SECURITIES AND EXCHANGE COMMISSION
                   WASHINGTON, D. C. 20549
                        ____________
                          Form 10-K
                        ____________

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
    SECURITIES EXCHANGE ACT OF 1934
    FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
               OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
    THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-13159
                              
                         ENRON CORP.
   (Exact name of registrant as specified in its charter)

            Oregon                            47-0255140
 (State or other jurisdiction               (I.R.S. Employer
    of incorporation or                    Identification No.)
       organization)

                       ENRON BUILDING
        1400 Smith Street, Houston, Texas 77002-7369
     (Address of principal executive offices) (zip code)

Registrant's telephone number, including area code: 713-853-6161
                        ____________

 Securities registered pursuant to Section 12(b) of the Act:
     Title of each class              Name of each exchange on
                                        which registered
                                         
     Common Stock, no par value          New York Stock
                                         Exchange;
                                         Chicago Stock
                                         Exchange; and
                                         Pacific Stock
                                         Exchange
                                         
     Cumulative Second Preferred         New York Stock
     Convertible Stock,                  Exchange and
             no par value                Chicago Stock
                                         Exchange
                                         
                              
 Securities registered pursuant to Section 12(g) of the Act:
                            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.
Aggregate market value of the voting stock held by non-
affiliates of the registrant, based on closing prices in the
daily composite list for transactions on the New York Stock
Exchange on February 16, 1999, was approximately
$21,923,278,704.  As of March 1, 1999, there were
351,041,239 shares of registrant's Common Stock, no par
value, outstanding.

Documents incorporated by reference.  Certain portions of
the registrant's definitive Proxy Statement for the May 4,
1999 Annual Meeting of Shareholders ("Proxy Statement") are
incorporated herein by reference in Part III of this Form 10-K.
                              
<PAGE>
                      TABLE OF CONTENTS
                              
                           PART I
                                                             Page

Item 1.  Business                                             1
          General                                             1
          Business Segments                                   1
          Exploration and Production                          2
          Transportation and Distribution                     6
            Interstate Transmission of Natural Gas            6
            Electricity Transmission and Distribution
             Operations                                       9
          Wholesale Energy Operations and Services           10
            North American Markets                           11
            European Markets                                 12
            Other International Markets                      13
          Retail Energy Services                             16
          Other Enron Businesses                             16
          Regulation                                         17
          Revenues by Business Segment                       24
          Current Executive Officers of the Registrant       26

Item 2.  Properties                                          28
          Oil and Gas Exploration and Production Properties
            and Reserves                                     28
          Natural Gas Transmission                           31
          International Power Plants and Pipelines           32
          Electric Utility Properties                        32

Item 3.  Legal Proceedings                                   33

Item 4.  Submission of Matters to a Vote of Security Holders 35

                           PART II

Item 5.  Market for the Registrant's Common Equity
            and Related Shareholder Matters                  36

Item 6.  Selected Financial Data (Unaudited)                 37

Item 7.  Management's Discussion and Analysis of
         Financial Condition and Results of Operations       38

Item 7A. Financial Risk Management                           58

         Information Regarding Forward Looking Statements    61

Item 8.  Financial Statements and Supplementary Data         62

Item 9.  Disagreements on Accounting and Financial
         Disclosure                                          62

                          PART III

Item 10. Directors and Executive Officers of the Registrant  63

Item 11. Executive Compensation                              63

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

Item 13. Certain Relationships and Related Transactions      64

                           PART IV

Item 14. Exhibits, Financial Statement Schedules, and
         Reports on Form 8-K                                 65


<PAGE>
                           PART I
                              
                      Item 1. BUSINESS
                           GENERAL

     Enron Corp., an Oregon corporation, is an integrated
natural gas and electricity company with headquarters in
Houston, Texas.  Enron's operations are conducted through
its subsidiaries and affiliates which are principally
engaged in the exploration for and production of natural gas
and crude oil in the United States and internationally; the
transportation of natural gas through pipelines to markets
throughout the United States; the generation and
transmission of electricity to markets in the northwestern
United States; the marketing of natural gas, electricity and
other commodities and related risk management and finance
services worldwide; and the development, construction and
operation of power plants, pipelines and other energy
related assets worldwide.  As of December 31, 1998, Enron
employed approximately 17,800 persons.

     As used herein, unless the context indicates otherwise,
"Enron" refers to Enron Corp. and its subsidiaries and
affiliates.

                      BUSINESS SEGMENTS

     Enron's operations are classified into the following
business segments:

     Exploration and Production - Natural gas and crude oil
exploration and production primarily in the United States,
Canada, Trinidad and India.

     Transportation and Distribution - Regulated industries;
interstate transmission of natural gas; management and
operation of pipelines; electric utility operations.

     Wholesale Energy Operations and Services - Energy
commodity sales and services, risk management products and
financial services to wholesale customers; development,
acquisition and operation of power plants, natural gas
pipelines and other energy related assets.

     Retail Energy Services - Sale of natural gas and
electricity directly to end-use customers, particularly in
the commercial and industrial sectors, including the
outsourcing of energy-related activities.

     Corporate and Other - Includes operation of
telecommunications and renewable energy businesses and clean
fuels plants, as well as Enron's investment in crude oil
transportation and water activities.

     For financial information by business segment for the
fiscal years ended December 31, 1996 through December 31,
1998, please see Note 17 to the Consolidated Financial
Statements on page F-35.

                   EXPLORATION AND PRODUCTION

     Enron's natural gas and crude oil exploration and
production operations are conducted by Enron Oil & Gas
Company ("EOG").  Enron currently owns a majority of the
outstanding common stock of EOG.  As previously reported in
December 1998, Enron received an unsolicited indication of
interest from a third party with respect to exploring a
possible transaction pursuant to which the third party would
acquire Enron's shares of EOG common stock and offer to
acquire the remaining shares of outstanding EOG common
stock.  Although Enron currently intends to actively explore
alternative transactions for its EOG common stock including
the unsolicited indication of interest, there can be no
assurance that any such transaction will be pursued or, if
pursued, will be consummated.

     EOG is an independent (non-integrated) oil and gas
company engaged in the exploration for, and development,
production and marketing of, natural gas and crude oil
primarily in major producing basins in the United States, as
well as in Canada, Trinidad and India and, to a lesser
extent, selected other international areas.  At December 31,
1998, EOG's estimated net proved natural gas reserves were
5,229 billion cubic feet ("Bcf") (including 1,180 Bcf of
proved undeveloped methane reserves in the Big Piney deep
Paleozoic formations in Wyoming), and estimated net proved
crude oil, condensate and natural gas liquids reserves were
105 million barrels, and at such date, approximately 53% of
EOG's reserves (on a natural gas equivalent basis) were
located in the United States, 18% in Trinidad, 18% in India,
9% in Canada and 2% in China.

     EOG's eight principal United States producing areas are
the Big Piney area in Wyoming, the South Texas area, the
East Texas area, the offshore Gulf of Mexico area, the
Canyon/Strawn Trend area in West Texas, the Sand Tank and
Pitchfork Ranch areas in New Mexico, and the Vernal area in
Utah.  Properties in these areas comprised approximately 81%
of EOG's United States reserves (on a natural gas equivalent
basis) and 82% of EOG's United States net natural gas
deliverability as of December 31, 1998.  These properties
are substantially all operated by EOG.  EOG's other United
States natural gas and crude oil producing properties are
located primarily in other areas of Texas, Utah, New Mexico,
Oklahoma, California, Mississippi and Kansas.  At December
31, 1998, 93% of EOG's proved United States reserves,
including the reserves in the Big Piney deep Paleozoic
formations (on a natural gas equivalent basis) were natural
gas and 7% were crude oil, condensate and natural gas
liquids.

     EOG is also engaged in the exploration for and the
development, production and marketing of natural gas,
natural gas liquids and crude oil in western Canada,
principally in the provinces of Alberta, Saskatchewan and
Manitoba.  EOG conducts its Canadian operations from offices
in Calgary, Alberta.  At December 31, 1998, Canadian natural
gas deliverability net to EOG was approximately 120 million
cubic feet ("MMcf") per day, and EOG held approximately
555,000 net undeveloped acres in Canada.

     EOG also has producing operations offshore Trinidad and
India and is evaluating and conducting exploration and
development in selected other international areas.  In 
November 1992, EOG was awarded a 95% working interest 
concession and operatorship in the South East Coast Consortium
("SECC") Block offshore Trinidad, encompassing three undeveloped 
fields, previously held by three government-owned energy companies.  
The Kiskadee field has been developed, the Ibis field is 
under development, and the Oilbird field is anticipated to be 
developed over the next several years.  Existing surplus 
processing and transportation capacity at the Pelican field 
facilities owned and operated by Trinidad and Tobago 
government-owned companies is being used to process and 
transport the production.  Natural gas is being sold into 
the local market under a take-or-pay agreement with the 
National Gas Company of Trinidad and Tobago.  In 1998, 
deliveries net to EOG averaged 139 MMcf per day of
natural gas and three thousand barrels ("MBbl") per day 
of crude oil and condensate.  At December 31, 1998, 
EOG held approximately 144,000 net undeveloped acres in Trinidad.

     In 1995, EOG was awarded the right to develop the
modified U(a) block adjacent to the SECC Block, and a
production sharing contract with the Government of Trinidad
and Tobago was signed in 1996.  The contract committed EOG
to the acquisition of 3-D seismic data and to drilling three
wells.  The first well was drilled in 1998 and was
successful.

     In December 1994, EOG signed agreements covering profit
sharing, joint operations and product sales and representing
a 30% working interest in, and was designated operator of,
the Tapti, Panna and Mukta Blocks located offshore the
western coast of India.  The blocks were previously operated
by the Indian national oil company, Oil & Natural Gas
Corporation Limited, which retained a 40% working interest.
The 363,000 acre Tapti Block contains two major proved
natural gas accumulations delineated by 22 expendable
exploration wells that have been plugged.  EOG has
implemented an initial development plan for the Tapti Block
accumulations, and production began in 1997.  At December
31, 1998, production, net to EOG, from the Tapti Block was
50 MMcf per day.  The 106,000 acre Panna Block and the
192,000 acre Mukta Block are partially developed with 65
wells capable of producing from six production platforms
located in the Panna and Mukta fields.  The fields were
producing approximately 7.1 MBbl per day of crude oil net to
EOG as of December 31, 1998.  Natural gas sales from the
Panna field began in early 1998 and as of December 31, 1998,
production, net to EOG, was 18 MMcf per day.  EOG intends to
continue development of the fields.

     EOG was awarded exploration, exploitation and
development rights for a block offshore the eastern State of
Sucre, Venezuela in early 1996.  EOG has signed agreements
with the government of Venezuela and other participants
associated with a concession awarded in the Gulf of Paria
East.  EOG holds an initial 90% working interest in the
joint venture and acts as operator.  One exploratory well
was drilled during 1998 and encountered hydrocarbons.
Additional evaluation work is being done, and another well
is expected to be drilled in 1999.

     In August 1997, EOG signed a 30-year production sharing
contract with the China National Petroleum Corporation for
the appraisal and potential development of oil and gas
reserves within the Chuanzhong Block situated in the central
Sichuan Province.  EOG holds a 100% interest in the fields
and is the operator.  The contract provides for a two-year
evaluation period during which EOG will perform work to
improve productivity in existing wells and will drill three
new wells in the proved areas.  Further commitments, if any,
would arise from entering into the development period as
specified in the contract.

     EOG is also pursuing other opportunities in countries
where natural gas and crude oil reserves have been
identified, particularly where synergies in natural gas
transportation, processing and power generation can be
optimized with other Enron Corp. affiliated companies.  EOG
is also participating in discussions concerning the
potential for natural gas development opportunities in
Mozambique, as well as other opportunities in Trinidad,
India and other countries.

     EOG actively competes for reserve acquisitions and
exploration leases, licenses and concessions, frequently
against companies with substantially larger financial and
other resources.  EOG's ability to compete effectively for
certain reserves, leases, licenses and concessions is, in
part, dependent on EOG's exploration budget relative to its
competitors.  Competitive factors include price, contract
terms and quality of service, including pipeline connection
times and distribution efficiencies.  In addition, EOG faces
competition from other producers and suppliers, including
competition from other world-wide energy supplies, such as
natural gas from Canada.

     All of EOG's oil and gas activities are subject to the
risks normally incident to the exploration for and
development and production of natural gas and crude oil,
including blowouts, cratering and fires, each of which could
result in damage to life and property.  Offshore operations
are subject to usual marine perils, including hurricanes and
other adverse weather conditions, and governmental
regulations as well as interruption or termination by
governmental authorities based on environmental and other
considerations.  In accordance with customary industry
practices, insurance is maintained by EOG against some, but
not all, of the risks.  Losses and liabilities arising from
such events could reduce revenues and increase costs to EOG
to the extent not covered by insurance.

     EOG's overseas operations are subject to certain risks,
including expropriation of assets, risks of increases in
taxes and government royalties, renegotiation of contracts
with foreign governments, political instability, payment
delays, limits on allowable levels of production and current
exchange and repatriation losses, as well as changes in laws
and policies governing operations of overseas-based
companies generally.

     The following table sets forth certain information
regarding EOG's wellhead volumes of and average prices for
natural gas per thousand cubic feet ("Mcf"), crude oil and
condensate, and natural gas liquids per barrel ("Bbl"), and
average lease and well expenses per thousand cubic feet
equivalent ("Mcfe" - natural gas equivalents are determined
using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of
crude oil and condensate or natural gas liquids) delivered
during each of the three years in the period ended December
31, 1998:

<TABLE>
<CAPTION>
                                    Year Ended December 31,
                                   1998      1997       1996
<S>                               <C>       <C>       <C>
Volumes (per day)
     Natural Gas (MMcf)
       United States(1)              671       657       608
       Canada                        105       101        98
       Trinidad                      139       113       124
       India                          56        18         -
          Total                      971       889       830


     Crude Oil and Condensate (MBbl)
       United States                14.0      11.7       9.2
       Canada                        2.6       2.5       2.4
       Trinidad                      3.0       3.4       5.2
       India                         5.1       2.3       2.8
          Total                     24.7      19.9      19.6

     Natural Gas Liquids (MBbl)
       United States                  2.9      2.6       1.3
       Canada                         1.0      1.3       1.2
          Total                       3.9      3.9       2.5

Average Prices
     Natural Gas ($/Mcf)
       United States(2)           $ 1.93    $ 2.32    $ 2.04
       Canada                       1.40      1.43      1.15
       Trinidad                     1.06      1.05      1.00
       India                        2.41      2.79        -
          Composite                 1.78      2.07      1.78

     Crude Oil and Condensate ($/Bbl)
       United States              $12.84    $19.81    $21.88
       Canada                      11.82     17.16     18.01
       Trinidad                    12.26     18.68     19.76
       India                       12.86     20.05     20.17
          Composite                12.66     19.30     20.60

     Natural Gas Liquids ($/Bbl)
       United States              $ 8.38    $12.76    $14.67
       Canada                       5.32      8.94      9.14
          Composite                 7.56     11.54     11.99

Lease and Well Expenses ($/Mcfe)
       United States              $ 0.22    $ 0.23    $ 0.19
       Canada                       0.37      0.39      0.35
       Trinidad                     0.12      0.16      0.16
       India                        0.24      0.64      0.99
          Composite                 0.24      0.26      0.22
          

<FN>
__________________
(1)  Includes 48 MMcf per day in 1998, 1997 and 1996
     delivered under the terms of a volumetric production
     payment agreement effective October 1, 1992, as
     amended.  Delivery obligations were terminated in
     December 1998.
(2)  Includes an average equivalent wellhead value of $1.53
     per Mcf in 1998, $1.73 per Mcf in 1997 and $1.17 per
     Mcf in 1996 for the volumes described in note (1), net
     of transportation costs.
</TABLE>

               TRANSPORTATION AND DISTRIBUTION

     Enron's Transportation and Distribution business is
comprised of the company's North American interstate natural
gas transportation systems and its electricity transmission
and distribution operations in Oregon.

Interstate Transmission of Natural Gas

     Enron and its subsidiaries operate domestic interstate
natural gas pipelines extending from Texas to the Canadian
border and across the southern United States from Florida to
California.  Included in Enron's domestic interstate natural
gas pipeline operations are Northern Natural Gas Company
("Northern"), Transwestern Pipeline Company ("Transwestern")
and Florida Gas Transmission Company ("Florida Gas")
(indirectly 50% owned by Enron).  Northern, Transwestern and
Florida Gas are interstate pipelines and are subject to the
regulatory jurisdiction of the Federal Energy Regulatory
Commission (the "FERC").  Each pipeline serves customers in
a specific geographical area:  Northern, the upper Midwest;
Transwestern, principally the California market and pipeline
interconnects on the east end of the Transwestern system;
and Florida Gas, the State of Florida.  In addition, Enron
holds an interest in Northern Border Partners, L.P., which
owns a 70% interest in the Northern Border Pipeline system.
An Enron subsidiary operates the Northern Border Pipeline
system, which transports gas from Western Canada to delivery
points in the midwestern United States.

     Northern Natural Gas Company.  Through its
approximately 17,000-mile natural gas pipeline system
stretching from Texas to Michigan's Upper Peninsula,
Northern transports natural gas to points in its traditional
market area of Illinois, Iowa, Kansas, Michigan, Minnesota,
Nebraska, South Dakota and Wisconsin.  Gas is transported to
town border stations for consumption and resale by non-
affiliated gas utilities and municipalities and to other
pipeline companies and gas marketers.  Northern also
transports gas at various points outside its traditional
market area in the production areas of Colorado, Kansas, New
Mexico, Oklahoma, Texas and Wyoming for utilities, end-users
and other pipeline and marketing companies.  Northern
provides transportation and storage services to
approximately 90 utility customers and end-users in the
upper midwestern United States.  Most of Northern's revenues
are comprised of monthly demand charges that are based on
contracted capacity rather than throughput.

     In Northern's market area, natural gas is an energy
source available for traditional residential, commercial and
industrial uses.  Northern's throughput totaled 1,496
trillion British thermal units ("Tbtu") in 1998, compared to
1,593 Tbtu in 1997.  This slight decrease was due primarily
to a warmer than normal winter in Northern's service
territory in 1998.

     In 1998, Northern maintained its existing customer base
in an increasingly competitive market while initiating
expansion projects to meet increased market demand and to
increase Northern's market presence.  Northern completed the
first phase of a five-year, $113 million growth plan to
expand incremental firm capacity into Iowa, Wisconsin and
Minnesota by approximately 350 MMcf of natural gas per day.
This expansion is fully subscribed with five-year to ten-
year firm transportation contracts.  In addition, Northern
has several smaller service expansions underway which are
expected to be in service in late 1999.

     Northern also operates three natural gas storage
facilities and two liquefied natural gas storage peaking
units.  These storage facilities provide Northern the
operational capacity to balance its system on a daily basis
and assist in meeting customers' heating season system
requirements.  Northern competes with other interstate
pipelines in the transportation and storage of natural gas.
In addition, the FERC continues its efforts to introduce
more competition into the natural gas industry, having the
effect of increasing transportation and purchase options of
Northern's traditional customer base.  See "Regulation -
Natural Gas Rates and Regulations".

     Transwestern Pipeline Company.  Transwestern is an
interstate pipeline engaged in the transportation of natural
gas.  Through its approximately 2,700-mile pipeline system,
Transwestern transports natural gas from West Texas,
Oklahoma, eastern New Mexico and the San Juan Basin in
northwestern New Mexico and southern Colorado primarily to
the California market and to markets off the east end of its
system.  Transwestern has access to three significant gas
basins for its gas supply: the San Juan Basin, the Permian
Basin in West Texas and eastern New Mexico and the Anadarko
Basin in the Texas and Oklahoma Panhandles. Transwestern's
peak delivery capacity was approximately 1.6 Bcf per day in
1998.  Substantially all of Transwestern's delivery capacity
to California was held by shippers on a firm basis until
November 1, 1996, when approximately 450 MMcf per day of
firm capacity was turned back to Transwestern by a major
customer. Anticipating this turnback, Transwestern entered
into a settlement agreement with its customers whereby the
costs associated with this turnback are shared by
Transwestern and its Current Firm Customers, as defined in
the settlement agreement.  Transwestern is responsible for
70% of the risk of resubscribing the released capacity, and
Transwestern's customers have the remaining 30% of such risk
through 2001.  In addition to this cost-sharing mechanism,
Transwestern and its current firm customers also agreed to
contract rates through 2006 and agreed that Transwestern
would not be required to file a new rate case for rates to
be effective prior to November 1, 2006.

     Transwestern's mainline includes a lateral pipeline to
the San Juan Basin which allows Transwestern to access San
Juan Basin gas supplies.  Via Transwestern's San Juan
lateral pipeline, the San Juan Basin gas may be delivered to
California markets as well as markets off the east end of
Transwestern's system.  This bi-directional flow capability
enhances pipeline utilization.  Transwestern is currently
negotiating with customers to expand the system from San
Juan to California.  Since adding bi-directional capability
in 1995, Transwestern has reestablished its volumes flowing
into the previously oversupplied California market. Total
throughput volumes to California averaged approximately 889
MMcf per day in 1998, compared to 558 MMcf per day in 1997.
Transwestern has firm transportation service on the east end
of its system and transports Permian, Anadarko and San Juan
Basin supplies into Texas, Oklahoma and the midwestern
United States.  Transwestern previously made certain
modifications to its mainline system which increased the
volumes flowing from the San Juan Basin to the east end of
the Transwestern system. Transwestern transported an average
of 489 MMcf per day off the east end of its system in 1998,
as compared to 657 MMcf per day in 1997.

     Transwestern competes with several interstate pipelines
in the California market and its markets off the east end of
its system.

     Florida Gas Transmission Company.  An Enron subsidiary
owns a 50% interest in Florida Gas by virtue of its 50%
interest in Citrus Corp., which owns all of the capital
stock of Florida Gas.  Another Enron subsidiary operates the
Florida Gas pipeline.

     Florida Gas is an interstate pipeline company that
transports natural gas for third parties.  Its approximately
4,950-mile dual pipeline system extends from South Texas to
a point near Miami, Florida.  Florida Gas provides a high
degree of gas supply flexibility for its customers because
of its proximity to the Gulf of Mexico producing region and
its interconnections with other interstate pipeline systems
which provide access to virtually every major natural gas
producing region in the United States.  Florida Gas serves a
mix of customers anchored by electric utility generators.

     Florida Gas has periodically expanded its system
capacity to keep pace with the growing demand for natural
gas in Florida.  In December 1998, Florida Gas filed an
application with the FERC to expand its pipeline capacity to
meet Florida's growing electric generation load and local
distribution company and industrial demand.  The proposed
272 billion British thermal units ("BBtu") per day Phase IV
expansion is backed by 20-year firm transportation contracts
and, subject to regulatory approvals, is expected to be in
service in 2001, introducing Florida Gas to the southwest
Florida market.  Florida Gas' current firm average delivery
capacity into Florida is 1,455 BBtu per day.  Florida Gas
also owns an interest in facilities that link its system to
the Mobile Bay producing area.  Florida Gas' customers have
reserved over 99% of the existing capacity on the Florida
Gas system pursuant to firm, long-term transportation
service agreements.

     Florida Gas is the only interstate natural gas pipeline
serving peninsular Florida.  Florida Gas faces competition
from residual fuel oil in the Florida market.  A primary
advantage of the straight fixed variable rate design (a FERC
mandated rate design to allow pipelines to recover
substantially all fixed costs, a return on equity and income
taxes in the capacity reservation component of their rates)
is that Florida Gas will recover substantially all of its
fixed costs regardless of levels of usage by its customers.
See "Regulation - Natural Gas Rates and Regulations".

     Northern Border Partners, L.P.  Northern Border
Partners, L.P., a Delaware limited partnership, owns 70% of
Northern Border Pipeline Company, a Texas general
partnership ("Northern Border").  An Enron subsidiary holds
a 12.4% interest in the limited partnership and serves as
operator of the pipeline.  Northern Border owns an
approximately 1,214-mile interstate pipeline system that
transports natural gas from the Montana-Saskatchewan border
near Port of Morgan, Montana to interconnecting pipelines
and local distribution systems in the States of North
Dakota, South Dakota, Minnesota, Iowa and Illinois.
Northern Border has pipeline access to natural gas reserves
in the provinces of Alberta, British Columbia and
Saskatchewan, as well as the Williston Basin in the United
States.  The pipeline system also has access to production
of synthetic gas from the Dakota Gasification Plant in North
Dakota.  Interconnecting pipeline facilities provide
Northern Border shippers access to markets in the Midwest,
as well as other markets throughout the United States by
transportation, displacement and exchange agreements.
Therefore, Northern Border is strategically situated to
transport significant quantities of natural gas to major gas
consuming markets. Based upon existing contracts and
capacity, 100% of Northern Border's firm capacity
(approximately 2.4 Bcf of natural gas per day) is
contractually committed through October 31, 2001.  Northern
Border competes with two other interstate pipeline systems
that transport gas from Canada to the Midwest.

     In December 1998, Northern Border completed its Chicago
Project which expanded its existing system by delivering an
additional 700 MMcf of natural gas per day from Canada, and
extended the pipeline 245 miles to Chicago.  The project is
fully subscribed by over 20 shippers with 10-year minimum
transportation contracts.

     In October 1998, Northern Border filed an application
with FERC to seek approval of its "Project 2000" which seeks
to expand and extend the pipeline system into Indiana by
November 2000.  In addition to providing additional Canadian
natural gas to United States' markets, Project 2000 would
afford shippers on the extended pipeline system access to
industrial gas consumers in northern Indiana.

Electricity Transmission and Distribution Operations

     Enron's electric utility operations are conducted
through its wholly-owned subsidiary Portland General
Electric Company ("PGE").  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 approximately 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 December 31, 1998 PGE
served approximately 704,000 retail customers.

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

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

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

     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 from the
creation of public utility districts or municipal utilities
by voters.

            WHOLESALE ENERGY OPERATIONS AND SERVICES

     Enron's wholesale energy operations and services
businesses ("Enron Wholesale") operate in North America,
Europe and evolving energy markets in developing countries.
Activities in such businesses are conducted primarily by
Enron Capital & Trade Resources Corp. and Enron
International Inc.  Enron Wholesale is categorized into two
business lines: Commodity Sales and Services, and Energy
Assets and Investments.  Integrated energy-related products
and services related to these business lines are offered to
wholesale customers in varying degrees in each of Enron
Wholesale's markets.

     Commodity Sales and Services.  The commodity sales and
services operations include the purchase, sale, marketing
and delivery of natural gas, electricity, liquids and other
commodities, restructuring of existing long-term contracts
and the management of Enron's commodity portfolios.  In
addition, Enron provides risk management products and
services to energy customers that hedge movements in price
and location-based price differentials.  Enron's risk
management products and services are designed to provide
stability to customers in markets impacted by commodity
price volatility.  Also included in this business is the
management of certain operating assets that directly relate
to this business, including domestic intrastate pipelines
and storage facilities.

     Energy Assets and Investments.  Enron Wholesale's
energy assets and investments activities include investments
in debt and equity securities of oil and gas producers and
other energy intensive companies.  Additionally, Enron
Wholesale develops, constructs, operates and manages a large
portfolio of energy assets such as power plants and natural
gas pipelines.  Enron may reduce its ownership interests in
certain energy assets based on market opportunities,
allowing it to capture significant value created during the
development and construction process and to reinvest capital
into new projects.  Enron's long-term ownership interest in
each of its energy assets will be determined by various
factors, including the operating control necessary to
maximize Enron's return on investment.


     The following table presents selected statistical
information for Enron's wholesale energy operations and
services businesses.

<TABLE>
<CAPTION>
                                     Year Ended December 31,
                                      1998      1997      1996

<S>                                <C>       <C>        <C>
Physical Volumes (Bbtue/d)(a)(b)
Gas:
  United States                      7,418     7,654     6,998
  Canada                             3,486     2,263     1,406
  Europe and Other                   1,251       660       289
                                    12,155    10,577     8,693
Transport Volumes                      559       460       544
     Total Gas Volumes              12,714    11,037     9,237
Crude Oil and Liquids                3,570     1,677     1,507
Electricity(c)                      11,024     5,256     1,648
     Total Physical Volumes         27,308    17,970    12,392
      (BBtue/d)
Electricity Volumes Marketed 
 (Thousand MWh)
  United States                    401,843   191,746    60,150
  Europe and Other                     529       100         -
     Total                         402,372   191,846    60,150

Financial Settlements (Notional)    75,266    49,082    35,259
         (Bbtue/d)

<FN>
 (a) Billion British thermal units equivalent per day.
 (b) Includes third-party transactions by Enron Energy Services.
 (c) Represents Electricity Volumes Marketed, converted to Bbtue/d.
</TABLE>

North American Markets

     Enron markets natural gas, electricity and other energy
commodities in North America and provides risk management
products and financial services to producers and end-users
of energy commodities.  Enron offers a broad range of
services including risk management and financing expertise
through a variety of products including forward contracts,
swap agreements and other contractual commitments.
Customers include independent oil and gas producers, energy-
intensive industrials, public and investor-owned utility
power companies, small independent power producers and local
distribution companies.

     In 1998, there was a 52% increase in Enron's physical
wholesale commodity sales over 1997 with volumes for all
commodities totaling more than 27 trillion British thermal
units equivalent ("Tbtue") per day.  This included a more
than doubling of the electricity volumes from 191.8 million
megawatt hours in 1997 to over 400 million megawatt hours in
1998.  In addition, financial settlements totaled 75.3 Tbtue
per day.  Enron's strategy is to enhance the scale, scope,
flexibility and speed of its North American energy network
through building and acquiring strategically placed
generation assets and forming alliances with customers.

     Enron's intrastate pipelines include Houston Pipe Line
Company ("HPL") and Louisiana Resources Company.  HPL owns a
5,269-mile pipeline in Texas which interconnects with
Northern, Transwestern, Florida Gas and numerous other
interstate and intrastate pipelines.  HPL's intrastate
natural gas transportation and storage services are subject
to seasonal variation because many of its customers have
weather-sensitive natural gas requirements.  The Railroad
Commission of Texas has jurisdiction over intrastate gas
pipeline rates, operations and transactions in Texas.  See
"Regulation--Natural Gas Rates and Regulations."  Louisiana
Resources Company is a 540-mile intrastate pipeline which
spans the state of Louisiana and serves the industrial
complex along the Mississippi River from Baton Rouge to New
Orleans.  The pipeline interconnects with the Henry Hub,
which is the NYMEX physical settlement location, and has
numerous interconnections with both interstate and
intrastate pipelines.

     Enron's Napoleonville natural gas storage facility
located in Louisiana, which accesses the Louisiana Resources
Company pipeline, provides approximately 4 Bcf of working
capacity.  This facility enhances the benefits of Louisiana
Resources Company by improving Enron's ability to meet the
firm requirements of industrial markets in Louisiana, and
provides the swing and peak capability required by local
distribution companies and electric utilities along the
Eastern seaboard.  Enron's Bammel natural gas storage
facility located near Houston provides approximately 58
Bcf of working capacity.  This facility has the flexibility
to deliver gas to the Texas market, or to the East Coast or
the midwestern United States.  In 1998, Enron installed new
compression units to increase its withdrawal and injection
capabilities.

European Markets

     As the energy markets liberalize across Europe, Enron's
strategy is to build a presence early in each key market in
order to create an integrated pan European energy operation.
Energy service capabilities are in place in Europe similar
to those established in North America, such as providing
reliable delivery of physical commodities and risk
management and financing services. At the end of 1998, Enron
employed more than 700 people in trading, marketing and
power generation across continental Europe including the
United Kingdom, Norway, Germany, Turkey, Poland, Russia and
Italy.

     In contrast to the early stages of energy deregulation
in North America where there was generally adequate
infrastructure in place to produce and transport gas and
power, the international energy markets have generally
lacked adequate energy infrastructure, providing Enron
opportunities to develop, construct and operate large energy
projects.  In December 1998, Enron acquired the Teesside
Utilities and Services business in northeast England, whose
assets include a 154-megawatt power plant and distribution
systems for gas, power, steam and water.  Enron's asset
position in the United Kingdom also includes a second gas-
fired combined cycle 790-megawatt plant sited at Sutton
Bridge currently under construction and scheduled for
commercial operation early in 1999.  This investment
provides opportunities and value to both Enron and the
plant's major customer from the flexibility to convert from
natural gas to power as determined by the market price of
each commodity.

     In 1996, Enron opened an office in Oslo to access the
power trading opportunities available in the Nordic region,
the most open market for power trading in the Europe region.
Enron provides power risk management services to regional
municipalities, utilities and large industrials.  Enron was
appointed market maker for all base load electricity trades
on the Nord Pool Nordic Power Exchange.  During 1998,
Enron's power volumes in the United Kingdom and Nordic
countries totaled 38 million megawatt hours.

     Enron has also invested in continental Europe where
there is a need for energy infrastructure and an interest
from large industrials to restructure their energy supply
contracts and to benefit from more liberalized gas and power
markets.  Enron made its first power trade in continental
Europe in 1998, and these volumes are continuing to
increase. Enron owns a gas-fired power plant of
approximately 125 megawatts, owned jointly with the second
largest regional utility in Germany.  Enron has a 97.5%
interest in a natural gas fired, 116-megawatt electric, 70-
megawatt thermal power plant to be located in Nowa Sarzyna,
Poland.  Enron is the turnkey contractor and will be the
operator of the plant.  Twenty-year power purchase
agreements have been signed with the Polish power grid
company for electricity and with a state-owned chemical
company and the City of Nowa Sarzyna for steam.  Financing
was completed and construction began in early 1998, with
commercial operation expected in the fourth quarter of 1999.
Enron is pursuing other opportunities such as joint ventures
with national utilities or other energy companies in the
development, operation or construction of power generation
facilities across Europe, including Spain, Croatia and
Italy.

Other International Markets

     In many markets outside of North America and Europe, a
shortage of energy infrastructure exists, providing Enron
significant opportunities to develop, construct, promote and
operate natural gas pipeline, power plants and other energy
infrastructure.  In these markets, Enron's strategy is to
facilitate completion of vital energy assets and investments
which will connect areas of energy supply to areas where
energy is consumed.  By creating energy networks, Enron
seeks to provide reliable delivery of physical energy
commodities and develop risk management and financing
services to wholesale customers in key international
regions.  Enron has developed regional wholesale energy
businesses around its international asset base in both South
America and in India and continues to pursue a range of
energy infrastructure opportunities outside of North America
and Europe.

     Enron's energy infrastructure projects are, to varying
degrees, subject to all the risks associated with project
development, construction and financing in foreign
countries, including without limitation, the receipt of
permits and consents, the availability of project financing
on acceptable terms, expropriation of assets, renegotiation
of contracts with foreign governments and political
instability, as well as changes in laws and policies
governing operations of foreign-based businesses generally.

     South America

     In South America, Enron owns and operates several
investments which collectively comprise the asset base for
its integrated business strategy.  Enron acquired its
initial interest in Transportadora de Gas del Sur ("TGS") in
1992, when the state privatized its natural gas pipeline
systems.  The 4,104-mile pipeline system has a capacity of
approximately 1.9 Bcf per day and primarily serves four
distribution companies in the greater Buenos Aries area
under long-term, firm transportation contracts.

     In 1997, Enron acquired a 25% interest in Transredes
Transporte de Hidrocarburos S.A. ("Transredes"), a 3,093-
mile system of natural gas, crude oil and products pipelines
located in Bolivia and connecting Bolivian oil and gas
reserves to major markets in Bolivia.  Enron is upgrading
Transredes' existing pipeline operations and increasing the
capacity of the pipeline system to 1.3 Bcf per day to supply
market needs primarily in eastern Brazil.

     Enron is developing, along with Petrobras, the national
oil and gas company of Brazil, and others, a pipeline which
will connect with Transredes in Bolivia and transport
natural gas to markets in Brazil.  The pipeline project
includes an approximately 1,864-mile natural gas pipeline
from Santa Cruz, Bolivia to Porto Alegre, Brazil.  Enron
currently owns (including through its ownership interest in
Transredes) 29.75% of the Bolivian segment of the pipeline
and 7% of the Brazilian segment of the pipeline.  Commercial
operation of the first phase of the pipeline is expected in
1999.

     Enron is developing a 480-megawatt combined-cycle power
plant at Cuiaba in the State of Mato Grosso in western
Brazil to feed power into the Brazilian energy grid in
Cuiaba, at a strategic delivery point having few existing
alternate generation sources.  Construction is underway on
Phase I of the project (150 megawatts), with commercial
operations expected in early 1999. Commercial operations of
Phase II (additional 150 megawatts) and Phase III
(additional 180 megawatts) are expected to commence in 2000.
As an additional part of this project, Enron is developing a
385-mile, 18-inch natural gas pipeline connecting to the
Bolivia to Brazil pipeline in Bolivia.  Including its
ownership interest through Transredes, Enron owns 65.625% of
the power plant, 50% of the Brazilian segment of the
pipeline and 20% of the Bolivian segment of the pipeline.

     In 1997, Enron acquired interests in the Rio de Janeiro
municipal gas distribution company, the gas distribution
company of the State of Rio de Janeiro and natural gas
distribution systems in seven other Brazilian states.  These
systems encompass an area with a population of approximately
55 million people.  Through these ownership interests, Enron
has long-term franchises for gas distribution in the largest
gas consuming regions in Brazil.

     In 1998, Enron acquired an interest in Elektro -
Eletricidades e Servicos S.A. ("Elektro").  Elektro has a
51,000-mile transmission system for the distribution of
electricity to approximately 1.5 million consumers
throughout 228 municipalities in the State of Sao Paulo, and
a number of other municipalities in the State of Mato Grosso
do Sul, Brazil.

     India

     In India, Enron's strategy is to deliver natural gas to
the west coast of India to fuel Enron's own gas-fired power
plants as well as to deliver natural gas to the industrial
regions further north in India and to new power plants
expected to be constructed in southern India.

     In connection with a Power Purchase Agreement between
Dabhol Power Company, Enron's 50%-owned subsidiary, and the
Maharashtra State Electricity Board (the "MSEB"), Dabhol
Power Company is constructing Phase I of an electricity
generating power plant south of Mumbai, State of
Maharashtra, India.  The power plant will have an initial
capacity of 740 megawatts (or 826 megawatts gross) (Phase
I), which is expected to begin commercial operations in
early 1999.  Enron will be the fuel manager and operator of
the plant, which will provide electricity for the growing
Maharashtra State economy.

     Enron is currently developing Phase II of the Dabhol
power project, a 1,624-megawatt combined-cycle power plant
to be fueled by natural gas.  A 20-year power purchase
agreement has been signed with the MSEB.  Financing of Phase
II is targeted for early 1999, with commercial operations
expected to commence in 2001.  Phase II will include
construction of a liquefied natural gas (LNG) terminal and
harbor, which will be capable of handling LNG to fuel both
the Dabhol power projects and for additional natural gas
demand in India.

     Other

     As a result of its development and construction
activities, Enron owns or operates various other energy
assets and investments, including the following:

     Enron has a 50% interest in an approximately 110-
megawatt fuel-oil-fired diesel engine power plant mounted on
two movable barges at Puerto Quetzal on Guatemala's Pacific
Coast.  The U.S. flagged vessels went into commercial
operation in February 1993, and sell all of their power
output under a long-term contract to a large Guatemalan
electric utility, a majority interest in which is owned by
Guatemala's national electric utility.

     Enron currently has interests in two power plants in
the Philippines.  The Batangas power project, owned 100% by
Enron, is an approximately 110-megawatt fuel-oil-fired
diesel engine plant located at Pinamucan, Batangas, on Luzon
Island, which began commercial operation in July 1993.  The
Subic Bay power project, owned 50% by Enron, is an
approximately 116-megawatt fuel-oil-fired diesel engine
plant located at the Subic Bay Freeport complex on Luzon
Island, which began commercial operation in February 1994.
Both projects were developed by Enron and sell power to the
National Power Corporation of the Philippines.

     Enron operates a 185-megawatt barge-mounted combined-
cycle power plant at Puerto Plata on the north coast of the
Dominican Republic.  The plant began operation in January
1996.  Power is sold pursuant to a 19-year power purchase
agreement with the Dominican Republic government utility.

     Enron has a 50% interest in an approximately 357-mile
natural gas pipeline which runs from the northern coast of
Colombia to the central region of the country.  Ecopetrol,
the state-owned oil company of Colombia, is the sole
customer for the transportation services and has a 15-year
contractual commitment to pay for all of the initial
capacity.

     Enron has a 100% interest in a 152-megawatt diesel
combined-cycle power plant on Hainan Island, an economic
free trade zone off the southeastern coast of China.  The
independent power project is the first such project
developed by a U.S. company in China.  An Enron affiliate is
operator and fuel manager.

     Enron has a 50% interest in an 80-megawatt baseload
diesel power plant located in Piti, Guam.  The project
includes a 20-year power purchase agreement with the Guam
Power Authority, an agency of the Guam government.
Operations commenced in early 1999.

     Enron has an interest in a 507-megawatt combined-cycle
power plant, including a liquefied natural gas terminal and
desalination facility, under construction in Penuelas,
Puerto Rico.  Enron is the turnkey contractor and will
operate the project.  A 22-year power purchase agreement has
been signed with the Puerto Rico Electric Power Authority.
Construction commenced in 1997, with commercial operation
anticipated in late 1999.

     In addition to the projects referenced above, Enron is
involved in projects in varying stages of development in
Europe, Mozambique, Qatar, China, Egypt and Saudi Arabia,
and is pursuing projects elsewhere.

     Certain of Enron's operations in the Caribbean area are
conducted through Enron Americas, Inc. and its subsidiary
companies.  Enron Americas' subsidiary Industrias Ventane,
organized in 1953, operates the leading natural gas liquids
transportation and distribution business in Venezuela.
Enron has a natural gas distribution system in Puerto Rico,
and liquid fuels businesses in both Puerto Rico and Jamaica.

                   RETAIL ENERGY SERVICES

     Enron Energy Services Operations, Inc. ("Energy
Services") is a nationwide provider of energy outsource
products and services to business customers.  This includes
sales of natural gas, electricity and energy management
services directly to commercial and industrial customers, as
well as investments in related businesses.  Energy Services
provides end-users with a broad range of energy products and
services at competitive prices.  These products and services
include energy tariff and information management, demand-
side services and financing.  In deregulated markets such as
California, products can include electricity and natural gas
and related metering and billing.

     Energy Services' products and services help commercial
and industrial businesses understand how they can maximize
total energy savings while meeting their operational needs.
With a focus on total energy savings and nationwide
commodity, services and finance capabilities, Energy
Services provides outsourcing and other innovative programs
not only to supply electricity and natural gas to
businesses, but also to manage unregulated energy assets to
reduce their energy consumption, delivery and billing costs,
to eliminate inefficiencies of decentralized systems and to
minimize the risk of energy prices and operations to the
customer.
                                                           
                   OTHER ENRON BUSINESSES

Water

     In January 1998, Enron formed Azurix Corp. to pursue
opportunities in the global water business.  As a key step
in establishing this new business, Azurix Europe, an
indirect, wholly-owned subsidiary of Azurix Corp., acquired
all of the outstanding ordinary share capital of Wessex
Water Plc ("Wessex"), a water and wastewater services
company based in southwestern England.  In December 1998, as
part of restructuring the financing for the Wessex
acquisition, Enron became a 50% indirect owner of Azurix
Corp.  Azurix is engaged in the business of acquiring,
owning, operating and managing water and wastewater assets,
providing water and wastewater related services and
developing and managing water resources.

Communications

     Enron is building a long-haul fiber-optic network on
strategic routes throughout the United States to create the
nation's first Pure IPsm (Internet Protocol) backbone known
as the Enron Intelligent Network (EIN).  The EIN, which is
enabled with intelligent messaging software, enhances the
company's existing national fiber-optic network to bring to
market a reliable, bandwidth-on-demand platform for
delivering data, applications and streaming rich media to
the desktop.  Enron's strategy is based on a business model
that offers immediate national reach while minimizing
capital deployed through strategic alliances with industry
technology leaders whose presence, customer access, market
share, and content enable Enron to efficiently enter this
new, emerging marketplace.

Crude Oil Transportation Services

     EOTT Energy Partners, L.P. ("EOTT"), a Delaware limited
partnership, is engaged in the purchasing, gathering,
transporting, trading, storage and resale of crude oil and
refined petroleum products, and related activities.  EOTT
Energy Corp. (a wholly-owned subsidiary of Enron) serves as
the general partner of EOTT.  Enron owns a minority interest
in EOTT.  Through its North American crude oil gathering and
marketing operations, EOTT purchases crude oil produced from
approximately 40,000 leases in 18 states and is a purchaser
of lease crude oil in Canada.  EOTT provides transportation
and trading services for third party purchasers of crude
oil.  EOTT is in competition with major oil companies and a
number of smaller entities.


                           REGULATION

General

     Enron's interstate natural gas pipeline companies are
subject to the regulatory jurisdiction of the FERC under the
Natural Gas Act ("NGA") with respect to rates, accounts and
records, the addition of facilities, the extension of
services in some cases, the abandonment of services and
facilities, the curtailment of gas deliveries and other
matters.  Enron's intrastate pipeline companies are subject
to state and some federal regulation.  Enron's importation
of natural gas from Canada is subject to approval by the
Office of Fossil Energy of the Department of Energy ("DOE").
Certain activities of Enron are subject to the Natural Gas
Policy Act of 1978 ("NGPA").  Enron's pipelines which carry
natural gas liquids and refined petroleum products are
subject to the regulatory jurisdiction of the FERC under the
Interstate Commerce Act as to rates and conditions of
service.

     Enron's power marketing companies are subject to the
FERC's regulatory jurisdiction under the Federal Power Act
("FPA") with respect to rates, terms and conditions of
service and certain reporting requirements.  Certain of the
power marketing companies' exports of electricity are
subject to approval by the DOE.  Enron's affiliates involved
in cogeneration and independent power production are subject
to regulation by the FERC under the Public Utility
Regulatory Policies Act ("PURPA") and the FPA with respect
to rates, the procurement and provision of certain services
and operating standards.

     The regulatory structure that has historically applied
to the natural gas and electric industry is in transition.
Legislative and regulatory initiatives, at both federal and
state levels, are designed to supplement regulation with
increasing competition.  Legislation to restructure the
electric industry is under active consideration on both the
federal and state levels.  Proposed federal legislation
would make the electric industry more competitive by
providing retail electric customers with the right to choose
their power suppliers.  Modifications to PURPA and the
Public Utility Holding Company Act of 1935 ("PUHCA") have
also been proposed.  In addition, new technology and
interest in self-generation and cogeneration have provided
opportunities for alternative sources and supplies of
energy.  Retention of existing customers and potential
growth of Enron's customer base will depend, in part, upon
the ability of Enron to respond to new customer expectations
and changing economic and regulatory conditions.

     Domestic legislation affecting the oil and gas industry
is under constant review for amendment or expansion.  Also,
numerous departments and agencies, both federal and state,
are authorized by statute to issue and have issued rules and
regulations which, among other things, require permits for
the drilling of wells, regulate the spacing of wells,
prevent the waste of natural gas and crude oil resources
through proration, require drilling bonds and regulate
environmental and safety matters.  The regulatory burden on
the oil and gas industry increases its cost of doing
business and, consequently, affects its ability to compete
and profitability.

     A substantial portion of EOG's oil and gas leases in
the Big Piney area and in the Gulf of Mexico, as well as
some in other areas, are granted by the federal government
and administered by the Bureau of Land Management (the
"BLM") and the Minerals Management Service (the "MMS")
federal agencies.  Operations conducted by EOG on federal
oil and gas leases must comply with numerous statutory and
regulatory restrictions.  Certain operations must be
conducted pursuant to appropriate permits issued by the BLM
and the MMS.

     Various federal, state and local laws and regulations
covering the discharge of materials into the environment, or
otherwise relating to the protection of the environment, may
affect Enron's operations and costs through their effect on
oil and gas exploration, development and production
operations as well as their effect on the construction,
operation and maintenance of pipeline and terminaling
facilities.  It is not anticipated that Enron will be
required in the near future to expend amounts that are
material in relation to its total capital expenditures
program by reason of environmental laws and regulations, but
inasmuch as such laws and regulations are frequently
changed, Enron is unable to predict the ultimate cost of
compliance.

     Enron's international operations are subject to the
jurisdiction of numerous governmental agencies in the
countries in which its projects are located, with respect to
environmental and other regulatory matters.  Generally, many
of the countries in which Enron does and will do business
have recently developed or are in the process of developing
new regulatory and legal structures to accommodate private
and foreign-owned businesses.  These regulatory and legal
structures and their interpretation and application by
administrative agencies are relatively new and sometimes
limited.  Many detailed rules and procedures are yet to be
issued.  The interpretation of existing rules can also be
expected to evolve over time.  Although Enron believes that
its operations are in compliance in all material respects
with all applicable environmental laws and regulations in
the applicable foreign jurisdictions, Enron also believes
that the operations of its projects eventually may be
required to meet standards that are comparable in many
respects to those in effect in the United States and in
countries within the European Community.  In addition, as
Enron acquires additional projects in various countries, it
will be affected by the environmental and other regulatory
restrictions of such countries.

Natural Gas Rates and Regulations

     Northern, Transwestern, Florida Gas and Northern Border
are "natural gas companies" under the NGA and, as such, are
subject to the jurisdiction of the FERC.  The FERC has
jurisdiction over, among other things, the construction and
operation of pipeline and related facilities used in the
transportation, storage and sale of natural gas in
interstate commerce, including the extension, expansion or
abandonment of such facilities.  The FERC also has
jurisdiction over the rates and charges for the
transportation of natural gas in interstate commerce and the
sale by a natural gas company of natural gas in interstate
commerce for resale.  Northern, Transwestern, Florida Gas
and Northern Border hold the required certificates of public
convenience and necessity issued by the FERC authorizing
them to construct and operate all of their pipelines,
facilities and properties for which certificates are
required in order to transport and sell natural gas for
resale in interstate commerce.

     As necessary, Northern, Transwestern, Florida Gas and
Northern Border file applications with the FERC for changes
in their rates and charges designed to allow them to recover
substantially all their costs of providing service to
transportation customers, including a reasonable rate of
return.  These rates are normally allowed to become
effective after a suspension period, and in certain cases
are subject to refund under applicable law, until such time
as the FERC issues an order on the allowable level of rates.

     Since 1985, the FERC has made natural gas
transportation more accessible to gas buyers and sellers on
an open and non-discriminatory basis.  These efforts have
significantly altered the marketing and pricing of natural
gas.  The FERC's Order No. 636, issued in April 1992,
mandated a fundamental restructuring of interstate pipeline
sales and transportation services.  Order No. 636 required
interstate natural gas pipelines to "unbundle" or segregate
the sales, transportation, storage, and other components of
their existing sales service, and to separately state the
rates for each unbundled service.  Order No. 636 also
required interstate pipelines to assign capacity rights they
had on upstream pipelines to such pipelines' former sales
customers and provided for the recovery by interstate
pipelines of costs associated with the transition from
providing bundled sales services to providing unbundled
transportation and storage services.  The purpose of Order
No. 636 was to further enhance competition in the natural
gas industry by assuring the comparability of pipeline sales
service and services offered by a pipelines' competitors.  A
key effect of Order No. 636 and its progeny has been to
substantially eliminate merchant sales by pipelines like
Northern, Transwestern and Florida Gas.

     The series of 636 orders mandated a rate design, known
as straight fixed variable, which is designed to allow
pipelines to recover substantially all fixed costs, a return
on equity and income taxes in the capacity reservation
component of their rates.  Northern, Transwestern and
Florida Gas have implemented the service restructuring
required by such orders by unbundling their sales service,
offering a limited market based merchant service and
establishing a straight fixed variable rate design to
recover all fixed costs, including return on equity, in the
demand component of their rates.

     Enron believes that, overall, Order No. 636 has had a
positive impact on Enron and the natural gas industry as a
whole.  The structural changes mandated by Order No. 636
have resulted in a more competitive industry.  The straight
fixed variable rate design included in Order No. 636 allows
pipelines to recover in the demand component of their rates
all fixed costs, including income taxes and return on
equity, allocated to firm customers.  Since a pipeline
recovers demand costs regardless of whether gas is ever
transported, the straight fixed variable rate design has
reduced the volatility of the revenue stream to pipelines.

     Additional proposals and proceedings that might affect
the natural gas industry are pending before Congress, the
FERC and the courts.  Enron cannot predict when or whether
any such proposals or proceedings may become effective.

     The rates at which natural gas is sold in Texas to gas
utilities serving customers within an incorporated area are
subject to the original jurisdiction of the Railroad
Commission of Texas.  The rates set by city councils or
commissions for gas sold within their jurisdiction may be
appealed to the Railroad Commission.  Regulation of
intrastate gas sales and transportation by the Railroad
Commission is governed by certain provisions of the Texas
Gas Utility Regulatory Act of 1983.  The Railroad Commission
also regulates production activities and to some degree the
operation of affiliated special marketing programs.

Electric Industry Regulation

     Historically, the electric industry has been subject to
comprehensive regulation at the federal and state levels.
The FERC regulated sales of electric power at wholesale and
the transmission of electric energy in interstate commerce
pursuant to the FPA.  The FERC subjected public utilities
under the FPA to rate and tariff regulation, accounting and
reporting requirements, as well as oversight of mergers and
acquisitions, securities issuances and dispositions of
facilities.  States or local authorities have historically
regulated the distribution and retail sale of electricity,
as well as the construction of generating facilities.

     Enacted in 1978, PURPA created opportunities for
independent power producers, including cogenerators.  If a
generating project obtained the status of a "Qualifying
Facility," it was exempted by PURPA from most provisions of
the FPA and certain state laws relating to securities, rate
and financial regulation.  PURPA also required electric
utilities (i) to purchase electricity generated by
Qualifying Facilities at a price based on the utility's
avoided cost of purchasing electricity or generating
electricity itself, and (ii) to sell supplementary, back-up,
maintenance and interruptible power to Qualifying Facilities
on a just and reasonable and non-discriminatory basis.

     PUHCA subjects certain entities that directly or
indirectly own, control or hold the power to vote 10% of the
outstanding voting securities of a "public utility company"
or a company which is a "holding company" of a public
utility company to registration requirements of the
Securities and Exchange Commission ("SEC") and regulation
under PUHCA, unless the entity is eligible for an exemption
or has been granted an SEC order declaring the entity not to
be a holding company.  Affiliates, or direct or indirect
holders of 5% of the voting securities of such companies,
are also subject to regulation under PUHCA unless so
eligible for an exemption or SEC order.  PUHCA requires
registration for a holding company of a public utility
company, and requires a public utility holding company to
limit its operations to a single integrated utility system
and to divest any other operations not functionally related
to the operation of the utility system.  A public utility
company which is a subsidiary of a registered holding
company under PUHCA is subject to financial and
organizational regulation, including SEC approval of its
financing transactions.

     The Energy Policy Act of 1992 ("EP Act") exempted from
some traditional federal utility regulation generators
selling power at wholesale in an effort to enhance
competition in the wholesale generation market.  The EP Act
also authorized FERC to require utilities to transport and
deliver or "wheel" energy for the supply of bulk power to
wholesale customers.

     Recent FERC regulatory initiatives are changing the
electric power industry.  In April 1996, FERC paved the way
for the transition to more competitive electric markets by
issuing its Order Nos. 888 and 889.  Order No. 888 required
utilities to provide third parties wholesale open access to
transmission facilities on terms comparable to those that
apply when utilities use their own systems.  Utilities were
required by the order to file open access tariffs in July
1996.  Power pools, which are associations of interconnected
electric transmission and distribution systems that have an
agreement for integrated and coordinated operations, were
directed to file their open access tariffs by the end of
1996.  These tariffs enable eligible parties to obtain
wholesale transmission service over utilities' transmission
systems.  In Order No. 888, FERC stated its intention to
permit utilities to recover legitimate, verifiable and
prudently incurred costs that are rendered uneconomic or
"stranded" as a result of customers taking advantage of
wholesale open access to meet their power needs from others.
In Order No. 889, FERC required utilities owning
transmission facilities to adopt procedures for an open
access same-time information system ("OASIS") that will make
available, on a real-time basis, pertinent information
concerning each transmission utility's services.  The order
also promulgated standards of conduct to ensure that
utilities separate their transmission functions from their
wholesale power merchant functions and to prevent the misuse
of commercially valuable information.  In March 1997 FERC
issued its orders on rehearing of Order Nos. 888 and 889.
In these orders FERC upheld the basic open access and OASIS
regulatory framework established in Order Nos. 888 and 889,
while making certain modifications to its open access and
stranded cost recovery rules.

     Congress is considering legislation to modify federal
laws affecting the electric industry.  Bills have been
introduced in the Senate and the House of Representatives
that would, among other things, provide retail electric
customers with the right to choose their power suppliers.
Modifications to PURPA and PUHCA have also been proposed.
In addition, various states have either enacted or are
considering legislation designed to deregulate the
production and sale of electricity.  Deregulation is
expected to result in a shift from cost-based rates to
market-based rates for electric energy and related services.
Although the legislation and regulatory initiatives vary,
common themes include the availability of market pricing,
retail customer choice, recovery of stranded costs, and
separation of generation assets from transmission,
distribution and other assets.  It is unclear whether or
when all power customers will obtain open access to power
supplies.  Decisions by regulatory agencies may have a
significant impact on the future economics of the power
marketing business.

     The Oregon Public Utility Commission ("OPUC"), a three-
member commission appointed by the Governor of Oregon,
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 Oregon Energy Facility Siting Counsel.


Environmental Regulations

     Enron and its subsidiaries are subject to extensive
federal, state and local laws and regulations covering the
discharge of materials into the environment, or otherwise
relating to the protection of the environment, and which
require expenditures for remediation at various operating
facilities and waste disposal sites, as well as expenditures
in connection with the construction of new facilities.
Enron believes that its operations and facilities are in
general compliance with applicable environmental
regulations.  Environmental laws and regulations have
changed substantially and rapidly over the last 20 years,
and Enron anticipates that there will be continuing changes.
The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may impact
the environment, such as emissions of pollutants, generation
and disposal of wastes and use and handling of chemical
substances.  Increasingly strict environmental restrictions
and limitations have resulted in increased operating costs
for Enron and other businesses throughout the United States,
and it is possible that the costs of compliance with
environmental laws and regulations will continue to
increase.  Enron will attempt to anticipate future
regulatory requirements that might be imposed and to plan
accordingly in order to remain in compliance with changing
environmental laws and regulations and to minimize the costs
of such compliance.

     The Comprehensive Environmental Response, Compensation
and Liability Act ("CERCLA"), also known as the "Superfund"
law, requires payments for cleanup of certain abandoned
waste disposal sites, even though such waste disposal
activities were undertaken in compliance with regulations
applicable at the time of disposal.  Under the Superfund
legislation, one party may, under certain circumstances, be
required to bear more than its proportional share of cleanup
costs at a site where it has responsibility pursuant to the
legislation, if payments cannot be obtained from other
responsible parties.  Other legislation mandates cleanup of
certain wastes at facilities that are currently being
operated.  States also have regulatory programs that can
mandate waste cleanup.  CERCLA authorizes the Environmental
Protection Agency ("EPA") and, in some cases, third parties
to take actions in response to threats to the public health
or the environment and to seek to recover from the
responsible classes of persons the costs they incur.  The
scope of financial liability under these laws involves
inherent uncertainties.  Enron has entered into consent
decrees with the EPA with respect to the cleanup of two
Superfund sites.  Enron has received requests for information
from the EPA and state agencies concerning what wastes Enron
may have sent to certain sites, and it has also received
requests for contribution from other parties with respect to
the cleanup of other sites.  However, management does not
believe that any costs incurred in connection with these
sites (either individually or in the aggregate) will have a
material impact on Enron's financial position or results of
operations.  (See Item 3, "Legal Proceedings").

     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.  State agencies or departments which have direct
jurisdiction over environmental matters include the
Environmental Quality Commission, the Oregon Department of
Environmental Quality, the Oregon Office of Energy and
Oregon Energy Facility Siting Counsel.  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.
                                                           
Water Industry Regulation

     In the United States, the rates for water and
wastewater services are generally subject to state and local
laws and regulation.  The Safe Drinking Water Act directs
the EPA to set drinking water standards for the community
water supply systems in the United States.  The Federal
Water Pollution Control Act (the "Clean Water Act")
establishes a system of standards, permits and enforcement
procedures for the discharge of pollutants from industrial
and municipal wastewater sources.  The law requires permits
for discharges from water treatment facilities and sets
treatment standards for industries and wastewater treatment
plants.  Discharge permits issued under the Clean Water Act
are subject to renewal once every five years.  The economic
aspects of the water industry in England and Wales is
principally regulated under the provisions of the Water Act
1989, the Water Industry Act 1991 (which consolidated the
Water Act 1989) and the Water Resources Act 1991.  In
general, most countries where Azurix has invested, or
intends to consider investments, have drinking water quality
and environmental laws and regulations.  Azurix intends to
invest in companies or projects that operate in material
compliance with drinking water quality and environmental
laws and regulations.  However, Azurix cannot guarantee that
due diligence performed by it in advance of investing in an
entity will identify any or all non-compliance with
environmental laws and regulations by such entities.

Other

     PGE is a 67.5% owner of the Trojan Nuclear Plant
("Trojan").  The Nuclear Regulatory Commission ("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 Oregon Energy
Facility Siting Counsel has allowed PGE to commence
decommissioning activities, which are proceeding
satisfactorily and within approved cost estimates.  PGE
received regulatory approval in 1998 to ship and dispose of
the Trojan reactor vessel as a single package, called the
Reactor Vessel and Internals Removal Project.  In 1998, PGE
applied for approval of the Independent Spent Fuel Storage
Installation Project, and expects full approval in 1999.
Equipment removal and disposal activities will also continue
in 1999.  Trojan will be subject to NRC regulation until
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.


<TABLE>
                     REVENUES BY BUSINESS SEGMENT


  The following table presents revenues for each business segment
(in millions):

<CAPTION>
                                   Year Ended December 31,
                                   1998      1997      1996

<S>                              <C>       <C>       <C> 
Exploration and Production
  Natural Gas and Other Products
     Unaffiliated                $   728   $   774   $   620
     Intersegment                    114       169       197
                                     842       943       817
  Other Revenues
     Unaffiliated                     22        15        27
     Intersegment                     20      (61)      (20)
                                      42      (46)         7

  TOTAL                              884       897       824


Transportation and Distribution
  Natural Gas and Other Products
     Unaffiliated                     16        10        11
     Intersegment                      -         -         8
                                      16        10        19
  Electricity
     Unaffiliated                  1,137       712         -
     Intersegment                      -         -         -
                                   1,137       712         -
  Transportation
     Unaffiliated                    617       639       682
     Intersegment                     11        10        15
                                     628       649       697
  Other Revenues
     Unaffiliated                     63        41         9
     Intersegment                      5         4         -
                                      68        45         9

  TOTAL                            1,849     1,416       725


Wholesale Energy Operations 
 and Services
  Natural Gas and Other Products
     Unaffiliated                 11,916    11,778    10,013
     Intersegment                    399       595       477
                                  12,315    12,373    10,490
  Electricity
     Unaffiliated                 12,714     4,376       980
     Intersegment                      -         -         -
                                  12,714     4,376       980
  Transportation
     Unaffiliated                     11        13        25
     Intersegment                      1         2         2
                                      12        15        27
  Other Revenues
     Unaffiliated                  2,579     1,177       395
     Intersegment                    105        81        12
                                   2,684     1,258       407

  TOTAL                           27,725    18,022    11,904


Retail Energy Services
  Natural Gas and Other Products
     Unaffiliated                    616       649       513
     Intersegment                      -         2        15
                                     616       651       528
  Electricity
     Unaffiliated                     84         1         -
     Intersegment                      -         -         -
                                      84         1         -
  Other Revenues
     Unaffiliated                    372        33         -
     Intersegment                      -         -         -
                                     372        33         -

  TOTAL                            1,072       685       528


Corporate and Other
  Natural Gas and Other Products
     Unaffiliated                      -         -         -
     Intersegment                    159         -         -
                                     159         -         -
  Electricity
     Unaffiliated                      3        12         -
     Intersegment                      -         -         -
                                       3        12         -
  Other Revenues
     Unaffiliated                    382        43        14
     Intersegment                    (28)        -         -
                                     354        43        14

  TOTAL                              516        55        14

Intersegment Eliminations           (786)     (802)     (706)

Total Revenues                   $31,260   $20,273   $13,289
</TABLE>


<PAGE>
        CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT


    Name and Age      Present Principal Position and Other Material
                          Positions Held During Last Five Years


Kenneth L. Lay (56)        Chairman of the Board and Chief
                           Executive Officer, Enron Corp., since
                           February 1986.

Jeffrey K. Skilling (45)   President and Chief Operating
                           Officer, Enron Corp., since January
                           1997.  Chief Executive Officer and
                           Managing Director of Enron Capital &
                           Trade Resources Corp. ("ECT") from
                           June 1995 to December 1996.  From
                           August 1990 to June 1995, Mr. Skilling
                           served ECT in a variety of executive
                           managerial positions.

Ken L. Harrison (56)       Vice Chairman, Enron Corp., since July
                           1997.  Chairman of the Board and Chief
                           Executive Officer of Portland General
                           Electric Company since 1987.

Rebecca P. Mark (44)       Vice Chairman, Enron Corp., since May
                           1998.  Chairman and Chief Executive
                           Officer, Azurix Corp., since July
                           1998.  Chairman, Enron International
                           Inc., from January 1996 until March
                           1999.  Chief Executive Officer, Enron
                           International Inc., from January 1996
                           to May 1998.  Chairman and Chief
                           Executive Officer of Enron Development
                           Corp. from July 1991 until March 1998.
                           Vice President and Chief Development
                           Officer of Enron Power Corp. from July
                           1990 to July 1991.

Mark A. Frevert (44)       President and Chief Executive Officer
                           of ECT Europe and Enron Europe Ltd.
                           since March 1997.  From 1993 to March
                           1997, Mr. Frevert served ECT in a
                           variety of executive managerial
                           positions.

Stanley C. Horton (49)     Chairman and Chief Executive
                           Officer, Enron Gas Pipeline Group,
                           since January 1997.  Co-Chairman and
                           Chief Executive Officer of Enron
                           Operations Corp. from February 1996 to
                           January 1997. President and Chief
                           Operating Officer of Enron Operations
                           Corp. from June 1993 to February 1996.
                           President of Northern Natural Gas
                           Company from June 1991 to June 1993.
                           President of Florida Gas Transmission
                           Company from 1988 to May 1991.

Lou L. Pai (51)            Chairman of the Board and Chief
                           Executive Officer of Enron Energy
                           Services since March 1997.  President
                           and Chief Operating Officer of ECT
                           from August 1995 to March 1997.  From
                           March 1993 to August 1995, Mr. Pai
                           served ECT in a variety of executive
                           managerial positions.

Kenneth D. Rice (40)       Chairman and Chief Executive Officer
                           of ECT - North America since March
                           1997.  From 1993 to March 1997, Mr.
                           Rice served ECT in a variety of
                           executive managerial positions.

Joseph W. Sutton (51)      Chief Executive Officer, Enron
                           International Inc., since May 1998.
                           President, Enron International Inc.,
                           since January 1996. President and
                           Chief Operating Officer, Enron
                           Development Corp., from May 1995 to
                           January 1996.  Vice President, Enron
                           Development Corp., from 1992 to 1995.

J. Clifford Baxter (40)    Senior Vice President, Corporate
                           Development, Enron Corp., since
                           January 1997.  Vice Chairman, ECT,
                           since February 1999.  Managing
                           Director, ECT, 1996; Vice President,
                           Corporate Development, ECT, 1995-1996;
                           Managing Director, Koch Equities,
                           1995; Director, Corporate Development,
                           ECT, 1992-1994.

Richard A. Causey (39)     Senior Vice President and Chief
                           Accounting and Information Officer,
                           Enron Corp., since January 1997.
                           Managing Director, ECT, from June 1996
                           to January 1997; Vice President, ECT,
                           from January 1992 to June 1996.

James V. Derrick, Jr.(54)  Senior Vice President and General
                           Counsel, Enron Corp., since June 1991.
                           Partner, Vinson & Elkins from January
                           1977 until June 1991.

Andrew S. Fastow (37)      Senior Vice President and Chief
                           Financial Officer since March 1998.
                           Senior Vice President, Finance, Enron
                           Corp., from January 1997 to March
                           1998.  Managing Director, Retail and
                           Treasury, ECT, from May 1995 to
                           January 1997.  Vice President, ECT,
                           from January 1993 to May 1995.
                           Account Director, ECT, from 1990 to
                           1993.



Item 2.  PROPERTIES

Oil and Gas Exploration and Production Properties and
Reserves

     Reserve Information

     For estimates of EOG's net proved reserves and proved
developed reserves of natural gas and liquids, including
crude oil, condensate and natural gas liquids, see Note 18
to the Consolidated Financial Statements.

     Estimates of proved and proved developed reserves at
December 31, 1998, 1997 and 1996 were based on studies
performed by EOG's engineering staff for reserves in the
United States, Canada, Trinidad, India and China.  Opinions
by DeGolyer and MacNaughton, independent petroleum
consultants, for the years ended December 31, 1998, 1997 and
1996 covering producing areas containing 39%, 54% and 64%,
respectively, of proved reserves (excluding deep Paleozoic
methane reserves) of EOG on a net-equivalent-cubic-feet-of-
gas basis. These opinions indicate that the estimates of proved
reserves prepared by EOG's engineering staff for the properties
reviewed by DeGolyer and MacNaughton, when compared in total
on a net-equivalent-cubic-feet-of-gas basis, do not differ
more than 5% from the estimates prepared by DeGolyer and
MacNaughton.  In addition, the deep Paleozoic methane
reserves were covered by the opinion of DeGolyer and
MacNaughton at December 31, 1995.  All reports by DeGolyer
and MacNaughton were developed utilizing geological and
engineering data provided by EOG.

     There are numerous uncertainties inherent in estimating
quantities of proved reserves and in projecting future rates
of production and timing of development expenditures,
including many factors beyond the control of the producer.
The reserve data set forth in Note 18 to the Consolidated
Financial Statements represents only estimates.  Reserve
engineering is a subjective process of estimating
underground accumulations of natural gas and liquids,
including crude oil, condensate and natural gas liquids,
that cannot be measured in an exact manner.  The accuracy of
any reserve estimate is a function of the amount and quality
of available data and of engineering and geological
interpretation and judgment.  As a result, estimates of
different engineers normally vary.  In addition, results of
drilling, testing and production subsequent to the date of
an estimate may justify revision of such estimate.
Accordingly, reserve estimates are often different from the
quantities ultimately recovered.  The meaningfulness of such
estimates is highly dependent upon the accuracy of the
assumptions upon which they were based.

     In general, the volume of production from oil and gas
properties owned by EOG declines as reserves are depleted.
Except to the extent EOG acquires additional properties
containing proved reserves or conducts successful
exploration and development activities, or both, the proved
reserves of EOG will decline as reserves are produced.
Volumes generated from future activities of EOG are
therefore highly dependent upon the level of success in
acquiring or finding additional reserves and the costs
incurred in doing so.

     EOG's estimates of reserves filed with other federal
agencies agree with the information set forth in Note 18 to
the Consolidated Financial Statements.

     Producing Oil and Gas Wells

     The following table reflects EOG's ownership at
December 31, 1998 in gas and oil wells located in Texas, the
Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming and
various other states, Canada, Trinidad, India and China.
"Net" is obtained by multiplying "Gross" by EOG's working
interests in the properties.  Gross gas and oil wells
include 255 with multiple completions.

        Productive          Productive            Total
        Gas Wells           Oil Wells       Productive Wells
     Gross      Net      Gross      Net      Gross      Net

     5,253     3,788       897       506     6,150     4,294


     Acreage

     The following table summarizes EOG's developed and
undeveloped acreage at December 31, 1998.  Excluded is
acreage in which EOG's interest is limited to owned royalty,
overriding royalty and other similar interests.

<TABLE>
<CAPTION>
                     Developed          Undeveloped                Total
                   Gross     Net        Gross      Net      Gross         Net

<S>            <C>         <C>      <C>        <C>         <C>         <C>
United States
 California       21,324    16,747    821,738    748,238     843,062     764,985
 Texas           413,305   220,075    637,850    513,807   1,051,155     733,882
 Offshore
  Gulf of Mexico 283,571   126,306    564,775    417,827     848,346     544,133
 Wyoming         153,597   116,092    324,531    251,792     478,128     367,884
 Oklahoma        188,963   104,633    122,848     87,264     311,811     191,897
 Montana         119,686     1,651    146,013    103,779     265,699     105,430
 New Mexico       71,945    35,091    106,133     64,232     178,078      99,323
 Utah             74,454    50,311     40,873     27,205     115,327      77,516
 Mississippi       5,144     5,052     43,174     42,950      48,318      48,002
 Kansas           17,339    15,489      6,747      4,009      24,086      19,498
 Colorado         20,619     1,233     30,908     13,618      51,527      14,851
 Louisiana         6,285     5,429      6,520      3,767      12,805       9,196
 Arkansas          8,522     1,319      2,457      2,010      10,979       3,329
 Other             5,247       984      1,015        795       6,262       1,779
   Total       1,390,001   700,412  2,855,582  2,281,293   4,245,583   2,981,705

Canada
 Saskatchewan    251,805   235,121    288,834    283,732     540,639     518,853
 Alberta         372,612   243,225    336,713    243,971     709,325     487,196
 Manitoba         11,743     9,954     23,730     21,966      35,473      31,920
 British Columbia    656       164      8,755      5,553       9,411       5,717
   Total Canada  636,816   488,464    658,032    555,222   1,294,848   1,043,686

Other International
 China             5,000     2,500  1,844,531    922,266   1,849,531     924,766
 Venezuela            -         -     268,413    241,572     268,413     241,572
 India            98,300    29,490    564,307    169,292     662,607     198,782
 France               -         -     168,032    168,032     168,032     168,032
 Trinidad          4,200     3,990    147,233    143,490     151,433     147,480
Total Other
  International  107,500    35,980  2,992,516  1,644,652   3,100,016   1,680,632
      Total    2,134,317 1,224,856  6,506,130  4,481,167   8,640,447   5,706,023
</TABLE>
     
     
     Drilling and Acquisition Activities

      During each of the years ended December 31, 1998, 1997
and 1996, EOG spent approximately $769 million, $693 million
and $599 million, respectively, for exploratory and
development drilling and acquisition of leases and producing
properties.  EOG drilled, participated in the drilling of or
acquired wells as set out in the table below for the periods
indicated:

<TABLE>
<CAPTION>
                                      Year Ended December 31,
                              1998             1997            1996
                          Gross    Net      Gross   Net     Gross   Net

<S>                        <C>  <C>          <C>  <C>        <C>   <C>
Development Wells Completed
   North America
     Gas                   478  402.80       467  352.90     396   325.04
     Oil                    38   34.98        94   74.85      80    57.46
     Dry                    79   62.16       101   80.01      80    68.77
        Total              595  499.94       662  507.76     556   451.27
   Outside North America
     Gas                     -     -          12    3.60      -        -
     Oil                    21    6.30         6    1.80       1     0.30
     Dry                     -     -           -       -      -        -
        Total               21    6.30        18    5.40       1     0.30
   Total Development       616  506.24       680  513.16     557   451.57

Exploratory Wells Completed
   North America
     Gas                     5    4.40         8    5.12      14    10.36
     Oil                     6    5.50         -       -       1     0.78
     Dry                    22   15.70        12    7.53      26    19.00
        Total               33   25.60        20   12.65      41    30.14
   Outside North America
     Gas                     1    1.00         -       -      -        -
     Oil                     1    0.90         -       -      -        -
     Dry                     -       -         -       -       1     0.50
        Total                2    1.90         -       -       1     0.50
   Total Exploratory        35   27.50        20   12.65      42    30.64
        Total              651  533.74       700  525.81     599   482.21
Wells in Progress           28   15.73        44   36.39      87    61.08
 at End of Period
        Total              679  549.47       744  562.20     686   543.29
Wells Acquired
       Gas                 333  317.23*      227   82.45*    350   148.20*
     Oil                     -    1.70*       48   20.50*      5     0.65
        Total              333  318.93       275  102.95     355   148.85

<FN>
*  Includes acquisition of additional interests in certain wells
   in which EOG previously held an interest.
</TABLE>

      All of EOG's drilling activities are conducted on a contract basis   
with independent drilling contractors.  EOG owns no drilling equipment.

Natural Gas Transmission

     Enron's domestic natural gas facilities include
approximately 31,000 miles of transmission lines, five
underground gas storage fields and two liquefied natural gas
storage facilities.  Enron also owns interests in pipeline and
related facilities associated with its participation and
investments in jointly-owned pipeline systems.

     Substantially all the transmission lines of Enron are
constructed on rights-of-way granted by the apparent record
owners of such property.  In many instances, lands over
which rights-of-way have been obtained are subject to prior
liens which have not been subordinated to the right-of-way
grants.  In some cases, not all of the apparent record
owners have joined in the right-of-way grants, but in
substantially all such cases, signatures of the owners of
majority interests have been obtained.  Permits have been
obtained from public authorities to cross over or under, or
to lay facilities in or along, water courses, county roads,
municipal streets and state highways, and in some instances,
such permits are revocable at the election of the grantor,
or, the pipeline may be required to move its facilities at
its own expense.  Permits have also been obtained from
railroad companies to cross over or under lands or rights-of-
way, many of which are also revocable at the grantor's
election.  Some such permits require annual or other
periodic payments.  In a few minor cases, property for
pipeline purposes was purchased in fee.

     In most cases, Enron's transmission subsidiaries have
the right of eminent domain to acquire rights-of-way and
lands necessary for their pipelines and appurtenant
facilities.

     Enron's regulator and compressor stations, clean fuel
facilities and offices are located on tracts of land owned
by it in fee or leased from others.

     Enron is of the opinion that it has generally
satisfactory title to its rights-of-way and lands used in
the conduct of its businesses, subject to liens for current
taxes, liens incident to operating agreements and minor
encumbrances, easements and restrictions which do not
materially detract from the value of such property or the
interest of Enron therein or the use of such properties in
such businesses.


International Power Plants and Pipelines

     Enron's principal international operating power plants
and pipelines and appurtenant facilities are (i) situated on
land owned by Enron (or joint ventures in which Enron has an
ownership interest) in fee or land under the control of
Enron (or such joint ventures) pursuant to valid existing
leases, licenses, easements or other agreements, or (ii) in
the case of certain power plants, barge-mounted on vessels
owned by Enron (or such joint ventures).  Power plants and
pipelines in which Enron owns an interest are set forth in
the following table:

                                                                       Enron
  Facility       Location             Fuel       Size/Capacity       Interest
                                                           
Power Plants:                                              
Puerto Quetzel   Guatemala            Gas            110 MW              50%
Batangas         Philippines          Fuel oil       110 MW             100%
Subic Bay        Philippines          Fuel oil       116 MW              50%
Bitterfeld       Germany              Gas            125 MW              50%
Puerto Plata     Dominican Republic   Fuel oil       185 MW              50%
Hainan Island    China                Diesel         152 MW             100%
Piti             Guam                 Diesel          80 MW              50%
                                                                 
Pipelines:                                                       
TGS              Argentina              -           1.9 Bcf/d;           35%
                                                  4,104 miles
Centragas        Colombia               -          110 MMcf/d;           50%
                                                    357 miles
Transredes       Bolivia                -           1.3 Bcf/d;           25%
                                                     35 MMb/d;
                                                  3,093 miles

Electric Utility 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.

     Generating facilities owned by PGE are set forth in the
following table:
                                                       
                                                      PGE Net
                                                        MW
   Facility              Location           Fuel     Capability
   Wholly Owned:
   Faraday             Estacada, OR         Hydro       44
   North Fork          Estacada, OR         Hydro       54
   Oak Grove           Three Lynx, OR       Hydro       44
   River Mill          Estacada, OR         Hydro       25
   Pelton              Madras, OR           Hydro      108
   Round Butte         Madras, OR           Hydro      300
   Bull Run            Bull Run, OR         Hydro       22
   Sullivan            West Linn, OR        Hydro       16
   Beaver              Clatskanie, OR       Gas/Oil    500
   Coyote Springs      Boardman, OR         Gas/Oil    241

                                                                 PGE
                                                               Interest
Jointly Owned:

   Boardman            Boardman, OR         Coal       348      65.8%
   Centralia           Centralia, WA        Coal        33       2.5%
   Colstrip 3 & 4      Colstrip, MT         Coal       288      20.0%
                                                     2,023

     PGE holds licenses under the Federal Power Act for its
hydroelectric generating plants.  All of its licenses expire during the
years 2001 to 2006.  The FERC requires that a notice of intent to
relicense these projects be filed approximately five years prior to
expiration of the license.  PGE filed for relicensing of the Pelton
Round Butte Project in December 1998 and is actively pursuing the
renewal of all other licenses.  The State of Oregon also has licensed
all or portions of five hydro plants.

     Following the 1993 closure of the Trojan nuclear plant, PGE was
granted a possession-only license amendment by the NRC.  In early 1996
PGE received NRC approval of its Trojan decommissioning plan.

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

Item 3.  LEGAL PROCEEDINGS
  
     Enron is a party to various claims and litigation, the significant
items of which are discussed below.  Although no assurances can be
given, Enron believes, based on its experience to date and after
considering appropriate reserves that have been established, that the
ultimate resolution of such items, individually or in the aggregate,
will not have a materially adverse impact on Enron's financial position
or its results of operations.
  
     Litigation.  In 1995, several parties (the Plaintiffs) filed suit
in Harris County District Court in Houston, Texas, against Intratex Gas
Company (Intratex), Houston Pipe Line Company and Panhandle Gas Company
(collectively, the Enron Defendants), each of which is a wholly-owned
subsidiary of Enron.  The Plaintiffs were either sellers or royalty
owners under numerous gas purchase contracts with Intratex, many of
which have terminated.  Early in 1996, the case was severed by the Court
into two matters to be tried (or otherwise resolved) separately.  In the
first matter, the Plaintiffs alleged that the Enron Defendants committed
fraud and negligent misrepresentation in connection with the "Panhandle
program," a special marketing program established in the early 1980s.
This case was tried in October 1996 and resulted in a verdict for the
Enron Defendants.  In the second matter, the Plaintiffs allege that the
Enron Defendants violated state regulatory requirements and certain gas
purchase contracts by failing to take the Plaintiffs' gas ratably with
other producers' gas at certain times between 1978 and 1988.  The court
has certified a class action with respect to ratability claims.  The
Enron Defendants deny the Plaintiffs' claims and have asserted various
affirmative defenses, including the statute of limitations.  The Enron
Defendants believe that they have strong legal and factual defenses, and
intend to vigorously contest the claims.  Although no assurances can be
given, Enron believes that the ultimate resolution of these matters will
not have a materially adverse effect on its financial position or
results of operations.

     On November 21, 1996, an explosion occurred in or around the
Humerto Vidal Building in San Juan, Puerto Rico.  The explosion resulted
in fatalities, bodily injuries and damage to the building and
surrounding property.  San Juan Gas Company, Inc. (San Juan), an Enron
subsidiary, operated a propane/air distribution system in the vicinity.
Although San Juan did not provide service to the building, the
investigation report of the National Transportation Safety Board (NTSB)
concluded that the probable cause of the incident was propane leaking
from San Juan's distribution system.  San Juan and Enron strongly
disagree with the NTSB findings.  The NTSB investigation found no path
of migration of propane from San Juan's system to the building and no
forensic evidence that propane fueled the explosion.  Enron, San Juan,
several San Juan affiliates and third parties have been named as
defendants in numerous lawsuits filed in U.S. District Court for the
district of Puerto Rico and the Commonwealth court of Puerto Rico.
These suits, which seek damages for wrongful death, personal injury,
business interruption and property damage, allege that negligence of
Enron and San Juan, among others, caused the explosion.  Enron and San
Juan are vigorously contesting the claims.  Although no assurances can
be given, Enron believes that the ultimate resolution of these matters
will not have a materially adverse effect on its financial position or
results of operations.

     Trojan Investment Recovery.  In early 1993, PGE ceased commercial
operation of Trojan.  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% of its remaining investment in Trojan.  The
1994 ruling was appealed to the Oregon Court of Appeals and stayed
pending the appeal of the OPUC's March 1995 order.  Both PGE and the
OPUC have separately appealed the April 1996 ruling, which appeals were
combined with the appeal of the November 1994 ruling at the Oregon Court
of Appeals.  On June 24, 1998, the Court of Appeals of the State of
Oregon ruled that the OPUC does not have the authority to allow PGE to
recover a rate of return on its undepreciated investment in the Trojan
generating facility.  The court upheld the OPUC's authorization of PGE's
recovery of its undepreciated investment in Trojan.

   PGE has filed a petition for review with the Oregon Supreme Court.
The OPUC has also filed such a petition for review.  In addition, on
August 26, 1998, the Utility Reform Project filed a Petition for Review
with the Oregon Supreme Court seeking review of that portion of the
Oregon Court of Appeals decision relating to PGE's recovery of its
undepreciated investment in Trojan.  Enron cannot predict the outcome of
these actions.  Additionally, due to uncertainties in the regulatory
process, management cannot predict, with certainty, what ultimate rate-
making action the OPUC will take regarding PGE's recovery of a rate of
return on its Trojan investment.  Although no assurances can be given,
Enron believes that the ultimate resolution of these matters will not
have a material adverse effect on its financial position or results of
operations.

     Environmental Matters.  Enron is subject to extensive federal,
state and local environmental laws and regulations.  These laws and
regulations require expenditures in connection with the construction of
new facilities, the operation of existing facilities and for
remediation at various operating sites.  The implementation of the
Clean Air Act Amendments is expected to result in increased operating
expenses.  These increased operating expenses are not expected to have
a materially adverse effect on Enron's financial position or results of
operations.

     The EPA has informed Enron that it is a potentially responsible
party at the Decorah Former Manufactured Gas Plant Site (the Decorah
Site) in Decorah, Iowa, pursuant to the provisions of CERCLA.  The
manufactured gas plant in Decorah ceased operations in 1951.  A
predecessor company of Enron purchased the Decorah Site in 1963.
Enron's predecessor did not operate the gas plant and sold the Decorah
Site in 1965.  The EPA alleges that hazardous substances were released
to the environment during the period in which Enron's predecessor owned
the site, and that Enron's predecessor assumed the liabilities of the
company that operated the plant.  Enron contests these allegations.  To
date, the EPA has identified no other potentially responsible parties
with respect to this site.  Enron has entered into a consent order with
the EPA by which it has agreed, although admitting no liability, to
replace affected topsoil and remove impacted subsurface soils in certain
areas of the tract where the plant was formerly located.  Enron
completed the final removal actions at the site in November 1998, and
expects to conclude all remaining site activities in the spring of 1999.
In 1998, Enron's expenses related to the Decorah Site were $300,000 as
compared with $400,000 in 1997.  Enron believes that expenses incurred
in connection with this matter will not have a materially adverse effect
on its financial position or results of operations.

     By order dated June 27, 1995, the Florida Department of
Environmental  Protection approved a remedial action plan for the Enron
Gas Processing Company Brooker Plant in Bradford County, Florida.  Soil
and groundwater at the plant site had been impacted by historical
releases of hydrocarbons from the now inactive liquids extraction
plant.  Site remedial work commenced in 1996 and is expected to
continue for several years at a total cost of approximately $5 million.

     Enron has also received from the EPA an Order issued under CERCLA
alleging that Enron and two other parties are responsible for the cost
of demolition and proper disposal of two 110-foot towers that
apparently had been used in the manufacture of carbon dioxide at a site
called the "City Bumper Site" in Cincinnati, Ohio.  The carbon dioxide
plant, according to agency documents, was in operation from 1926 to
1966.  Houston Natural Gas Corporation, a predecessor of Enron Corp.,
merged with Liquid Carbonic Industries (LCI) on January 31, 1969.
Liquid Carbonic Corporation (LCC), a subsidiary of LCI, had title to
the site.  Twenty-eight days after the merger, on February 28, 1969,
the site was sold to a third party.  In 1984, LCC was sold to an
unaffiliated party in a stock sale.  Although Enron does not admit
liability with respect to any costs at this site, it agreed to
cooperate with the EPA and other potentially responsible parties to
undertake the work contemplated by EPA's Order.  The tower demolition
and removal activities were completed in October 1998, and a final
project report has been prepared for submission to the EPA.  In 1998,
Enron's expenses related to the City Bumper Site were $600,000.  Enron
does not expect to incur material expenditures in connection with this
site.

     Enron's natural gas pipeline companies conduct soil and
groundwater remediation of a number of their facilities.  In 1998,
these expenses were $1.3 million as compared with $1.7 million in 1997.
Enron does not expect to incur material expenditures in connection with
soil and groundwater remediation.

     In addition, Enron has received requests for information from the
EPA and state environmental agencies inquiring whether Enron has
disposed of materials at other waste disposal sites.  Enron has also
received requests for contribution from other parties with respect to
the cleanup of other sites.  Enron may be required to share in the
costs of the cleanup of some of these sites.  However, based upon the
amounts claimed and the nature and volume of materials sent to sites at
which Enron has an interest, management does not believe that any
potential costs incurred in connection with these notices and third
party claims, either taken individually or in the aggregate, will have
a material impact on Enron's financial position or results of
operations.

Item 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     None.

<PAGE>
                                 PART II

Item 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
         SHAREHOLDER MATTERS

Common Stock

     The following table indicates the high and low sales prices for
the common stock of Enron as reported on the New York Stock Exchange
(consolidated transactions reporting system), the principal market in
which the securities are traded, and dividends paid per share for the
calendar quarters indicated.  The common stock is also listed for
trading on the Chicago Stock Exchange and the Pacific Stock Exchange,
as well as The London Stock Exchange and Frankfurt Stock Exchange.

<TABLE>
<CAPTION>
                               1998                             1997
                      High      Low    Dividends      High       Low     Dividends

<S>                 <C>       <C>       <C>          <C>        <C>        <C>
First  Quarter      $48       $38 1/8   $.2375       $45 1/8    $37 7/8    $.2250
Second Quarter       54 5/16   45 9/16   .2375        42 3/8     35 5/8     .2250
Third Quarter        58 7/16   40 5/8    .2375        42         35         .2250
Fourth Quarter       58 3/4    49 1/2    .2500        41 15/16   35 15/16   .2375
</TABLE>

Cumulative Second Preferred Convertible Stock

     The following table indicates the high and low sales prices for
the Cumulative Second Preferred Convertible Stock ("Second Preferred
Stock") of Enron as reported on the New York Stock Exchange
(consolidated transactions reporting system), the principal market in
which the securities are traded, and dividends paid per share for the
calendar quarters indicated.  The Second Preferred Stock is also listed
for trading on the Chicago Stock Exchange.

<TABLE>
<CAPTION>
                                 1998                           1997
                      High       Low     Dividends      High    Low      Dividends

<S>                  <C>        <C>      <C>            <C>     <C>       <C>
First  Quarter       $634       $565     $3.2424        $600    $600      $3.0717
Second  Quarter       684 13/16  622 3/4  3.2424         555     496       3.0717
Third  Quarter         --         --      3.2424         540     535       3.0717                                   
Fourth  Quarter       732 1/2    718      3.4130         523     523       3.2424
</TABLE>

     At December 31, 1998, there were approximately 58,598 record
holders of common stock and 209 record holders of Second Preferred
Stock.

     Other information required by this item is set forth under Item 6
-- "Selected Financial Data (Unaudited) - Common Stock Statistics" for
the years 1994-1998.

Recent Sales of Unregistered Equity Securities

     On December 17, 1998, Enron issued in a private placement pursuant
to Section 4(2) of the Securities Act 204,800 shares of its Mandatorily
Convertible Reset Preferred Stock, Series A, to Preferred Voting Trust,
a Delaware statutory business trust, in exchange for all of the
beneficial interests in such trust.  On December 30, 1998, Enron issued
in a private placement pursuant to Section 4(2) of the Securities Act
83,000 shares of its Mandatorily Convertible Reset Preferred Stock,
Series B, to Aguia Voting Trust, a Delaware statutory business trust,
in exchange for all of the beneficial interests in such trust.

<PAGE>
<TABLE>
Item 6.  SELECTED FINANCIAL DATA (UNAUDITED)

<CAPTION>
                                        1998      1997      1996      1995      1994

<S>                                   <C>       <C>       <C>       <C>       <C>
Operating Revenues (millions)         $31,260   $20,273   $13,289   $ 9,189   $ 8,984

Total Assets (millions)               $29,350   $22,552   $16,137   $13,239   $11,966


Common Stock Statistics
  Income from continuing operations
     Total (millions)                    $703      $105      $584      $520      $453
     Per share - basic                  $2.14     $0.32     $2.31     $2.07     $1.80
     Per share - diluted                $2.02     $0.32     $2.16     $1.94     $1.70
  Earnings on common stock
     Total (millions)                    $686      $ 88      $568      $504      $438
     Per share - basic                  $2.14     $0.32     $2.31     $2.07     $1.80
     Per share - diluted                $2.02     $0.32     $2.16     $1.94     $1.70
  Dividends
     Total (millions)                    $312      $243      $212      $205      $192
     Per share                          $0.96     $0.91     $0.86     $0.81     $0.76
  Shares outstanding (millions)
     Actual at year-end                   331       307       251       245       244
     Average for the year                 321       272       246       244       243


Capitalization (millions)
  Long-term debt                      $ 7,357   $ 6,254    $3,349    $3,065   $2,805
  Preferred stock of subsidiary         1,001       993       592       377      377
  Minority interest                     2,143     1,147       755       549      290
  Shareholders' equity                  7,048     5,618     3,723     3,165    2,880
     Total capitalization             $17,549   $14,012    $8,419    $7,156   $6,352
</TABLE>

<PAGE>
Item 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
          CONDITION AND RESULTS OF OPERATIONS

   The following review of the results of operations and
financial condition of Enron Corp. and its subsidiaries and
affiliates (Enron) should be read in conjunction with the
Consolidated Financial Statements.

RESULTS OF OPERATIONS

Consolidated Net Income
   Enron's net income for 1998 was $703 million compared to
$105 million in 1997 and $584 million in 1996.  Enron's
operating segments include Exploration and Production (Enron
Oil & Gas Company), Transportation and Distribution (Gas
Pipeline Group and Portland General), Wholesale Energy
Operations and Services (Enron Capital & Trade Resources and
Enron International), Retail Energy Services (Enron Energy
Services) and Corporate and Other, which includes certain
new businesses.  The results of Portland General have been
included in Enron's Consolidated Financial Statements
beginning July 1, 1997.  See Note 2 to the Consolidated
Financial Statements.  Items impacting comparability are
discussed in the respective segment results.  Net income
includes the following:

<TABLE>
<CAPTION>
(In Millions)                               1998   1997    1996

<S>                                        <C>    <C>     <C>
After-tax results before items impacting
 comparability                             $ 698  $ 515   $ 493

Items impacting comparability:(a)
  Gain on sale of 7% of Enron Energy
   Services shares                             -     61       -
  Gains on sales of Enron Oil & Gas
   Company stock                              45      -      90
  Charge to reflect losses on
   contracted MTBE production                (40)   (74)      -
  Charge to reflect impact of amended
   J-Block gas contract                        -   (463)      -
  Gains on sales of liquids and
   gathering assets                            -     66      59
  Reserve for qualified facilities
   disposition                                 -      -     (54)
  Other                                        -      -      (4)
Reported net income                        $ 703  $ 105   $ 584

<FN>
(a) Tax affected at 35%, except where a specific tax rate
    applied.
</TABLE>

   Diluted earnings per share of common stock were as
follows:

<TABLE>
<CAPTION>
                                      1998      1997      1996

<S>                                   <C>       <C>       <C>
Diluted earnings per share:
  After-tax results before items
   impacting comparability            $2.01     $1.74     $1.82
  Items impacting comparability:
     Gain on sale of 7% of Enron
      Energy Services shares              -      0.21         -
     Gains on sales of Enron Oil &
       Gas Company stock               0.13         -      0.33
     Charge to reflect losses on
      contracted MTBE production      (0.12)    (0.25)        -
     Charge to reflect impact of
      amended J-Block gas contract        -     (1.57)        -
     Gains on sales of liquids and
      gathering assets                    -      0.22      0.22
     Reserve for qualified facilities
      disposition                         -         -     (0.20)
     Other                                -         -     (0.01)
     Effect of anti-dilution(a)           -     (0.03)        -
Reported diluted earnings per share   $2.02     $0.32     $2.16

<FN>
(a) For 1997, the conversion of preferred shares to
    common shares for purposes of the diluted earnings per
    share calculation was anti-dilutive by $0.03 per share.
    However, in order to present comparable results, per
    share amounts for each earnings component were calculated
    using 295 million shares, which assumes the conversion of
    preferred shares to common shares.
</TABLE>

Income Before Interest, Minority Interests and Income Taxes
   The following table presents income before interest,
minority interests and income taxes (IBIT) for each of
Enron's operating segments (see Note 17 to the Consolidated
Financial Statements):

<TABLE>
<CAPTION>
(In Millions)                          1998   1997    1996

<S>                                  <C>     <C>    <C>
Exploration and Production           $  128  $ 183  $  200
Transportation and Distribution:
  Gas Pipeline Group                    351    466     524
  Portland General                      286    114       -
Wholesale Energy Operations 
 and Services                           968    654     466
Retail Energy Services                 (119)  (107)      -
Corporate and Other                     (32)  (745)     48
  Reported income before interest,
   minority interests and taxes      $1,582  $ 565  $1,238
</TABLE>

Exploration and Production
   Enron's exploration and production operations are
conducted by Enron Oil & Gas Company (EOG).
   
   Wellhead volume and price statistics (including
intercompany amounts) are as follows:

<TABLE>
<CAPTION>
                                              1998    1997    1996

<S>                                         <C>     <C>     <C>
Natural gas volumes (MMcf/d)(a)
  North America                                776     758     706
  Trinidad                                     139     113     124
  India                                         56      18       -
     Total                                     971     889     830
Average natural gas prices ($/Mcf)
  North America                              $1.86   $2.20   $1.92
  Trinidad                                    1.06    1.05    1.00
  India                                       2.41    2.79       -
     Composite                                1.78    2.07    1.78
Crude oil/condensate volumes (MBbl/d)(a)
  North America                               16.6    14.2    11.6
  Trinidad                                     3.0     3.4     5.2
  India                                        5.1     2.3     2.8
     Total                                    24.7    19.9    19.6
Average crude oil/condensate prices ($/Bbl)
  North America                             $12.67  $19.33  $21.08
  Trinidad                                   12.26   18.68   19.76
  India                                      12.86   20.05   20.17
     Composite                               12.66   19.30   20.60

<FN>
(a) Million cubic feet per day or thousand barrels per day,
    as applicable.
</TABLE>

   The following analyzes the significant components of IBIT
for Exploration and Production:

<TABLE>
<CAPTION>
(In Millions)                                1998   1997   1996

<S>                                         <C>     <C>    <C>
Net revenues                                $769    $783   $730
Corporate hedging activities                  19      (8)    (4)
Operating expenses                           219     210    181
Exploration expenses                         121     102     89
Depreciation, depletion and amortization     315     278    251
  Operating income                           133     185    205
Other income, net                             (5)     (2)    (5)
  Reported income before interest, 
   minority interests and taxes             $128    $183   $200
</TABLE>

Net Revenues
   Exploration and Production's revenues, net of gas sold in
connection with natural gas marketing, decreased $14 million
(2%) in 1998 after increasing $53 million (7%) in 1997.  The
1998 change reflects lower average wellhead natural gas
prices and crude oil and condensate prices, partially offset
by increased production volumes of both natural gas and
crude oil and condensate.  The 1997 increase reflected both
increased average wellhead natural gas prices and increased
production volumes.  Other marketing activities, which
include hedging, trading and natural gas marketing
transactions by EOG, reduced net revenues by $4 million in
1998 and $61 million in 1997, compared with an increase of
$4 million in 1996.  Net revenues also include gains on
sales of crude oil and gas reserves and related assets of
$26 million in 1998, $9 million in 1997 and $20 million in
1996.

Costs and Expenses
   Operating expenses and depreciation, depletion and
amortization (DD&A) increased in 1998 and 1997 primarily due
to expanded operations and increased worldwide production
volumes in both years and a higher DD&A rate in North
America in 1998.

   Exploration expenses increased 19% in 1998 and 15% in
1997 as compared to the prior year, primarily as a result of
increased exploratory drilling activities and expenses
related to lease acquisitions in North America.

Outlook
   EOG plans to continue to focus a substantial portion of
its development and exploration expenditures in its major
producing areas in North America.  In addition, EOG
anticipates additional spending for the continued
development of its projects in India, Trinidad and China.

   In December 1998, Enron received an unsolicited
indication of interest from a third party with respect to
exploring a possible transaction pursuant to which the third
party would acquire Enron's shares of EOG common stock and
offer to acquire the remaining shares of outstanding EOG
common stock.  There can be no assurance that any such
transaction will be consummated.

Transportation and Distribution
   Transportation and Distribution consists of Gas Pipeline
Group and Portland General.  Gas Pipeline Group includes
Enron's interstate natural gas pipelines, primarily Northern
Natural Gas Company (Northern), Transwestern Pipeline
Company (Transwestern), Enron's 50% interest in Florida Gas
Transmission Company (Florida Gas) and Enron's interest in
Northern Border Pipeline.  Portland General results are
included for the period since the July 1, 1997 merger (see
Note 2 to the Consolidated Financial Statements).

   Gas Pipeline Group.  The following table summarizes total
volumes transported by each of Enron's interstate natural
gas pipelines.

<TABLE>
<CAPTION>
                                         1998    1997    1996

<S>                                     <C>     <C>     <C>
Total Volumes Transported (Bbtu/d)(a)
  Northern Natural Gas                  4,098   4,364   4,577
  Transwestern Pipeline                 1,608   1,416   1,341
  Florida Gas Transmission              1,341   1,341   1,296
  Northern Border Pipeline              1,770   1,800   1,801

<FN>
(a) Billion British thermal units per day.  Amounts
    reflect 100% of each entity's throughput volumes.
    Florida Gas and Northern Border Pipeline are
    unconsolidated affiliates.
</TABLE>

   Significant components of IBIT are as follows:

<TABLE>
<CAPTION>
(In Millions)                         1998   1997   1996

<S>                                   <C>    <C>    <C>
Net revenues                          $640   $665   $719
Operating expenses                     276    310    316
Depreciation and amortization           70     69     66
Equity in earnings                      32     40     35
Other income, net                       25     38     44
  IBIT before items impacting 
   comparability                       351    364    416
Gains on sales of liquids and 
 gathering assets                        -    102     90
Other                                    -      -     18
  Reported income before interest 
   and taxes                          $351   $466   $524
</TABLE>

Net Revenues
     Revenues, net of cost of sales, of Gas Pipeline Group
declined $25 million (4%) during 1998 and $54 million (8%)
during 1997 as compared to the applicable preceding year.
The decrease in net revenue in 1998 compared to 1997 was
primarily due to the warmer than normal winter in Northern's
service territory and the reduction of transition costs
recovered through a regulatory surcharge at Northern.  The
decrease in net revenues in 1997 compared to 1996 was
primarily due to the sale of natural gas liquids assets in
early 1997 and the turnback of capacity at Transwestern,
resulting in reduced transportation revenues beginning in
November 1996.

Operating Expenses
   Operating expenses of Gas Pipeline Group decreased $34
million (11%) during 1998, primarily as a result of the
reduction of transition costs at Northern and lower overhead
costs.  Operating expenses declined $6 million (2%) during
1997, primarily due to a reduction of transition costs at
Northern.

Equity in Earnings
   Equity in earnings of unconsolidated affiliates decreased
$8 million in 1998 after increasing $5 million during 1997
as compared to 1996.  These changes were primarily due to
higher 1997 earnings from Citrus Corp. (Citrus), which holds
Enron's 50% interest in Florida Gas.  Earnings from Citrus
were higher in 1997 due to a contract restructuring.

Other Income, Net
   Other income, net decreased $13 million (34%) in 1998 as
compared to 1997 primarily as a result of income recognized
in 1997 related to liquids assets sold in 1997.  Included in
1998 were gains of $21 million recognized from the
monetization of an interest in an equity investment,
substantially offset by charges related to litigation.

Items Impacting Comparability
   Gains of $102 million were recognized in 1997 related to
the sales of liquids assets, including processing plants and
Enron's interest in Enron Liquids Pipeline L.P.  During
1996, gains of $90 million related to the disposition of non-
strategic natural gas gathering facilities were recognized,
and gains of $18 million were recorded as a result of
favorable resolution of litigation.

   Portland General.  Results for Portland General have been
included in Enron's Consolidated Financial Statements
beginning July 1, 1997.  Since that date, Portland General
realized IBIT, as follows:

<TABLE>
<CAPTION>
(In Millions)                            1998      1997(a)

<S>                                    <C>          <C>
Revenues                               $1,196       $746
Purchased power and fuel                  451        389
Operating expenses                        295        154
Depreciation and amortization             183         91
Other income, net                          19          2
  Reported income before interest 
   and taxes                           $  286       $114

<FN>
(a) Represents the period from July 1, 1997 through
    December 31, 1997.
</TABLE>

   The 1998 results were impacted by a warmer than normal
winter and the transfer of the majority of its electricity
wholesale business to the Enron Wholesale segment, partially
offset by an increase in sales to retail customers.

   Statistics for Portland General for 1998 and for the
period from July 1 through December 31, 1997 are as follows:

<TABLE>
<CAPTION>
                                             1998      1997

<S>                                         <C>       <C>
Electricity Sales (Thousand MWh)(a)
  Residential                                7,101     3,379
  Commercial                                 6,781     3,618
  Industrial                                 3,562     2,166
     Total Retail                           17,444     9,163
  Wholesale                                 10,869    13,448
     Total Electricity Sales                28,313    22,611

Resource Mix
  Coal                                          16%       10%
  Combustion Turbine                            12         5
  Hydro                                          9         5
     Total Generation                           37        20
  Firm Purchases                                56        74
  Secondary Purchases                            7         6
     Total Resources                           100%      100%

Average Variable Power Cost (Mills/KWh)(b)
  Generation                                   8.6       8.7
  Firm Purchases                              17.3      18.9
  Secondary Purchases                         23.6      13.2
     Total Average Variable Power Cost        15.6      17.2

Retail Customers (end of period, thousands)    704       685

<FN>
(a)  Thousand megawatt-hours.
(b)  Mills (1/10 cent) per kilowatt-hour.
</TABLE>

Outlook
   Transportation and Distribution should continue to
provide stable earnings and cash flows during 1999,
including steady growth over 1998 levels.

   Gas Pipeline Group continues to expand its pipeline
system to provide services to existing customers and new
markets.  Florida Gas has an expansion planned to provide
new capacity of 270 MMcf/d into Southwest Florida by the
year 2001 and is evaluating other expansions to meet
Florida's expected strong growth in gas consumption.  Future
results of Northern Border Pipeline will reflect its 700
MMcf/d extension of service to the Chicago market area.  A
further expansion to Indiana through a 35-mile, 545 MMcf/d
extension of its pipeline will be placed in service in the
year 2000.  Transwestern is considering expansions to bring
in additional supplies from the San Juan basin to
California.

   Portland General anticipates continuing retail customer
growth in one of the fastest growing service territories in
the U.S.  In late 1997, Portland General filed a Customer
Choice Plan proposal and rate case with the Oregon Public
Utility Commission (OPUC) which would open its service
territory to competition.  Under the proposed Customer
Choice Plan, Portland General would separate its generation
business from its transmission and distribution businesses
and Portland General would become a regulated transmission
and distribution company focused on delivering, but not
selling, electricity.  In July 1998, the OPUC staff issued
its position, disagreeing with Portland General's proposal
for full customer choice.

   In January 1999, the OPUC issued an order, which is
contingent upon the adoption of certain regulatory changes
by the Oregon Legislature, with recommendations that
included allowing small retail customers a limited set of
options including the ability to continue to purchase rate-
regulated electricity, allowing most commercial and
industrial users to have the ability to choose their
electricity provider and allowing Portland General to sell
its coal- and gas-fired generation plants but rejecting
Portland General's request to sell its hydroelectric assets.
Additionally, the order requires Portland General, should it
choose to adopt OPUC's recommendations, to file a new rate
case.  Portland General is reviewing the OPUC order, but
will not implement any of the recommendations until the
changes are agreed upon by all parties.  The issue of
restructuring will be further addressed by the 1999 Oregon
Legislature.  Portland General will support legislation that
creates a comprehensive approach to the electricity industry
that helps develop a market that is truly competitive.

Wholesale Energy Operations and Services
   Enron's wholesale energy operations and services business
(Enron Wholesale) operates in North America, Europe and
other countries.  Activities are conducted primarily by
Enron Capital & Trade Resources and Enron International.
Enron Wholesale is categorized into two business lines: (a)
Commodity Sales and Services and (b) Energy Assets and
Investments.  Integrated energy-related products and
services related to these business lines are offered to
wholesale customers in varying degrees in each of Enron
Wholesale's markets.

   Enron manages its commodity and asset portfolios in order
to maximize value, minimize the associated risks and provide
overall liquidity.  In this process, Enron utilizes
portfolio and risk management disciplines including certain
hedging transactions to manage portions of its market
exposures (commodity, interest rate, foreign currency and
equity exposures).  Enron Wholesale from time to time
monetizes its contract portfolios (producing cash and
transferring counterparty credit risk to third parties) and
sells interests in investments and assets.

   The following table reflects IBIT for each business line:

<TABLE>
<CAPTION>
(In Millions)                          1998  1997   1996

<S>                                   <C>    <C>    <C>
Commodity Sales and Services          $411   $249   $348
Energy Assets and Investments          709    565    263
Unallocated expenses                 (152)   (160)  (145)
  Reported income before interest, 
   minority interests and taxes      $968    $654   $466
</TABLE>

   The following discussion analyzes the contributions to
IBIT for each business line.

   Commodity Sales and Services.  Enron Wholesale provides
reliable delivery of energy commodities at predictable
prices.  The commodity sales and services operations
includes the purchase, sale, marketing and delivery of
natural gas, electricity, liquids and other commodities,
restructuring of existing long-term contracts and the
management of Enron's commodity contract portfolios.  In
addition, Enron provides risk management products and
services to energy customers that hedge movements in price
and location-based price differentials.  Enron's risk
management products and services are designed to provide
stability to customers in markets impacted by commodity
price volatility.  Also included in this business is the
management of certain operating assets that directly relate
to this business, including domestic intrastate pipelines
and storage facilities.

   Enron Wholesale markets and transports a substantial
quantity of energy commodities as reflected in the following
table (including intercompany amounts):

<TABLE>
<CAPTION>
                                                1998      1997     1996

<S>                                           <C>       <C>       <C>
Physical Volumes (BBtue/d)(a)(b)
Gas:
  United States                                 7,418     7,654    6,998
  Canada                                        3,486     2,263    1,406
  Europe and Other                              1,251       660      289
                                               12,155    10,577    8,693
Transport Volumes                                 559       460      544
     Total Gas Volumes                         12,714    11,037    9,237
Crude Oil and Liquids                           3,570     1,677    1,507
Electricity(c)                                 11,024     5,256    1,648
     Total Physical Volumes (BBtue/d)          27,308    17,970   12,392
Electricity Volumes Marketed (Thousand MWh)
  United States                               401,843   191,746   60,150
  Europe and Other                                529       100        -
     Total                                    402,372   191,846   60,150

Financial Settlements (Notional) (BBtue/d)     75,266    49,082   35,259

<FN>
(a) Billion British thermal units equivalent per day.
(b) Includes third-party transactions by Enron Energy
    Services.
(c) Represents Electricity Volumes Marketed, converted to
    BBtue/d.
</TABLE>

   The earnings from commodity sales and services operations
increased 65% in 1998 as compared to 1997.  The change is
primarily due to increased earnings from originations of
risk management products and services in North America,
including contract restructurings, and increased power
marketing earnings, where volumes have increased over 100%,
partially offset by fewer originations in Europe, lower
earnings related to domestic operating assets and higher
expenses.

   The earnings from commodity sales and services operations
decreased 28% in 1997 as compared to 1996 primarily due to
lower domestic gas and power margins in 1997 compared with
1996.  Although volumes were higher in 1997, greater
seasonal volatility of domestic natural gas prices provided
higher margins in 1996.  Domestic liquids marketing activity
was also lower in 1997 compared with 1996. These decreases
were partially offset by increased activity in the European
markets related to natural gas and power contracts,
including originations with utilities and independent power
producers (IPPs) in 1997.  Originations from long-term
contracts in North America decreased in 1997 for both
natural gas and power.

   Energy Assets and Investments.  Enron Wholesale's energy
assets and investments activities include investments in
debt and equity securities of oil and gas producers and
other energy-intensive companies.  Additionally, Enron
Wholesale develops, constructs, operates and manages a large
portfolio of energy investments such as power plants and
natural gas pipelines.  Earnings primarily result from
changes in the market value of merchant investments held
during the period, equity earnings and gains on sales or
restructurings of energy investments.  See Note 4 to the
Consolidated Financial Statements for a summary of these
investments.

   Earnings from energy assets and investments increased 25%
in 1998 as compared to 1997 primarily as a result of
earnings from the sale of interests in the Puerto Rico,
Turkey, Italy and U.K. power projects, from which Enron
realized the value created during the development and
construction phases, partially offset by development costs
and decreased earnings from the management of Enron
Wholesale's merchant investments.  Some of these
transactions involved securitizations in which Enron
retained certain interests associated with the underlying
assets.

   Earnings from energy assets and investments increased
115% in 1997 compared with 1996 due primarily to a
significant increase in the market value of its investments,
including the positive impact of a change in the structure
of a joint venture investment, as well as increased earnings
from originations and earnings from the sale of interests in
U.K. power projects.  Also contributing to the increase were
fees earned on projects in the U.K.

   Unallocated Expenses.  Net unallocated expenses include
rent, systems expenses and other support group costs.

Outlook

   Enron anticipates continued growth in Enron Wholesale
during 1999 due to further expansion into new products and
markets.  In the commodity sales and services business,
volumes are expected to continue to increase as Enron
maintains or increases its market share in the growing
unregulated U.S. power market and the European gas and power
markets.  In addition, Enron expects to benefit from
opportunities related to its substantial portfolio of
commodity contracts.  Enron also expects to continue
increased integration of financial products with its energy
commodity portfolio.  In the energy assets and investments
business, Enron will continue to benefit from opportunities
related to its energy investments, including sales or
restructurings of appreciated investments, and in providing
capital to energy-intensive customers.  Equity earnings from
operations are expected to increase as a result of
commencement of commercial operations of new power plants
and pipeline in early 1999 including the larger power
project in India.

   At December 31, 1998, the following international
projects were under construction:

<TABLE>
<CAPTION>
                                                Estimated
                                                Commercial
                              Size/Capacity   Operations Date

<S>                            <C>               <C>
Pipeline(a)
  Bolivia/Brazil (Phase I)     1,180 miles       2Q 1999

Power Plants(a)
  Cuiaba - Brazil (Phase I)      150 MW(b)       1Q 1999
  Dabhol - India (Phase I)       826 MW          1Q 1999
  Piti - Guam                     80 MW          1Q 1999
  Sutton Bridge - U.K.           790 MW          1Q 1999
  Trakya - Turkey                478 MW          1Q 1999
  Corinto - Nicaragua             71 MW          2Q 1999
  EcoElectrica - Puerto Rico     507 MW          3Q 1999
  Nowa Sarzyna - Poland          116 MW          4Q 1999
  Sarlux - Italy                 551 MW          1Q 2000

<FN>
(a)  Enron holds varying interests in these projects.
(b)  Megawatts.
</TABLE>

   Earnings from Enron Wholesale are dependent on the
origination and completion of transactions, some of which
are individually significant and which are impacted by
market conditions, the regulatory environment and customer
relationships.  Enron Wholesale's transactions have
historically been based on a diverse product portfolio,
providing a solid base of earnings.  Enron's strengths,
including its ability to identify and respond to customer
needs, access to extensive physical assets and its
integrated approach to meeting customers needs, are
important drivers of the expected continued earnings growth.
In addition, significant earnings are expected from Enron
Wholesale's commodity portfolio and investments, which are
subject to market fluctuations.  External factors, such as
the amount of volatility in market prices, impact the
earnings opportunity associated with Enron Wholesale's
business.  Risk related to these activities is managed using
naturally offsetting transactions and hedge transactions.
The effectiveness of Enron's risk management activities can
have a material impact on future earnings.  See "Financial
Risk Management" for a discussion of market risk related to
Enron Wholesale.

Retail Energy Services
   Enron Energy Services (Energy Services), formed in late
1996, is extending Enron's energy expertise to end-use
business customers.  This includes sales of natural gas,
electricity and outsourcing energy management services
directly to commercial and industrial customers.  Energy
Services reported losses before interest, minority interests
and taxes of $119 million in 1998 and $107 million in 1997
related to significant investments in building its sales and
service capabilities, developing products and services,
establishing a support system to service its contracts and
supporting Energy Services' regulatory efforts.

   During 1998, Energy Services completed a significant
number of transactions which will provide future revenues
and margins.  Energy Services revenues totaled $1.1 billion
during 1998, a 57% increase from 1997.

   In late 1997, Enron sold approximately 7% of its
ownership of Energy Services for $130 million, to defray
startup costs and establish a valuation for this new
business.  The transaction resulted in an after-tax gain of
$61 million, which has been reflected in Corporate and
Other.  This sale of Energy Services ownership reflected a
total enterprise value of $1.9 billion.  Since that time,
significant new customers and long-term contracts have been
obtained.

Outlook
   During 1999, Enron anticipates continued growth in the
demand for energy outsourcing solutions.  Energy Services
will focus on delivering these services to its existing
customers, while continuing to expand its commercial and
industrial customer base for total energy outsourcing.
Energy Services also plans to continue integrating its
service delivery capabilities, focusing on the development
of best practices, nation-wide procurement opportunities,
efficient use of capital and centralized decision making.
Energy Services expects reduced losses in 1999.

Corporate and Other
   Corporate and Other includes results of Azurix Corp.,
which provides water and wastewater services, Enron
Communications, Inc. (ECI), which is building a national
Internet-protocol fiber-optic network to deliver high
content media to business customers, Enron Renewable Energy
Corp. (EREC), EOTT Energy Corp. (EOTT) and the operations of
Enron's methanol and MTBE plants.  Significant components of
IBIT are as follows:

<TABLE>
<CAPTION>
(In Millions)                                    1998    1997    1996

<S>                                              <C>    <C>     <C>
IBIT before items impacting comparability        $  7   $ (31)  $ (22)

Items impacting comparability:
  Gain on sale of 7% of Enron Energy
   Services shares                                  -      61       -
  Gains on sales of Enron Oil & Gas
   Company stock                                   22       -     178
  Charge to reflect losses on contracted
   MTBE production                                (61)   (100)      -
  Charge to reflect impact of amended
   J-Block gas contract                             -    (675)      -
  Reserve for qualified facilities disposition      -       -     (83)
  Miscellaneous reserves and other items            -       -     (25)
Reported income before interest and taxes        $(32)  $(745)  $  48
</TABLE>

   Results in 1998 were favorably impacted by increased
earnings related to ECI from the sale of capacity on its
fiber-optic network and increases in the market value of
certain corporate-managed financial instruments, partially
offset by higher corporate expenses.

   During 1998, Enron recognized a pre-tax gain of $22
million on the delivery of 10.5 million shares of EOG stock
held by Enron as repayment of mandatorily exchangeable debt.
Enron also recorded a $61 million charge to reflect losses
on contracted MTBE production.

   During 1997, Enron recorded a non-recurring charge of
$675 million, primarily reflecting the impact of Enron's
amended J-Block gas contract in the U.K., and a $100 million
charge primarily to reflect losses on contracted MTBE
production.  In 1996, a gain of $178 million was recognized,
primarily related to the sale of 12 million outstanding
shares of EOG stock held by Enron.  The 1996 results
included an $83 million reserve related to the required
disposition of certain assets in connection with the merger
with Portland General.

Interest and Related Charges, Net
   Interest and related charges, net of interest
capitalized, increased $149 million in 1998 and $127 million
in 1997.  The increase in 1998 as compared to 1997 was
primarily a result of higher debt levels, including the
issuance of approximately $2.1 billion in debt between
November 1997 and the end of 1998, mainly to finance capital
expenditures and investments.  The 1998 interest expense
also reflects the impact of twelve months of interest
expense on debt related to the merger with Portland General.
The 1997 increase was primarily due to higher debt levels,
including debt of $1.1 billion from Portland General
following the merger on July 1, 1997 (see Note 2 to the
Consolidated Financial Statements). Interest capitalized,
which totaled $66 million, $18 million and $12 million for
1998, 1997, and 1996, respectively, increased in 1998 as a
result of the commencement of construction of several power
projects.

Dividends on Company-Obligated Preferred Securities of
Subsidiaries
   Dividends on company-obligated preferred securities of
subsidiaries increased from $34 million in 1996 to $69
million in 1997 and to $77 million in 1998, primarily due to
the issuance of $215 million and $372 million of additional
preferred securities by Enron subsidiaries during 1996 and
1997, respectively.  Company-obligated preferred securities
of subsidiaries also increased by $29 million in 1997 for
securities of Portland General.

Minority Interests
   Minority interests were $77 million in 1998 compared to
$80 million in 1997 and $75 million in 1996.  Minority
interests in 1998 include EOG and the minority owner's share
of dividends on preferred stock issued in connection with
the formation of an Enron-controlled joint venture in late
1997.  See Note 8 to the Consolidated Financial Statements.
Minority interests in 1997 and 1996 relate to EOG and Enron
Global Power & Pipelines, L.L.C. (EPP) until Enron's
acquisition of the EPP minority interest in November 1997.

Income Tax Expense
   Income tax expense increased in 1998 as compared to 1997
primarily as a result of increased earnings, partially
offset by differences between the book and tax basis of
certain assets and stock sales.

   Income tax expense decreased for 1997 as compared to 1996
primarily as a result of pretax losses due to the non-
recurring charges for the restructuring of Enron's J-Block
contract and for losses on contracted MTBE production.  In
addition, the 1997 tax provision was reduced for differences
between the book and tax basis of certain assets and stock
sales.

YEAR 2000

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

   The effects of the Year 2000 problem are exacerbated
because of the interdependence of computer and
telecommunications systems in the United States and
throughout the world.  This interdependence certainly is
true for Enron and Enron's suppliers, trading partners, and
customers, as well as for governments of countries around
the world where Enron does business.

State of Readiness
   Enron's Board of Directors has been briefed about the
Year 2000 problems generally and as they may affect Enron.
The Board has adopted a Year 2000 plan (the "Plan") covering
all of Enron's business units.  The aim of the Plan is to
take reasonable steps to prevent Enron's mission-critical
functions from being impaired due to the Year 2000 problem.
"Mission-critical" functions are those critical functions
whose loss would cause an immediate stoppage of or
significant impairment to major business areas  (a major
business area is one of material importance to Enron's
business).

   Implementation of Enron's Year 2000 plan is directly
supervised by a Senior Vice President who is aided by a Year
2000 Project Director.  The Project Director coordinates the
implementation of the Plan among Enron's business units.  As
part of the overall Plan, each business unit in turn has
developed, and is implementing, a Year 2000 plan specific to
it.  Enron also has engaged outside consultants, technicians
and other external resources to aid in formulating and
implementing the Plan.

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

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

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

   As of February 15, 1999, Enron and all its business units
were at various stages in implementation of the Plan, as
shown in the following tables. The first table deals with
the Enron business units' mission-critical internal systems
(including embedded chips) and the second deals with the
business units' mission-critical Outside Systems of Outside
Entities.  Any notation of "complete" conveys the fact only
that the initial iteration of this phase has been
substantially completed.

<TABLE>
Year 2000 Plan Readiness by Enron Business Unit
(Mission-Critical Internal Items)

<CAPTION>
                                                                                         Contingency
                        Inventory  Assessment  Analysis  Conversion  Testing  Y2K-Ready      Plan

<S>                         <C>        <C>        <C>        <C>        <C>      <C>          <C>
Exploration and                                                     
Production                  C          IP         IP         IP         IP       IP           IP
Transportation                                                      
and Distribution:
 Gas Pipeline Group         C          C          IP         IP         IP       IP           IP
 Portland General           C          C          C          IP         IP       IP           IP
Wholesale:                                                          
 Domestic                   C          C          C          IP         IP       IP           IP
 Europe                     C          C          C          IP         IP       IP           IP
 Other International        IP         IP         IP         IP         IP       IP           IP
Retail Energy Services      C          C          IP         IP         IP       IP           IP
Corporate and Other         IP         IP         IP         IP         IP       IP           IP
</TABLE>

<TABLE>
Year 2000 Plan Readiness by Enron Business Unit
(Mission-Critical Outside Entities)

<CAPTION>
                                                                                         Contingency
                        Inventory  Assessment  Analysis  Conversion  Testing  Y2K-Ready      Plan

<S>                         <C>        <C>        <C>        <C>        <C>      <C>          <C>
Exploration and                                                     
Production                  IP         IP         IP         IP         IP       IP           IP
Transportation                                                      
and Distribution:  
 Gas Pipeline Group         C          C          IP         IP         IP       IP           IP
 Portland General           C          C          C          IP         IP       IP           IP 
Wholesale:                                                          
 Domestic                   C          IP         IP         IP         TBI      IP           TBI
 Europe                     C          C          IP         TBI        TBI      IP           TBI
 Other International        IP         IP         IP         IP         IP       IP           IP
Retail Energy Services      C          C          IP         IP         IP       IP           IP
Corporate and Other         C          IP         IP         IP         IP       IP           IP

Legend:  C = Complete     IP = In Process     TBI = To Be Initiated
</TABLE>

   The following tables show, by business unit, historical and estimated
completion dates, as applicable, for the initial iteration of various stages of
the Plan.  The first table deals with the Enron business units' mission-
critical internal systems (including embedded chips) and the second deals with
the business units' mission-critical Outside Systems of Outside Entities.

<TABLE>
Year 2000 Plan Completion Dates by Enron Business Unit
(Mission-Critical Internal Items)

<CAPTION>
                                                                                         Contingency
                        Inventory  Assessment  Analysis  Conversion  Testing  Y2K-Ready      Plan

<S>                       <C>          <C>        <C>        <C>        <C>       <C>         <C>
Exploration and                                                     
Production                12/98        3/99       3/99       6/99       9/99      9/99        9/99
Transportation                                                      
and Distribution: 
 Gas Pipeline Group       12/98        1/99       4/99       6/99       7/99      8/99        6/99
 Portland General         12/97       10/98      10/98       6/99       6/99      6/99        6/99
Wholesale:                                                          
 Domestic                  6/98        8/98      12/98       6/99       6/99      6/99        9/99
 Europe                    7/98        8/98       8/98       4/99       4/99      7/99        7/99
 Other International       3/99        3/99       4/99       6/99       7/99      8/99        6/99
Retail Energy Services     1/99        2/99       3/99       4/99       5/99      7/99        7/99
Corporate and Other        2/99        2/99       3/99       3/99       3/99      6/99        6/99
</TABLE>

<TABLE>
Year 2000 Plan Completion Dates by Enron Business Unit
(Mission-Critical Outside Entities)

<CAPTION>
                                                                                         Contingency
                        Inventory  Assessment  Analysis  Conversion  Testing  Y2K-Ready      Plan

<S>                        <C>         <C>        <C>        <C>        <C>       <C>         <C>
Exploration and                                                     
Production                 3/99        6/99       6/99       9/99       9/99      9/99        9/99
Transportation                                                      
and Distribution: 
 Gas Pipeline Group       11/98        1/99       4/99       5/99       5/99      6/99        6/99
 Portland General         10/98       11/98      11/98       6/99       6/99      6/99        6/99
Wholesale:                                                          
 Domestic                  7/98        3/99       5/99       7/99       9/99      9/99        9/99
 Europe                    6/98        7/98       3/99       8/99       8/99      8/99        8/99
 Other International       2/99        2/99       4/99       6/99       7/99      8/99        6/99
Retail Energy Services     1/99        1/99       3/99       4/99       5/99      6/99        6/99
Corporate and Other       10/98        3/99       3/99       6/99       6/99      6/99        6/99
</TABLE>

   Enron will continue to closely monitor work under the Plan and
to revise estimated completion dates for the initial iteration of
each listed process.

Costs to Address Year 2000 Issues
   Under the Plan and otherwise, Enron has not incurred material
historical costs for Year 2000 awareness, inventory, assessment,
analysis, conversion, testing, or contingency planning.  Further,
Enron anticipates that its future costs for these purposes,
including those for implementing its Year 2000 contingency plans,
will not be material.

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

Year 2000 Risk Factors
   Regulatory requirements.  Certain of Enron's business units
operate in industries that are regulated by governmental
authorities.  Enron expects to satisfy these regulatory
authorities' requirements for achieving Year 2000 readiness.  If
Enron's reasonable expectations in this regard are in error, and
if a regulatory authority should order the temporary cessation of
Enron's operations in one or more of these areas, the adverse
effect on Enron could be material.  Outside Entities could face
similar problems that materially adversely affect Enron.

   Shortage of resources.  Between now and Year 2000 there will
be increased competition for people with the technical and
managerial skills necessary to deal with the Year 2000 problem.
While Enron is taking substantial precautions to recruit and
retain sufficient people skilled in dealing with the Year 2000
problem and has hired consultants who bring additional skilled
people to deal with the Year 2000 problem as it affects Enron,
Enron could face shortages of skilled personnel or other
resources, such as Year 2000 ready computer chips, and these
shortages might delay or otherwise impair Enron's progress
towards making its mission-critical systems Year 2000 ready.
Outside Entities could face similar problems that materially
adversely affect Enron.  Enron believes that the possible impact
of the shortage of skilled people is not, and will not be, unique
to Enron.

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

   Cascading effect.  Enron and its business units are taking
reasonable steps to identify, assess, and, where appropriate,
replace devices that contain embedded chips.  Despite these
reasonable efforts, Enron anticipates that it will not be able to
find and remediate all embedded chips in systems in Enron's
business units.  Further, Enron anticipates that Outside Entities
on which Enron depends also will not be able to find and
remediate all embedded chips in their systems.  Some of the
embedded chips that fail to operate or that produce anomalous
results may create system disruptions or failures.  Some of these
disruptions or failures may spread from the systems in which they
are located to other systems in a cascade.  These cascading
failures may have adverse effects upon Enron's ability to
maintain safe operations and may also have adverse effects upon
Enron's ability to serve its customers and otherwise to fulfill
certain contractual and other legal obligations.  The embedded
chip problem is widely recognized as one of the more difficult
aspects of the Year 2000 problem across industries and throughout
the world.  Enron believes that the possible adverse impact of
the embedded chip problem is not, and will not be, unique to
Enron.

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

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

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

   Enron's contingency plans include the creation of teams that
will be standing by on the evening of December 31, 1999, prepared
to respond rapidly and otherwise as necessary to mission-critical
Year 2000-related problems as soon as they become known.  The
composition of teams that are assigned to deal with Year 2000
problems will vary according to the nature, mission-criticality,
and location of the problem.  Because Enron operates
internationally, some of its Year 2000 contingency teams will be
stationed at Enron's mission-critical facilities overseas.

Worst Case Scenario
   The Securities and Exchange Commission requires that public
companies forecast the most reasonably likely worst case Year
2000 scenario.  Analysis of the most reasonably likely worst case
Year 2000 scenarios Enron may face leads to contemplation of the
following possibilities which, though unlikely in some or many
cases, must be included in any consideration of worst cases:
widespread failure of electrical, gas, and similar supplies by
utilities serving Enron domestically and internationally;
widespread disruption of the services of communications common
carriers domestically and internationally; similar disruption to
means and modes of transportation for Enron and its employees,
contractors, suppliers, and customers;  significant disruption to
Enron's ability to gain access to, and remain working in, office
buildings and other facilities; the failure of substantial
numbers of Enron's mission-critical information (computer)
hardware and software systems, including both internal business
systems and systems (such as those with embedded chips)
controlling operational facilities such as electrical generation,
transmission, and distribution systems and oil and gas plants and
pipelines, domestically and internationally; and the failure,
domestically and internationally, of Outside Systems, the effects
of which would have a cumulative material adverse impact on
Enron's mission-critical systems.  Among other things, Enron
could face substantial claims by customers or loss of revenues
due to service interruptions, inability to fulfill contractual
obligations, inability to account for certain revenues or
obligations or to bill customers accurately and on a timely
basis, and increased expenses associated with litigation,
stabilization of operations following mission-critical failures,
and the execution of contingency plans.  Enron could also
experience an inability by customers, traders, and others to pay,
on a timely basis or at all, obligations owed to Enron.  Under
these circumstances, the adverse effect on Enron, and the
diminution of Enron's revenues, would be material, although not
quantifiable at this time.  Further in this scenario, the
cumulative effect of these failures could have a substantial
adverse effect on the economy, domestically and internationally.
The adverse effect on Enron, and the diminution of Enron's
revenues, from a domestic or global recession or depression also
is likely to be material, although not quantifiable at this time.

   Enron will continue to monitor business conditions with the
aim of assessing and minimizing adverse effects, if any, that
result or may result from the Year 2000 problem.

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

NEW ACCOUNTING PRONOUNCEMENTS

   On April 3, 1998, the AICPA issued Statement of Position 98-5
(SOP 98-5), "Reporting on the Costs of Start-Up Activities,"
which requires that costs for all start-up activities and
organization costs be expensed as incurred and not capitalized in
certain instances, as had previously been allowed.  SOP 98-5 is
effective for financial statements for fiscal years beginning
after 1998 and initial adoption is required to be reflected as a
cumulative effect of accounting change.  Although Enron continues
to evaluate the impact of adopting SOP 98-5, it expects to
recognize an after-tax charge of approximately $130 million in
the first quarter of 1999 related primarily to differences in
timing of commencement of capitalization of project development
costs compared to Enron's current policy.  This charge will be
reflected net of tax as a separate line item in Enron's
Consolidated Income Statement.

   In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities."
SFAS No. 133 establishes accounting and reporting standards
requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded
on the balance sheet as either an asset or liability measured at
its fair value.  The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met.  Special
accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document,
designate and assess the effectiveness of transactions that
receive hedge accounting.

   SFAS No. 133 is effective for fiscal years beginning after
June 15, 1999.  A company may also implement the Statement as of
the beginning of any fiscal quarter after issuance, however, SFAS
No. 133 cannot be applied retroactively.  Enron has not yet
determined the timing of adoption of SFAS No. 133.  Enron
believes that SFAS No. 133 will not have a material impact on its
accounting for price risk management activities but has not yet
quantified the effect on its hedging activities or physical base
contracts.

   In December 1998, the Emerging Issues Task Force reached
consensus on Issue No. 98-10, "Accounting for Contracts involved
in Energy Trading and Risk Management Activities" (EITF 98-10).
EITF 98-10 is effective for fiscal years beginning after December
15, 1998 and requires energy trading contracts to be recorded at
fair value on the balance sheet, with the changes in fair value
included in earnings.  The effect of initial application of EITF
98-10 will be reported as a cumulative effect of a change in
accounting principle.  Because Enron currently records its
trading activities at fair value, management believes that the
adoption of EITF 98-10 will not have a materially adverse impact
on its financial position or results of operations.

FINANCIAL CONDITION

<TABLE>
Cash Flows

<CAPTION>
(In Millions)                 1998      1997      1996

<S>                         <C>       <C>       <C> 
Cash provided by (used in):
   Operating activities     $ 1,640   $   211   $   884
   Investing activities     (3,965)   (2,146)   (1,074)
   Financing activities       2,266     1,849       331
</TABLE>

   Net cash provided by operating activities increased $1,429
million in 1998, reflecting positive operating cash flow from
Enron's major business segments other than Retail Energy
Services, which continued investing in its new business.
Operating cash flow in 1998 also included proceeds from sales of
interests in energy-related financial assets and cash from timing
and other changes related to Enron's commodity portfolio.  New
investments in merchant assets and investments totaling $721
million partially offset these increases.  See Note 4 to the
Consolidated Financial Statements.  The decrease of $673 million
in 1997 was primarily a result of a cash payment of $440 million
made in connection with the resolution of the J-Block gas
contract.

   Net cash used in investing activities primarily reflects
increased capital expenditures and equity investments, which
total $3,564 million in 1998, $2,092 million in 1997 and $1,483
million in 1996.  See "Capital Expenditures and Equity
Investments" below.  Partially offsetting these uses of cash were
proceeds from the sales of assets totaling $239 million in 1998,
$473 million in 1997 and $477 million in 1996.  These proceeds
were primarily from the sales of liquids assets in 1997 and from
the sales of 12 million shares of EOG common stock held by Enron
and non-strategic gathering and processing assets in 1996.

   Cash provided by financing activities in 1998 included $875
million from the net issuance of short- and long-term debt, $867
million from the issuance of common stock and $828 million
primarily from the sale of a minority interest in a subsidiary
(see Note 8 to the Consolidated Financial Statements), partially
offset by payments of $414 million for dividends.  Cash provided
by financing activities in 1997 was generated from net issuances
of $1,674 million of short- and long-term debt, $372 million of
preferred securities by subsidiary companies and $555 million of
subsidiary equity (see Note 8 to the Consolidated Financial
Statements).  These inflows were partially offset by payments of
$354 million for cash dividends and $422 million for treasury
stock.  Primary cash inflows from financing activities during
1996 included $282 million from the net issuance of short- and
long-term debt, $215 million from the issuance of preferred
securities by subsidiary companies and $102 million from the
issuance of Enron common stock.  Cash outflows in 1996 included
cash dividend payments of $281 million.

Working Capital
   At December 31, 1998, Enron had a working capital deficit of
$174 million.  Enron has credit facilities in place to fund
working capital requirements.  At December 31, 1998, those credit
lines provided for up to $3.4 billion of committed and
uncommitted credit, of which $149 million was outstanding at
December 31, 1998.  Certain of the credit agreements contain
prefunding covenants.  However, such covenants are not expected
to restrict Enron's access to funds under these agreements.  In
addition, Enron sells commercial paper and has agreements to sell
trade accounts receivable, thus providing financing to meet
seasonal working capital needs.  Management believes that the
sources of funding described above are sufficient to meet short-
and long-term liquidity needs not met by cash flows from
operations.

Capital Expenditures and Equity Investments
   Capital expenditures by operating segment are as follows:

<TABLE>
<CAPTION>
                                 1999
(In Millions)                  Estimate   1998     1997     1996

<S>                             <C>      <C>      <C>       <C>
Exploration and Production(a)   $  550   $  690   $  626    $540
Transportation and Distribution    310      310      337     175
Wholesale Energy Operations 
 and Services                      410     706       318     136
Retail Energy Services              40       75       36       -
Corporate and Other                300      124       75      13
  Total                         $1,610   $1,905   $1,392    $864

<FN>
(a) Excludes exploration expenses of $70 million (estimate),
    $89 million, $75 million and $68 million for 1999, 1998, 1997
    and 1996, respectively.
</TABLE>

   Capital expenditures increased $513 million in 1998 and $528
million during 1997 as compared to the previous year.  During
1998, increased expenditures in Exploration and Production were
primarily a result of the acquisition of producing properties in
the Gulf of Mexico, and Enron Wholesale expenditures increased
primarily related to domestic and international power plant
construction.  During 1997, increased expenditures in Exploration
and Production reflect increased development expenditures in the
United States and increased property acquisitions in Canada.
Transportation and Distribution expenditures increased due to
expansion projects by the interstate natural gas pipelines.
Included in Enron Wholesale were send-or-pay payments totaling
$63 million in 1998 and $167 million in 1997 related to a
transportation agreement in the U.K.

   Cash used for equity investments by the operating segments is
as follows:

<TABLE>
<CAPTION>
                                 1999
(In Millions)                  Estimate  1998    1997    1996

<S>                             <C>     <C>      <C>     <C>
Exploration and Production      $   80  $    -   $  -    $  -
Transportation and Distribution    120      27      3       -
Wholesale Energy Operations 
 and Services                      600    703     580     511
Retail Energy Services             210       -      -       -
Corporate and Other                120     929    117     108
  Total                         $1,130  $1,659   $700    $619
</TABLE>

   Equity investments increased in 1998 as compared to 1997
primarily due to the acquisitions of Elektro and Wessex, net of
proceeds from transactions reducing Enron's interest in these
investments.  See Note 9 to the Consolidated Financial
Statements.

   The level of spending for capital expenditures and equity
investments will vary depending upon conditions in the energy
markets, related economic conditions and identified
opportunities.  Management expects that the capital spending
program will be funded by a combination of internally generated
funds, proceeds from dispositions of selected assets, short- and
long-term borrowings and proceeds from the sale of common stock
in February 1999.

CAPITALIZATION

   Total capitalization at December 31, 1998 was $17.5 billion.
Debt as a percentage of total capitalization decreased to 41.9%
at December 31, 1998 as compared to 44.6% at December 31, 1997.
The decrease primarily reflects the issuance during 1998 of
approximately 17 million shares of common stock and the
conversion in late 1998 of 10.5 million Exchangeable Notes into
EOG shares held by Enron, partially offset by increased debt and
minority interests.

   Enron is a party to certain financial contracts which contain
provisions for early settlement in the event of a significant
market price decline in which Enron's common stock falls below
certain levels (prices ranging from $15 to $37.84 per share) or
if the credit ratings for Enron's unsecured, senior long-term
debt obligations fall below investment grade.  The impact of this
early settlement could include the issuance of additional shares
of Enron common stock.

   Enron's senior unsecured long-term debt is currently rated
BBB+ by Standard & Poor's Corporation and Baa2 by Moody's
Investor Services.  Enron's continued investment grade status is
critical to the success of its wholesale businesses as well as
its ability to maintain adequate liquidity.  Enron's management
believes it will be able to maintain or improve its credit
rating.

   In February 1999, Enron issued 13.8 million shares of common
stock in a public offering and approximately 3.8 million shares
of common stock in connection with the acquisition of certain
assets.

   Enron has investments in entities whose functional currency is
denominated in Brazilian Reals.  Subsequent to December 31, 1998
the exchange rate for Brazilian Reals to the U.S. dollar has
declined.  As a result, Enron anticipates recording a non-cash
foreign currency translation adjustment, reducing shareholders'
equity, in the first quarter of 1999.  Based on the exchange rate
in mid-February, the equity reduction would be approximately $600
million.

Item 7A.  FINANCIAL RISK MANAGEMENT

   Enron Wholesale offers price risk management services
primarily related to commodities associated with the energy
sector (natural gas, crude oil, natural gas liquids and
electricity).  These services are provided through a variety of
financial instruments including forward contracts, which may
involve physical delivery of an energy commodity, swap
agreements, which may require payments to (or receipt of payments
from) counterparties based on the differential between a fixed
and variable price for the commodity, options and other
contractual arrangements. Interest rate risks and foreign
currency risks associated with the fair value of its energy
commodities portfolio are managed in this segment using a variety
of financial instruments, including financial futures, swaps and
options.

   In order to mitigate the risk associated with its merchant
investments, Enron actively manages the systematic or market
risks inherent in the investments.  Using various analytical
methods, Enron generally disaggregates and manages the equity
index, interest rate and commodity risks embedded in the
investments, leaving the specific asset or idiosyncratic risk
which is diversified among the investments.

   Enron's other businesses also enter into forwards, swaps and
other contracts primarily for the purpose of hedging the impact
of market fluctuations on assets, liabilities, production or
other contractual commitments.  Changes in the market value of
these hedge transactions are deferred until the gain or loss is
recognized on the hedged item.

   Management of the market risks associated with its portfolio
of transactions is critical to the success of Enron. Therefore,
comprehensive risk management processes, policies and procedures
have been established to monitor and control these market risks.

   Enron manages market risk on a portfolio basis, subject to
parameters established by its Board of Directors. Market risks
are monitored by an independent risk control group operating
separately from the units that create or actively manage these
risk exposures to ensure compliance with Enron's stated risk
management policies.  Enron's fixed price commodity contract
portfolio is typically balanced to within an annual average of 1%
of the total notional physical and financial transaction volumes
marketed.

Market Risk
   The use of financial instruments by Enron's businesses may
expose Enron to market and credit risks resulting from adverse
changes in commodity and equity prices, interest rates and
foreign exchange rates.  For Enron's Wholesale businesses, the
major market risks are discussed below:

   Commodity Price Risk.  Commodity price risk is a consequence
of providing price risk management services to customers as well
as owning and operating production facilities. As discussed
above, Enron actively manages this risk on a portfolio basis to
ensure compliance with Enron's stated risk management policies.
Forwards, futures, swaps and options are utilized to manage
Enron's consolidated exposure to price fluctuations related to
production from its production facilities.

   Interest Rate Risk. Interest rate risk is also a consequence
of providing price risk management services to customers and
having variable rate debt obligations, as changing interest rates
impact the discounted value of future cash flows. Enron utilizes
swaps, forwards, futures and options to manage its interest rate
risk.

   Foreign Currency Exchange Rate Risk. Foreign currency exchange
rate risk is the result of Enron's international operations and
price risk management services provided to its worldwide customer
base.  The primary purpose of Enron's foreign currency hedging
activities is to protect against the volatility associated with
foreign currency purchase and sale transactions. Enron primarily
utilizes forward exchange contracts, futures and purchased
options to manage Enron's risk profile.

     Equity Risk. Equity risk arises from the energy assets and
investments operations of Enron Wholesale, which provides capital
to customers through equity participations in various investment
activities.  Enron manages this risk by disaggregating the market
risks (such as equity index, interest rate and commodity risks)
from the individual investments and managing these risks on a
portfolio basis through the use of futures, forwards, swaps and
options to ensure compliance with Enron's stated risk management
policies.  The idiosyncratic risk or specific risk is managed on
both an individual and portfolio basis within the risk management
polices.

   Enron measures the market risk in its investments on a daily
basis utilizing value at risk and other methodologies.  The
quantification of market risk using value at risk provides a
consistent measure of risk across diverse energy markets and
products. The use of these methodologies requires a number of key
assumptions including the selection of a confidence level for
expected losses, the holding period for liquidation and the
treatment of risks outside the value at risk methodologies,
including liquidity risk and event risk.  Value at risk
represents an estimate of reasonably possible net losses in
earnings that would be recognized on its investments assuming
hypothetical movements in future market rates and no change in
positions.  This is not necessarily indicative of actual results
which may occur.

Value at Risk
     Enron has performed an entity-wide value at risk analysis of
virtually all of Enron's financial assets and liabilities.  Enron
utilizes value at risk in its daily business to evaluate, measure
and manage its overall risk exposure.  Value at risk incorporates
numerous variables that could impact the fair value of Enron's
investments, including commodity prices, interest rates, foreign
exchange rates, equity prices and associated volatilities, as
well as correlation within and across these variables.  Enron's
methodology includes the use of delta/gamma approximations for
option positions and relies to a certain extent on historical
correlations across commodity groups.   Enron estimates value at
risk commodity, interest rate and foreign exchange exposures
using a model based on Monte Carlo simulation of delta/gamma
positions which captures a significant portion of the exposure
related to option positions.  The value at risk for equity
exposure discussed above is based on J.P. Morgan's RiskMetricsT
approach utilizing historical estimates of volatility and
correlation.  Both value at risk methods utilize a one-day
holding period and a 95% confidence level.  Cross-commodity
correlations are used as appropriate.

   The use of value at risk models allows management to aggregate
risks across the company, compare risk on a consistent basis and
identify the drivers of risk.  Because of the inherent
limitations to value at risk, including the use of delta/gamma
approximations to value options, subjectivity in the choice of
liquidation period and reliance on historical data to calibrate
the models, Enron relies on value at risk as only one component
in its risk control process.  In addition to using value at risk
measures, Enron performs regular stress and scenario analyses to
estimate the economic impact of sudden market moves on the value
of its portfolios.  The results of the stress testing, along with
the professional judgment of experienced business and risk
managers, are used to supplement the value at risk methodology
and capture additional market-related risks, including
volatility, liquidity and event, concentration and correlation
risks.

   The following table illustrates the value at risk for each
component of market risk:

<TABLE>
<CAPTION>
                            December 31,       Year ended December 31, 1998
                                                           High           Low
(In Millions)               1998   1997   Average(a)   Valuation(a)   Valuation(a)

<S>                          <C>   <C>      <C>           <C>            <C>
Trading Market Risk:
  Commodity price            $20   $25      $25           $47(b)         $17
  Interest rate                -     -        2             4              -
  Foreign currency
   exchange rate               -     1        2             3              -
  Equity                      12     4        6            12              3

Non-Trading Market Risk(c):
  Commodity price             10     9       13            19              6
  Interest rate                -     -        -             1              -
  Foreign currency
   exchange rate               -     1        -             -              -
  Equity                       -     -        -             -              -

<FN>
(a) The average values presents a twelve month average of the
    month end values.  The high and low valuations for each market
    risk component represent the highest and lowest month end
    value during 1998.
(b) In late June and early July 1998, significant price
    swings in the U.S. power markets caused Enron's value at risk
    to increase significantly for a period of less than a month
    before returning to normal levels.
(c) Includes only the risk related to the financial
    instruments that serve as hedges and does not include the
    related underlying hedged item.
</TABLE>

Accounting Policies
   Accounting policies for price risk management and hedging
activities are described in Note 1 to the Consolidated Financial
Statements.


                      INFORMATION REGARDING
                   FORWARD LOOKING STATEMENTS

   This Annual Report 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
Enron 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 in foreign countries; the
ability of Enron to penetrate new retail natural gas and
electricity markets in the United States and Europe; the timing
and extent of deregulation of energy markets in the United States
and in foreign jurisdictions; other regulatory developments in
the United States and in foreign countries, including tax
legislation and regulations; the extent of efforts by governments
to privatize natural gas and electric utilities and other
industries; the timing and extent of changes in commodity prices
for crude oil, natural gas, electricity, foreign currency and
interest rates; the extent of EOG's success in acquiring oil and
gas properties and in discovering, developing, producing and
marketing reserves; the timing and success of Enron's efforts to
develop international power, pipeline, water and other
infrastructure projects; the ability of counterparties to
financial risk management instruments and other contracts with
Enron to meet their financial commitments to Enron; Enron's
success in implementing its Year 2000 Plan, the effectiveness of
Enron's Year 2000 Plan, and the Year 2000 readiness of Outside
Entities; and Enron's ability to access the capital markets and
equity markets during the periods covered by the forward looking
statements, which will depend on general market conditions and
Enron's ability to maintain or increase the credit ratings for
its unsecured senior long-term debt obligations.

Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The information required hereunder is included in this
report as set forth in the "Index to Financial Statements"
on page F-1.

Item 9.  DISAGREEMENTS ON ACCOUNTING AND FINANCIAL
         DISCLOSURE

     None.
         
<PAGE>
                          PART III

Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The information required by Item 10 of Form 10-K
relating to directors who are nominees for election as
directors at Enron's Annual Meeting of Shareholders to be
held on May 4, 1999 is set forth under the caption entitled
"Election of Directors" in Enron's Proxy Statement, and is
incorporated herein by reference.

     The information required by Item 10 of Form 10-K with
respect to executive officers is set forth in Part I of this
Form 10-K under the heading "Current Executive Officers of
the Registrant".

     Section 16(a) of the Securities Exchange Act of 1934
requires Enron's executive officers and directors, and
persons who own more than 10% of a registered class of
Enron's equity securities, to file reports of ownership and
changes in ownership with the SEC and the New York Stock
Exchange.  Based solely on its review of the copies of such
reports received by it, or written representations from
certain reporting persons that no Forms 5 were required for
those persons, Enron believes that during 1998, its
executive officers, directors and greater than 10%
shareholders complied with all applicable filing
requirements, with the exception of one 10% shareholder who
did not timely file two reports relating to a total of six
transactions, and one executive officer who did not timely
file his Form 3 Initial Statement of Beneficial Ownership.

     There are no family relationships among the officers
listed, and there are no arrangements or understandings
pursuant to which any of them were elected as officers.
Officers are appointed or elected annually by the Board of
Directors at its first meeting following the Annual Meeting
of Shareholders, each to hold office until the corresponding
meeting of the Board in the next year or until a successor
shall have been elected, appointed or shall have qualified.

Item 11.  EXECUTIVE COMPENSATION

     The information regarding executive compensation is set
forth in the Proxy Statement under the captions
"Compensation of Directors and Executive Officers - Director
Compensation; Executive Compensation; Stock Option Grants
During 1998; Aggregated Stock Option/SAR Exercises During
1998 and Stock Option/SAR Values as of December 31, 1998;
Long-Term Incentive Plan - Awards in 1998; Retirement and
Supplemental Benefit Plans; Severance Plans; Employment
Contracts; Certain Transactions; and Compensation Committee
Interlocks and Insider Participation", and is incorporated
herein by reference.

Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
          AND MANAGEMENT

 (a) Security ownership of certain beneficial owners

     The information regarding security ownership of certain 
     beneficial owners is set forth in the Proxy Statement under 
     the caption "Election of Directors - Security Ownership of 
     Certain Beneficial Owners", and is incorporated herein by
     reference.

 (b) Security ownership of management

     The information regarding security ownership of management 
     is set forth in the Proxy Statement under the caption 
     "Election of Directors - Stock Ownership of Management 
     and Board of Directors as of February 15, 1999", and is 
     incorporated herein by reference.

 (c) Changes in control

      None.

Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information regarding certain relationships and
related transactions is set forth in the Proxy Statement
under the caption "Certain Transactions" and "Compensation
Committee Interlocks and Insider Participation", and is
incorporated herein by reference.

<PAGE>
                           PART IV

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

(a)(1) and (2) Financial Statements and Financial Statement
Schedules.  See "Index to Financial Statements" set forth on
page F-1.

(a)(3)   Exhibits:

      *3.01  - Amended and Restated Articles of
               Incorporation of Enron (Annex E to the Proxy
               Statement/Prospectus included in Enron's
               Registration Statement on Form S-4 - File No.
               333-13791).

      *3.02  - Articles of Merger of Enron Oregon
               Corp., an Oregon corporation, and Enron
               Corp., a Delaware corporation (Exhibit 3.02
               to Post-Effective Amendment No. 1 to Enron's
               Registration Statement on Form S-3 - File No.
               33-60417).

      *3.03  - Articles of Merger of Enron Corp.,
               an Oregon corporation, and Portland General
               Corporation, an Oregon corporation (Exhibit
               3.03 to Post-Effective Amendment No. 1 to
               Enron's Registration Statement on Form S-3 -
               File No. 33-60417).

      *3.04  - Bylaws of Enron (Exhibit 3.04 to
               Post-Effective Amendment No. 1 to Enron's
               Registration Statement on Form S-3 - File No.
               33-60417).

      *3.05  - Form of Series Designation for the
               Enron Convertible Preferred Stock (Annex F to
               the Proxy Statement/Prospectus included in
               Enron's Registration Statement on Form S-4 -
               File No. 333-13791).

      *3.06  - Form of Series Designation for the
               Enron 9.142% Preferred Stock (Annex G to the
               Proxy Statement/Prospectus included in
               Enron's Registration Statement on Form S-4 -
               File No. 333-13791).

      *3.07  - Statement of Resolutions
               Establishing Series A Junior Voting
               Convertible Preferred Stock (Exhibit 3.07 to
               Enron's Registration Statement on Form S-3 -
               File No. 333-44133).

      *3.08  - Statement of Resolutions
               Establishing A Series of Preferred Stock of
               Enron Corp. - Mandatorily Convertible Single
               Reset Preferred Stock, Series A (Exhibit 4.01
               to Enron's Form 8-K filed on January 26,
               1999).

      *3.09  - Statement of Resolutions
               Establishing A Series of Preferred Stock of
               Enron Corp. - Mandatorily Convertible Single
               Reset Preferred Stock, Series B (Exhibit 4.02
               to Enron's Form 8-K filed on January 26,
               1999).

      *4.01  - Indenture dated as of November 1,
               1985, between Enron and Harris Trust and
               Savings Bank, as supplemented and amended by
               the First Supplemental Indenture dated as of
               December 1, 1995 (Form T-3 Application for
               Qualification of Indentures under the Trust
               Indenture Act of 1939, File No. 22-14390,
               filed October 24, 1985; Exhibit 4(b) to Form
               S-3 Registration Statement No. 33-64057 filed
               on November 8, 1995).  There have not been
               filed as exhibits to this Form 10-K other
               debt instruments defining the rights of
               holders of long-term debt of Enron, none of
               which relates to authorized indebtedness that
               exceeds 10% of the consolidated assets of
               Enron and its subsidiaries.  Enron hereby
               agrees to furnish a copy of any such
               instrument to the Commission upon request.

      *4.02 -  Supplemental Indenture, dated
               as of May 8, 1997, by and among Enron Corp.,
               Enron Oregon Corp. and Harris Trust and
               Savings Bank, as Trustee (Exhibit 4.02 to
               Post-Effective Amendment No. 1 to Enron's
               Registration Statement on Form S-3, File No.
               33-60417).

      *4.03  - Form of Supplemental Indenture,
               dated as of September 1, 1997, between Enron
               Corp. and Harris Trust and Savings Bank, as
               Trustee (Exhibit 4.03 to Enron Registration
               Statement on Form S-3, File No. 333-35549).

      *4.04  - Form of Amended and Restated
               Agreement of Limited Partnership of Enron
               Capital Resources, L.P. (Exhibit 3.1 to Enron
               Form 8-K dated August 2, 1994).

      *4.05  - Form of Payment and Guarantee
               Agreement dated as of August 3, 1994,
               executed by Enron Corp. for the benefit of
               the holders of Enron Capital Resources, L.P.
               9% Cumulative Preferred Securities, Series A
               (Exhibit 4.1 to Enron Form 8-K dated August
               2, 1994).

      *4.06  - Form of Loan Agreement, dated as of
               August 3, 1994, between Enron Corp. and Enron
               Capital Resources, L.P.  (Exhibit 4.2 to
               Enron Form 8-K dated August 2, 1994).

      *4.07  - Articles of Association of Enron
               Capital LLC (Exhibit 9 to Enron Corp. Form 8-K
               dated November 12, 1993).

      *4.08  - Form of Payment and Guarantee
               Agreement of Enron Corp., dated as of
               November 15, 1993, in favor of the holders of
               Enron Capital LLC 8% Cumulative Guaranteed
               Monthly Income Preferred Shares (Exhibit 2 to
               Enron Form 8-K dated November 12, 1993).

      *4.09  - Form of Loan Agreement, dated as of
               November 15, 1993, between Enron Corp. and
               Enron Capital LLC (Exhibit 3 to Enron Form 8-
               K dated November 12, 1993).


     Executive Compensation Plans and Arrangements Filed as
     Exhibits Pursuant to Item 14(c) of Form 10-K:  Exhibits
     10.01 through 10.43

     *10.01  - Enron Executive Supplemental
               Survivor Benefits Plan, effective January 1,
               1987 (Exhibit 10.01 to Enron Form 10-K for
               1992).

    *10.02  -  First Amendment to Enron
               Executive Supplemental Survivor Benefits Plan
               (Exhibit 10.02 to Enron Form 10-K for 1995).

     *10.03  - Enron Corp. 1988 Stock Plan
               (Exhibit 4.3 to Form S-8 Registration
               Statement No. 33-27893).

     *10.04  - Second Amendment to Enron Corp.
               1988 Stock Plan (Exhibit 10.04 to Enron Form
               10-K for 1996).

     *10.05  - Enron Corp. 1988 Deferral Plan
               (Exhibit 10.19 to Enron Form 10-K for 1987).

     *10.06  - First Amendment to Enron Corp. 1988
               Deferral Plan (Exhibit 10.06 to Enron Form 10-K
               for 1995).

     *10.07  - Second Amendment to Enron Corp.
               1988 Deferral Plan (Exhibit 10.07 to Enron
               Form 10-K for 1995).

     *10.08  - Third Amendment to Enron Corp. 1988
               Deferral Plan (Exhibit 10.09 to Enron Form 10-K
               for 1996).

     *10.09  - Fourth Amendment to Enron Corp.
               1988 Deferral Plan (Exhibit 10.10 to Enron
               Form 10-K for 1996).

     *10.10  - Fifth Amendment to Enron Corp. 1988
               Deferral Plan (Exhibit 10.11 to Enron Form 10-K
               for 1996).

     *10.11  - Enron Corp. 1991 Stock Plan
               (Exhibit 10.08 to Enron Form 10-K for 1991).

     *10.12  - Amended and Restated Enron Corp.
               1991 Stock Plan (Exhibit A to Enron Proxy
               Statement filed pursuant to Section 14(a) on
               March 24, 1997).

     *10.13  - First Amendment to Enron Corp.
               Amended and Restated 1991 Stock Plan (Exhibit
               10.13 to Enron Form 10-K for 1997).

     *10.14  - Second Amendment to Enron Corp.
               Amended and Restated 1991 Stock Plan (Exhibit
               10.14 to Enron Form 10-K for 1997).

     *10.15  - Enron Corp. 1992 Deferral Plan
               (Exhibit 10.09 to Enron Form 10-K for 1991).

     *10.16  - First Amendment to Enron Corp. 1992
               Deferral Plan (Exhibit 10.10 to Enron Form 10-K
               for 1995).

     *10.17  - Second Amendment to Enron Corp.
               1992 Deferral Plan (Exhibit 10.11 to Enron
               Form 10-K for 1995).

     *10.18  - Enron Corp. Directors' Deferred
               Income Plan (Exhibit 10.09 to Enron Form 10-K
               for 1992).

     *10.19  - Split Dollar Life Insurance
               Agreement between Enron and the KLL and LPL
               Family Partnership, Ltd., dated April 22,
               1994 (Exhibit 10.17 to Enron Form 10-K for
               1994).

     *10.20  - Employment Agreement between Enron
               Corp. and Kenneth L. Lay, executed December
               18, 1996 (Exhibit 10.25 to Enron Form 10-K
               for 1996).

     *10.21  - Consulting Services Agreement
               between Enron and John A. Urquhart dated
               August 1, 1991 (Exhibit 10.23 to Enron Form
               10-K for 1991).

     *10.22  - First Amendment to Consulting
               Services Agreement between Enron and John A.
               Urquhart, dated August 27, 1992 (Exhibit
               10.25 to Enron Form 10-K for 1992).

     *10.23  - Second and Third Amendments to
               Consulting Services Agreement between Enron
               and John A. Urquhart, dated November 24, 1992
               and February 26, 1993, respectively (Exhibit
               10.26 to Enron Form 10-K for 1992).

     *10.24  - Fourth Amendment to Consulting
               Services Agreement between Enron and John A.
               Urquhart dated as of May 9, 1994 (Exhibit
               10.35 to Enron Form 10-K for 1995).

     *10.25  - Fifth Amendment to Consulting
               Services Agreement between Enron and John A.
               Urquhart (Exhibit 10.36 to Enron Form 10-K
               for 1995).

     *10.26  - Sixth Amendment to Consulting
               Services Agreement between Enron and John A.
               Urquhart (Exhibit 10.37 to Enron Form 10-K
               for 1995).

     *10.27  - Seventh Amendment to Consulting
               Services Agreement between Enron and John A.
               Urquhart, dated October 27, 1997 (Exhibit
               10.27 to Enron Form 10-K for 1997).

      10.28  - Eighth Amendment to Consulting
               Services Agreement between Enron and John A.
               Urquhart, dated May 27, 1998.

      10.29  - Ninth Amendment to Consulting
               Services Agreement between Enron and John A.
               Urquhart, dated December 31, 1998.

     *10.30  - Enron Corp. Performance Unit Plan
               (Exhibit A to Enron Proxy Statement filed
               pursuant to Section 14(a) on March 25, 1994).

     *10.31  - Enron Corp. Annual Incentive Plan
               (Exhibit B to Enron Proxy Statement filed
               pursuant to Section 14(a) on March 25, 1994).

     *10.32  - Enron Corp. Performance Unit Plan
               (as amended and restated effective May 2,
               1995) (Exhibit A to Enron Proxy Statement
               filed pursuant to Section 14(a) on March 27,
               1995).

     *10.33  - First Amendment to Enron Corp.
               Performance Unit Plan (Exhibit 10.46 to Enron
               Form 10-K for 1995).

     *10.34  - Enron Corp. Restated 1994 Deferral
               Plan (Exhibit 4.3 to Enron Form S-8
               Registration Statement, File No. 333-48193).

     *10.35  - Employment Agreement between Enron
               Capital Trade & Resources Corp. and Jeffrey
               K. Skilling, dated January 1, 1996 (Exhibit
               10.63 to Enron Form 10-K for 1996).

     *10.36  - First Amendment effective January
               1, 1997, by and among Enron Corp., Enron
               Capital & Trade Resources Corp., and Jeffrey
               K. Skilling, amending Employment Agreement
               between Enron Capital & Trade Resources Corp.
               and Jeffrey K. Skilling dated January 1, 1996
               (Exhibit 10.64 to Enron Form 10-K for 1996).

     *10.37  - Split Dollar Agreement between
               Enron and Jeffrey K. Skilling dated May 23,
               1997 (Exhibit 10.41 to Enron Form 10-K for
               1997).

     *10.38  - Second Amendment effective October
               13, 1997, to Employment Agreement between
               Enron Corp. and Jeffrey K. Skilling (Exhibit
               10.42 to Enron Form 10-K for 1997).

     *10.39  - Loan Agreement effective October
               13, 1997, between Enron Corp. and Jeffrey K.
               Skilling (Exhibit 10.43 to Enron Form 10-K
               for 1997).

     *10.40  - Employment Agreement dated July 20,
               1996 (effective July 1, 1997) between Enron
               and Ken L. Harrison (Exhibit 10.1 to Post-
               Effective Amendment No. 1 to Enron's
               Registration Statement on Form S-4, File No.
               333-13791).

      10.41  - Executive Employment Agreement
               between Enron Corp. and Rebecca P. Mark,
               effective May 4, 1998.

      10.42  - Executive Employment Agreement
               between Enron Corp. and Joseph W. Sutton,
               effective June 23, 1998.

      10.43  - Executive Employment Agreement
               between Enron Corp. and Kenneth D. Rice,
               effective June 1, 1998.

      12     - Statement re computation of ratios
               of earnings to fixed charges.


      21     - Subsidiaries of registrant.

      23.01  - Consent of Arthur Andersen LLP.

      23.02  - Consent of DeGolyer and
               MacNaughton.

      23.03  - Letter Report of DeGolyer and
               MacNaughton dated January 11, 1999.

      24     - Powers of Attorney for the
               directors signing this Form 10-K.

      27     - Financial Data Schedule.


* Asterisk indicates exhibits incorporated
  by reference.

(b)  Reports on Form 8-K

     Current Report on Form 8-K filed October 16, 1998, as
     amended by Form 8-K/A filed on November 6, 1998.

     Current Report on Form 8-K filed March 18, 1999.


<PAGE>
                 INDEX TO FINANCIAL STATEMENTS

                          ENRON CORP.

                                                           Page No.

Consolidated Financial Statements



  Report of Independent Public Accountants                   F-2

  Consolidated Income Statement and Consolidated Statement
  of Comprehensive Income for the years ended December 31,
  1998, 1997 and 1996                                        F-3

  Consolidated Balance Sheet as of December 31, 1998 and
  1997                                                       F-4

  Consolidated Statement of Cash Flows for the years
  ended December 31, 1998, 1997 and 1996                     F-6

  Consolidated Statement of Changes in Shareholders'
  Equity Accounts for the years ended December 31,
  1998, 1997 and 1996                                        F-7

  Notes to the Consolidated Financial Statements             F-8

Financial Statements Schedule

  Report of Independent Public Accountants on
  Financial Statement Schedule                               S-1

  Schedule II  -  Valuation and Qualifying Accounts          S-2


  Other financial statement schedules have been omitted
because they are inapplicable or the information required
therein is included elsewhere in the financial statements or
notes thereto.


<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and Board of Directors of Enron Corp.:

   We have audited the accompanying consolidated balance sheet of
Enron Corp. (an Oregon corporation) and subsidiaries as of
December 31, 1998 and 1997, and the related consolidated
statements of income, comprehensive income, cash flows and
changes in shareholders' equity for each of the three years in
the period ended December 31, 1998. These financial statements
are the responsibility of Enron Corp.'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 Enron Corp. and subsidiaries as of December 31, 1998 and 1997,
and the results of their operations, cash flows and changes in
shareholders' equity for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted
accounting principles.





                         Arthur Andersen LLP

Houston, Texas
March 5, 1999



<PAGE>
<TABLE>
                  ENRON CORP. AND SUBSIDIARIES
                  CONSOLIDATED INCOME STATEMENT

<CAPTION>
                                               Year Ended December 31,
(In Millions, except Per Share Amounts)        1998      1997      1996                                          

<S>                                          <C>       <C>       <C>
Revenues
  Natural gas and other products             $13,276   $13,211   $11,157
  Electricity                                 13,939     5,101       980
  Transportation                                 627       652       707
  Other                                        3,418     1,309       445
     Total Revenues                           31,260    20,273    13,289
Costs and Expenses
  Cost of gas, electricity and
   other products                             26,381    17,311    10,478
  Operating expenses                           2,352     1,406     1,421
  Oil and gas exploration expenses               121       102        89
  Depreciation, depletion and
   amortization                                  827       600       474
  Taxes, other than income taxes                 201       164       137
  Contract restructuring charge                    -       675         -
     Total Costs and Expenses                 29,882    20,258    12,599
Operating Income                               1,378        15       690
Other Income and Deductions
  Equity in earnings of unconsolidated
   affiliates                                     97       216       215
  Gains on sales of assets and investments        56       186       274
  Other income, net                               51       148        59
Income Before Interest, Minority
 Interests and Income Taxes                    1,582       565     1,238
Interest and Related Charges, net                550       401       274
Dividends on Company-Obligated Preferred
 Securities of Subsidiaries                       77        69        34
Minority Interests                                77        80        75
Income Tax Expense (Benefit)                     175       (90)      271
Net Income                                       703       105       584
Preferred Stock Dividends                         17        17        16
Earnings on Common Stock                     $   686   $    88   $   568
Earnings Per Share of Common Stock
  Basic                                      $  2.14   $  0.32   $  2.31
  Diluted                                    $  2.02   $  0.32   $  2.16
Average Number of Common Shares Used
 in Computation
  Basic                                          321       272       246
  Diluted                                        348       277       270


                  ENRON CORP. AND SUBSIDIARIES
         CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

                                               Year Ended December 31,
(In Millions)                                  1998      1997      1996

Earnings on Common Stock                     $   686   $    88   $   568
Other comprehensive income:
  Foreign currency translation adjustment        (14)      (21)       26
Total Comprehensive Income                   $   672   $    67   $   594

<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
    
            
<PAGE>
<TABLE>
                
                ENRON CORP. AND SUBSIDIARIES
                 CONSOLIDATED BALANCE SHEET

<CAPTION>
                                                  December 31,
(In Millions)                                  1998         1997

<S>                                          <C>         <C>
ASSETS
Current Assets
  Cash and cash equivalents                  $   111     $   170
  Trade receivables (net of allowance
   for doubtful accounts of $14 and
   $11, respectively)                          2,060       1,372
  Other receivables                              833         454
  Assets from price risk management
   activities                                  1,904       1,346
  Inventories                                    514         136
  Other                                          511         635
     Total Current Assets                      5,933       4,113

Investments and Other Assets
  Investments in and advances to
   unconsolidated affiliates                   4,433       2,656
  Assets from price risk management
   activities                                  1,941       1,038
  Goodwill                                     1,949       1,910
  Other                                        4,437       3,665
     Total Investments and Other Assets       12,760       9,269

Property, Plant and Equipment, at cost
  Exploration and Production, successful
   efforts method                              4,814       4,291
  Transportation and Distribution              5,481       5,279
  Wholesale Energy Operations and Services     4,858       3,879
  Retail Energy Services                         141          44
  Corporate and Other                            498         249
                                              15,792      13,742
  Less accumulated depreciation,
   depletion and amortization                  5,135       4,572
     Property, Plant and Equipment, net       10,657       9,170

Total Assets                                 $29,350     $22,552

<FN>
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>

<PAGE>
<TABLE>
                ENRON CORP. AND SUBSIDIARIES
                 CONSOLIDATED BALANCE SHEET

<CAPTION>
                                                 December 31,
(In Millions, except Shares)                  1998         1997

<S>                                          <C>         <C>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
  Accounts payable                           $ 2,380     $ 1,794
  Liabilities from price risk
   management activities                       2,511       1,245
  Other                                        1,216         817
     Total Current Liabilities                 6,107       3,856

Long-Term Debt                                 7,357       6,254

Deferred Credits and Other Liabilities
  Deferred income taxes                        2,357       2,039
  Liabilities from price risk
   management activities                       1,421         876
  Other                                        1,916       1,769
     Total Deferred Credits and
      Other Liabilities                        5,694       4,684
Commitments and Contingencies
 (Notes 3, 13, 14 and 15)
Minority Interests                             2,143       1,147

Company-Obligated Preferred Securities
 of Subsidiaries                               1,001         993

Shareholders' Equity
  Second preferred stock, cumulative, no par
   value, 1,370,000 shares authorized,
   1,319,848 shares and 1,337,645 shares of
   Cumulative Second Preferred Convertible
   Stock issued, respectively                    132         134
  Common stock, no par value, 600,000,000
   shares authorized, 335,547,276 shares
   and 318,297,276 shares issued,
   respectively                                5,117       4,224
  Retained earnings                            2,226       1,852
  Accumulated other comprehensive income        (162)       (148)
  Common stock held in treasury, 4,666,661
   shares and 7,050,965 shares,
   respectively                                 (195)       (269)
  Other                                          (70)       (175)
     Total Shareholders' Equity                7,048       5,618

Total Liabilities and Shareholders' Equity   $29,350     $22,552

<FN>
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>

                   
<PAGE>
<TABLE>
                       ENRON CORP. AND SUBSIDIARIES
                   CONSOLIDATED STATEMENT OF CASH FLOWS

<CAPTION>
                                               Year Ended December 31,
(In Millions)                                  1998      1997      1996

<S>                                          <C>       <C>       <C> 
Cash Flows From Operating Activities
Reconciliation of net income to net
 cash provided by operating activities
  Net income                                 $   703   $   105   $   584
  Depreciation, depletion and amortization       827       600       474
  Oil and gas exploration expenses               121       102        89
  Deferred income taxes                           87      (174)      207
  Gains on sales of assets and investments       (82)     (195)     (274)
  Changes in components of working
   capital                                      (233)      (65)      142
  Net assets from price risk management
   activities                                    350       201        15
  Merchant assets and investments:
     Realized gains on sales                    (628)     (136)        -
     Proceeds from sales                       1,434       339         -
     Additions                                  (721)     (308)     (192)
  Other operating activities                    (218)     (258)     (161)
Net Cash Provided by Operating
 Activities                                    1,640       211       884
Cash Flows From Investing Activities
  Capital expenditures                        (1,905)   (1,392)     (864)
  Equity investments                          (1,659)     (700)     (619)
  Proceeds from sales of investments and
   other assets                                  239       473       477
  Acquisition of subsidiary stock               (180)        -         -
  Business acquisitions, net of cash acquired
   (see Note 2)                                 (104)      (82)        -
  Other investing activities                    (356)     (445)      (68)
Net Cash Used in Investing Activities         (3,965)   (2,146)   (1,074)
Cash Flows From Financing Activities
  Issuance of long-term debt                   1,903     1,817       359
  Repayment of long-term debt                   (870)     (607)     (294)
  Net increase (decrease) in short-term 
   borrowings                                   (158)      464       217
  Issuance of company-obligated preferred
   securities of subsidiaries                      8       372       215
  Issuance of common stock                       867         -       102
  Issuance of subsidiary equity                  828       555         -
  Dividends paid                                (414)     (354)     (281)
  Net (acquisition) disposition of 
   treasury stock                                 13      (422)        5
  Other financing activities                      89        24         8
Net Cash Provided by Financing Activities      2,266     1,849       331
Increase (Decrease) in Cash and Cash 
 Equivalents                                     (59)      (86)      141
Cash and Cash Equivalents, Beginning
 of Year                                         170       256       115
Cash and Cash Equivalents, End of Year       $   111   $   170   $   256

Changes in Components of Working Capital
  Receivables                                $(1,055)  $   351   $  (678)
  Inventories                                   (372)       63       (53)
  Payables                                       433      (366)      870
  Other                                          761      (113)        3
     Total                                   $  (233)  $   (65)  $   142

<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
</TABLE>
                   

<PAGE>
<TABLE>
                       ENRON CORP. AND SUBSIDIARIES
         CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY

<CAPTION>
(In Millions, except Per Share                    1998               1997               1996
 Amounts; Shares in Thousands)              Shares    Amount   Shares    Amount   Shares    Amount

<S>                                         <C>       <C>      <C>       <C>      <C>       <C>
Cumulative Second Preferred
 Convertible Stock
  Balance, beginning of year                  1,338   $  134     1,371   $  137     1,375   $  138
  Exchange of common stock
   for convertible preferred stock              (18)      (2)      (33)      (3)       (4)      (1)
  Balance, end of year                        1,320   $  132     1,338   $  134     1,371   $  137
Common Stock
  Balance, beginning of year                318,297   $4,224   255,945   $   26   253,860   $   25
  Exchange of common stock
   for convertible preferred stock                -       (7)      382        -        19        -
  Issuances related to benefit
   and dividend reinvestment plans                -       45         -       (3)        -        -
  Sales of common stock                      17,250      836         -        -     2,066        1
  Issuances of common stock in business
   acquisitions (see Note 2)                      -        -    61,970    2,281         -        -
  Issuance of no par stock in
   reincorporation merger                         -        -         -    1,881         -        -
  Other                                           -       19         -       39         -        -
  Balance, end of year                      335,547   $5,117   318,297   $4,224   255,945   $   26
Additional Paid-in Capital
  Balance, beginning of year                          $    -             $1,870             $1,791
  Exchange of common stock
   for convertible preferred stock                         -                  1                 (1)
  Issuances related to benefit
   and dividend reinvestment plans                         -                 (9)               (16)
  Sales of common stock                                    -                 18                109
  Issuance of no par stock in
   reincorporation merger                                  -             (1,881)                 -
  Other                                                    -                  1                (13)
  Balance, end of year                                $    -             $    -             $1,870
Retained Earnings
  Balance, beginning of year                          $1,852             $2,007             $1,651
  Net income                                             703                105                584
  Cash dividends
     Common stock ($0.9625, $0.9125 and
      $0.8625 per share in 1998,
      1997 and 1996, respectively)                      (312)              (243)              (212)
     Preferred stock ($13.1402, $12.4584,
      and $11.7750 per share in 1998,
      1997 and 1996, respectively)                       (17)               (17)               (16)
  Balance, end of year                                $2,226             $1,852             $2,007
Accumulated Other Comprehensive Income -
 Cumulative Foreign Currency
 Translation Adjustment
  Balance, beginning of year                          $ (148)            $ (127)            $ (153)
  Translation adjustments                                (14)               (21)                26
  Balance, end of year                                $ (162)            $ (148)            $ (127)
Treasury Stock
  Balance, beginning of year                 (7,051)  $ (269)     (821)  $  (30)   (2,618)  $  (93)
  Shares acquired                            (1,118)     (61)   (9,790)    (374)   (2,226)     (85)
  Exchange of common stock
   for convertible preferred stock              243        9        70        3        46        2
  Issuances related to benefit
   and dividend reinvestment plans            3,213      124     2,838      106     2,249       81
  Sales of treasury stock                         -        -         -        -     1,728       65
  Issuances of treasury stock in
   business acquisitions (see Note 2)            46        2       652       26         -        -
  Balance, end of year                       (4,667)  $ (195)   (7,051)  $ (269)     (821)  $  (30)
Other
  Balance, beginning of year                          $ (175)            $ (160)            $ (194)
  Issuances related to benefit
   and dividend reinvestment plans                       105                (15)                34
  Balance, end of year                                $  (70)            $ (175)            $ (160)
Total Shareholders' Equity                            $7,048             $5,618             $3,723

<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
</TABLE>


<PAGE>
                  ENRON CORP. AND SUBSIDIARIES
         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


1  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

   Consolidation Policy and Use of Estimates.  The accounting and
financial reporting policies of Enron Corp. and its subsidiaries
conform to generally accepted accounting principles and
prevailing industry practices.  The consolidated financial
statements include the accounts of all majority-owned
subsidiaries of Enron Corp. after the elimination of significant
intercompany accounts and transactions.

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

   "Enron" is used from time to time herein as a collective
reference to Enron Corp. and its subsidiaries and affiliates.
The businesses of Enron are conducted by Enron Corp.'s
subsidiaries and affiliates whose operations are managed by their
respective officers.

   Cash Equivalents.  Enron records as cash equivalents all
highly liquid short-term investments with original maturities of
three months or less.

   Inventories.  Inventories consist primarily of commodities,
priced at market.

   Depreciation, Depletion and Amortization.  The provision for
depreciation and amortization with respect to operations other
than oil and gas producing activities is computed using the
straight-line or regulatorily mandated method, based on estimated
economic lives.  Composite depreciation rates are applied to
functional groups of property having similar economic
characteristics.  The cost of utility property units retired,
other than land, is charged to accumulated depreciation.

   Provisions for depreciation, depletion and amortization of
proved oil and gas properties are calculated using the units-of-
production method.

   Income Taxes.  Enron accounts for income taxes using an asset
and liability approach under which deferred tax assets and
liabilities are recognized based on anticipated future tax
consequences attributable to differences between financial
statement carrying amounts of assets and liabilities and their
respective tax bases (see Note 5).

   Earnings Per Share.  Basic earnings per share is computed
based upon the weighted-average number of common shares
outstanding during the periods.  Diluted earnings per share is
computed based upon the weighted-average number of common shares
plus the assumed issuance of common shares for all potentially
dilutive securities.  See Note 11 for additional information and
a reconciliation of the basic and diluted earnings per share
computations.

   Accounting for Price Risk Management.  Enron engages in price
risk management activities for both trading and non-trading
purposes.  Financial instruments utilized in connection with
trading activities are accounted for using the mark-to-market
method. Under the mark-to-market method of accounting, forwards,
swaps, options and other financial instruments with third parties
are reflected at market value, net of future physical delivery
related costs, and are shown as "Assets and Liabilities From
Price Risk Management Activities" in the Consolidated Balance
Sheet.  Unrealized gains and losses from newly originated
contracts, contract restructurings and the impact of price
movements are recognized as "Other Revenues."  Changes in the
assets and liabilities from price risk management activities
result primarily from changes in the valuation of the portfolio
of contracts, newly originated transactions and the timing of
settlement relative to the receipt of cash for certain contracts.
The market prices used to value these transactions reflect
management's best estimate considering various factors including
closing exchange and over-the-counter quotations, time value and
volatility factors underlying the commitments.  The values are
adjusted to reflect the potential impact of liquidating Enron's
position in an orderly manner over a reasonable period of time
under present market conditions.

   Financial instruments are also utilized for non-trading
purposes to hedge the impact of market fluctuations on assets,
liabilities, production and other contractual commitments.  Hedge
accounting is utilized in non-trading activities when there is a
high degree of correlation between price movements in the
derivative and the item designated as being hedged.  In instances
where the anticipated correlation of price movements does not
occur, hedge accounting is terminated and future changes in the
value of the financial instruments are recognized as gains or
losses.  If the hedged item is sold, the value of the financial
instrument is recognized in income.  Gains and losses on
financial instruments used for hedging purposes are recognized in
the Consolidated Income Statement in the same manner as the
hedged item.

   The cash flow impact of financial instruments is reflected as
cash flows from operating activities in the Consolidated
Statement of Cash Flows.  See Note 3 for further discussion of
Enron's price risk management activities.

   Accounting for Oil and Gas Producing Activities.  Enron
accounts for oil and gas exploration and production activities
under the successful efforts method of accounting.  All
development wells and related production equipment and lease
acquisition costs are capitalized when incurred.  Unproved
properties are assessed regularly and any impairment in value is
recognized.  Lease rentals and exploration costs, other than the
costs of drilling exploratory wells, are expensed as incurred.
Unsuccessful exploratory wells are expensed when determined to be
non-productive.

   Gains and losses associated with the sale of natural gas and
crude oil reserves in place with related assets are classified as
"Other Revenues" in the Consolidated Income Statement.

   Exploration costs and dry hole costs are included in the
Consolidated Statement of Cash Flows as investing activities.

   Accounting for Development Activity.  Enron capitalizes
project development costs which may be recovered through
development cost reimbursements from joint venture partners or
other third parties, written off against development fees
received or included as part of an investment in those ventures
in which Enron continues to participate.  Accumulated project
development costs are otherwise expensed in the period that
management determines it is probable that the costs will not be
recovered.

   In the first quarter of 1999, Enron will adopt the AICPA
Statement of Position 98-5 (SOP 98-5), "Reporting on the Costs of
Start-Up Activities," which requires that all start-up costs be
expensed as incurred.  Certain costs which are currently
classified as development costs will qualify as start-up costs
under SOP 98-5.  Although Enron continues to evaluate the impact
of adopting SOP 98-5, it expects to recognize an after-tax charge
of approximately $130 million in the first quarter of 1999.  The
cumulative effect of this accounting change will be reflected net
of tax as a separate line item in the Consolidated Income
Statement.

   Development revenue results from development fees, recognized
when realizable under the development agreement; long-term
construction contracts, recognized using the percentage-of-
completion method; and the operation and ownership of various
projects.  Proceeds from the sale of all or part of Enron's
investment in development projects are recognized as revenues at
the time of sale to the extent that such sales proceeds exceed
the proportionate carrying amount of the investment.  See Note 4.

   Environmental Expenditures.  Expenditures that relate to an
existing condition caused by past operations, and do not
contribute to current or future revenue generation, are expensed.
Environmental expenditures relating to current or future revenues
are expensed or capitalized as appropriate.  Liabilities are
recorded when environmental assessments and/or clean-ups are
probable and the costs can be reasonably estimated.

   Computer Software.  Enron's accounting policy for the costs of
computer software (all of which is for internal use only) is to
capitalize direct costs of materials and services consumed in
developing or obtaining software, including payroll and payroll-
related costs for employees who are directly associated with and
who devote time to the software project.  Costs may begin to be
capitalized once the application development stage has begun.
All other costs are expensed as incurred.  Enron amortizes the
costs on a straight-line basis over the useful life of the
software.  Impairment is evaluated based on changes in the
expected usefulness of the software.  At December 31, 1998, Enron
has capitalized $189 million of software costs covering numerous
systems, including trading and settlement, billing and payroll
systems and upgrades.

   Investments in Unconsolidated Affiliates.  Investments in
unconsolidated affiliates are accounted for by the equity method,
except for certain equity investments resulting from Enron's
merchant investment activities which are included at market value
in "Other Investments" in the Consolidated Balance Sheet.  Where
acquired assets are accounted for under the equity method based
on temporary control, earnings or losses related to the
investments to be sold are deferred until the time of the sale.
See Notes 4 and 9.

   Foreign Currency Translation.  For international subsidiaries,
asset and liability accounts are translated at year-end rates of
exchange and revenue and expenses are translated at average
exchange rates prevailing during the year.  For subsidiaries
whose functional currency is deemed to be other than the U.S.
dollar, translation adjustments are included as a separate
component of other comprehensive income and shareholders' equity.
Currency transaction gains and losses are recorded in income.

   Recently Issued Accounting Pronouncements.  In 1998, the
Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities" and the Emerging
Issues Task Force reached a consensus on Issue No. 98-10,
"Accounting for Contracts involved in Energy Trading and Risk
Management Activities" (EITF 98-10).

   SFAS No. 133 establishes accounting and reporting standards
requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded
on the balance sheet as either an asset or liability measured at
its fair value.  The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met.  Special
accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document,
designate and assess the effectiveness of transactions that
receive hedge accounting.

   SFAS No. 133 is effective for fiscal years beginning after
June 15, 1999.  A company may also implement the statement as of
the beginning of any fiscal quarter after issuance, however, SFAS
No. 133 cannot be applied retroactively.  Enron has not yet
determined the timing of adoption of SFAS No. 133.  Enron
believes that SFAS No. 133 will not have a material impact on its
accounting for price risk management activities but has not yet
quantified the effect on its hedging activities or physical base
contracts.

   EITF 98-10 is effective for fiscal years beginning after
December 15, 1998 and requires energy trading contracts to be
recorded at fair value on the balance sheet, with the changes in
fair value included in earnings.  The effect of initial
application of EITF 98-10 will be reported as a cumulative effect
of a change in accounting principle.  Because Enron currently
records its trading activities at fair value, management believes
that the adoption of EITF 98-10 will not have a materially
adverse impact on its financial position or results of
operations.

   Reclassifications.  Certain reclassifications have been made
to the consolidated financial statements for prior years to
conform with the current presentation.

2  BUSINESS ACQUISITIONS

   Effective July 1, 1997, Enron merged with Portland General
Corporation (PGC) in a stock-for-stock transaction.  Enron issued
approximately 50.5 million common shares, valued at $36.88 per
share, to shareholders of PGC in a ratio of 0.9825 share of Enron
common stock for each share of PGC common stock, and assumed
PGC's outstanding debt of approximately $1.1 billion.

   On November 18, 1997, Enron acquired the minority interest in
Enron Global Power & Pipelines L.L.C. (EPP) in a stock-for-stock
transaction.  Enron issued approximately 11.5 million common
shares, valued at $36.09 per share, to shareholders of EPP in a
ratio of 0.9189 share of Enron common stock for each EPP share
held by the minority shareholders.  Additionally, during 1998 and
1997, Enron acquired renewable energy, telecommunications and
energy management businesses for cash, Enron and subsidiary stock
and notes.

   Enron has accounted for these acquisitions using the purchase
method of accounting as of the effective date of each
transaction.  Accordingly, the purchase price of each transaction
has been allocated to the assets and liabilities acquired based
upon the estimated fair value of those assets and liabilities as
of the acquisition date.  The excess of the aggregate purchase
price over estimated fair value of the net assets acquired has
been reflected as goodwill in the Consolidated Balance Sheet and
is being amortized on a straight-line basis over 5 to 40 years.
Assets acquired, liabilities assumed and consideration paid as a
result of businesses acquired were as follows:

<TABLE>
<CAPTION>
(In Millions)                                     1998      1997

<S>                                              <C>       <C>
Fair value of assets acquired, other than cash   $ 269     $3,829
Goodwill                                            94      1,847
Fair value of liabilities assumed                 (259)    (3,235)
Common stock of Enron and subsidiary issued          -     (2,359)
Net cash paid                                    $ 104    $    82
</TABLE>

   The following summary presents unaudited pro forma
consolidated results of operations as if the business
acquisitions had occurred at the beginning of each period
presented.  The pro forma results are for illustrative purposes
only and are not necessarily indicative of the operating results
that would have occurred had the business acquisitions been
consummated at that date, nor are they necessarily indicative of
future operating results.

<TABLE>
<CAPTION>
(In Millions, except Per Share Amounts)    1997      1996

<S>                                      <C>       <C>
Revenues                                 $20,950   $14,401
Income before interest, minority
 interests and income taxes                  716     1,511
Net income                                   181       691
Earnings per share
   Basic                                 $  0.53   $  2.20
   Diluted                                  0.52      2.08
</TABLE>

   During 1998, Enron, through wholly-owned subsidiaries,
acquired Elektro-Eletricidades e Servicos S.A. (Elektro), Wessex
Water Plc (Wessex) and assets related to The ICI Group's Teesside
utilities and services business (the ICI assets) in separate cash
transactions.  These acquisitions are being accounted for using
the equity method (see Note 9).

3  PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

   Trading Activities.  Enron, through its Wholesale Energy
Operations and Services segment (Enron Wholesale), offers price
risk management services to energy-related businesses through a
variety of financial and other instruments including forward
contracts involving physical delivery of an energy commodity,
swap agreements, which require payments to (or receipt of
payments from) counterparties based on the differential between a
fixed and variable price for the commodity, options and other
contractual arrangements.  Interest rate risks and foreign
currency risks associated with the fair value of the energy
commodities portfolio are managed using a variety of financial
instruments, including financial futures.

   Notional Amounts and Terms.  The notional amounts and terms of
these financial instruments at December 31, 1998 are shown below
(volumes in trillions of British thermal units equivalent
(TBtue), dollars in millions):

<TABLE>
<CAPTION>
                        Fixed Price   Fixed Price      Maximum
                           Payor       Receiver     Terms in years

<S>                       <C>          <C>                <C>
Commodities
  Natural gas              6,694        5,989             25
  Crude oil and liquids    5,545        5,001             11
  Electricity              1,162        1,782             26
  Other                      583          893             10
Financial products
  Interest rate(a)        $6,574       $5,766             24
  Foreign currency         2,719        2,699             17
Equity investments         2,633          363             17

<FN>
(a) The interest rate fixed price receiver includes the net
    notional dollar value of the interest rate sensitive component
    of the combined commodity portfolio.  The remaining interest
    rate fixed price receiver and the entire interest rate fixed
    price payor represent the notional contract amount of a
    portfolio of various financial instruments used to hedge the
    net present value of the commodity portfolio.  For a given
    unit of price protection, different financial instruments
    require different notional amounts.
</TABLE>

   Enron Wholesale includes sales and purchase commitments
associated with commodity contracts based on market prices
totaling 6,047 TBtue, with terms extending up to 22 years.

   Notional amounts reflect the volume of transactions but do not
represent the amounts exchanged by the parties to the financial
instruments.  Accordingly, notional amounts do not accurately
measure Enron's exposure to market or credit risks.  The maximum
terms in years detailed above are not indicative of likely future
cash flows as these positions may be offset in the markets at any
time in response to the company's risk management needs.

   The volumetric weighted average maturity of Enron's fixed
price portfolio as of December 31, 1998 was approximately 2.6
years.

   Fair Value.  The fair value of the financial instruments
related to price risk management activities as of December 31,
1998, which include energy commodities and the related foreign
currency and interest rate instruments, and the average fair
value of those instruments held during the year are set forth
below:

<TABLE>
<CAPTION>
                                               Average Fair Value
                             Fair Value        for the Year Ended
                           as of 12/31/98          12/31/98(a)
(In Millions)           Assets   Liabilities   Assets   Liabilities

<S>                     <C>        <C>         <C>        <C>
Natural gas             $2,294     $1,876      $2,328     $1,728
Crude oil and liquids    1,053      1,470         731        764
Electricity                600        396         654        517
Other commodities          162        119         269        193
Equity                      61         71          88         32
  Total                 $4,170     $3,932      $4,070     $3,234

<FN>
(a) Computed using the ending balance at each month end.
</TABLE>

   The income before interest, taxes and certain unallocated
expenses arising from price risk management activities for 1998
was $414 million.

   Credit Risk.  In conjunction with the valuation of its
financial instruments, Enron provides reserves for risks
associated with such activity, including credit risk.  Credit
risk relates to the risk of loss that Enron would incur as a
result of nonperformance by counterparties pursuant to the terms
of their contractual obligations.  Enron maintains credit
policies with regard to its counterparties that management
believes significantly minimize overall credit risk.  These
policies include an evaluation of potential counterparties'
financial condition (including credit rating), collateral
requirements under certain circumstances and the use of
standardized agreements which allow for the netting of positive
and negative exposures associated with a single counterparty.
The counterparties associated with assets from price risk
management activities as of December 31, 1998 and 1997 are
summarized as follows:

<TABLE>
<CAPTION>
                                     1998                1997
                             Investment          Investment
(In Millions)                 Grade(a)   Total    Grade(a)   Total

<S>                           <C>       <C>       <C>       <C>
Gas and electric utilities    $1,181    $1,251    $  637    $  676
Energy marketers                 684       795       324       481
Financial institutions           505       505       413       416
Independent power producers      416       613       283       436
Oil and gas producers            365       549       280       435
Industrials                      229       341        59       106
Other                            101       116       118       116
  Total                       $3,481     4,170    $2,114     2,666
Credit and other reserves                 (325)               (282)
  Assets from price risk
   management activities(b)             $3,845              $2,384

<FN>
(a) "Investment Grade" is primarily determined using publicly
    available credit ratings along with consideration of
    collateral, which encompass standby letters of credit, parent
    company guarantees and property interests, including oil and
    gas reserves.  Included in "Investment Grade" are
    counterparties with a minimum Standard & Poor's or Moody's
    rating of BBB- or Baa3, respectively.
(b) Two and one customers' exposures at December 31, 1998 and
    1997, respectively, comprise greater than 5% of Assets From
    Price Risk Management Activities.  All are included above as
    Investment Grade.
</TABLE>

   This concentration of counterparties may impact Enron's
overall exposure to credit risk, either positively or negatively,
in that the counterparties may be similarly affected by changes
in economic, regulatory or other conditions.  Based on Enron's
policies, its exposures and its credit and other reserves, Enron
does not anticipate a materially adverse effect on financial
position or results of operations as a result of counterparty
nonperformance.

   Non-Trading Activities.  Enron's other businesses also enter
into swaps and other contracts primarily for the purpose of
hedging the impact of market fluctuations on assets, liabilities,
production or other contractual commitments.

   Energy Commodity Price Swaps.  At December 31, 1998, Enron was
a party to energy commodity price swaps covering 156 TBtu, 4 TBtu
and 56 TBtu of natural gas for the years 1999, 2000 and the
period 2001 through 2006, respectively, and 1.8 million barrels
of crude oil for the year 1999.

   Interest Rate Swaps.  At December 31, 1998, Enron had entered
into interest rate swap agreements with a notional principal
amount of $4.0 billion to manage interest rate exposure.  These
swap agreements are scheduled to terminate $0.6 billion in 1999
and $3.4 billion in the period 2000 through 2014.

   Foreign Currency Contracts.  At December 31, 1998, foreign
currency contracts with a notional principal amount of $0.8
billion were outstanding.  Such contracts will expire in the
period 2000 through 2009.

   Credit Risk.  While notional amounts are used to express the
volume of various financial instruments, the amounts potentially
subject to credit risk, in the event of nonperformance by the
third parties, are substantially smaller.  Counterparties to
forwards, futures and other contracts are equivalent to
investment grade financial institutions.  Accordingly, Enron does
not anticipate any material impact to its financial position or
results of operations as a result of nonperformance by the third
parties on financial instruments related to non-trading
activities.

   Enron has concentrations of customers in the electric and gas
utility and oil and gas exploration and production industries.
These concentrations of customers may impact Enron's overall
exposure to credit risk, either positively or negatively, in that
the customers may be similarly affected by changes in economic or
other conditions.  However, Enron's management believes that its
portfolio of receivables is well diversified and that such
diversification minimizes any potential credit risk.  Receivables
are generally not collateralized.

   Financial Instruments.  The carrying amounts and estimated
fair values of Enron's financial instruments, excluding trading
activities which are marked to market, at December 31, 1998 and
1997 were as follows:

<TABLE>
<CAPTION>
                                    1998                  1997
                             Carrying  Estimated   Carrying  Estimated
(In Millions)                 Amount   Fair Value   Amount   Fair Value

<S>                           <C>        <C>        <C>        <C>
Long-term debt (Note 7)       $7,357     $7,624     $6,254     $6,501
Company-obligated preferred
 securities of subsidiaries
 (Note 10)                     1,001      1,019        993      1,024
Energy commodity price swaps       -         (5)         -        (31)
Interest rate swaps                -         12          -         13
Foreign currency contracts         -          1          -          -
</TABLE>

   Enron uses the following methods and assumptions in estimating
fair values: (a) long-term debt - the carrying amount of variable-
rate debt approximates fair value, the fair value of marketable
debt is based on quoted market prices, and the fair value of
other debt is based on the discounted present value of cash flows
using Enron's current borrowing rates; (b) Company-obligated
preferred securities of subsidiaries - the fair value is based on
quoted market prices, where available, or based on the discounted
present value of cash flows using Enron's current borrowing rates
if not publicly traded; and (c) energy commodity price swaps,
interest rate swaps and foreign currency contracts - estimated
fair values have been determined using available market data and
valuation methodologies.  Judgment is necessarily required in
interpreting market data and the use of different market
assumptions or estimation methodologies may affect the estimated
fair value amounts.

   The fair market value of cash and cash equivalents, trade and
other receivables, accounts payable, equity investments accounted
for at fair value and equity swaps are not materially different
from their carrying amounts.

   Guarantees of liabilities of unconsolidated entities and
residual value guarantees have no carrying value and fair values
which are not readily determinable (see Note 15).

4  MERCHANT ACTIVITIES

   Merchant Investments.  Through the Enron Wholesale segment,
Enron provides capital primarily to energy-related businesses
seeking debt or equity financing.  The investments made by Enron
include public and private equity, debt, production payments and
interests in limited partnerships.  These investments are managed
as a group, by disaggregating the market risks embedded in the
individual investments and managing them on a portfolio basis,
utilizing public equities, equity indices and commodities as
hedges of specific industry groups and interest rate swaps as
hedges of interest rate exposure, to reduce Enron's exposure to
overall market volatility.  The specific investment or
idiosyncratic risks which remain are then managed and monitored
within the Enron risk management policies.

   As part of its complement of services, and to add value to its
investments, Enron may have involvement with the investees'
business, including representation on the board of directors and
providing risk management products and services to the business.

   The investments are recorded at market value in "Other Assets"
on the Consolidated Balance Sheet, with fair value adjustments
reflected in "Other Revenues" on the Consolidated Income
Statement.  The valuation methodologies utilize market values of
publicly-traded securities, independent appraisals and cash flow
analyses.

   Merchant Assets.  Also included in Enron's wholesale business
are investments in merchant energy assets such as power plants,
natural gas pipelines and local gas and electric distribution
companies, primarily held through equity investments.  Some of
these assets were developed and constructed by Enron, which may
also operate the facility for the joint venture.  From time to
time, Enron sells interests in these energy-related financial
assets. Some of these sales are completed in securitizations, in
which Enron retains certain interests through swaps associated
with the underlying assets.  Such swaps are adjusted to fair
value using quoted market prices, if available, or estimated fair
value based on management's best estimate of the present value of
future cash flow.  These swaps are included in Price Risk
Management activities.  See Note 3.

   For the years ended December 31, 1998 and 1997, respectively,
pre-tax gains from sales of merchant assets and investments
totaling $628 million and $136 million are included in "Other
Revenues," and proceeds were $1,434 million and $339 million.

   An analysis of the composition of Enron's wholesale merchant
investments and energy assets at December 31, 1998 and 1997 is as
follows:

<TABLE>
<CAPTION>
                                              December 31,
(In Millions)                                 1998     1997

<S>                                          <C>      <C>
Merchant Investments
  Held directly by Enron
     Oil and gas exploration and
      production                             $  279   $  147
     Energy-intensive industries                331      139
     Natural gas transportation                 132      131
     Other                                      334       80
                                              1,076      497
  Held through unconsolidated affiliates(a)
     Oil and gas exploration and
      production                                610      553
     Oil services                               123       68
     Other                                       50        -
                                                783      621
                                              1,859    1,118

Merchant Assets
  Independent power plants                      148      401
  Natural gas transportation                     38       31
  Other                                           -       46
                                                186      478

Total                                        $2,045   $1,596

<FN>
(a) Amounts represent Enron's interests.
</TABLE>

5  INCOME TAXES

   The components of income before income taxes are as follows:

<TABLE>
<CAPTION>
(In Millions)                  1998    1997   1996

<S>                            <C>     <C>    <C>
United States                  $197    $96    $551
Foreign                         681    (81)    304
                               $878    $15    $855
</TABLE>

   Total income tax expense (benefit) is summarized as follows:

<TABLE>
<CAPTION>
(In Millions)                  1998     1997   1996

<S>                            <C>     <C>     <C>
Payable currently -
  Federal                      $ 30    $  29   $ 16
  State                           8        9     11
  Foreign                        50       46     37
                                 88       84     64
Payment deferred -
  Federal                       (14)     (39)   174
  State                          11      (42)    (1)
  Foreign                        90      (93)    34
                                 87     (174)   207
Total income tax expense 
 (benefit)                     $175    $ (90)  $271
</TABLE>

   The differences between taxes computed at the U.S. federal
statutory tax rate and Enron's effective income tax rate are as
follows:

<TABLE>
<CAPTION>
(In Millions, except Percentages)         1998         1997          1996

<S>                                      <C>      <C>     <C>        <C>
Statutory federal income tax provision    35.0%   $  5      35.0%    35.0%
Net state income taxes                     1.7     (21)   (140.0)     0.8
Tight gas sands tax credit                (1.4)    (12)    (80.0)    (1.8)
Equity earnings                           (4.3)    (38)   (253.3)    (3.3)
Minority interest                          0.8      28     186.7      3.1
Assets and stock sale differences        (14.2)    (79)   (526.7)     1.8
Cash value in life insurance              (1.1)     (7)    (46.7)    (3.2)
Goodwill amortization                      2.0       9      60.0        -
Other                                      1.5      25     166.7     (0.7)
                                          20.0%   $(90)   (598.3)%   31.7%
</TABLE>

   The principal components of Enron's net deferred income tax
liability are as follows:

<TABLE>
<CAPTION>
                                                    December 31,
(In Millions)                                     1998       1997

<S>                                              <C>        <C>
Deferred income tax assets -
  Alternative minimum tax credit carryforward    $  238     $ 247
  Net operating loss carryforward                   605       361
  Other                                             111       218
                                                    954       826
Deferred income tax liabilities -
  Depreciation, depletion and amortization        1,940     2,036
  Price risk management activities                  645       457
  Other                                             700       588
                                                  3,285     3,081
Net deferred income tax liabilities(a)           $2,331    $2,255

<FN>
(a) Includes $(26) million and $216 million in other current
    liabilities for 1998 and 1997, respectively.
</TABLE>

   Enron has an alternative minimum tax (AMT) credit carryforward
of approximately $238 million which can be used to offset regular
income taxes payable in future years.  The AMT credit has an
indefinite carryforward period.

   Enron has a federal consolidated net operating loss
carryforward for tax purposes of approximately $1.4 billion,
which will begin to expire in 2011.  Enron has a net operating
loss carryforward applicable to non-U.S. subsidiaries of
approximately $353 million of which $237 million can be carried
forward indefinitely.  The remaining $116 million will begin to
expire in 2002 but is projected to be utilized before its
expiration period.  The benefits of the domestic and foreign net
operating losses have been recognized as deferred tax assets.

   U.S. and foreign income taxes have been provided for earnings
of foreign subsidiary companies that are expected to be remitted
to the U.S.  Foreign subsidiaries' cumulative undistributed
earnings of approximately $840 million are considered to be
indefinitely reinvested outside the U.S. and, accordingly, no
U.S. income taxes have been provided thereon.  In the event of a
distribution of those earnings in the form of dividends, Enron
may be subject to both foreign withholding taxes and U.S. income
taxes net of allowable foreign tax credits.

6  SUPPLEMENTAL CASH FLOW INFORMATION

   Cash paid for income taxes and interest expense, including
fees incurred on sales of accounts receivable, is as follows:

<TABLE>
<CAPTION>
(In Millions)                            1998      1997      1996

<S>                                      <C>       <C>       <C>
Income taxes (net of refunds)            $ 73      $ 68      $ 89
Interest (net of amounts capitalized)     585       420       290
</TABLE>

   Non-Cash Transactions.  In December 1998, Enron exchanged its
6.25% Exchangeable Notes for 10.5 million shares of EOG common
stock.

   During 1997, Enron issued common stock in connection with
business acquisitions.  See Note 2.

7  CREDIT FACILITIES AND DEBT

   Enron has credit facilities with domestic and foreign banks
which provide for an aggregate of $1.67 billion in long-term
committed credit and $1.37 billion in short-term committed
credit.  Expiration dates of the committed facilities range from
April 1999 to June 2002.  Interest rates on borrowings are based
upon the London Interbank Offered Rate, certificate of deposit
rates or other short-term interest rates.  Certain credit
facilities contain covenants which must be met to borrow funds.
Such debt covenants are not anticipated to materially restrict
Enron's ability to borrow funds under such facilities.
Compensating balances are not required, but Enron is required to
pay a commitment or facility fee.  At December 31, 1998, $149
million was outstanding under these facilities.

   Enron has also entered into agreements which provide for
uncommitted lines of credit totaling $335 million at December 31,
1998.  The uncommitted lines have no stated expiration dates.
Neither compensating balances nor commitment fees are required as
borrowings under the uncommitted credit lines are available
subject to agreement by the participating banks.  At December 31,
1998, no amounts were outstanding under the uncommitted lines.

   In addition to borrowing from banks on a short-term basis,
Enron and certain of its subsidiaries sell commercial paper to
provide financing for various corporate purposes.  As of December
31, 1998 and 1997, short-term borrowings of $680 million and $825
million, respectively, have been reclassified 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 subject to overall
reductions in debt levels.  Similarly, at December 31, 1998 and
1997, $541 million and $462 million, respectively, of long-term
debt due within one year remained classified as long-term.
Weighted average interest rates on short-term debt outstanding at
December 31, 1998 and 1997 were 5.5% and 6.0%, respectively.

   Detailed information on long-term debt is as follows:

<TABLE>
<CAPTION>
                                               December 31,
(In Millions)                                 1998      1997

<S>                                         <C>       <C>
Enron Corp.
  Debentures
     6.75% to 8.25% due 2005 to 2012        $  350    $  350
  Notes payable
     6.25% - exchangeable notes due 1998         -       228
     6.40% to 10.00% due 1998 to 2028        3,342     2,492
     Floating rate notes due 1999 to 2037      400       350
     Other                                      38        67
Northern Natural Gas Company
  Notes payable
     6.75% to 8.00% due 1999 to 2008           500       350
Transwestern Pipeline Company
  Notes payable
     7.55% to 9.20% due 1998 to 2004           147       150
Portland General Electric Company
  First mortgage bonds
     5.65% to 9.46% due 1998 to 2023           502       564
  Pollution control bonds
     3.50% to 7.13% due 2010 to 2033           200       192
  Other                                        160       172
Enron Oil & Gas Company
  Notes payable
     Floating rate notes due 1998 to 2001      105       120
     5.44% to 9.10% due 1998 to 2028           675       390
Other                                          302        37
Amount reclassified from short-term debt       680       825
Unamortized debt discount and premium          (44)      (33)
Total long-term debt                        $7,357    $6,254
</TABLE>

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

   The Enron 6.25% Exchangeable Notes were exchanged in December
1998 for 10.5 million shares of EOG common stock held by Enron.

   The aggregate annual maturities of long-term debt outstanding
at December 31, 1998 were $541 million, $413 million, $666
million, $182 million and $656 million for 1999 through 2003,
respectively.

8  MINORITY INTERESTS

   Enron's minority interests primarily include amounts related
to EOG and two joint ventures.  Also included was EPP prior to
Enron's acquisition of the EPP minority interest in November 1997
(see Note 2).

   In December 1998, Enron formed a wholly-owned limited
partnership for the purpose of holding $1.6 billion of assets
contributed by various business units.  That partnership
contributed $850 million of assets to a second newly-formed
limited partnership in exchange for a 53% interest; a third party
investor contributed $750 million in exchange for a 47% interest.
The assets held by the wholly-owned limited partnership represent
collateral for a $750 million note receivable held by the other
newly-formed limited partnership.  In 1997, Enron and a third-
party investor contributed approximately $579 million and $500
million, respectively, for interests in an Enron-controlled joint
venture.  The joint venture purchased 250,000 shares of junior
convertible preferred stock from Enron.  Each share of junior
convertible preferred stock has a cumulative, market-based
dividend, is convertible at the option of the holder (currently
the Enron-controlled joint venture) initially into 100 shares of
Enron stock, subject to certain adjustments, and has a
liquidation value of $4,000 per share, subject to certain
adjustments.

   These entities are separate legal entities from Enron and have
separate assets and liabilities.  Absent certain defaults or
other specified events, Enron has the option to acquire the
minority holders' interests in the entities.  If Enron does not
acquire the minority holders' interests before December 2005 or
December 2002, respectively, or earlier upon certain specified
events, the entities will liquidate their assets and dissolve.
These entities are included in Enron's consolidated financial
statements and the third-party investors' interests are included
in "Minority Interests" in the Consolidated Balance Sheet.

9  UNCONSOLIDATED AFFILIATES

   Enron's investment in and advances to unconsolidated
affiliates which are accounted for by the equity method is as
follows:

<TABLE>
<CAPTION>
                                             Net
                                          Ownership     December 31,
(In Millions)                             Interest    1998        1997

<S>                                         <C>      <C>         <C>  
Azurix Corp.(a)                              50%     $  918      $    -
Citrus Corp.(b)                              50%        455         432
Companhia Distribuidora de Gas do Rio 
 de Janeiro, S.A.(c)                         25%        192         194
Dabhol Power Company(c)                      50%        285           -
Enron Teesside Operations Limited(c)        100%        118           -
Jacare Electrical Distribution Trust(c)      51%        447           -
Joint Energy Development Investments L.P.                        
 (JEDI)(c)(d)                                50%        356         392
Transportadora de Gas del Sur S.A.(c)        35%        463         472
Other                                                 1,199       1,166
                                                     $4,433(e)   $2,656
<FN>
(a) Included in the Corporate and Other segment.
(b) Included in the Transportation and Distribution segment.
(c) Included in the Wholesale Energy Operations and Services
    segment.
(d) JEDI accounts for its investments at fair value.
(e) At December 31, 1998, the unamortized excess of Enron's
    investment in unconsolidated affiliates was $203 million,
    which is being amortized over the expected lives of the
    investments.
</TABLE>

   Enron's equity in earnings (losses) of unconsolidated
affiliates is as follows:

<TABLE>
<CAPTION>
(In Millions)                               1998   1997  1996

<S>                                         <C>    <C>   <C>
Citrus Corp.                                $ 23   $ 27  $ 22
Joint Energy Development Investments L.P.    (45)    68    71
Transportadora de Gas del Sur S.A.            36     45    29
Other                                         83     76    93
                                            $ 97   $216  $215
</TABLE>

   Summarized combined financial information of Enron's
unconsolidated affiliates is presented below:

<TABLE>
<CAPTION>
                                           December 31,
(In Millions)                            1998        1997

<S>                                    <C>           <C>
Balance sheet
  Current assets(a)                    $ 2,309       $3,611
  Property, plant and equipment, net    12,640        8,851
  Other noncurrent assets                7,176        1,089
  Current liabilities(a)                 3,501        1,861
  Long-term debt(a)                      7,621        5,694
  Other noncurrent liabilities           2,016        1,295
  Owners' equity                         8,897        4,701

<FN>
(a) Includes $196 million and $0 million receivable from
    Enron and $296 million and $569 million payable to Enron at
    December 31, 1998 and 1997, respectively.
</TABLE>

<TABLE>
<CAPTION>
(In Millions)                  1998      1997      1996

<S>                           <C>      <C>       <C>
Income statement(a)
  Operating revenues          $8,508   $11,183   $11,676
  Operating expenses           7,244    10,246    10,567
  Net income                     142       336       464
Distributions paid to Enron       87       118        84

<FN>
(a) Enron recognized revenues from unconsolidated affiliates
    of $142 million in 1998, $219 million in 1997 and $253 million
    in 1996.
</TABLE>

   In August 1998, Enron, through a wholly-owned subsidiary,
completed the acquisition of a controlling interest in Elektro,
Brazil's sixth largest electricity distributor, for approximately
$1.3 billion.  Elektro serves approximately 1.5 million customers
through approximately 51,000 miles of distribution lines in the
state of Sao Paulo.  Enron's interest in Elektro is held by
Jacare Electrical Distribution Trust.  In October 1998, Enron,
through a wholly-owned subsidiary, acquired Wessex, which
provides water supply and wastewater services in southern
England, for approximately $2.4 billion.  Wessex is held through
Azurix Corp.  On December 31, 1998, Enron's wholly-owned
subsidiary, Enron Teesside Operations Limited (ETOL), acquired
assets from The ICI Group for approximately $500 million.  The
acquisition of the ICI assets allows ETOL to supply steam, water,
power and other utility services to large industrial customers in
the U.K.

   Although Enron initially owned more than 50 percent of the
voting interest in each of these entities, they are reported
using the equity method as a result of management's intent to
ultimately hold a voting interest of not more than 50 percent.
In December 1998, Enron completed financial restructuring of
Enron's ownership interest in Wessex, reducing its interest to
50%, and financially closed the Elektro financial restructuring,
reducing its interest in the subsidiary that holds Elektro to
51%.  Enron will transfer an additional 1% interest in Elektro
following the receipt of certain regulatory approvals, which are
expected in the first half of 1999.

   Proceeds of approximately $1.6 billion received from the
Elektro and Wessex financial restructurings were used to repay
debt incurred in the initial acquisitions.  In connection with
the financings, Enron committed to cause the sale of its
convertible preferred stock, with the number of common shares
issuable upon conversion determined based on future common stock
prices, if certain debt obligations of the related entities
acquiring such interests are defaulted upon, or in certain
events, including, among other things, Enron's credit ratings
falling below specified levels.  If the sale of stock is not
sufficient to retire such obligations, Enron would be liable for
the shortfall.  The obligations will mature in December 2000 and
2001 for Elektro and Wessex, respectively.

   Enron has investments in entities whose functional currency is
denominated in Brazilian Reals.  Subsequent to December 31, 1998,
the exchange rate for Brazilian Reals to the U.S. dollar has
declined.  As a result, Enron anticipates recording a non-cash
foreign currency translation adjustment, reducing shareholders'
equity, in the first quarter of 1999.  Based on the exchange rate
in mid-February, the equity reduction would be approximately $600
million.

   From time to time, Enron has entered into various
administrative service, management, construction, supply and
operating agreements with its unconsolidated affiliates.  Enron's
management believes that its existing agreements and transactions
are reasonable compared to those which could have been obtained
from third parties.

10  PREFERRED STOCK

   Preferred Stock.  Following Enron's reincorporation in Oregon
on July 1, 1997, Enron has authorized 16,500,000 shares of
preferred stock, no par value.  At December 31, 1998, Enron had
outstanding 1,319,848 shares of Cumulative Second Preferred
Convertible Stock (the Convertible Preferred Stock), no par
value.  The Convertible Preferred Stock pays dividends at an
amount equal to the higher of $10.50 per share or the equivalent
dividend that would be paid if shares of the Convertible
Preferred Stock were converted to common stock.  Each share of
the Convertible Preferred Stock is convertible at any time at the
option of the holder thereof into 13.652 shares of Enron's common
stock, subject to certain adjustments.  The Convertible Preferred
Stock is currently subject to redemption at Enron's option at a
price of $100 per share plus accrued dividends.  During 1998,
1997 and 1996, 17,797 shares, 33,069 shares and 4,780 shares,
respectively, of the Convertible Preferred Stock were converted
into common stock.

   Company-Obligated Preferred Securities of Subsidiaries.  Summarized
information for Enron's Company-Obligated Preferred Securities of 
Subsidiaries is as follows:

<TABLE>
<CAPTION>
                                                                    Liquidation
                                                      December 31,     Value
(In Millions, except Per Share Amounts and Shares)    1998    1997   Per Share

<S>                                                  <C>      <C>    <C>   
Enron Capital LLC
  8% Cumulative Guaranteed Monthly Income
   Preferred Shares (MIPS) (8,550,000 shares)(a)     $  214   $214   $     25

Enron Capital Trust I
  8.3% Trust Originated Preferred Securities
   (8,000,000 preferred securities)(a)                  200    200         25

Enron Capital Trust II
  8 1/8% Trust Originated Preferred Securities
   (6,000,000 preferred securities)(a)                  150    150         25

Enron Capital Trust III
  Adjustable-Rate Capital Trust Securities
   (200,000 preferred securities)(b)                    200    200      1,000

Enron Equity Corp.
  8.57% Preferred Stock (880 shares)(a)                  88     88    100,000
  7.39% Preferred Stock (150 shares)(a)(c)               15     15    100,000

Enron Capital Resources, L.P.
  9% Cumulative Preferred Securities, Series A
   (3,000,000 preferred securities)(a)                   75     75         25

Other                                                    59     51
                                                     $1,001   $993

<FN>
(a) Redeemable under certain circumstances after specified
    dates.
(b) Mature in 2046.
(c) Mandatorily redeemable in 2006.
</TABLE>

11  COMMON STOCK

   Earnings Per Share.  The computation of basic and diluted
earnings per share is as follows:

<TABLE>
<CAPTION>
                                             Year Ended December 31,
(In Millions, except per share amounts)      1998     1997      1996

<S>                                         <C>      <C>       <C>
Numerator:
  Net income                                $ 703    $ 105     $ 584
  Preferred stock dividends                   (17)     (17)      (16)
  Numerator for basic earnings per
   share - income available to common
   shareholders                               686       88       568
  Effect of dilutive securities:
     Preferred stock dividends(a)              17        -        16
  Numerator for diluted earnings per
   share - income available to common
   shareholders after assumed conversions   $ 703    $  88     $ 584
Denominator:
  Denominator for basic earnings per
   share - weighted-average shares            321      272       246
  Effect of dilutive securities:
     Preferred stock (a)                       18        -        19
     Stock options                              9        5         5
  Dilutive potential common shares             27        5        24
  Denominator for diluted earnings per
   share - adjusted weighted-average
   shares and assumed conversions             348      277       270
Basic earnings per share                    $2.14    $0.32     $2.31
Diluted earnings per share                  $2.02    $0.32     $2.16

<FN>
(a) For 1997, the dividends and conversion of preferred stock
    have been excluded from the computation because conversion is
    antidilutive.
</TABLE>

  Enron has outstanding certain instruments that are potentially
convertible into common stock but which do not qualify as
dilutive securities for computation of earnings per share.  See
Notes 8 and 9 for further description of these instruments.

  In February 1999, Enron issued 13.8 million shares of common
stock in a public offering and  approximately 3.8 million shares
of common stock in connection with the acquisition of certain
assets.

   Forward Contracts and Options.  At December 31, 1998, Enron
had forward contracts to purchase 6.7 million shares of Enron
Corp. common stock at an average price of $43.37 per share.
Enron may purchase the shares pursuant to the forward contracts
with cash or an equivalent value of Enron common stock until
April 2001.  Shares potentially deliverable to the counterparty
under the contracts are assumed to be outstanding in calculating
diluted earnings per share unless they are antidilutive.

   At December 31, 1998, Enron had issued put options for
approximately nine million shares at a weighted average exercise
price of $54.73.  If exercised by the counterparty, Enron may
purchase the shares pursuant to the put options for the
difference between the exercise price and the market price, in
either cash or an equivalent value of Enron common stock.  These
put options have been included in the diluted earnings per share
calculation.

   In 1997, Enron granted options to EOG to purchase 3.2 million
shares of Enron common stock (exercise price of $39.1875) in
connection with certain agreements between Enron and EOG.  The
options vested 25% immediately with 15% vesting in 1998 and the
remainder vesting equally in 1999 through 2004.

   Stock Option Plans.  Enron applies Accounting Principles Board
(APB) Opinion 25 and related interpretations in accounting for
its stock option plans.  In accordance with APB Opinion 25, no
compensation expense has been recognized for the fixed stock
option plans.  Compensation expense charged against income for
the restricted stock plan for 1998, 1997 and 1996 was $58
million, $14 million and $4 million, respectively.  Had
compensation cost for Enron's stock option compensation plans
been determined based on the fair value at the grant dates for
awards under those plans, Enron's net income and earnings per
share would have been $674 million ($2.04 per share basic, $1.94
per share diluted) in 1998, $66 million ($0.18 per share basic,
$0.18 per share diluted) in 1997 and $562 million ($2.22 per
share basic, $2.07 per share diluted) in 1996.

   The fair value of each option grant is estimated on the date
of grant using the Black-Scholes option-pricing model with
weighted-average assumptions for grants in 1998, 1997 and 1996,
respectively:  (i) dividend yield of 2.5%, 2.5% and 2.3%; (ii)
expected volatility of 18.3%, 17.4% and 23.8%; (iii) risk-free
interest rates of 5.0%, 5.9% and 5.9%; and (iv) expected lives of
3.8 years, 3.7 years and 4.0 years.

   Enron has three fixed option plans (the Plans) under which
options for shares of Enron's common stock have been or may be
granted to officers, employees and non-employee members of the
Board of Directors.   Options granted may be either incentive
stock options or nonqualified stock options and are granted at
not less than the fair market value of the stock at the time of
grant.  The Plans provide for options to be granted with a stock
appreciation rights feature; however, Enron does not presently
intend to issue options with this feature.  Under the Plans,
Enron may grant options with a maximum term of 10 years.  Options
vest under varying schedules.

   Summarized information for Enron's Plans is as follows:

<TABLE>
<CAPTION>
                             1998                1997                1996
                                 Weighted            Weighted            Weighted
                                 Average             Average             Average
                                 Exercise            Exercise            Exercise
(Shares in Thousands)   Shares    Price     Shares    Price     Shares    Price

<S>                     <C>      <C>        <C>      <C>        <C>      <C>
Outstanding,
 beginning of year      39,429   $35.77     25,476   $32.69     22,493   $29.02
  Granted(a)             7,851    49.97     17,658    38.63      7,370    39.71
  Exercised             (6,536)   31.39     (2,165)   23.29     (3,615)   24.41
  Forfeited               (749)   39.54     (1,514)   35.25       (749)   31.66
  Expired                 (193)   39.52        (26)   34.59        (23)   30.65
Outstanding,
 end of year            39,802    39.19     39,429   $35.77     25,476   $32.69
Exercisable,
 end of year            22,971   $36.31     21,252   $33.55     12,883   $30.65
Available for grant,
 end of year(b)          5,249              13,047               6,505
Weighted average
 fair value of
 options granted                 $ 8.39              $ 7.10              $ 9.44

<FN>
(a) Includes 1,768,074 shares issued in 1997 in connection with
    business acquisitions discussed in Note 2.
(b) Includes up to  5,248,835 shares, 12,246,040 shares and
    5,232,218 shares as of December 31, 1998, 1997 and 1996,
    respectively, which may be issued either as restricted stock
    or pursuant to stock options.
</TABLE>

   The following table summarizes information about stock options
outstanding at December 31, 1998 (shares in thousands):

<TABLE>
<CAPTION>
                            Options Outstanding            Options Exercisable
                                  Weighted
                                   Average     Weighted                 Weighted
                      Number      Remaining    Average       Number     Average
  Range of         Outstanding   Contractual   Exercise   Exercisable   Exercise
Exercise Prices    at 12/31/98       Life       Price     at 12/31/98    Price

<C>                  <C>             <C>        <C>           <C>        <C>
$10.69 to $30.25      4,119          4.1        $25.94        3,708      $25.66
 30.50 to  36.06      6,779          4.9         31.71        5,498       31.87
 36.75 to  39.88     10,310          6.9         37.73        6,322       37.73
 40.00 to  45.00     12,810          6.3         42.21        6,489       42.32
 46.38 to  57.06      5,784          9.2         53.33          954       52.46
$10.69 to  57.06     39,802          6.4        $39.19       22,971      $36.31
</TABLE>

   Restricted Stock Plan.  Under Enron's Restricted Stock Plan,
participants may be granted stock without cost to the
participant.  The shares granted under this plan vest to the
participants at various times ranging from immediate vesting to
vesting at the end of a five-year period.  Upon vesting, the
shares are released to the participants.  The following
summarizes shares of restricted stock under this plan:

<TABLE>
<CAPTION>
(Shares in Thousands)               1998       1997      1996
                                             
<S>                                <C>       <C>       <C>
Outstanding, beginning of year      2,537       825       159
  Granted                           1,061     2,088     1,772
  Released to participants           (532)     (321)   (1,062)
  Forfeited or expired                (49)      (55)      (44)
Outstanding, end of year            3,017     2,537       825
Available for grant, end of year    5,249    12,246     5,232
Weighted average fair value of
 restricted stock granted          $47.40    $38.26    $37.04
</TABLE>

12  PENSION AND OTHER BENEFITS

   Enron maintains a retirement plan (the Enron Plan) which is a
noncontributory defined benefit plan covering substantially all
employees in the United States and certain employees in foreign
countries.  The benefit accrual is in the form of a cash balance
of 5% of annual base pay.

   Portland General has a noncontributory defined benefit pension
plan (the Portland General Plan) covering substantially all of
its employees.  Benefits under the Plan are based on years of
service, final average pay and covered compensation.

   Enron also maintains a noncontributory employee stock
ownership plan (ESOP) which covers all eligible employees.
Allocations to individual employees' retirement accounts within
the ESOP offset a portion of benefits earned under the Enron
Plan.  All shares included in the ESOP have been allocated to the
employee accounts.  At December 31, 1998 and 1997, 10,919,050
shares and 13,508,794 shares, respectively, of Enron common stock
were held by the ESOP, a portion of which may be used to offset
benefits under the Enron Plan.

   Assets of the Enron Plan and the Portland General Plan are
comprised primarily of equity securities, fixed income securities
and temporary cash investments.  It is Enron's policy to fund all
pension costs accrued to the extent required by federal tax
regulations.

   Enron provides certain postretirement medical, life insurance
and dental benefits to eligible employees and their eligible
dependents.  Benefits are provided under the provisions of
contributory defined dollar benefit plans.  Enron is currently
funding that portion of its obligations under these
postretirement benefit plans which are expected to be recoverable
through rates by its regulated pipelines and electric utility
operations.

   Enron accrues these postretirement benefit costs over the
service lives of the employees expected to be eligible to receive
such benefits.  Enron is amortizing the transition obligation
which existed at January 1, 1993 over a period of approximately
19 years.

   Enron adopted SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits," in 1998.  This
statement changed the disclosure requirements, but not the method
of measurement or recognition of these obligations.  The
following table sets forth information related to changes in the
benefit obligations, changes in plan assets, a reconciliation of
the funded status of the plans and components of the expense
recognized related to Enron's pension and other postretirement
plans:

<TABLE>
<CAPTION>
                                           Pension Benefits   Other Benefits
(In Millions)                                 1998   1997      1998   1997

<S>                                           <C>    <C>       <C>    <C>
Change in benefit obligation
  Benefit obligation, beginning of year       $617   $308      $148   $144
  Service cost                                  27     22         2      2
  Interest cost                                 44     32         9     10
  Plan participants' contributions               -      -         3      3
  Plan amendments                                -      -         3     (4)
  Actuarial loss (gain)                         26     35       (16)   (14)
  Acquisitions and divestitures                  -    255         -     27
  Benefits paid                                (27)   (35)      (15)   (20)
Benefit obligation, end of year               $687   $617      $134   $148

Change in plan assets
  Fair value of plan assets, beginning
   of year(a)                                 $727   $315      $ 54   $ 15
  Actual return on plan assets                  41     84         3      3
  Acquisitions and divestitures                  -    360         -     32
  Employer contribution                         33      3         8      8
  Plan participants' contributions               -      -         3      3
  Benefits paid                                (27)   (35)       (8)    (7)
Fair value of plan assets, end of year(a)     $774   $727      $ 60   $ 54

Reconciliation of funded status, end of year
  Funded status, end of year                  $ 87   $110      $(74)  $(94)
  Unrecognized transition obligation (asset)   (18)   (24)       58     62
  Unrecognized prior service cost               33     35        17     22
  Unrecognized net actuarial loss (gain)        79     34       (10)     6
Prepaid (accrued) benefit cost                $181   $155      $ (9)  $ (4)

Weighted-average assumptions at December 31
  Discount rate                               6.75%  7.25%     6.75%  7.25%
  Expected return on plan assets (pre-tax)     (b)    (b)       (c)    (c)
  Rate of compensation increase                (d)    (d)       (d)    (d)

Components of net periodic benefit cost
  Service cost                                $ 27   $ 22      $  2   $  2
  Interest cost                                 44     32         9     10
  Expected return on plan assets               (63)   (43)       (3)    (2)
  Amortization of transition obligation
   (asset)                                      (6)    (6)        4      4
  Amortization of prior service cost             5      5         1      1
  Recognized net actuarial loss (gain)           2      2         -      1
Net periodic benefit cost                     $  9   $ 12      $ 13   $ 16

<FN>
(a) Includes plan assets of the ESOP of $139 million and $135
    million at December 31, 1998 and 1997, respectively.
(b) Long-term rate of return on assets is assumed to be 10.5%
    for the Enron Retirement Plan and 9.0% for the Portland
    General Plan.
(c) Long-term rate of return on assets is assumed to be 7.5%
    for the Enron assets and 9.5% for the Portland General assets.
(d) Rate of compensation increase is assumed to be 4.0% for
    the Enron Plan and 4.0% to 9.5% for the Portland General Plan.
</TABLE>

   Included in the above amounts are the unfunded obligations for
the supplemental executive retirement plans.  At December 31,
1998 and 1997, respectively, the projected benefit obligation for
these unfunded plans was $54 million and $48 million and the fair
value of assets was $2 million and $1 million.

   The measurement date of the Enron Plan and the ESOP is
September 30, and the measurement date of the Portland General
Plan and the postretirement benefit plans is December 31.  The
funded status as of the valuation date of the Enron Plan, the
Portland General Plan, the ESOP and the postretirement benefit
plans reconciles with the amount detailed above which is included
in "Other Assets" on the Consolidated Balance Sheet.

  For measurement purposes, a 7.0% annual rate of increase in the
per capita cost of covered health care benefits was assumed for
1999.  The rate was assumed to decrease to 5.0% by 2003.  Assumed
health care cost trend rates have a significant effect on the
amounts reported for the health care plans.  A one-percentage
point change in assumed health care cost trend rates would have
the following effects:

<TABLE>
<CAPTION>
                                         1-Percentage     1-Percentage
(In Millions)                           Point Increase   Point Decrease

<S>                                          <C>             <C>
Effect on total of service and
 interest cost components                    $0.4            $(0.4)
Effect on postretirement benefit 
 obligation                                   5.4             (4.5)
</TABLE>

   Additionally, certain Enron subsidiaries maintain various
incentive based compensation plans for which participants may
receive a combination of cash or stock options of the
subsidiaries, based upon the achievement of certain performance
goals.

13  RATES AND REGULATORY ISSUES

   Rates and regulatory issues related to certain of Enron's
natural gas pipelines and its electric utility operations are
subject to final determination by various regulatory agencies.
The domestic interstate pipeline operations are regulated by the
Federal Energy Regulatory Commission (FERC) and the electric
utility operations are regulated by the FERC and the Oregon
Public Utility Commission (OPUC).  As a result, these operations
are subject to the provisions of SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation," which recognizes the
economic effects of regulation and, accordingly, Enron has
recorded regulatory assets and liabilities related to such
operations.

   The regulated pipelines operations' net regulatory assets were
$241 million and $283 million at December 31, 1998 and 1997,
respectively, which are expected to be recovered over varying
time periods.

   The electric utility operations' net regulatory assets at
December 31, 1998 and 1997, respectively, were $494 million and
$561 million.  Based on rates in place at December 31, 1997,
Enron estimates that it will collect the majority of these
regulatory assets within the next 10 years and substantially all
of these regulatory assets within the next 20 years.

   Pipeline Operations.  On May 1, 1998, Northern Natural Gas
Company (Northern) filed a general rate case proceeding with the
FERC which fulfilled a commitment made in a previous settlement.
The rate case included an annual increase of $35 million to
Northern's revenues over 1997.  The FERC accepted the rate case
for filing and suspended the filed rates.  Northern implemented
the filed rates effective November 1, 1998, subject to refund.

   Transwestern Pipeline Company implemented on November 1, 1998,
a rate escalation of settled transportation rates, per a May 1996
settlement.

   Electric Utility Operations.  PGE is a 67.5% owner of the
Trojan Nuclear Plant (Trojan).  In March 1995, the OPUC issued an
order authorizing PGE to recover all of the estimated costs of
decommissioning Trojan and 87% of its remaining investment in the
plant.  At December 31, 1998, PGE's regulatory asset related to
recovery of Trojan costs from customers was $438 million.
Amounts are to be collected over Trojan's original license period
ending in 2011.  As discussed in Note 14, 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.

   Enron believes, based upon its experience to date and after
considering appropriate reserves that have been established, that
the ultimate resolution of pending regulatory matters will not
have a material impact on Enron's financial position or results
of operations.

14  LITIGATION AND OTHER CONTINGENCIES

   Enron is a party to various claims and litigation, the
significant items of which are discussed below.  Although no
assurances can be given, Enron believes, based on its experience
to date and after considering appropriate reserves that have been
established, that the ultimate resolution of such items,
individually or in the aggregate, will not have a materially
adverse impact on Enron's financial position or its results of
operations.

   Litigation.  In 1995, several parties (the Plaintiffs) filed
suit in Harris County District Court in Houston, Texas, against
Intratex Gas Company (Intratex), Houston Pipe Line Company and
Panhandle Gas Company (collectively, the Enron Defendants), each
of which is a wholly-owned subsidiary of Enron.  The Plaintiffs
were either sellers or royalty owners under numerous gas purchase
contracts with Intratex, many of which have terminated.  Early in
1996, the case was severed by the Court into two matters to be
tried (or otherwise resolved) separately.  In the first matter,
the Plaintiffs alleged that the Enron Defendants committed fraud
and negligent misrepresentation in connection with the "Panhandle
program," a special marketing program established in the early
1980s.  This case was tried in October 1996 and resulted in a
verdict for the Enron Defendants.  In the second matter, the
Plaintiffs allege that the Enron Defendants violated state
regulatory requirements and certain gas purchase contracts by
failing to take the Plaintiffs' gas ratably with other producers'
gas at certain times between 1978 and 1988.  The court has
certified a class action with respect to ratability claims.  The
Enron Defendants deny the Plaintiffs' claims and have asserted
various affirmative defenses, including the statute of
limitations.  The Enron Defendants believe that they have strong
legal and factual defenses, and intend to vigorously contest the
claims.  Although no assurances can be given, Enron believes that
the ultimate resolution of these matters will not have a
materially adverse effect on its financial position or results of
operations.

   On November 21, 1996, an explosion occurred in or around the
Humberto Vidal Building in San Juan, Puerto Rico.  The explosion
resulted in fatalities, bodily injuries and damage to the
building and surrounding property.  San Juan Gas Company, Inc.
(San Juan), an Enron subsidiary, operated a propane/air
distribution system in the vicinity.  Although San Juan did not
provide service to the building, the investigation report of the
National Transportation Safety Board (NTSB) concluded that the
probable cause of the incident was propane leaking from San
Juan's distribution system.  San Juan and Enron strongly disagree
with the NTSB findings.  The NTSB investigation found no path of
migration of propane from San Juan's system to the building and
no forensic evidence that propane fueled the explosion.  Enron,
San Juan, several San Juan affiliates and third parties have been
named as defendants in numerous lawsuits filed in U.S. District
Court for the district of Puerto Rico and the Commonwealth court
of Puerto Rico.  These suits, which seek damages for wrongful
death, personal injury, business interruption and property
damage, allege that negligence of Enron and San Juan, among
others, caused the explosion.  Enron and San Juan are vigorously
contesting the claims.  Although no assurances can be given,
Enron believes that the ultimate resolution of these matters will
not have a material adverse effect on its financial position or
results of operations.

   Trojan Investment Recovery.  In early 1993, PGE ceased
commercial operation of Trojan.  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% of its remaining investment in Trojan.  The 1994 ruling
was appealed to the Oregon Court of Appeals and was stayed
pending the appeal of the Commission's March 1995 order.  Both
PGE and the OPUC have separately appealed the April 1996 ruling,
which appeals were combined with the appeal of the November 1994
ruling at the Oregon Court of Appeals.  On June 24, 1998, the
Court of Appeals of the State of Oregon ruled that the OPUC does
not have the authority to allow PGE to recover a rate of return
on its undepreciated investment in the Trojan generating
facility.  The court upheld the OPUC's authorization of PGE's
recovery of its undepreciated investment in Trojan.

   PGE has filed a petition for review with the Oregon Supreme
Court. The OPUC has also filed such a petition for review.  Also
on August 26, 1998, the Utility Reform Project filed a Petition
for Review with the Oregon Supreme Court seeking review of that
portion of the Oregon Court of Appeals decision relating to PGE's
recovery of its undepreciated investment in Trojan.  Enron cannot
predict the outcome of these actions.  Additionally, due to
uncertainties in the regulatory process, management cannot
predict, with certainty, what ultimate rate-making action the
OPUC will take regarding PGE's recovery of a rate of return on
its Trojan investment.  Although no assurances can be given,
Enron believes that the ultimate resolution of these matters will
not have a material adverse effect on its financial position or
results of operations.

   Environmental Matters.  Enron is subject to extensive federal,
state and local environmental laws and regulations.  These laws
and regulations require expenditures in connection with the
construction of new facilities, the operation of existing
facilities and for remediation at various operating sites.  The
implementation of the Clean Air Act Amendments is expected to
result in increased operating expenses.  These increased
operating expenses are not expected to have a material impact on
Enron's financial position or results of operations.

   The Environmental Protection Agency (EPA) has informed Enron
that it is a potentially responsible party at the Decorah Former
Manufactured Gas Plant Site (the Decorah Site) in Decorah, Iowa,
pursuant to the provisions of the Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA, also commonly
known as Superfund).  The manufactured gas plant in Decorah
ceased operations in 1951.  A predecessor company of Enron
purchased the Decorah Site in 1963.  Enron's predecessor did not
operate the gas plant and sold the Decorah Site in 1965.  The EPA
alleges that hazardous substances were released to the
environment during the period in which Enron's predecessor owned
the site, and that Enron's predecessor assumed the liabilities of
the company that operated the plant.  Enron contests these
allegations.  To date, the EPA has identified no other
potentially responsible parties with respect to this site.  Enron
has entered into a consent order with the EPA by which it has
agreed, although admitting no liability, to replace affected
topsoil and remove impacted subsurface soils in certain areas of
the tract where the plant was formerly located.  Enron completed
the final removal actions at the site in November 1998, and
expects to conclude all remaining site activities in the spring
of 1999.  In 1998, Enron's expenses related to the Decorah Site
were $300,000 as compared with $400,000 in 1997.  Enron believes
that expenses incurred in connection with this matter will not
have a materially adverse effect on its financial position or
results of operations.

   Enron has also received from the EPA an Order issued under
CERCLA alleging that Enron and two other parties are responsible
for the cost of demolition and proper disposal of two 110 foot
towers that apparently had been used in the manufacture of carbon
dioxide at a site called the "City Bumper Site" in Cincinnati,
Ohio.  The carbon dioxide plant, according to agency documents,
was in operation from 1926 to 1966.  Houston Natural Gas
Corporation, a predecessor of Enron Corp., merged with Liquid
Carbonic Industries (LCI) on January 31, 1969.  Liquid Carbonic
Corporation (LCC), a subsidiary of LCI, had title to the site.
Twenty-eight days after the merger, on February 28, 1969, the
site was sold to a third party.  In 1984, LCC was sold to an
unaffiliated party in a stock sale.  Although Enron does not
admit liability with respect to any costs at this site, it agreed
to cooperate with the EPA and other potentially responsible
parties to undertake the work contemplated by EPA's Order.  The
tower demolition and removal activities were completed in October
1998, and a final project report has been prepared for submission
to the EPA.  In 1998, Enron's expenses related to the City Bumper
Site were $600,000.  Enron does not expect to incur material
expenditures in connection with this site.

   Enron's natural gas pipeline companies conduct soil and
groundwater remediation of a number of their facilities.  In
1998, these expenses were $1.3 million as compared with $1.7
million in 1997.  Enron does not expect to incur material
expenditures in connection with soil and groundwater remediation.

15  COMMITMENTS

   Firm Transportation Obligations.  Enron has firm
transportation agreements with various joint venture pipelines.
Under these agreements, Enron must make specified minimum
payments each month.  At December 31, 1998, the estimated
aggregate amounts of such required future payments were $53
million, $67 million, $69 million, $71 million and $72 million
for 1999 through 2003, respectively, and $601 million for later
years.

   The costs recognized under firm transportation agreements,
including commodity charges on actual quantities shipped, totaled
$30 million, $27 million and $25 million in 1998, 1997 and 1996,
respectively.  Enron has assigned firm transportation contracts
with two of its joint ventures to third parties and guaranteed
minimum payments under the contracts averaging approximately $36
million annually through 2001 and $3 million in 2002.

   Other Commitments.  Enron leases property, operating
facilities and equipment under various operating leases, certain
of which contain renewal and purchase options and residual value
guarantees.  Future commitments related to these items at
December 31, 1998 were $208 million, $210 million, $324 million,
$148 million and $131 million for 1999 through 2003,
respectively, and $954 million for later years. Guarantees under
the leases total $1,039 million at December 31, 1998.

   Total rent expense incurred during 1998, 1997 and 1996 was
$147 million, $156 million and $149 million, respectively.

   Enron guarantees certain long-term contracts for the sale of
electrical power and steam from a cogeneration facility owned by
one of Enron's equity investees.  Under terms of the contracts,
which initially extend through June 1999, Enron could be liable
for penalties should, under certain conditions, the contracts be
terminated early.  Enron also guarantees the performance of
certain of its unconsolidated affiliates in connection with
letters of credit issued on behalf of those unconsolidated
affiliates.  At December 31, 1998, a total of $209 million of
such guarantees were outstanding, including $44 million on behalf
of EOTT.  In addition, Enron is a guarantor on certain
liabilities of unconsolidated affiliates and other companies
totaling approximately $755 million, including $366 million
related to EOTT trade obligations.  The EOTT letters of credit
and guarantees of trade obligations are secured by the assets of
EOTT.  Enron has also guaranteed $453 million in lease
obligations for which it has been indemnified by an "Investment
Grade" company.  Management does not consider it likely that
Enron would be required to perform or otherwise incur any losses
associated with the above guarantees.  In addition, certain
commitments have been made related to 1999 planned capital
expenditures and equity investments.

16  QUARTERLY FINANCIAL DATA (Unaudited)

   Summarized quarterly financial data is as follows:

<TABLE>
<CAPTION>
(In Millions, Except           First    Second     Third    Fourth     Total
 Per Share Amounts)           Quarter   Quarter   Quarter   Quarter    Year

<S>                           <C>       <C>       <C>        <C>      <C>
1998
Revenues                      $5,682    $6,557    $11,320    $7,701   $31,260
Income before
 interest, minority
 interests and income taxes      471       345        405       361     1,582
Net income                       214       145        168       176       703
Earnings per share:
  Basic                       $ 0.69    $ 0.44    $  0.50    $ 0.52   $  2.14(a)
  Diluted                       0.65      0.42       0.47      0.49      2.02(a)

1997
Revenues                      $5,344    $3,251    $ 5,806    $5,872   $20,273
Income (loss) before
 interest, minority
 interests and income taxes      429      (548)       311       373       565
Net income (loss)                222      (420)       134       169       105
Earnings (loss) per share:
  Basic                       $ 0.88    $(1.71)   $  0.44    $ 0.55   $  0.32(a)
  Diluted                       0.81     (1.71)      0.42      0.53      0.32(a)

<FN>
(a) The sum of earnings per share for the four quarters may not
    equal earnings per share for the total year due to changes in
    the average number of common shares outstanding.
    Additionally, certain items in the diluted earnings per share
    computation were antidilutive in the second quarter and total
    year 1997.
</TABLE>

17  GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION

   Enron adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information," during the fourth quarter of
1998.  SFAS No. 131 establishes standards for reporting
information about operating segments in annual financial
statements and requires selected information about operating
segments in interim financial reports.  Operating segments are
defined as components of an enterprise about which separate
financial information is available and evaluated regularly by the
chief operating decision maker, or decision making group, in
deciding how to allocate resources and in assessing performance.
Enron's chief operating decision making group is the Management
Committee, which consists of the Chairman, President, and other
key officers.

   The segments described below aggregate similar businesses
together based on such factors as regulatory environment,
products and services and customers.

   Enron's operations are classified into the following business
segments:

   Exploration and Production - Natural gas and crude oil
exploration and production primarily in the United States,
Canada, Trinidad and India.

   Transportation and Distribution - Regulated industries.
Interstate transmission of natural gas.  Management and operation
of pipelines.  Electric utility operations.

   Wholesale Energy Operations and Services - Energy commodity
sales and services, risk management products and financial
services to wholesale customers.  Development, acquisition and
operation of power plants, natural gas pipelines and other energy
related assets.

   Retail Energy Services - Sale of natural gas and electricity
directly to end-use customers, particularly in the commercial and
industrial sectors, including the outsourcing of energy-related
activities.

   Corporate and Other - Includes operation of water,
telecommunications and renewable energy businesses and clean
fuels plants, as well as Enron's investment in crude oil
transportation activities.

   Financial information by geographic and business segment
follows for each of the three years in the period ended December
31, 1998.

Geographic Segments

<TABLE>
<CAPTION>
                                  Year Ended December 31,
(In Millions)                     1998      1997      1996

<S>                              <C>       <C>       <C>
Operating revenues from
 unaffiliated customers
  United States                  $25,247   $17,328   $11,262
  Foreign                          6,013     2,945     2,027
                                 $31,260   $20,273   $13,289
Income (loss) before interest,
 minority interests and income
 taxes
  United States                  $ 1,008   $   601   $   938
  Foreign                            574       (36)      300
                                 $ 1,582   $   565   $ 1,238
Long-lived assets
  United States                  $ 9,382   $ 8,425   $ 6,490
  Foreign                          1,275       745       622
                                 $10,657   $ 9,170   $ 7,112
</TABLE>

<TABLE>
Business Segments

<CAPTION>
                                                               Wholesale
                                Exploration  Transportation     Energy        Retail    Corporate
                                    and           and          Operations     Energy       and
(In Millions)                   Production    Distribution    and Services   Services   Other(c)    Total

<S>                              <C>             <C>            <C>           <C>        <C>       <C>
1998
Unaffiliated revenues(a)         $  750          $1,833         $27,220       $1,072     $  385    $31,260
Intersegment revenues(b)            134              16             505            -       (655)         -
  Total revenues                    884           1,849          27,725        1,072       (270)    31,260
Depreciation, depletion and
 amortization                       315             253             195           31         33        827
Operating income (loss)             133             562             880         (124)       (73)     1,378
Equity in earnings of
 unconsolidated affiliates            -              33              42           (2)        24         97
Interest income                       1               3              61            -         17         82
Other income, net                    (6)             39             (15)           7          -         25
Income (loss) before interest,
 minority interests and
 income taxes                       128             637             968         (119)       (32)     1,582
Capital expenditures                690             310             706           75        124      1,905
Identifiable assets               3,001           6,955          12,205          747      2,009     24,917
Investments in and advances to
 unconsolidated affiliates            -             661           2,632            -      1,140      4,433
  Total assets                   $3,001          $7,616         $14,837       $  747     $3,149    $29,350

1997
Unaffiliated revenues(a)         $  789          $1,402         $17,344       $  683     $   55    $20,273
Intersegment revenues(b)            108              14             678            2       (802)         -
  Total revenues                    897           1,416          18,022          685       (747)    20,273
Depreciation, depletion and
 amortization                       278             160             133            7         22        600
Operating income (loss)             185             398             376         (105)      (839)        15
Equity in earnings of
 unconsolidated affiliates            -              40             172           (1)         5        216
Interest income                       2               3              52            -         11         68
Other income, net                    (4)            139              54           (1)        78        266
Income (loss) before interest,
 minority interests and
 income taxes                       183             580             654         (107)      (745)       565
Capital expenditures                626             337             318           36         75      1,392
Identifiable assets               2,668           7,115           8,661          322      1,130     19,896
Investments in and advances to
 unconsolidated affiliates            -             521           1,932            -        203      2,656
  Total assets                   $2,668          $7,636         $10,593       $  322     $1,333    $22,552

1996
Unaffiliated revenues(a)         $  647          $  702         $11,413       $  513     $   14    $13,289
Intersegment revenues(b)            177              23             491           15       (706)         -
  Total revenues                    824             725          11,904          528       (692)    13,289
Depreciation, depletion and
 amortization                       251              66             138            -         19        474
Operating income (loss)             205             337             287            -       (139)       690
Equity in earnings of
 unconsolidated affiliates            -              35             168            -         12        215
Interest income                       2               4              28            -          7         41
Other income, net                    (7)            148             (17)           -        168        292
Income before interest,
 minority interests and
 income taxes                       200             524             466            -         48      1,238
Capital expenditures                540             175             136            -         13        864
Identifiable assets               2,371           2,363           8,879            -        823     14,436
Investments in and advances to
 unconsolidated affiliates            -             516           1,005            -        180      1,701
  Total assets                   $2,371          $2,879         $ 9,884       $    -     $1,003    $16,137

<FN>
(a) Unaffiliated revenues include sales to unconsolidated affiliates.
(b) Intersegment sales are made at prices comparable to those received
    from unaffiliated customers and in some instances are affected by
    regulatory considerations.
(c) Includes consolidating eliminations.
</TABLE>

18  OIL AND GAS PRODUCING ACTIVITIES (Unaudited except for
Results of Operations for Oil and Gas Producing Activities)

   The following information regarding Enron's oil and gas
producing activities should be read in conjunction with Note 1.
This information includes amounts attributable to a minority
interest of 46%, 45%, 47% and 39% at December 31, 1998, 1997,
1996 and 1995, respectively.

<TABLE>
Capitalized Costs Relating to Oil and Gas Producing Activities

<CAPTION>
                                December 31,
(In Millions)                   1998      1997

<S>                           <C>       <C>
Proved properties             $ 4,630   $ 4,070
Unproved properties               184       221
  Total                         4,814     4,291
Accumulated depreciation,
 depletion and amortization    (2,138)   (1,904)
  Net capitalized costs       $ 2,676   $ 2,387
</TABLE>

<TABLE>
Costs Incurred in Oil and Gas Property Acquisition, Exploration
and Development Activities(a)

<CAPTION>
(In Millions)               United States   Foreign   Total

<S>                             <C>          <C>      <C>
1998
Acquisition of properties
  Unproved                      $ 33         $  3     $ 36
  Proved                         198           13      211
     Total                       231           16      247
Exploration                       82           55      137
Development                      298           97      395
     Total                      $611         $168     $779

1997
Acquisition of properties
  Unproved                      $ 69         $  8     $ 77
  Proved                          43           38       81
     Total                       112           46      158
Exploration                       74           27      101
Development                      333          109      442
     Total                      $519         $182     $701

1996
Acquisition of properties
  Unproved                      $ 39         $  6     $ 45
  Proved                          69            -       69
     Total                       108            6      114
Exploration                       61           27       88
Development                      283          123      406
     Total                      $452         $156     $608

<FN>
(a) Costs have been categorized on the basis of Financial
    Accounting Standards Board definitions which include costs of
    oil and gas producing activities whether capitalized or
    charged to expense as incurred.
</TABLE>

Results of Operations for Oil and Gas Producing Activities(a)

   The following tables set forth results of operations for oil
and gas producing activities for the three years in the period
ended December 31, 1998:

<TABLE>
<CAPTION>
(In Millions)               United States   Foreign   Total

<S>                             <C>          <C>      <C>
1998
Operating revenues
  Associated companies          $118         $ 15     $133
  Trade                          432          193      625
  Gains on sales of
   reserves and related
   assets                         29           (3)      26
     Total                       579          205      784
Exploration expenses,
 including dry hole costs         64           25       89
Production costs                  99           45      144
Impairment of unproved
 oil and gas properties           30            2       32
Depreciation, depletion and
 amortization                    265           49      314
  Income before income taxes     121           84      205
Income tax expense                23           45       68
  Results of operations         $ 98         $ 39     $137

1997
Operating revenues
  Associated companies          $207         $ 15     $222
  Trade                          449          160      609
  Gains on sales of
   reserves and related
   assets                          4            5        9
     Total                       660          180      840
Exploration expenses,
 including dry hole costs         51           24       75
Production costs                 106           43      149
Impairment of unproved
 oil and gas properties           24            3       27
Depreciation, depletion and
 amortization                    239           39      278
  Income before income taxes     240           71      311
Income tax expense                69           40      109
  Results of operations         $171         $ 31     $202

1996
Operating revenues
  Associated companies          $253         $ 14     $267
  Trade                          282          153      435
  Gains on sales of
   reserves and related
   assets                         19            1       20
     Total                       554          168      722
Exploration expenses,
 including dry hole costs         45           23       68
Production costs                  77           42      119
Impairment of unproved
 oil and gas properties           19            2       21
Depreciation, depletion and
 amortization                    209           42      251
  Income before income taxes     204           59      263
Income tax expense                54           39       93
  Results of operations         $150         $ 20     $170

<FN>
(a) Excludes net revenues associated with other marketing
    activities, interest charges, general corporate expenses and
    certain gathering and handling fees, which are not part of
    required disclosures about oil and gas producing activities.
</TABLE>

Oil and Gas Reserve Information

   The following summarizes the policies used by Enron in
preparing the accompanying oil and gas supplemental reserve
disclosures, Standardized Measure of Discounted Future Net Cash
Flows Relating to Proved Oil and Gas Reserves and reconciliation
of such standardized measure from period to period.

   Estimates of proved and proved developed reserves at December
31, 1998, 1997 and 1996 were based on studies performed by
Enron's engineering staff for reserves in the United States,
Canada, Trinidad, India and China.  Opinions by DeGolyer and
MacNaughton, independent petroleum consultants, for the years
ended December 31, 1998, 1997 and 1996 covered producing areas,
in the United States, Canada and Trinidad, containing 39%, 54%
and 64%, respectively, of proved reserves, excluding deep
Paleozoic reserves, of Enron on a net-equivalent-cubic-feet-of-
gas basis.  These opinions indicate that the estimates of proved
reserves prepared by Enron's engineering staff for the properties
reviewed by DeGolyer and MacNaughton, when compared in total on a
net-equivalent-cubic-feet-of-gas basis, do not differ by more
than 5% from those prepared by DeGolyer and MacNaughton's
engineering staff.  In addition, the deep Paleozoic reserves were
covered by the opinion of DeGolyer and MacNaughton at December
31, 1995.  All reports by DeGolyer and MacNaughton were developed
utilizing geological and engineering data provided by Enron.

   The standardized measure of discounted future net cash flows
does not purport, nor should it be interpreted, to present the
fair market value of Enron's crude oil and natural gas reserves.
An estimate of fair value would also take into account, among
other things, the recovery of reserves not presently classified
as proved reserves, anticipated future changes in prices and
costs and a discount factor more representative of the time value
of money and the risks inherent in reserve estimates.

<TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves

<CAPTION>
(In Millions)                       United States   Foreign    Total

<S>                                    <C>          <C>       <C>
1998
Future cash inflows(a)                 $ 5,471      $ 4,724   $10,195
Future production costs                 (1,281)      (1,351)   (2,632)
Future development costs                  (316)        (608)     (924)
Future net cash flows before
 income taxes                            3,874        2,765     6,639
Future income taxes                       (904)        (970)   (1,874)
Future net cash flows                    2,970        1,795     4,765
Discount to present value at
 10% annual rate                        (1,399)        (845)   (2,244)
Standardized measure of discounted
 future net cash flows relating
 to proved oil and gas reserves(a)     $ 1,571      $   950   $ 2,521

1997
Future cash inflows(a)                 $ 5,187       $2,994   $ 8,181
Future production costs                 (1,138)        (836)   (1,974)
Future development costs                  (313)        (124)     (437)
Future net cash flows before
 income taxes                            3,736        2,034     5,770
Future income taxes                       (888)        (810)   (1,698)
Future net cash flows                    2,848        1,224     4,072
Discount to present value at
 10% annual rate                        (1,298)        (473)   (1,771)
Standardized measure of discounted
 future net cash flows relating
 to proved oil and gas reserves(a)     $ 1,550       $  751   $ 2,301

1996
Future cash inflows(a)                 $ 9,391       $2,288   $11,679
Future production costs                 (1,640)        (856)   (2,496)
Future development costs                  (306)         (10)     (316)
Future net cash flows before
 income taxes                            7,445        1,422     8,867
Future income taxes                     (2,260)        (572)   (2,832)
Future net cash flows                    5,185          850     6,035
Discount to present value at
 10% annual rate                        (2,693)        (273)   (2,966)
Standardized measure of discounted
 future net cash flows relating
 to proved oil and gas reserves(a)     $ 2,492       $  577   $ 3,069

<FN>
(a) Based on year-end market prices determined at the point
    of delivery from the producing unit.  Based on natural gas and
    crude oil prices as of March 1, 1999, the standardized measure
    of discounted future net cash flows for operations in the
    United States would have been lower by approximately 23%.
    Changes in other producing areas and changes in reported
    quantities were not material.
</TABLE>

<TABLE>
Changes in Standardized Measure of Discounted Future Net Cash
Flows

<CAPTION>
(In Millions)                          United States   Foreign   Total

<C>                                       <C>           <C>     <C>
December 31, 1995                         $1,240(a)     $345    $1,585(a)
  Sales and transfers of oil
   and gas produced, net
   of production costs                      (437)       (126)     (563)
  Net changes in prices and
   production costs                        1,817         172     1,989
  Extensions, discoveries, additions
   and improved recovery, net of
   related costs                             581         275       856
  Development costs incurred                  58           4        62
  Revisions of estimated development
   costs                                     (14)         12        (2)
  Revisions of previous quantity
   estimates                                   7          79        86
  Accretion of discount                      137          47       184
  Net change in income taxes                (656)       (191)     (847)
  Purchases of reserves in place             162           -       162
  Sales of reserves in place                (103)         (3)     (106)
  Changes in timing and other               (300)        (37)     (337)
December 31, 1996                         $2,492(a)     $577    $3,069(a)
  Sales and transfers of oil
   and gas produced, net
   of production costs                      (519)       (132)     (651)
  Net changes in prices and
   production costs                       (1,664)        (50)   (1,714)
  Extensions, discoveries, additions
   and improved recovery, net of
   related costs                             374         300       674
  Development costs incurred                  52           2        54
  Revisions of estimated development
   costs                                       4         (28)      (24)
  Revisions of previous quantity
   estimates                                 (17)         26         9
  Accretion of discount                      328          89       417
  Net change in income taxes                 606         (67)      539
  Purchases of reserves in place              44          53        97
  Sales of reserves in place                 (29)          -       (29)
  Changes in timing and other               (121)        (19)     (140)
December 31, 1997                         $1,550(a)     $751    $2,301(a)
  Sales and transfers of oil
   and gas produced, net
   of production costs                      (424)       (164)     (588)
  Net changes in prices and
   production costs                          (34)       (136)     (170)
  Extensions, discoveries, additions
   and improved recovery, net of
   related costs                             326         440       766
  Development costs incurred                  60          56       116
  Revisions of estimated  development
   costs                                     (27)        (80)     (107)
  Revisions of previous quantity
   estimates                                 (35)         32        (3)
  Accretion of discount                      174         113       287
  Net change in income taxes                  48          (6)       42
  Purchases of reserves in place             157          20       177
  Sales of reserves in place                 (34)          -       (34)
  Changes in timing and other               (190)        (76)     (266)
December 31, 1998                         $1,571(a)     $950    $2,521(a)

<FN>
(a) Includes approximately $155 million, $86 million and $344
    million (discounted, pre-tax) related to the reserves in the
    Big Piney deep Paleozoic formations at December 31, 1998, 1997
    and 1996, respectively.
</TABLE>

Reserve Quantity Information

   Enron's estimates of proved developed and net proved reserves
of crude oil, condensate, natural gas liquids and natural gas and
of changes in net proved reserves were as follows:

<TABLE>
<CAPTION>
                                United States   Foreign     Total

<C>                             <C>           <C>        <C>
Net proved developed reserves
Natural gas (Bcf)
  December 31, 1995              1,218.1(a)      544.0    1,762.1(a)
  December 31, 1996              1,325.7(a)      814.3    2,140.0(a)
  December 31, 1997              1,349.0(a)      986.3    2,335.3(a)
  December 31, 1998              1,429.7(a)    1,077.8    2,507.5(a)
Liquids (MBbl)(b)
  December 31, 1995             19,977        23,654     43,631
  December 31, 1996             24,868        26,411     51,279
  December 31, 1997             27,707        39,108     66,815
  December 31, 1998             33,045        45,719     78,764

Natural gas (Bcf)
Net proved reserves at
 December 31, 1995               2,654.1(a)      634.4    3,288.5(a)
  Revisions of previous
   estimates                         3.6          76.7       80.3
  Purchases in place               100.6           0.9      101.5
  Extensions, discoveries and
   other additions                 256.8         264.5      521.3
  Sales in place                   (58.4)         (4.3)     (62.7)
  Production                      (210.2)        (81.5)    (291.7)
Net proved reserves at
 December 31, 1996               2,746.5(a)      890.7    3,637.2(a)
  Revisions of previous
   estimates                       (50.8)         23.2      (27.6)
  Purchases in place                60.0          67.6      127.6
  Extensions, discoveries and
   other additions                 275.9         299.0      574.9
  Sales in place                   (17.7)         (0.4)     (18.1)
  Production                      (229.1)        (84.6)    (313.7)
Net proved reserves at
 December 31, 1997               2,784.8(a)    1,195.5    3,980.3(a)
  Revisions of previous
   estimates                       (55.9)         34.1      (21.8)
  Purchases in place               123.0          54.9      177.9
  Extensions, discoveries and
   other additions                 272.8       1,200.6    1,473.4
  Sales in place                   (37.5)          -        (37.5)
  Production                      (233.8)       (109.6)    (343.4)
Net proved reserves at
 December 31, 1998               2,853.4(a)    2,375.5    5,228.9(a)
</TABLE>

<TABLE>
<CAPTION>
                               United States   Foreign   Total

<C>                                <C>         <C>       <C>
Liquids (MBbl)(b)
Net proved reserves at
 December 31, 1995                 25,399      24,997    50,396
  Revisions of previous
   estimates                          339       2,026     2,365
  Purchases in place                  312           2       314
  Extensions, discoveries and
   other additions                  7,103       3,779    10,882
  Sales in place                     (447)       (121)     (568)
  Production                       (3,830)     (4,272)   (8,102)
Net proved reserves at
 December 31, 1996                 28,876      26,411    55,287
  Revisions of previous
   estimates                        3,515         213     3,728
  Purchases in place                  127       1,123     1,250
  Extensions, discoveries and
   other additions                  6,037      21,713    27,750
  Sales in place                   (1,683)          -    (1,683)
  Production                       (5,223)     (3,458)   (8,681)
Net proved reserves at
 December 31, 1997                 31,649      46,002    77,651
  Revisions of previous
   estimates                         (152)      1,583     1,431
  Purchases in place                3,104           -     3,104
  Extensions, discoveries and
   other additions                  9,396      24,467    33,863
  Sales in place                   (1,039)          -    (1,039)
  Production                       (6,131)     (4,309)  (10,440)
Net proved reserves at
 December 31, 1998                 36,827      67,743   104,570

<FN>
(a) Includes 1,180 Bcf related to net proved deep Paleozoic
    natural gas reserves.
(b) Includes crude oil, condensate and natural gas liquids.
</TABLE>

<PAGE>
          REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
               ON FINANCIAL STATEMENT SCHEDULE


To Enron Corp.:

We have audited in accordance with generally accepted
auditing standards, the consolidated financial statements of
Enron Corp. and subsidiaries included in this Form 10-K and
have issued our report thereon dated March 5, 1999.  Our
audit was made for the purpose of forming an opinion on
the basic financial statements taken as a whole.  The
schedule listed in Item 14(a)2 is the responsibility of the
company's management and is presented for purposes of
complying with the Securities and Exchange Commission's
rules and is not part of the basic financial statements.
This schedule has been subjected to the auditing procedures
applied in the audit of the basic financial statements and,
in our opinion, fairly states in all material respects the
financial data required to be set forth therein in relation
to the basic financial statements taken as a whole.





                              Arthur Andersen LLP

Houston, Texas
March 5, 1999


<PAGE>
<TABLE>
                                                                SCHEDULE II
                                     
                       ENRON CORP. AND SUBSIDIARIES
              SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
           FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
                               (In Millions)

<CAPTION>
       Column A                   Column B          Column C             Column D        Column E
                                                    Additions           Deductions
                                 Balance at   Charged to   Charged    For Purpose For
                                  Beginning   Costs and    to Other   Which Reserves    Balance at
     Description                   of Year     Expenses    Accounts    Were Created     End of Year

<S>                                 <C>         <C>          <C>          <C>              <C>
1998
Reserves deducted from
 assets from price risk
 management activities              $282        $141         $  -         $ 98             $325

Reserves for regulatory issues       262          15           27           57              247

Other reserves(a)                     45          20            1           17               49

1997
Reserves deducted from
 assets from price risk
 management activities              $249        $ 50         $  6         $ 23             $282

Reserves for regulatory issues         8          28          249           23              262

Other reserves(a)                     35          13            3            6               45

1996
Reserves deducted from
 assets from price risk
 management activities              $207        $ 87         $ (8)        $ 37             $249

Reserves for regulatory issues        51           1            -           44                8

Other reserves(a)                     36          15            -           16               35

<FN>
(a) Consists of allowance for doubtful accounts and reserve for insurance
    claims and losses.
</TABLE>

<PAGE>
                         SIGNATURES


     Pursuant to the requirements of Section 13 or 15(d) of
the Securities Exchange Act of 1934, the Registrant has duly
caused this Report to be signed on its behalf by the
undersigned, thereunto duly authorized, on this 29th day of
March, 1999.

                              ENRON CORP.
                              (Registrant)



                              By:  RICHARD A. CAUSEY
                                   (Richard A. Causey)
                                   Senior Vice President,
                                   Chief Accounting, Information
                                   and Administrative Officer


     Pursuant to the requirements of the Securities Exchange
Act of 1934, this Report has been signed below on March 29,
1999 by the following persons on behalf of the Registrant
and in the capacities indicated.


       Signature                  Title

     KENNETH L. LAY           Chairman of the Board, Chief
     (Kenneth L. Lay)         Executive Officer and Director
                              (Principal Executive Officer)

     RICHARD A. CAUSEY        Senior Vice President, Chief Accounting,
    (Richard A. Causey)       Information and Administrative Officer
                              (Principal Accounting Officer)

     ANDREW S. FASTOW         Senior Vice President and Chief
    (Andrew S. Fastow)        Financial Officer
                              (Principal Financial Officer)

     ROBERT A. BELFER*        Director
    (Robert A. Belfer)

    NORMAN P. BLAKE, JR.*     Director
   (Norman P. Blake, Jr.)

      RONNIE C. CHAN*         Director
     (Ronnie C. Chan)

      JOHN H. DUNCAN*         Director
     (John H. Duncan)

       JOE H. FOY*            Director
      (Joe H. Foy)

     WENDY L. GRAMM*          Director
    (Wendy L. Gramm)

    KEN L. HARRISON*          Director
   (Ken L. Harrison)

    ROBERT K. JAEDICKE*       Director
   (Robert K. Jaedicke)

   CHARLES A. LeMAISTRE*      Director
  (Charles A. LeMaistre)

     JEROME J. MEYER*         Director
    (Jerome J. Meyer)

    JEFFREY K. SKILLING*      Director and President and Chief
   (Jeffrey K. Skilling)      Operating Officer

     JOHN A. URQUHART*        Director
    (John A. Urquhart)

      JOHN WAKEHAM*           Director
     (John Wakeham)

     CHARLS E. WALKER*        Director
    (Charls E. Walker)

   HERBERT S. WINOKUR, JR.*   Director
  (Herbert S. Winokur, Jr.)




*By:  PEGGY B. MENCHACA
     (Peggy B. Menchaca)
(Attorney-in-fact for persons indicated)