 6.6 mills from 8.0
mills in 1995. Excluding Coyote Springs, thermal plants generation was down
13% due to economic displacement early in the year.

Operating expenses (excluding purchased power, fuel, depreciation and
taxes)
were $30 million or 14% higher than 1995. The increase is primarily due to
additional costs associated with fixed natural gas transportation, storm
related repair and maintenance projects, and increased customer support.
Incremental operating costs associated with Coyote Springs, which was placed in
operation in late 1995, were offset by decreased costs at other thermal
facilities resulting from economic displacement. Throughout the year PGE was
able to economically dispatch or displace thermal generation in response to
movements in the cost of short-term power and the availability of low-cost
hydro power.

Depreciation and amortization increased $22 million, or 16%, due
primarily to depreciation related to Coyote Springs.

Excluding regulatory disallowances of $50 million in 1995, other income
declined $9 million due to a reduced return on regulatory assets and the
absence of equity AFDC.

Interest charges were $7 million above 1995 due to reduced AFDC and higher
levels of short-term debt. Preferred dividend requirements were down $7
million due to the retirement of nearly $80 million in preferred stock in 1995.

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 1997
monthly balances ranged from $73 million to $115 million. PGE has committed
borrowing facilities 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. Decreased cash flow was due to price and related retail revenue
decreases.

CAPITAL EXPENDITURES GRAPH:
($ MILLIONS)

1993 149
1994 246
1995 234
1996 200
1997 180

INVESTING ACTIVITIES include generation, transmission and distribution
facilities improvements, energy efficiency programs and decommissioning
expenditures. 1997 capital expenditures of $180 million were primarily for the
expansion and upgrade of PGE's distribution system. Annual capital
expenditures are expected to be approximately $170 million over the next few
years. The majority of anticipated capital expenditures are for improvements
to the Company's expanding distribution system to support the addition of new
customers.

PGE does not anticipate construction of new generating resources in the
foreseeable future. PGE will continue to make energy efficiency
expenditures similar to 1997 levels.

FINANCING ACTIVITIES provide supplemental cash for day-to-day operations and
capital requirements as needed. PGE has issued no new long-term debt in 1997
and has instead relied on short-term borrowings to manage its day-to-day
financing requirements. During 1997 PGE's cash dividend payments to its parent
totaled $65 million compared $106 million in 1996.

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, 1997, 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

BUSINESS COMBINATION

CUSTOMER CHOICE

PGE is dependent upon the regulatory process to ensure that future revenues
will be provided for the recovery of regulatory assets, including the
transition costs mentioned above. In the event that the regulatory process does
not provide revenues for recovery of transition costs, PGE could be required to
write off all or a portion of such amounts from its balance sheet.

INTRODUCTORY PROGRAM
In a move to prepare for future retail competition, PGE initiated an
introductory Customer Choice Plan to allow 50,000 PGE customers in four cities
to buy their power from competing energy service providers. This program allows
certain customers in Oregon to experience a competitive electricity market. The
program, which received OPUC approval, is available to residential, small
business and commercial customers in the four cities, and industrial customers
throughout PGE's service territory. Since October 1997 PGE's large industrial
customers throughout its service territory have had the opportunity to purchase
up to 50 percent of their electricity from competing electricity providers.
Residential, small business and commercial customers were given the option of
receiving electricity from a company of their choice in December 1997.
Under this program, customers in the four cities can pool or aggregate their
electric load in order to negotiate a cheaper rate from energy suppliers. To
date over 7,000 retail customers have selected alternative energy service
providers. This program, which terminates on December 31, 1998, is being
undertaken to provide information to PGE and the OPUC on the effects of future
retail competition on PGE and its customers. PGE does not expect that this
program will have a materially adverse impact on operating margins.

REGULATION AND COMPETITION

FEDERAL
The Energy Policy Act of 1992 (Energy Act) set the stage for change in federal
and state regulations aimed at increasing both wholesale and retail 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.

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 which became effective July 1996 have
resulted in increased competition, lower prices and more choices to wholesale
energy customers.

STATE
Since the passage of the Energy Act, various state utility commissions have
addressed proposals which would allow retail customers direct access to
generation suppliers, marketers, brokers and other service providers in a
competitive marketplace for energy services (retail wheeling). Although
several bills proposing retail competition were introduced during the 1997
Oregon legislative session, none were approved. Industry restructuring bills
have also been introduced at the federal level.

RETAIL CUSTOMER GROWTH AND ENERGY SALES
During 1997 weather adjusted retail energy sales grew 5.7%. Commercial and
industrial sales increased by 4.2% and 12% respectively due to strong growth in
most industry segments. The addition of over 17,000 customers resulted in
residential sales growth of 2.9%. PGE expects retail energy sales growth to be
approximately 3%.

Effective January 1998 rates for PGE's residential and small farm customers
increased 11.9 percent due to the Bonneville Power Administration's (BPA)
elimination of the Residential Exchange Credit. PGE has contested this
decision and is working with the BPA to resolve the issue. Exchange benefits,
and any related changes in the amount of benefits, have generally passed
directly to PGE's customers in the form of price increases or decreases.

WHOLESALE SALES
The surplus of electric generating capability in the Western U.S., the entrance
of numerous wholesale marketers and brokers into the market, and open access
transmission is contributing to increasing pressure on the price of power. In
addition, the development of financial markets and NYMEX electricity contract
trading has led to increased price discovery available to market participants,
further adding to the competitive pressure on wholesale margins. During 1997
PGE's wholesale revenues increased over $300 million compared to the same
period last year, accounting for 35% of total revenues and 60% of total sales
volume. 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 to administer PGE's current long-term wholesale contracts. Due
to increasing volatility and reduced margins resulting from increased
competition, long-term wholesale marketing activities have been transferred to
PGE's non-regulated affiliates. PGE expects that its future revenues from the
wholesale marketplace will decline.

POWER & FUEL SUPPLY
PGE's base of hydro and thermal generating capacity provides the Company with
the flexibility needed to respond to seasonal fluctuations in the demand for
electricity both within its service territory and from its wholesale customers.
PGE has long-term power contracts with four hydro projects on the mid-Columbia
River which provide PGE with 590 MW. Early forecasts indicate slightly below
average water conditions for 1998. Efforts to restore salmon runs on the
Columbia and Snake rivers may reduce the amount of water available for
generation which could affect the supply, 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 1997 PGE generated approximately 40% of its retail load requirements,
with firm and secondary purchases meeting the remaining load. Purchases
were used to support PGE's wholesale sales activity. During 1997 PGE relied on
purchases to supply approximately 84% of its total energy needs. PGE expects
purchases will decline in 1998 due to the transfer of wholesale marketing
activities to non-regulated affiliates.

PGE has increasingly relied 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 Company generation and purchases
under existing firm power contracts.

RESTORATION OF SALMON RUNS - Several species of salmon found in the Snake River
and the Columbia River have been granted protection under the federal
Endangered Species Act (ESA). In an effort to help restore these fish, the
federal government has reduced the amount of water allowed to flow through the
turbines at the hydroelectric dams on the Snake and Columbia rivers while the
young salmon are migrating to the ocean. This has resulted in reduced amounts
of electricity generated at the dams. Favorable hydro conditions helped
mitigate the effect of these actions in 1996 and 1997. If this practice is
continued in future years it could mean less water available in the fall and
winter for generation when demand for electricity in the Pacific Northwest is
highest. Although PGE does not own any hydroelectric facilities on the
Columbia and Snake rivers, it does buy energy from both utilities and federal
agencies which do.

HYDRO RELICENSING
PGE HYDRO - PGE's hydroelectric plants are some of the Company's most valuable
resources supplying economical generation and flexible load following
capabilities. Company-owned hydro generation produced 2.9 million MWh of
renewable energy in 1997, meeting 6% of PGE's load. PGE's hydroelectric 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 1997. 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 in 1997 in support of relicensing
PGE's four Westside hydroelectric projects, with license expiration dates in
2004 and 2006 and combined generating capacity of 230 MW. Should relicensing
not be completed prior to the expiration of the original license, annual
licenses will be issued, usually under the original terms and conditions.

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 more than 50 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 FERC has never denied an application
or issued a license to anyone other than the incumbent licensee, there is no
assurance that a new license will be granted to PGE.

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 FERC seeking to change the allocation of generation from the Priest Rapids
and Wanapum dams between electric utilities in the region upon the expiration
of the current contracts. In early 1998 the FERC ruled that the portion of the
output from these dams to be made available to purchasers such as PGE be
reduced to 30%. FERC also ruled that such purchases be at market-based rather
than cost-based prices. This decision could substantially change PGE's share of
power from these facilities, as well as the price of such power. PGE, along
with other purchasers, has filed for a rehearing on this decision.

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 cost to decommission Trojan at $339 million in
nominal dollars (actual dollars to be spent in each year). This 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).

Trojan's single-package reactor vessel removal concept and spent fuel storage
concept are first-of-a-kind designs requiring approval by federal and state
regulatory agencies. The precedent-setting nature of these designs has
prompted intense scrutiny and has resulted in schedule delays. Further,
financial concerns associated with the spent fuel facility vendor have resulted
in cost increases to the spent fuel project.

In 1998, PGE will focus on the licensing and construction of a temporary dry
spent fuel storage facility and preparation for the removal of the Trojan
reactor vessel. Equipment removal and disposal activities will also continue.
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, thereby proving these hazards are no longer present. PGE
expects the final site survey to be completed by the end of 2002.

YEAR 2000
PGE utilizes software and related technologies that will be affected by the
date change in the year 2000. In 1997 PGE developed an inventory of date
sensitive software, equipment and embedded processors. PGE is currently
assessing the impact of the date change on these systems and is developing a
remediation plan. PGE expects to complete remediation activities by mid 1999.
PGE does not expect that Year 2000 remediation will have a material effect on
its operation, liquidity or capital resources.

In 1998, PGE will survey its major vendors and suppliers to assess their Year
2000 compliance.

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 for the years ended December 31, 1997,
1996 and 1995, 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 Corp.'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 Shareholders 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 for the year ended
December 31, 1997 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 for the year ended
December 31, 1997 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 criteria established in "Internal Control-Integrated
Framework" issued by the Committee of Sponsoring Organizations of the Treadway
Commission.

Arthur Andersen LLP

Portland, Oregon
January 20 , 1998

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have audited the accompanying consolidated balance sheets of Portland
General Electric Company and subsidiaries as of December 31, 1997 and 1996, and
the related consolidated statements of income, retained earnings and cash flows
for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1997 in conformity with generally accepted accounting
principles.

Arthur Andersen LLP

Portland, Oregon,
January 20, 1998

FOR THE YEARS ENDED DECEMBER 31 1997 1996 1995

(MILLIONS OF DOLLARS)
OPERATING REVENUES $ 1,416 $ 1,110 $ 982
OPERATING EXPENSES
Purchased power and fuel 675 308 285
Production and distribution 132 138 112
Administrative and other 107 104 100
Depreciation and amortization 155 162 140
Taxes other than income taxes 56 52 51
Income taxes 83 116 93
1,208 880 781
NET OPERATING INCOME 208 230 201
OTHER INCOME (DEDUCTIONS)
Regulatory disallowances - net of income taxes of $26 - - (50)

Miscellaneous (21) (3) 3
Income taxes 13 5 8
(8) 2 (39)
INTEREST CHARGES
Interest on long-term debt and other 69 67 62
Interest on short-term borrowings 5 9 7
74 76 69
NET INCOME 126 156 93
PREFERRED DIVIDEND REQUIREMENT 2 3 10
INCOME AVAILABLE FOR COMMON STOCK $ 124 $ 153 $ 83

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31
1997 1996 1995
(MILLIONS OF DOLLARS)
BALANCE AT BEGINNING OF YEAR $ 292 $ 246 $ 216
NET INCOME 126 156 93
MISCELLANEOUS (2) (2) (4)
416 400 305
DIVIDENDS DECLARED
Common stock - cash 47 105 50
Common stock - property 97 - -
Preferred stock 2 3 9
146 108 59
BALANCE AT END OF YEAR $ 270 $ 292 $ 246
The accompanying notes are an integral part of these consolidated statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME

AT DECEMBER 31 1997 1996

(MILLIONS OF DOLLARS)
ASSETS
ELECTRIC UTILITY PLANT - ORIGINAL COST
Utility plant (includes Construction Work in Progress of
$27 and $37) $ 3,078 $ 2,937
Accumulated depreciation and amortization (1,260) (1,155)
1,818 1,782
OTHER PROPERTY AND INVESTMENTS
Contract termination receivable 104 112
Receivable from parent 106 -
Trojan decommissioning trust, at market value 84 78
Corporate Owned Life Insurance, less loans of $30 and $26 58 51
Miscellaneous 17 21
369 262
CURRENT ASSETS
Cash and cash equivalents 3 19
Accounts and notes receivable 125 145
Unbilled and accrued revenues 46 53
Inventories, at average cost 30 33
Prepayments and other 21 17
225 267
DEFERRED CHARGES
Unamortized regulatory assets 819 896
WNP-3 settlement exchange agreement - 163
Miscellaneous 25 28
844 1,087
$ 3,256 $ 3,398

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 480 475
Retained earnings 270 292
Cumulative preferred stock
Subject to mandatory redemption 30 30
Long-term obligations 1,008 933
1,948 1,890
CURRENT LIABILITIES
Long-term debt due within one year - 93
Short-term borrowings - 92
Accounts payable and other accruals 167 145
Accrued interest 11 14
Dividends payable 1 17
Accrued taxes 63 31
242 392
OTHER
Deferred income taxes 363 498
Deferred investment tax credits 43 47
Trojan decommissioning and transition costs 313 358
Unamortized regulatory liabilities 258 149
Miscellaneous 89 64
1,066 1,116
$ 3,256 $ 3,398
The accompanying notes are an integral part of
these consolidated balance sheets.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

FOR THE YEARS ENDED DECEMBER 31 1997 1996 1995
(MILLIONS OF DOLLARS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net income to net cash provided by (used in)
operating activities
Net Income $ 126 $ 156 $ 93
Non-cash items included in net income:
Depreciation and amortization 127 119 102
Amortization of Trojan investment 39 38 38
Amortization of deferred charges (credits) (1) 11 3
Deferred income taxes - net (58) (9) 2
Regulatory disallowances - - 50
Other non-cash expenses 24 - -
Changes in working capital:
(Increase) Decrease in receivables 27 (32) (12)
(Increase) Decrease in inventories 3 5 (7)
Increase (Decrease) in payables and accrued taxes 51 38 13
Other working capital items - net (4) (1) 2
Other, net 25 44 1
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 359 369 285
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures & energy efficiency programs (180) (200) (234)
Trojan decommissioning expenditures (19) (8) (11)
Trojan decommissioning trust activity - (8) (3)
Other, net (9) (5) (9)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (208) (221) (257)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net increase (decrease) in short-term borrowings 8 (78) 22
Borrowings from Corporate Owned Life Insurance 5 - 5
Issuance of long-term debt - 171 147
Repayment of long-term debt (115) (98) (69)
Retirement of Preferred stock - (20) (80)
Dividends paid (65) (106) (60)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (167) (131) (35)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (16) 17 (7)
CASH AND CASH EQUIVALENTS, THE BEGINNING OF YEAR 19 2 9
CASH AND CASH EQUIVALENTS, END OF YEAR $ 3 $ 19 $ 2
Supplemental disclosures of cash flow information
Cash paid during the year:
Interest, net of amounts capitalized $ 71 $ 73 $ 64
Income taxes 96 108 94
The accompanying notes are an integral part of these
consolidated statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS

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
1997, PGE's service area population was approximately 1.5 million, constituting
approximately 44% of the state's population and serving approximately 685,000
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 ratemaking 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. BPA terminated these
benefits in October 1997 resulting in no future purchased power credits and a
retail price increase of 11.9%.

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 1997 and 1996, and 4.0% in 1995.

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, 1997 and 1996 accumulated amortization for capital leases totaled $33 and
$31 million, respectively.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC)
AFDC represents the pretax 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 rates used by PGE were 5.5%, 5.5% and 7.2% for the
years 1997, 1996 and 1995, respectively.

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 such as forwards and swaps to hedge against
exposures 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 No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS No. 71). 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 otherwise be reflected
in income but through the ratemaking process ultimately will be refunded to
customers.

Regulatory assets and liabilities are 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:

1997 1996

(millions of dollars)
Regulatory Assets
Trojan-related $488 $ 557
Income taxes recoverable 174 196
Debt reacquisition and other 47 51
Conservation investments - secured 72 80
Energy efficiency programs 19 12
Regional Power Act 19 -
Total Regulatory Assets $819 $ 896
Regulatory Liabilities
Deferred gain on SCE termination $103 $ 113
Merger payment obligation 103 -
Miscellaneous 52 36
Total Regulatory Liabilities $258 $ 149

As of December 31, 1997, 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 1997, the Company estimates that it will collect the
majority of its regulatory assets within the next 10 years and substantially
all of its regulatory assets within the next 20 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 conservation bonds collateralized by an OPUC assured
future revenue stream. These bonds provide savings to customers while granting
PGE immediate recovery of its prior energy efficiency program expenditures.
Future revenues collected from customers will pay debt service obligations.

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).

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 also provides and receives incidental
services from Enron affiliated companies. Amounts paid and received are not
material.

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. Benefits under the Plan are based on
years of service, final average pay and covered compensation. PGE's
policy is to contribute annually to the Plan at least the minimum
required under the Employee Retirement Income Security Act of 1974 but not
more than the maximum amount deductible for income tax purposes. The
Plan's assets are held in a trust and consist primarily of investments in
common stocks, corporate bonds and U.S. government issues.

PGE determines net periodic pension expense according to the principles of
SFAS No. 87, "Employers' Accounting for Pensions". Differences between the
actual and expected return on Plan assets are considered in the determination
of future pension expense. The following table sets forth the Plan's funded
status and amounts recognized in PGE's financial statements (millions of
dollars):

1997 1996

Actuarial present value of benefit obligations:
Accumulated benefit obligation, including
vested benefits of $187 and $171 $ 201 $ 184
Effect of projected future compensation levels 39 38
Projected benefit obligation (PBO) 240 222
Plan assets at fair value 375 315
Plan assets in excess of PBO 135 93
Unrecognized net experience gain (128) (90)
Unrecognized prior service costs amortized
over 13- to 16-year periods 11 12
Unrecognized net transition asset being
recognized over 18 years (14) (16)
Pension prepaid asset/(liability) $ 4 $ (1)

1997 1996 1995

ASSUMPTIONS:
Discount rate used to calculate PBO 7.25% 7.50% 7.00%
Rate of increase in future compensation levels 5.25 5.50 5.00
Long-term rate of return on assets 9.00 8.50 8.50

COMPONENTS OF NET PERIODIC PENSION EXPENSE
(MILLIONS OF DOLLARS):

Service cost $ 6 $ 7 $ 5
Interest cost on PBO 17 15 15
Actual return on plan assets (71) (38) (59)
Net amortization and deferral 43 15 37
Net periodic pension expense/(benefit) $ (5) $ (1) $ (2)

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. PGE
receives recovery for the annual provision in customer rates. 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, 1997 was $27 million, for which there were
$32 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 $12 million and $10 million at December 31, 1997 and 1996,
respectively.

DEFERRED COMPENSATION
PGE provides certain employees with benefits under an unfunded Management
Deferred Compensation Plan (MDCP). Obligations for the MDCP were $26 million
and $21 million at December 31, 1997 and 1996, 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 Corp. at current market prices.

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):

1997 1996 1995

Income Tax Expense
Currently payable
Federal $114 $ 98 $ 74
State & local 14 22 10
128 120 84
Deferred income taxes
Federal (45) (4) (11)
State & local (9) (1) (7)
(54) (5) (18)
Investment tax credit adjustments (4) (4) (6)
$ 70 $111 $ 60
Provision Allocated to:
Operations $ 83 $112 $ 90
Other income and deductions (13) (1) (30)
$ 70 $111 $ 60
Effective Tax Rate Computation:
Computed tax based on statutory
federal income tax rates applied
to income before income tax $ 69 $ 93 $ 53
Flow through depreciation 6 9 7
Regulatory disallowance - - 3
State and local taxes - net 13 12 6
State of Oregon refund (9) - (4)
Investment tax credits (4) (3) (5)
Excess deferred tax (1) (1) (1)
Other (4) 1 1
$ 70 $111 $ 60
Effective tax rate 35.7% 41.6% 39.2%

As of December 31, 1997 and 1996, the significant components of PGE's deferred
income tax assets and liabilities were as follows (millions of dollars):

1997 1996

DEFERRED TAX ASSETS
Plant-in-service $ 56 $ 64
Other 50 21
SCE termination payment 49 -
155 85
DEFERRED TAX LIABILITIES
Plant-in-service (402) (415)
Energy efficiency programs (32) (32)
Trojan abandonment (65) (69)
WNP-3 exchange contract - (59)
Other (19) (8)
(518) (583)
Total $(363) $(498)

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

NOTE 4 - COMMON AND PREFERRED STOCK

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, 1994 42,758,877 $ 160 1,297,040 $100 $30 $470 $(12)
Redemption of preferred stock (797,040) (80) - 3 -
Repayment of ESOP loan
and other - - - - - - 5

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 $ -

CUMULATIVE PREFERRED STOCK
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.

PGE's cumulative preferred stock consisted
of:

At December 31, 1997 1996
(millions of dollars)

Subject to mandatory redemption
No par value 30,000,000 shares authorized
7.75% Series 300,000 shares outstanding $30 $30

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 Corp. is the sole shareholder of PGE common stock. PGE is restricted
from paying dividends or making other distributions to Enron Corp. 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, 1997, PGE had total committed lines of credit of $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, 1997, 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, 1997, commercial paper borrowings of $100 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, 1997,
$71 million of long-term debt due within one year is classified as long-term.

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

1997 1996 1995

AS OF YEAR-END: (millions of dollars)
Aggregate short-term debt outstanding
Commercial paper $100 $ 83 $170
Bank loans - 9 -
Weighted average interest rate*
Commercial paper 6.0% 5.6% 6.1%
Bank loans - 7.3 -
Committed lines of credit $200 $200 $200

FOR THE YEAR ENDED:
Average daily amounts of short-term
debt outstanding
Commercial paper $ 89 $158 $111
Bank loans - 5 -
Weighted daily average interest rate*
Commercial paper 5.6% 5.6% 6.3%
Bank loans - 5.7 -
Maximum amount outstanding
during the year $115 $251 $170

* 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.

Schedule of long-term debt at December 31 1997 1996
(millions of dollars)
First Mortgage Bonds
Maturing 1997 through 2002
6.60% Series due October 1, 1997 $ - $ 15
Medium-term notes 5.65% - 8.88% 241 295
Maturing 2003 - 2007 6.47% - 9.07% 153 168
Maturing 2021 - 2023 7.75% - 9.46% 170 195
564 673
Pollution Control Bonds
Port of Morrow, Oregon, variable rate
(Average 3.7% - 3.8% for 1997), due 2013 & 29 29
2031
City of Forsyth, Montana, variable rate
(Average variable rates 3.6%- 3.7% for 119 119
1997), due 2013-2016
Amount held by trustee (8) (8)
Port of St. Helens, Oregon, variable rate due 2010
and 2014 (Average variable rates 3.6% - 3.7% 52 52
for 1997
192 192
Other
8.25% Junior Subordinated Deferrable Interest Debentures,
due December 31, 2035 75 75
6.91% Conservation Bonds maturing monthly to 2006 73 80
Capital lease obligations 4 7
Amount reclassified from short-term debt 100 -
Other - (1)
252 161
1,008 1,026
Long-term debt due within one year - (93)
Total long-term debt $1,008 $ 933

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

1998 1999 2000 2001 2002

Maturities:
PGE $71 $102 $32 $53 $23

NOTE 6 - OTHER FINANCIAL INSTRUMENTS

FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the
fair value of each class of financial instruments 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.

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

1997 1996

Carrying Fair Carrying Fair
Amount Value Amount Value

Preferred stock subject to
mandatory redemption $ 30 $ 34 $ 30 $ 31

Long-term debt $831 $861 $940 $960

INTEREST RATE SWAPS - In August 1996 PGE entered into a 3-year
interest rate swap agreement with a notional amount of $50
million. This puts PGE in a floating rate position on the
additional $50 million of long-term debt issued in August 1996.
In December 1997 PGE canceled this agreement. The amount
received at cancellation was not material.

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 $16 million annually in 1998
through 2002 and $137 million over the remaining years of the
contracts. 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 $28 million
at December 31, 1997. Cancellation of these purchase agreements
could result in cancellation charges.

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, 1997 $ 235 $ 174 $ 207 $ 178 $ 36
PGE's current share of:
Output 12.0% 13.9% 18.7% 20.4% 100%
Net capability (megawatts) 154 128 194 171 36
Annual cost, including debt service:
1997 $ 7 $ 3 $ 4 $ 6 $ 4
1996 5 4 5 6 4
1995 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 1998, $6 million for 1999 and 2000,
and $7 million for 2001 and 2002. The minimum payments through
the remainder of the contracts are estimated to total
$84 million.

PGE has entered into long-term contracts to purchase power from
other utilities in the West. These contracts will require fixed
payments of up to $23 million in 1998 through 1999, $20 million
in 2000, and $19 million in 2001 through 2002. After that date,
capacity contract charges will average $19 million annually until
2016.

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 amounted to $24
million for 1997, and $22 million for 1996 and 1995. PGE has
capitalized its combustion turbine leases. However, these leases
are considered operating leases for ratemaking 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

1998 $ 3 $ 22 $ 25
1999 1 23 24
2000 - 23 23
2001 - 23 23
2002 - 11 11
Remainder - 174 174
Total 4 $276 $280
Imputed Interest -
Present Value of
Minimum Future
Net Lease Payments $ 4

Included in the future minimum operating lease payments schedule above
is approximately $119 million for PGE's headquarters complex.

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). The
transfer of PGE's net investment in these contracts to Enron Corp.,
PGE's parent and sole common stockholder transaction was executed in the
form of a special non-cash dividend.

NOTE 9 - JOINTLY OWNED PLANT

At December 31, 1997, 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 508 65.0 $376 $197
Colstrip 3&4 Colstrip, MT Coal 1,440 20.0 453 220
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 - In April 1996 a circuit court judge in
Marion County, Oregon found 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. The 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.

The 1994 ruling was appealed to the Oregon Court of Appeals and stayed
pending the appeal of the Commission's March 1995 order. Both PGE and
the OPUC have separately appealed the April 1996 ruling which was
combined with the appeal of the November 1994 ruling at the Oregon Court
of Appeals.

Management believes that the authorized recovery of and return on the
Trojan investment and decommissioning costs will be upheld and that
these legal challenges will not have a material adverse impact on the
results of operations or financial condition of the Company for any
future reporting period.

OTHER LEGAL MATTERS - PGE and certain of its subsidiaries are 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 $17 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 in decommissioning estimate is a lower inflation rate,
coupled with accelerating 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 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
1997 dollars, the decommissioning cost estimate is $286 million.

TROJAN DECOMMISSIONING LIABILITY
(millions of dollars)

Estimate - 12/31/94 $351
Upates files with NRC - 11/16/95 7
Updates filed with OPUC - 12/01/97 (19)
339
Expenditures through 12/31/97 (43)
Liability - 12/31/97 $296

Decommissioning $296
Transition costs 17
Total Trojan obligation $313

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 1997 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.

INVESTMENT RECOVERY - The OPUC issued an order in March 1995 authorizing
PGE to recover all of the estimated costs of decommissioning Trojan and
87% of the remaining investment in the plant. Amounts are to be
collected over Trojan's original license period ending in 2011. The
OPUC's order and the agency's authority to grant recovery of the
Trojan investment under Oregon law are being challenged in state courts.
Management believes that the authorized recovery of the Trojan investment
and decommissioning costs will be upheld and that these legal challenges
will not have a material adverse impact on the results of operations or
financial condition of the Company for any future reporting period.

DECOMMISSIONING TRUST ACTIVITY
(millions of dollars)
1997 1996
Beginning Balance $78 $69
ACTIVITY
Contributions 14 15
Gain 6 2
Disbursements (14) (8)

Ending Balance $84 $78

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 .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 six 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 $155 million
level.

QUARTERLY COMPARISON FOR 1997 AND 1996 (UNAUDITED)

MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
(MILLIONS OF DOLLARS)
1997
Operating revenues $368 $308 $391 $349
Net operating income 65 46 46 51
Net income 48 28 15 35
Income available for
common stock 47 28 14 35

1996
Operating revenues $300 $233 $260 $317
Net operating income 68 52 47 63
Net income 50 35 28 43
Income/(loss) available for
common stock 49 34 27 43

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 53
Director since 1997
Mr. Derrick has served as Senior Vice President and General Counsel of Enron
Corp. since June 1991. Prior to joining Enron Corp. In 1991, Mr. Derrick was
a partner at the law firm of Vinson & Elkins L.L.P. for more than 13 years.

KEN L. HARRISON, age 55
Director since 1987
Mr. Harrison serves as a Director and Vice Chairman of Enron Corp. and has
served as Chairman of the Board and Chief Executive Officer of Portland
General Electric Company since 1987.

JOSEPH M. HIRKO, age 41
Director since 1997.
Mr. Hirko serves as Senior Vice President of Enron Corp. and Portland
General Electric Company. Mr. Hirko also serves as President and Chief
Executive Officer of First Point 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 55
Director since 1997
For over five years, Mr. Lay has been Chairman of the Board and Chief
Executive Officer of Enron Corp. 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 44
Director since 1997
Since January 1, 1997, Mr Skilling has served as President and Chief
Operating Officer of Enron Corp. 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 managerial positions.

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

EXECUTIVE OFFICERS OF THE REGISTRANT (*)

NAME AGE BUSINESS EXPERIENCE

Ken L. Harrison 55 Appointed to current position of Chairman of the Board and Chief Executive Officer on
Chairman of the Board, Chief December 1, 1988.
Executive Officer, PGE

Alvin Alexanderson 50 Appointed to current position on December 12, 1995. Served as Vice President, Rates and
Senior Vice President Regulatory Affairs from February 1991 until appointed to current position.
General Counsel and Secretary

Arleen Barnett 45 Appointed to current position on February 23, 1998. Served as Manager, Human Resources
Vice President from 1989 until appointed to current position.
Human Resources

David K. Carboneau 51 Appointed to current position in October 1989. Served as Vice President, Utility Service
Vice President 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.

Steven N. Elliott 37 Appointed to current position on February 23, 1998. Served as Vice President, Finance and
Vice President Treasurer from July 1997 until appointed to current position. Served as Manager, Corporate
Chief Financial Officer and Finance and Assistant Treasurer from April 1992 until July 1997.
Treasurer

Joseph E. Feltz 43 Appointed to current position on July 1, 1997. Previously served as Assistnat Controller
Controller and and Assistant Treasurer for over five years.
Chief Accounting Officer

Peggy Y. Fowler 46 Appointed to current position on July 1, 1997. Served as Executive Vice President
President and Chief Operating Officer, PGE from November 1996 until appointed to current position.
Chief Operating Officer Served as Senior Vice President, Energy Services from September 1995 until November 1996.
Distribution Operations Served as Vice President, Distribution and Power Production from January 1990 to
September 1995.

Stephen R. Hawke 48 Appointed to current position on July 1, 1997. Served as General Manager, System
Vice President Planning and Engineering until appointed to current position. Served as Manager,
Delivery System Planning & Response and Restoration from May 1993 until May 1995. Served as Manager, Western
Engineering Region from August 1990 until May 1993.

Joseph M. Hirko 41 Appointed to current position on September 12, 1995. Served as Vice President-Finance
Senior Vice President from December 1991 until July 1997. Served as Chief Financial Officer from December
1991 until February 1998. Served as Chief Accounting Officer from December 1991 until
July 1997. Served as Treasurer from June 1989 to July 1997.

Joe A. McArthur 50 Appointed to current position on July 1, 1997. Served as Manager of Western Region
Vice President from May 1996 until appointed to current position. Served as Manager, System
Substation and Line Operations 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 45 Appointed to current position on February 23, 1998. Served as General Manager, Planning Vice
President Support and Analysis from November 1992 until appointed to current position.

EXECUTIVE OFFICERS OF THE REGISTRANT (*) - CONT'D.

NAME AGE BUSINESS EXPERIENCE

Frederick D. Miller 55 Appointed to current position on July 1, 1997. Served as Senior Vice President, Public Senior
Vice President Affairs and Corporate Services from November 1996 until appointed to current position. Served
Public Policy and as Director of Executive Department, State of Oregon, from 1987 until appointed to Vice
Administrative President, Public Affairs and Corporate Services in October 1992.
Services and Distribution
System Services

Walter E. Pollock 55 Appointed to current position on July 1, 1997. Served as Vice President, Enron
Senior Vice President Capital and Trade and Senior Vice President, First Point Utility Solutions from
Power Supply 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.

Christopher D. Ryder 48 Appointed to current position on July 1, 1997. Served as General Manager, Customer
Vice President Services and Southern Region Operations from 1996 until appointed to current
Customer and Line Operations position. Served as General Manager, Customer Services and Marketing from 1992 to 1996.

(*) Officers are listed as of February 28, 1998. The officers are elected to
serve for a term of one year or until their successors are elected and
qualified.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth the total compensation earned for each year
ended December 31, 1997, 1996, 1995 by the Chief Executive Officer and the
four most highly compensated executive officers of PGE.

Long-Term
Annual Compensation Compensation All Other

Salary ($) Bonus ($) Restricted Stock Compensation
Name and Principal Position Year (1) (1) Awards ($) (2) ($) (3)

Ken L. Harrison (4) 1997 $243,570 $236,592 $204,755 $68,051
Chairman of the Board, 1996 399,510 252,193 251,410 40,480
Chief Executive Officer 1995 417,113 325,439 305,250 59,646

Peggy Fowler 1997 230,000 160,000 230,185 29,406
President, Distribution Operations 1996 202,504 106,379 150,500 24,045
Chief Operating Officer 1995 165,213 78,836 111,000 18,185

Richard E. Dyer (5) 1997 219,306 165,250 215,060 27,209
Senior Vice President, 1996 209,196 111,002 150,500 23,428
Power Supply 1995 198,297 104,655 111,000 11,979

Frederick D. Miller 1997 175,020 105,000 - 48,906
Senior Vice President, Public 1996 161,259 73,811 75,250 36,400
Policy, Administrative 1995 137,634 62,341 55,500 32,517
Services and Distribution
System Services

Joseph M. Hirko (4) (6) 1997 89,835 158,270 125,038 22,885
Senior Vice President 1996 103,934 95,509 114,277 18,477
1995 204,646 100,296 138,750 18,540

(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 Corp. common
stock for the July 1, 1997 grant, which will vest 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. The September 10, 1996
grant converted to Enron shares on the effective date
of the Merger. Dividends on this grant are paid as
declared. Restricted stock awards are valued at
$27.75 per share of PGC common stock for the November
6, 1995 grant. This grant vested November 1996 upon
PGC shareholder approval for the original Merger
Agreement. Aggregate restricted stock holdings listed
below are valued at $41.5625 per share, the closing
price of the Enron Corp. common stock on December 31,
1997.

Aggregate Restricted Stock Holdings

AGGREGATE SHARES (#) VALUE ($)
Ken L. Harrison 23,477 $975,763
Peggy Fowler 9,485 394,220
Richard E. Dyer 9,120 379,050
Frederick D. Miller 1,965 81,670
Joseph M. Hirko 10,947 454,985

(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 table lists the amount for 1997:

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

Ken L. Harrison $ 968 $ 2,038 $11,615 $53,430 $68,051

Peggy Fowler 705 8,833 13,800 6,068 29,406

Richard E. Dyer 1,290 9,862 10,886 5,171 27,209

Frederick D. Miller 925 21,031 13,700 13,250 48,906

Joseph M. Hirko 321 2,833 8,963 10,768 22,885

(4) Mr. Harrison and Mr. Hirko also serve as executive officers of Enron
Corp. The compensation shown represents the amount allocated to PGE.

(5) Richard E. Dyer retired from Portland General Electric Company as of
February 1, 1998.

(6) Joseph M. Hirko resigned his position as Chief Financial Officer of Portland
General Electric Company as of February 23, 1998.

The following table lists information concerning the stock options to purchase
shares of Enron Corp. common stock that were granted to PGE's five highest paid
officers during 1997. No stock appreciation rights were granted during 1997.

Options/SAR Grants in Last Fiscal Year

Number of % of Total
Securities Options/ Potential Realized Value at
Underlying SARs Granted Assumed Annual Rates of Stock
Options/ to Employees in Exercise or Price Appreciation for Option
SARs{(1)} Fiscal Year Base Price Expiration Term

NAME GRANTED FISCAL YEAR ($/SH) DATE 5% 10%

Ken L. Harrison 120,000{(2)} 0.71% $41.4375 07/01/07 $3,127,178 $7,924,884
33,335{(5)} 0.20% 41.5625 12/31/04 564,032 1,314,434
7,430{(6)} 0.04% 41.5625 12/31/07 194,209 492,163

Peggy Y. Fowler 30,000{(2)} 0.18% $41.4375 07/01/07 $ 781,795 $1,981,221
10,260{(5)} 0.06% 41.5625 12/31/04 173,600 404,563
3,255{(6)} 0.02% 41.5625 12/31/07 85,081 215,611

Joseph M. Hirko 50,000{(2)} 0.30% $41.4375 07/01/07 $1,302,991 $3,302,035
25,000{(3)} 0.15% 38.8750 10/13/07 611,207 1,548,919
4,525{(4)} 0.03% 39.8750 12/08/07 113,474 287,566
12,825{(5)} 0.08% 41.5625 12/31/04 217,000 505,703
3,680{(6)} 0.02% 41.5625 12/31/07 96,190 243,763

Richard E. Dyer 30,000{(2)} 0.18% $41.4375 07/01/07 $ 781,795 $1,981,221
3,045{(6)} 0.02% 41,5625 12/31/07 79,591 201,701

Frederick D. Miller 25,000{(2)} 0.15% $41.4375 07/01/07 $ 651,496 $1,651,018
3,850{(5)} 0.02% 41.5625 12/31/04 65,142 151,809
2,480{(6)} 0.01% 41.5625 12/31/07 64,823 164,275

(1)If a "Change of Control" (as defined in the Enron Corp. 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 on July 1, 1997, which vested 20% at grant
and 20% each anniversary date thereafter.
(3)Represents stock options awarded on October 13, 1997, which cliff vest 100%
on the 4th anniversary date of the grant.
(4)Represents stock options awarded on December 8, 1997, which cliff vest 100%
on the 4th anniversary date of the grant.
(5)Represents stock options awarded under the Long-Term Incentive Program for
1998. Stock options awarded on December 31, 1997 became 20% vested on the
date of grant with an additional 20% vested on the anniversary of the date
of grant until 100% vested December 31, 2001.
(6)Represents shares issued on December 31, 1997, as a new employee under the
All Employee Stock Option Program.

The following table lists information concerning the options to purchase shares
of Enron Corp. common stock that were exercised by the officers named above
during 1997 and the total options and their value held by each at year-end
1997.

Aggregate Stock Options/SAR
Exercised During 1997
and Stock Options/SAR Values
at December 31, 1997

Number of Securities Underlying
Unexercised Options/SAR Value of Unexercised In-the-Money
AT DECEMBER 31, 1997 Options/SARs
AT DECEMBER 31, 1997
Shares

Acquired Value Un-EXERCISABLE Un-EXERCISABLE
NAME ON EXERCISE (#) REALIZED ($) EXERCISABLE EXERCISABLE

Ken L. Harrison 20,000 $449,390 128,567 130,098 $2,502,583 $ 12,000
Peggy Y. Fowler - - 9,552 33,963 938 2,813
Joseph M. Hirko - - 42,040 83,465 763,806 79,823
Richard E. Dyer - - 7,500 25,545 937 2,812
Frederick D. Miller - - 7,020 24,310 781 2,344

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 OF: 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, 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 executive officers named in the table have had the following number of
service years with the Company: Ken L. Harrison, 22; Peggy Y. Fowler, 23;
Richard E. Dyer, 30; Joseph M. Hirko, 17; Frederick D. Miller, 5. 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; Richard E. Dyer, 55; Joseph M. Hirko, 55; Frederick D. Miller,
62.

EMPLOYMENT CONTRACTS
Mr. Harrison entered into an employment agreement with Enron on July 1, 1997,
the effective date of the merger between Enron Corp. and Portland General Corp.
(PGC), the former parent of PGE, pursuant to which he will serve as Vice
Chairman of Enron and Chairman and Chief Executive Officer of PGE. The
agreement is for a period of five years and expires on June 30, 2002. Per
the terms of the agreement, Mr. Harrison will receive an annual base salary of
not less than $525,000 and was granted 120,000 stock options which have a
10-year term and which vest 20% on the date of grant and 20% on each of the
first five anniversaries of the date of grant and in accordance with the
terms of his agreement. Mr. Harrison also received 12,670 shares of
restricted stock which vest 20%
on each of the four anniversaries of the date of grant. Also,
Mr. Harrison will receive an annual bonus of not less than $525,000, of which
20% will be paid in stock options and 80% will be paid in cash. In the event
of his involuntary termination, Mr. Harrison will receive amounts prescribed
in the agreement through the term of the agreement. If Mr. Harrison terminates
his employment voluntarily during a Window Period (defined as one of the
30-day periods beginning on the second, third, or fourth anniversaries of
the effective date of the merger between Enron Corp. and PGE), he will be
entitled to the insurance coverage equivalent to that under certain of
Enron's insurance plans for active employees and to all payments of his
annual base salary and bonus at such time and in such manner as if his
employment had continued for the balance of the initial term, provided that,
if the initial term would have continued beyond the second anniversary of
the termination date, then Enron will pay Mr. Harrison a lump sum amount
on such second anniversary date equal to the amount which would have been paid
to Mr. Harrison during the balance of the initial term if his employment had
continued during such period. In the event that the severance or other
payments payable under the agreement constitute "excess parachute
payments" within the meaning of Section 280G of the Code, and Mr. Harrison
becomes liable for any excise tax or penalties or interest thereon, Enron
will make a cash payment to him in an amount equal to the tax penalties plus
an amount equal to any additional tax for which he will be liable as a
result of receipt of the payment for such tax penalties and payment for
such reimbursement for additional tax. The employment agreement contains
noncompete provisions in the event of Mr. Harrison's termination of
employment.

Mr. Hirko's employment agreement is similar in structure to Mr. Harrison's
agreement. Under his agreement, Mr. Hirko will serve as a Senior Vice
President of Enron and as a senior executive officer of PGE for a period of
five years, subject to certain termination provisions similar to those in Mr.
Harrison's agreement, and thereafter as Mr. Hirko and Enron may agree. Mr.
Hirko will receive an annual base salary of not less than $250,000 and was
granted 50,000 stock options which have a 10-year term and will vest 20% on
the date of grant and 20% on each succeeding anniversary of the Effective Date,
except in the case of Mr. Hirko's Involuntary Termination (as defined in the
agreement), but not including a voluntary termination during a Window Period or
a Change in Control (as defined in the agreement) of Enron or PGE, in which
case the option will vest immediately. Mr. Hirko also received 6,035 shares of
Restricted Stock which vest in 20% increments on each of the first five
anniversaries of the date of grant and are subject to forfeiture upon
termination of Mr. Hirko's employment. Mr. Hirko will receive an annual bonus
of not less than $250,000, of which 20% will be paid in immediately vested
stock options and 80% will be paid in cash. Following termination of Mr.
Hirko's employment for any reason, he or his surviving spouse will be entitled
to a Supplemental Retirement Benefit (as defined in the agreement) to ensure
that the aggregate pension benefits he or his spouse receives, taking account
of all pension benefits from PGC and Enron, are at least equal to the aggregate
pension benefits he or his spouse would have received under PGC's Pension Plan
and the SERP had he continued to participate in such pension plan and the SERP
through the date of termination of employment.

Mr. Hirko's Supplemental Retirement Benefit thus differs from Mr. Harrison's
Supplemental Retirement Benefit described above.

The other terms of Mr. Hirko's employment agreement are substantially similar
to those of Mr. Harrison's, except that, in the event of an Involuntary
Termination prior to the expiration of the Initial Term, Mr. Hirko will be
entitled to receive a cash amount equal to the single sum actuarial equivalent
of the incremental amount that would be paid as the Supplemental Retirement
Benefit if that amount were computed assuming that Mr. Hirko has attained an
additional three years of age and an additional three years of service under
the SERP.

Ms. Fowler, Messrs. Dyer and 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 expire 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) Mr. Dyer's agreement provides that he will
be treated as having been involuntarily terminated and entitled to receive
three years severance pay if he terminates his employment for any reason
during a 30-day period beginning on the first anniversary of the Effective
Time; (iv) the aggregate minimum base salaries per year under such
agreements equal $620,000 per year and the aggregate minimum guaranteed
annual cash incentives per year under such agreements equal $328,750;
(v) each agreement provides for the grant of 30,000 options to purchase
shares of Enron Common Stock, except for Mr. Miller's which provides for
25,000 options; (vi) each agreement, other than Mr. Miller's, 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 salary which will vest over a
five-year period; (vii) Mr. Dyer's agreement provides that the failure of
PGE and Mr. Dyer to extend or enter into a new agreement in either case for
one year will be treated as involuntary termination, while Ms. Fowler's and
Mr. Miller's agreement provide that the failure of PGE and the employee to
extend or enter into a new agreement in either case for two years
will be treated as involuntary termination;
(viii) each agreement provides for a supplemental retirement benefit; (ix)
each agreement provides that in the event that the severance or other
payments payable under the agreement for involuntary termination
(except for an involuntary termination of the type described in clause
(vii) above) 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 and any incremental income tax liability arising from such payments,
grossing up such employee on such gross ups until the amount of the last
gross up is less than one hundred dollars; and (x) each agreement includes a
noncompetition covenant.

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 Corp. (Enron). As of December 31,
1997 Enron owned 100% of the outstanding shares of common stock of PGE.

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, 1997
Consolidated Statements of Retained Earnings for each of
the three years in the period ended December 31, 1997
Consolidated Balance Sheets at December 31, 1997 and 1996
Consolidated Statement of Cash Flows for each of the three
years in the period ended December 31, 1997
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 58 of this report.

(B) REPORT ON FORM 8-K
December 1, 1997 - Item 5. Other Events:
Customer Choice Implementation Proposal

Residential Exchange Program

WNP-3 Settlement Exchange Agreement

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 27, 1998 By /S/ KEN L. HARRISON
Ken L. Harrison

Chairman of the Board 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 of the Board and
/S/ KEN L. HARRISON Chief Executive Officer March 27, 1998
Ken L. Harrison

Vice President
Chief Financial Officer
/S/ STEVEN N. ELLIOTT and Treasurer March 27, 1998
Steven N. Elliott

Controller and
/S/ JOSEPH E. FELTZ Chief Accounting Officer March 27, 1998
Joseph E. Feltz

*James Y. Derrick
*Ken L. Harrison
*Joseph M. Hirko Directors March 27, 1998
*Kenneth L. Lay
*Jeffrey K Skilling

*By /S/ JOSEPH E. FELTZ
(Joseph E. Feltz, 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)].

(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)].

* Forty-Sixth Supplemental Indenture dated August 1, 1996 [Form 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.

PORTLAND GENERAL ELECTRIC COMPANY AND
SUBSIDIARIES

EXHIBIT INDEX

NUMBER EXHIBIT

(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)].

* Trust Indenture, Mortgage and Security Agreement, dated 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, 1985, Exhibit (10)].

Portland General Holdings, Inc. Outside Directors' Deferred
Compensation Plan, 1997 Restatement dated June 25, 1997 (Filed
herewith).

Portland General Holdings, Inc. Retirement Plan for Outside Directors,
1997 Restatement dated June 25, 1997 (Filed herewith).

PORTLAND GENERAL ELECTRIC COMPANY AND
SUBSIDIARIES

EXHIBIT INDEX

NUMBER EXHIBIT

(10) Portland General Holdings, Inc. Outside Directors' Life Insurance
CONT. Benefit Plan, 1997 Restatement dated June 25, 1997 (Filed herewith).

EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS

Portland General Holdings, Inc. Management Deferred Compensation Plan,
1997 Restatement dated June 25, 1997 (Filed herewith).

Portland General Holdings, Inc. Senior Officers Life Insurance Benefit
Plan, 1997 Restatement Amendment No. 1 dated June 25, 1997 (Filed
herewith).

* 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 (Filed herewith).

(23) CONSENTS OF EXPERTS AND COUNSEL

Portland General Electric Company Consent of Independent Public
Accountants (filed herewith).

(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:

Joseph E. Feltz
Controller
Chief Accounting Officer

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