SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
____________
Form 10-K
____________
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
OR
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
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 organization) Identification No.)
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
6-1/4% Exchangeable Notes due New York Stock
December 13, 1998 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 17, 1998, was approximately
$14,145,929,936. As of March 1, 1998, there were
311,604,046 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 5,
1998 Annual Meeting of Shareholders ("Proxy Statement") are
incorporated herein by reference in Part III of this Form
10-K.
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
Evolving International Markets 13
Retail Energy Services 16
Other Enron Businesses 17
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 33
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
Information Regarding Forward Looking Statements 55
Item 8. Financial Statements and Supplementary Data 55
Item 9. Disagreements on Accounting and Financial
Disclosure 55
PART III
Item 10. Directors and Executive Officers of the Registrant 56
Item 11. Executive Compensation 56
Item 12. Security Ownership of Certain Beneficial Owners
and Management 56
Item 13. Certain Relationships and Related Transactions 57
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 58
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 in international markets. As of December 31,
1997, Enron employed approximately 15,500 persons.
Effective July 1, 1997, Enron merged with Portland
General Corporation ("PGC") in a stock-for-stock
transaction. PGC, through its wholly-owned subsidiary
Portland General Electric Company ("PGE"), serves retail
electric customers in northwest Oregon as well as wholesale
electricity customers throughout the western United States.
Pursuant to the merger, Enron Corp., a Delaware corporation
organized in 1930, reincorporated in Oregon.
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 - 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 light industrial sectors.
Corporate and Other - Includes operation of renewable
energy businesses and methanol and MTBE plants, as well as
Enron's investment in crude oil transportation activities.
Enron's business segment information has been
reclassified from prior years to reflect the realignment of
Enron's operations.
For financial information by business segment for the
fiscal years ended December 31, 1995 through December 31,
1997, please see Note 17 to the Consolidated Financial
Statements on page F-31.
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 approximately 55% of
the outstanding common stock of EOG.
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. At December 31,
1997, EOG's estimated net proved natural gas reserves were
4,001 billion cubic feet ("Bcf"), and estimated net proved
crude oil, condensate and natural gas liquids reserves were
78 million barrels, and at such date, approximately 67% of
EOG's reserves (on a natural gas equivalent basis) were
located in the United States, 10% in Canada, 8% in Trinidad
and 15% in India.
EOG's eight principal U.S. 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 82% of
EOG's U.S. reserves (on a natural gas equivalent basis) and
79% of EOG's U.S. net natural gas deliverability as of
December 31, 1997. These properties are substantially all
operated by EOG. EOG's other U.S. 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, 1997, 94% of EOG's proved U.S.
reserves (on a natural gas equivalent basis) were natural
gas and 6% were crude oil, condensate and natural gas
liquids. EOG's reserves include 1,180 Bcf of proved
undeveloped methane reserves in the deep Paleozoic
formations of the Big Piney area of Wyoming.
EOG is also engaged in the exploration for and the
development, production and marketing of natural gas and
crude oil and the operation of natural gas processing plants
in western Canada, principally in the provinces of Alberta,
Saskatchewan, and Manitoba. EOG conducts its Canadian
operations from offices in Calgary. At December 31, 1997,
Canadian natural gas deliverability net to EOG was
approximately 100 million cubic feet ("MMcf") per day, and
EOG held approximately 490,000 net undeveloped acres in
Canada.
EOG also has producing operations offshore Trinidad and
India and is conducting exploration in selected other
international areas. Properties offshore Trinidad and India
comprised almost all of EOG's proved reserves and production
outside of North America at year-end 1997.
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
Oil Bird 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 1997, deliveries net to EOG
averaged 113 MMcf per day of natural gas and 3.4 thousand
barrels ("MBbl") per day of crude oil and condensate. At
December 31, 1997, EOG held approximately 168,000 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. A 3-D seismic data gathering
project has been completed and is being evaluated. Initial
drilling is expected to commence in 1998.
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 a development plan for the Tapti Block
accumulations, and production began in 1997. At December
31, 1997, production, net to EOG, from the Tapti Block was
48 MMcf per day. The 106,000 acre Panna Block and the
192,000 acre Mukta Block are partially developed with 29
wells producing from six production platforms located in the
Panna and Mukta fields. The fields were producing
approximately 4.3 MBbl per day of crude oil net to EOG as of
December 31, 1997. Natural gas sales from the Panna field
began in early 1998. 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. A 3-D seismic data project is currently
underway, and drilling is anticipated to begin in 1998.
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 areas of proven production. Further
commitments, if any, would arise from entering into the
development period as specified in the contract.
EOG continues to evaluate other selected natural gas
and crude oil opportunities outside North America. 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. In early 1995, EOG, an
Enron affiliate and the Qatar General Petroleum Corporation
signed a nonbinding letter of intent concerning the possible
development of a liquefied natural gas project for natural
gas to be produced from a block within the North Dome Field.
EOG and the Enron affiliate may jointly hold up to a 35%
equity interest in the project. EOG has also entered into a
Memorandum of Understanding with Uzbekneftigaz covering the
pursuit of joint development and marketing opportunities for
proven hydrocarbon reserves in eleven fields in the
Surhandarya and Bukhara regions of Uzbekistan. EOG is also
participating in discussions concerning the potential for
natural gas development opportunities in Mozambique, as well
as other opportunities in Trinidad, India, Venezuela and
Bangladesh.
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, 1997:
Year Ended December 31,
1997 1996 1995
Volumes (per day)
Natural Gas (MMcf)
United States(1) 657 608 560
Canada 101 98 76
Trinidad 113 124 107
India 18 - -
Total 889 830 743
Crude Oil and Condensate (MBbl)
United States 11.7 9.2 9.1
Canada 2.5 2.4 2.4
Trinidad 3.4 5.2 5.1
India 2.3 2.8 2.5
Total 19.9 19.6 19.1
Natural Gas Liquids (MBbl)
United States 2.6 1.3 1.0
Canada 1.3 1.2 .4
Total 3.9 2.5 1.4
Average Prices
Natural Gas ($/Mcf)
United States(2) $ 2.32 $ 2.04 $ 1.39
Canada 1.43 1.15 .97
Trinidad 1.05 1.00 .97
India 2.79 - -
Composite 2.07 1.78 1.29
Crude Oil and Condensate ($/Bbl)
United States $19.81 $21.88 $17.32
Canada 17.16 18.01 16.22
Trinidad 18.68 19.76 16.07
India 20.05 20.17 16.81
Composite 19.30 20.60 16.78
Natural Gas Liquids ($/Bbl)
United States $12.76 $14.67 $11.88
Canada 8.94 9.14 9.74
Composite 11.54 11.99 11.31
Lease and Well Expenses ($/Mcfe)
United States $ .23 $ .19 $ .19
Canada .39 .34 .35
Trinidad .16 .16 .15
India .64 .99 1.25(3)
Composite .26 .22 .22
<FN>
___________________
(1) Includes 48 MMcf per day in 1997, 1996 and 1995
delivered under the terms of a volumetric production
payment agreement effective October 1, 1992, as
amended.
(2) Includes an average equivalent wellhead value of $1.73
per Mcf in 1997, $1.17 per Mcf in 1996, and $.80 per
Mcf in 1995 for the volumes described in note (1), net
of transportation costs.
(3) Includes certain non-recurring startup costs.
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 11.8% 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 borders 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.
In Northern's market area, natural gas is an energy
source available for traditional residential, commercial and
industrial uses. Northern's throughput totaled 1,593
trillion British thermal units ("Tbtu") in 1997, compared to
1,675 Tbtu in 1996. This slight decrease was due primarily
to (i) colder weather in 1996 than in 1997, and (ii) better
price spreads in 1996 that resulted in more discretionary
shippers using Northern.
In 1997, 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 an expansion of approximately 60 MMcf per day underway
which is expected to be in service in late 1998.
Northern competes with other interstate pipelines in
the transportation and storage of natural gas. In recent
years, the FERC has issued orders designed to introduce more
competition into the natural gas industry, having the effect
of increasing transportation volumes and decreasing or
eliminating sales of natural gas by pipelines. 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 pipeline interconnects 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 peak delivery capacity of 1.5 Bcf
per day in 1997 was primarily delivered to local
distribution companies (approximately 65% of revenues) and
gas marketers (approximately 35% of revenues).
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. 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. Total throughput volumes to
California averaged approximately 558 MMcf per day in 1997,
compared to 414 MMcf per day in 1996. 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 has 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 657 MMcf per
day off the east end of its system in 1997, as compared to
773 MMcf per day in 1996.
Transwestern is subject to competition from other
transporters into the southern California market.
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 utility generators.
Florida Gas has periodically expanded its system
capacity to keep pace with the growing demand for natural
gas in Florida. Florida Gas placed its Phase III expansion
in service in 1995, expanding its pipeline through a
combination of the construction of new pipeline and
compression facilities and the purchase of third-party
facilities and transportation service. The Phase III
expansion increased Florida Gas' firm average delivery
capacity into Florida by 532 billion British thermal units
("BBtu") per day to 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
an 11.8% interest in the limited partnership and serves as
operator of the pipeline. Northern Border owns an
approximately 970-mile interstate pipeline system that
transports natural gas from the Montana-Saskatchewan border
near Port of Morgan, Montana to interconnecting pipelines in
the State of Iowa, one of which is Northern. The pipeline
system has access to natural gas reserves in the provinces
of Alberta, British Columbia and Saskatchewan, as well as
the Williston Basin in the U.S. The pipeline system also
has access to production of synthetic gas from the Great
Plains Coal Gasification Project in North Dakota.
Interconnecting pipeline facilities provide access to
markets in the Midwest, as well as other markets throughout
the U.S. 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 1.7 Bcf of natural gas per day) is
contractually committed through October 2001. Northern
Border competes with two other interstate pipeline systems
that transport gas from Canada to the Midwest.
Northern Border is currently constructing a project
which will expand its existing system by delivering an
additional 700 MMcf of natural gas per day from Canada, and
will extend the pipeline 243 miles to Chicago. Northern
Border's total system capacity will increase to
approximately 2.4 Bcf of natural gas per day, with an
expected in-service date of November 1998. The $840 million
project is fully subscribed by over 20 shippers with 10-year
minimum transportation contracts.
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 U.S. 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, 1997 PGE served
approximately 685,000 customers.
PGE serves a diverse retail customer base. Residential
customers constitute the largest customer class and account
for 44% of the of retail revenues. Residential demand is
highly sensitive to the effects of weather. Commercial
customers comprise 40% and industrial customers represent
16% of retail revenues. The commercial and industrial
classes are not dominated by any single industry. While the
20 largest customers constitute 21% of retail demand, they
represent 10 different industry groups including paper
manufacturing, high technology, metal fabrication,
transportation equipment and health services. No single
customer represents more than 10% of PGE's retail load.
In late 1997, PGE filed a proposal before the Oregon
Public Utility Commission ("OPUC") which would give all of
its customers a choice of electricity providers. PGE's
"Customer Choice Implementation Proposal" includes new
tariffs and a new structure for PGE. If approved by the
OPUC, PGE would become a regulated transmission and
distribution company focused on delivering, but not selling,
electricity. PGE would continue to operate and maintain the
electricity delivery system and handle outage restoration,
while other competitive companies would market power to
customers over that system. To effect this restructuring,
PGE is asking for OPUC approval to sell all its generating
assets and power supply and purchase contracts.
Wholesale revenues continue to make a significant
contribution to PGE revenues, providing over 35% of total
operating revenues for 1997. During the past several years,
PGE has actively marketed wholesale power throughout the
western United States. A majority of PGE's wholesale sales
were to its traditional customers comprised of investor
owned utilities, federal agencies, municipalities and public
utility districts. However, most of PGE's wholesale growth
has come through sales to marketers and brokers. These
sales are predominantly of a short-term nature. Long-term
wholesale marketing activities have been transferred to
Enron's non-regulated affiliates, and future revenues will
be reflected in Enron's wholesale energy operations and
services segment.
PGE operates within a state-approved service area, and
under current regulation is substantially free from direct
retail competition with other electric utilities. PGE's
competitors within its Oregon service territory include
other fuel suppliers, such as the local natural gas company,
which compete with PGE for the residential and commercial
space and water heating market. In addition, there is the
potential of a loss of PGE service territory to the creation
of public utility districts or municipal utilities by
voters. In the future, PGE will focus on transitioning to a
regulated transmission and distribution company.
WHOLESALE ENERGY OPERATIONS AND SERVICES
Enron's wholesale energy operations and services
businesses operate in North America, Europe and evolving
energy markets in developing countries, and such businesses
are conducted primarily by Enron Capital & Trade Resources
Corp. and Enron International Inc. These businesses provide
integrated energy-related products and services to wholesale
customers worldwide, including the development, construction
and operation of power plants, natural gas pipelines and
other energy-related assets, energy commodity sales and
services, risk management products and financial services.
Enron Engineering & Construction Company provides
comprehensive engineering and construction expertise for
power and pipeline projects, serving as turnkey contractor
or project manager for such projects.
Wholesale energy operations and services can be
categorized into four business lines: Asset Development and
Construction, Cash and Physical, Risk Management and Finance
and Investing. Products and services related to these
business lines are offered in varying degrees in North
American, European and evolving international markets.
Asset Development and Construction. This business
includes the development and construction of power plants,
pipelines and other energy infrastructure.
Cash and Physical. The cash and physical operations
include the day-to-day purchase, sale, marketing and
delivery of physical natural gas, electricity, liquids and
other commodities under contracts of one year or less and
the management of Enron's contract portfolios. Enron's cash
and physical business also includes the management of
operating assets of this segment, including domestic
intrastate pipelines, numerous storage facilities and power
plants.
Risk Management. The risk management activities
consist of long-term energy commodity contracts
(transactions greater than one year) and restructuring of
existing long-term contracts. Enron provides risk
management products and services that hedge movements in
price and location-based price differentials. Enron's risk
management services are designed to provide stability in
markets impacted by price volatility. Enron applies these
concepts for a diverse group of customers in structuring a
portfolio of products such as swap, option, and hybrid
products; long-term, fixed price contracts; innovative
pricing structures such as commodity prices tied to
alternative fuels and energy supply prices indexed to
output; and utility, local distribution company, and
independent power producer contract restructuring
alternatives. Enron originates new contracts for customers
in the energy industry and evaluates and restructures its
existing contracts on an ongoing basis to develop additional
products and services to meet its customers' changing needs.
The risk management activities also include the origination
of liquid fuels contracts associated with new product
offerings. The risk management group also purchases and
sells electrical energy to and from a variety of power
generators and wholesalers including investor-owned
utilities, rural electric cooperatives and municipal
utilities.
Finance and Investing. Enron's financing and investing
activities support independent exploration and production
companies and other energy-related businesses seeking debt
or equity financing. Enron provides a variety of capital
products including volumetric production payments, loans and
equity investments, either directly or through Enron
affiliates. In addition to capital, Enron may integrate its
marketing and risk management capabilities to help customers
capitalize on growth opportunities while maximizing the
value of their current assets.
The following table presents selected statistical
information for Enron's wholesale energy operations and
services businesses.
Year Ended December 31,
1997 1996 1995
Physical Volumes (Bbtue/d)(a)(b)
Gas:
United States 7,654 6,998 6,405
Canada 2,263 1,406 803
Europe 660 289 -
10,577 8,693 7,208
Transport Volumes 460 544 580
Total Gas Volumes 11,037 9,237 7,788
Oil 690 320 439
Liquids 987 1,187 526
Total Physical Volumes 12,714 10,744 8,753
Electricity Volumes Marketed 192,323 60,150 7,767
(Thousand MWh)
Financial Settlements (Notional) 49,069 35,259 32,938
(Bbtue/d)
Financings Arranged and Production
Payments (Millions) $561 $755 $382
<FN>
(a) Billion British thermal units equivalent per day.
(b) Includes third-party transactions by Enron Energy Services.
North American Markets
Enron's North American wholesale operations include
cash and physical, risk management and finance and investing
business lines.
Enron markets natural gas, electricity and other
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 to provide predictable pricing, reliable delivery
and low cost capital to its customers, including independent
oil and gas producers, energy intensive industrials, public
and investor owned utility power companies, small
independent power producers and local distribution
companies. These services are provided through a variety of
products including forward contracts, swap agreements and
other contractual commitments.
The day-to-day buying, selling and transporting of
commodities is facilitated by using the New York Mercantile
Exchange ("NYMEX"), allowing Enron to manage its portfolio
of contracts and to benefit from the relationship between
the financial and physical prices for natural gas. Total
physical volumes, including volumes transported, averaged
12.7 Tbtu of natural gas equivalents per day in 1997
compared to 10.7 Tbtu of natural gas equivalents per day in
1996. In addition, financial settlements were approximately
49.1 Tbtu of natural gas equivalents per day in 1997 and
35.3 Tbtu of natural gas equivalents per day in 1996.
Enron's intrastate pipelines include Houston Pipe Line
Company ("HPL") and Louisiana Resources Company. HPL owns
an approximately 5,243-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 North American electric power business consists
of various activities, such as providing natural gas
contract services to electric utilities; managing,
acquiring, developing and promoting power-related assets and
joint ventures; and marketing and supplying electricity.
Enron marketed 192.3 million megawatt hours and 60.1 million
megawatt hours of electricity during 1997 and 1996,
respectively. Enron also markets natural gas to the
electric power generation industry, offering firm contract
commitments with both fixed-price and other innovative
pricing terms (such contracts of greater than one year are
included in Enron's risk management operations). Enron will
continue marketing natural gas to independent power projects
as well as electric utilities converting to natural gas in
response to the Clean Air Act of 1990.
European Markets
Enron's European operations, headquartered in London,
commenced in 1989 with the development of the Teesside power
station described below. Since that time, Enron has
continued to operate and develop power assets and provide a
broad range of energy service capabilities similar to
Enron's North American operations, such as the purchase and
sale of physical commodities (natural gas, electricity and
liquids), risk management and finance activities. Enron has
expanded its business from the United Kingdom to continental
Europe with regional offices in Oslo, Stockholm, Moscow and
Frankfurt.
At December 31, 1997, Enron had an approximately 31%
ownership interest in an independent power facility with a
capacity of approximately 1,875 megawatts near Teesside in
northeast England. The gas-fired combined-cycle project was
developed and constructed and is operated by Enron
subsidiaries. The remaining ownership interest is held by
four of the twelve regional electric companies operating in
England and Wales. The Teesside plant has the capacity to
supply approximately 4% of all the electricity consumed in
the U.K., and 1,725 megawatts of this capacity is committed
under long-term contracts. In addition to the Teesside
power plant, Enron also operates an adjacent 300 MMcf per
day gas liquids processing facility.
Enron and the second largest regional utility company
in Germany jointly own an approximately 125 megawatt gas-
fired plant in Bitterfeld, Germany. The Bitterfeld project
provides Enron with a presence in Germany as well as access
to a site for possible expansion.
Enron has a 25% ownership interest in an independent
power facility under construction at Sutton Bridge in mid-
east England, with the remaining ownership interest held by
insurance companies and financial investors. Expected to
commence commercial operation in March 1999, the plant will
be a gas fired combined-cycle plant with a capacity of
approximately 790 megawatts. The project was developed, and
construction is being coordinated, by Enron subsidiaries.
The capacity of the plant is contracted to another Enron
subsidiary until May 2014 with a right to extend, at Enron's
option, for up to an additional ten years in one-year
increments.
Enron has a 45% interest in a 551-megawatt combined-
cycle oil gasification power plant to be located on the
island of Sardinia, Italy. The plant will employ technology
to gasify low-quality residual fuel. Enron will provide
technical services to the plant. A 20-year power purchase
agreement has been signed with ENEL, the Italian government
utility. Financing was completed and construction began in
December 1996, with commercial operation anticipated in
early 2000.
Enron has a 50% interest in a 478-megawatt gas-fired
power plant to be located at Marmara, Turkey, near Istanbul.
Enron will be operator and turnkey contractor of the plant.
A 20-year power purchase agreement has been signed with the
state power utility, financing has been completed, and
construction began in September 1996, with commercial
operation expected in 1999.
Enron's European operations include other power and
pipeline projects in various stages of development in
Poland, Greece, Italy, Turkey and Croatia.
Evolving International Markets
Enron is also involved in the development, acquisition,
financing, promotion, and operation of natural gas pipeline
and power projects in emerging markets and the marketing of
natural gas liquids and other liquid fuels. Asset
development activities are primarily focused on power
plants, gas processing and terminaling facilities, and gas
pipelines. Enron has expanded its international asset and
infrastructure development business by also offering
commodity marketing, finance and risk management products
and services to third parties in emerging markets. Enron
has established offices in Buenos Aires and Singapore to
offer similar physical commodity products, financial
services and risk management services currently available
through Enron's operations in North America and Europe. In
these markets, Enron's objective is to develop, finance, own
and operate energy projects worldwide and to integrate
additional energy related products and services into these
developing markets.
Operating Assets
Enron has an approximately 35% indirect interest in
Transportadora de Gas del Sur ("TGS"), the formerly state-
owned natural gas pipeline in southern Argentina. The 4,104-
mile pipeline system has a capacity of approximately 1.9 Bcf
per day and primarily serves four distribution companies
under long-term firm transportation contracts.
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 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 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, are
50% owned by Enron and sell power to the National Power
Corporation of the Philippines.
Enron has a 50% interest in 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 50% 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 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 1.0 Bcf per day to supply Brazilian
market needs.
Enron has recently acquired interests in the Rio de
Janeiro municipal gas distribution company, in addition to
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.
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. Also
in Venezuela, Enron is engaged in the manufacture and
distribution of appliances in a joint venture with General
Electric and local investors. Enron has a natural gas
distribution system in Puerto Rico, and liquid fuels
businesses in both Puerto Rico and Jamaica.
Projects Under Development
In the evolving international energy markets, Enron is
developing and constructing energy infrastructure to
establish an asset base for development of regional
businesses. Primary areas of focus are in India and South
America. The following is a brief description of certain of
Enron's power and natural gas pipeline projects which are in
varying stages of development, financing or construction.
Because of this, the information set forth below is subject
to change. These 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. There can be no assurances that
these projects will commence commercial operations.
India. In connection with a Power Purchase Agreement
between Dabhol Power Company, Enron's 80%-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 Bombay, 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 late
1998. Enron will be the fuel manager and operator of the
plant, which will provide electricity for the growing
Maharashtra State economy. Enron is expected to finalize in
1998 a sale of 30% of the project to the MSEB.
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 1998, with commercial operations expected
to commence in late 2000.
South America. 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 at a
strategic point which has few existing alternate generation
sources. Construction is underway on Phase I of the project
(150 megawatts), with commercial operations expected in late
1998. Commercial operations of Phase II (330 megawatts) are
expected to commence in late 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 53% of the power plant and
Brazilian segment of the pipeline and 35% of the Bolivian
segment of the pipeline.
Other. Enron has a 50% 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.
Enron has a 50% interest in an 80-megawatt baseload
diesel power plant to be located in Piti, Guam. A 20-year
power purchase agreement has been signed with the Guam Power
Authority, an agency of the Guam government. The project is
on a fast track schedule to meet critical power needs, with
operations targeted for year-end 1998.
In addition to the projects referenced above, Enron is
involved in projects in varying stages of development in
Vietnam, Europe, Mozambique, Qatar, China, Egypt and Saudi
Arabia, and is pursuing projects elsewhere.
RETAIL ENERGY SERVICES
Enron Energy Services (EES) was formed in late 1996 to
provide direct sales of energy products and services to end-
use customers, particularly in the commercial and light
industrial sectors. EES offers a range of energy-related
products and services to commercial and light industrial
customers in both regulated and deregulated markets. These
products and services include energy 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. EES
anticipates providing end-users with a broad range of energy
products and services at competitive prices. EES has
participated successfully in selected natural gas and
electric retail marketing pilots and continues to make
progress in expanding its customer base.
EES is creating products and services to help
commercial and light industrial businesses understand how
they can maximize total energy savings while meeting
operational needs. With a focus on total energy savings,
EES is designing and promoting innovative programs to not
only supply electricity and natural gas to businesses, but
also to reduce their energy consumption, delivery and
billing costs. EES is also investing in technology to
provide businesses with immediate feedback on energy usage
through real-time metering systems and protection from power
outages and surges. At the residential level, EES provides
customers with new and innovative service options in some
deregulated markets.
OTHER ENRON BUSINESSES
Clean Energy Businesses
Opportunities for "clean" energy are being driven by
concerns about the environment and increasing cost
competitiveness of renewable energy compared to other
wholesale energy sources. Enron participates in the
renewable energy market through the development and
operation of solar and wind energy power plants and the
manufacture and sale of solar and wind generation equipment.
Enron is pursuing wind power projects in the U.S., the
United Kingdom, Germany, Spain, Ireland, Greece and several
Central and South American countries. Enron is constructing
a 107-megawatt wind energy project in Minnesota and has
contracts to supply additional wind generated electricity
for projects in Minnesota (100 megawatts), Iowa
(approximately 200 megawatts), California (approximately 80
megawatts) and Greece (15 megawatts). In addition, through
a joint venture partnership, Enron is engaged in the
manufacture of solar energy equipment, with development
activities underway in the U.S., Greece, India and Japan.
Crude Oil Transportation Services
EOTT Energy Partners, L.P. ("EOTT"), a Delaware limited
partnership formed in March 1994, is an independent gatherer
and marketer of crude oil, and EOTT Energy Corp. (a wholly
owned subsidiary of Enron) serves as the general partner of
EOTT. Enron owns an approximately 49% interest in EOTT.
EOTT is engaged in the purchasing, gathering, transporting,
trading, storage and resale of crude oil and refined
petroleum products, and related activities. Through its
North American crude oil gathering and marketing operations,
EOTT purchases crude oil produced from approximately 25,000
leases in 17 states. In addition, EOTT is a purchaser of
lease crude oil in Canada. EOTT provides transportation and
trading services for third party purchasers of crude oil.
In its North American crude oil gathering and marketing
operations, EOTT purchased approximately 305,000 barrels per
day of lease crude oil during 1997. 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, FGT 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, FGT 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, FGT and Northern
Border file applications with the FERC for changes in their
rates and charges designed to allow them to recover fully
their costs of providing service to resale and
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.
Although the FERC's jurisdiction extends to the regulation
of gas transported in interstate commerce or sold in
interstate commerce for resale, the price at which gas is
sold to direct industrial customers by a natural gas company
is not subject to the FERC's jurisdiction.
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
have on upstream pipelines to such pipelines' former sales
customers and provides 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 is 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 FGT. Numerous parties filed
petitions for court review of FERC's Order No. 636 series,
as well as orders in individual pipeline restructuring
proceedings. Various aspects of Order No. 636 were
challenged, including alleged shifts of costs between
pipeline customer groups and the continuing reliability of
unbundled services. There have been two subsequent orders
on rehearing of Order No. 636 (Order Nos. 636-A and 636-B)
and one subsequent order on remand from the D.C. Circuit
Court of Appeals (Order No. 636-C) in which the FERC
modified the original order in response to these and other
concerns. Since the D.C. Circuit Court opinion has been
appealed and further judicial review of FERC's new orders
may result in such orders being reversed in whole or in
part, it is not possible to predict with precision the
ultimate effect of FERC's Order No. 636 series.
The series of 636 orders mandate 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 FGT
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. The FERC has indicated that Northern, Transwestern
and FGT will be authorized to recover all prudently incurred
costs associated with a reduced merchant role resulting from
the implementation of such orders.
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 is
expected to reduce the volatility of the revenue stream to
pipelines.
Regulatory issues and rates on Enron's regulated
pipelines are subject to final determination by the FERC.
Enron's regulated pipelines currently apply accounting
standards that recognize the economic effects of regulation
and, accordingly, have recorded regulatory assets and
liabilities related to their operations. Enron evaluates
the applicability of regulatory accounting and the
recoverability of these assets through rate or other
contractual mechanisms on an ongoing basis. Net regulatory
assets at December 31, 1997 were approximately $283 million,
which included transition costs incurred related to FERC
Order No. 636 of approximately $41 million. The regulatory
assets related to the FERC Order No. 636 transition costs
are scheduled to be primarily recovered from customers by
the end of 1998, while the remaining assets are expected to
be recovered over varying time periods.
Enron's regulated pipelines have all successfully
completed their transitions under FERC Order No. 636
although future transition costs may be incurred subject to
ongoing negotiations and market factors. 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.
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 a consent
decree with the EPA with respect to the cleanup of one
Superfund site. Enron has received requests for information
from the EPA andc 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 Department 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.
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. 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.
REVENUES BY BUSINESS SEGMENT
The following table presents revenues for each business segment
(in millions):
Year Ended December 31,
1997 1996 1995
Exploration and Production
Natural Gas and Other Products
Unaffiliated $ 774 $ 620 $ 410
Intersegment 169 197 165
943 817 575
Other Revenues
Unaffiliated 15 27 71
Intersegment (61) (20) 113
(46) 7 184
TOTAL 897 824 759
Transportation and Distribution
Natural Gas and Other Products
Unaffiliated 10 11 61
Intersegment - 8 34
10 19 95
Transportation Services
Unaffiliated 639 682 680
Intersegment 10 15 21
649 697 701
Electric
Unaffiliated 712 - -
Intersegment - - -
712 - -
Other Revenues
Unaffiliated 41 9 17
Intersegment 4 - -
45 9 17
TOTAL 1,416 725 813
Wholesale Energy Operations
and Services
Natural Gas and Other Products
Unaffiliated 11,778 10,013 6,671
Intersegment 595 477 219
12,373 10,490 6,890
Transportation Services
Unaffiliated 13 25 12
Intersegment 2 2 -
15 27 12
Electric
Unaffiliated 4,376 980 179
Intersegment - - -
4,376 980 179
Other Revenues
Unaffiliated 1,177 395 669
Intersegment 81 12 (53)
1,258 407 616
TOTAL 18,022 11,904 7,697
Retail Energy Services
Natural Gas and Other Products
Unaffiliated 649 513 399
Intersegment 2 15 -
651 528 399
Electric
Unaffiliated 1 - -
Intersegment - - -
1 - -
Other Revenues
Unaffiliated 33 - 1
Intersegment - - -
33 - 1
TOTAL 685 528 400
Corporate and Other
Natural Gas and Other Products
Unaffiliated - - (12)
Intersegment - - -
- - (12)
Electric
Unaffiliated 12 - -
Intersegment - - -
12 - -
Other Revenues
Unaffiliated 43 14 31
Intersegment - - -
43 14 31
TOTAL 55 14 19
Intersegment Eliminations (802) (706) (499)
Total Revenues $20,273 $13,289 $9,189
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
Name and Age Present Principal Position and Other
Material Positions Held During Last
Five Years
Kenneth L. Lay (55) Chairman of the Board and Chief
Executive Officer, Enron Corp., since
February 1986.
Jeffrey K. Skilling (44) 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 (55) Vice Chairman, Enron Corp., since July
1997. Chairman of the Board and Chief
Executive Officer of Portland General
Electric Company since 1987.
John A. Urquhart (69) Vice Chairman, Enron Corp., since
August 1991.
Stanley C. Horton (48) 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.
Rebecca P. Mark (43) Chairman and Chief Executive Officer,
Enron International Inc., since
January 1997. Chairman and Chief
Executive Officer of Enron Development
Corp. since July 1993. Vice President
and Chief Development Officer of Enron
Power Corp. from July 1991 to July
1993.
Thomas E. White (54) Chairman and Chief Executive Officer,
Enron Ventures Corp., since January
1997. Co-Chairman and Chief Executive
Officer of Enron Operations Corp. from
February 1996 to January 1997.
Chairman and Chief Executive Officer
of Enron Operations Corp. from June
1993 to February 1996. Chairman and
Chief Executive Officer of Enron Power
Corp. from July 1991 to June 1993.
Brigadier General, United States Army,
from 1988 to 1990. Executive
Assistant to Chairman of the Joint
Chiefs of Staff from 1989 to 1990.
J. Clifford Baxter (39) Senior Vice President, Corporate
Development, Enron Corp., since
January 1997. 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 (38) 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.(53) Senior Vice President and General
Counsel, Enron Corp., since June 1991.
Partner, Vinson & Elkins from January
1977 until June 1991.
Andrew S. Fastow (36) 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, 1997, 1996 and 1995 were based on studies
performed by EOG's engineering staff for reserves in the
United States, Canada, Trinidad and India. Opinions by
DeGolyer and MacNaughton, independent petroleum consultants,
for the years ended December 31, 1997, 1996 and 1995
covering producing areas containing 54%, 64% and 60%,
respectively, of proved reserves (excluding deep Paleozoic
methane reserves) of EOG on a net-equivalent-cubic-feet-of-
gas basis, 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
materially from the estimates prepared by DeGolyer and
MacNaughton. The deep Paleozoic methane reserves were
covered by the opinion of DeGolyer and MacNaughton for the
year ended December 31, 1995. Such estimates by DeGolyer
and MacNaughton in the aggregate varied by not more than 5%
from those prepared by EOG's engineering staff. 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, 1997 in gas and oil wells located in Texas, the
Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming and
various other states, Canada, Trinidad and India. "Net" is
obtained by multiplying "Gross" by EOG's working interests
in the properties. Gross gas and oil wells include 279 with
multiple completions.
Productive Productive Total
Gas Wells Oil Wells Productive Wells
Gross Net Gross Net Gross Net
4,622 3,413 703 464 5,325 3,877
Acreage
The following table summarizes EOG's developed and
undeveloped acreage at December 31, 1997. Excluded is
acreage in which EOG's interest is limited to owned royalty,
overriding royalty and other similar interests.
Developed Undeveloped Total
Gross Net Gross Net Gross Net
United States
California 17,691 14,951 746,318 727,230 764,009 742,181
Texas 275,995 182,999 518,376 364,083 794,371 547,082
Offshore
Gulf of Mexico 312,726 141,080 541,891 404,956 854,617 546,036
Wyoming 148,999 113,124 262,786 218,658 411,785 331,782
Oklahoma 148,637 85,494 113,274 83,123 261,911 168,617
New Mexico 60,136 31,070 84,224 52,519 144,360 83,589
Utah 57,820 46,512 33,062 27,564 90,882 74,076
Kansas 9,698 8,699 4,013 2,987 13,711 11,686
Colorado 8,353 1,233 26,380 13,645 34,733 14,878
Mississippi 4,761 4,516 33,161 25,524 37,922 30,040
Pennsylvania 1,103 735 16,089 10,727 17,192 11,462
Louisiana 6,131 4,938 4,608 1,592 10,739 6,530
Other 5,793 3,396 6,788 4,766 12,581 8,162
Total 1,057,843 638,747 2,390,970 1,937,374 3,448,813 2,576,121
Canada
Alberta 359,080 228,908 288,887 245,067 647,967 473,975
Saskatchewan 191,483 175,677 223,228 217,182 414,711 392,859
Manitoba 11,743 9,954 23,848 21,956 35,591 31,910
British Columbia 656 164 6,138 6,138 6,794 6,302
Total Canada 562,962 414,703 542,101 490,343 1,105,063 905,046
Other International
China - - 1,849,531 924,766 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
Trinidad 4,200 3,990 171,459 167,716 175,659 171,706
France - - 168,032 168,032 168,032 168,032
Total Other
International 102,500 33,480 3,021,742 1,671,378 3,124,242 1,704,858
Total 1,723,305 1,086,930 5,954,813 4,099,095 7,678,118 5,186,025
Drilling and Acquisition Activities
During each of the years ended December 31, 1997, 1996
and 1995, EOG spent approximately $693 million, $599 million
and $514 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:
Year Ended December 31,
1997 1996 1995
Gross Net Gross Net Gross Net
Development Wells Completed
North America
Gas 467 352.90 396 325.04 334 251.06
Oil 94 74.85 80 57.46 69 55.16
Dry 101 80.01 80 68.77 61 49.21
Total 662 507.76 556 451.27 464 355.43
Outside North America
Gas 12 3.60 - - 3 2.85
Oil 6 1.80 1 .30 3 2.85
Dry - - - - 1 .95
Total 18 5.40 1 .30 7 6.65
Total Development 680 513.16 557 451.57 471 362.08
Exploratory Wells Completed
North America
Gas 8 5.12 14 10.36 5 4.13
Oil - - 1 .78 8 3.61
Dry 12 7.53 26 19.00 21 13.28
Total 20 12.65 41 30.14 34 21.02
Outside North America
Gas - - - - 6 4.90
Oil - - - - - -
Dry - - 1 .50 - -
Total - - 1 .50 6 4.90
Total Exploratory 20 12.65 42 30.64 40 25.92
Total 700 525.81 599 482.21 511 388.00
Wells in Progress at 44 36.39 87 61.08 52 32.71
End of Period
Total 744 562.20 686 543.29 563 420.71
Wells Acquired
Gas 227 82.45* 350 148.20* 277 101.70*
Oil 48 20.50* 5 .65 5 .46*
Total 275 102.95 355 148.85 282 102.16
<FN>
* Includes acquisition of additional interests in
certain wells in which EOG previously held an interest.
All of EOG's drilling activities are conducted on a
contract basis with independent drilling contractors. EOG
owns no drilling equipment.
Gas Transmission
Enron's domestic natural gas facilities include
approximately 25,500 miles of transmission lines, 105
mainline compressor stations, 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.
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 in fee or land under the control of
Enron 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. Power
plants and pipelines in which Enron owns an interest are set
forth in the following table:
Facility Location Fuel Size/Capacity Enron
Interest
Power Plants:
Puerto Guatemala Gas 110 MW 50%
Quetzel
Teesside U.K. Gas 1,875 MW 31%
Batangas Philippines Fuel oil 110 MW 50%
Subic Bay Philippines Fuel oil 116 MW 50%
Bitterfeld Germany Gas 125 MW 50%
Puerto Plata Dominican Fuel oil 185 MW 50%
Republic
Hainan Island China Diesel 154 MW 50%
Pipelines:
TGS Argentina - 1.9 Bcf/d; 35%
4,104 miles
Centragas Colombia - 110 MMcf/d; 50%
357 miles
Transredes Bolivia - 320 MMcf/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 23
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
Bethel Salem, OR Gas/Oil 116
Coyote Springs Boardman, OR Gas/Oil 241
PGE
Jointly Interest
Owned:
Boardman Boardman, OR Coal 331 65.0%
Centralia Centralia, WA Coal 33 2.5%
Colstrip 3 & 4 Colstrip, MT Coal 288 20.0%
Trojan Rainier, OR Nuclear - 67.5%
2,120
PGE holds licenses under the Federal Power Act for its
hydroelectric generating plants. All of its licenses expire
during the years 2001 to 2006. The FERC requires that a
notice of intent to relicense these projects be filed
approximately five years prior to expiration of the license.
PGE is actively pursuing the renewal of these licenses. The
State of Oregon also has licensed all or portions of five
hydro plants.
Following the 1993 Trojan closure, PGE was granted a
possession-only license amendment by the NRC. In early 1996
PGE received NRC approval of its Trojan decommissioning
plan.
Combustion turbine generators at the Bethel Combustion
Turbine Plant and the Beaver Combustion Turbine Plant are
leased by PGE. These leases expire in 1998 and 1999. PGE
is currently evaluating its renewal options. PGE leases its
headquarters complex in downtown Portland and the coal-
handling facilities and certain railroad cars for 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
it's 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 Court
of Appeals has affirmed the trial court's order granting
class certification. An appeal to the Texas Supreme Court
will be pursued. 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 June 2, 1997, Enron announced the resolution of all
contractual issues involving the J-Block contract in the
U.K. North Sea with the J-Block producers, Phillips
Petroleum Company United Kingdom Limited, BG Exploration &
Production Limited and Agip (U.K.) Limited. The J-Block
contracts are long-term gas contracts that an Enron
subsidiary entered into in March 1993 with the J-Block
producers. As consideration for amending the contract,
Enron made a cash payment of approximately $440 million to
the producers. Enron recorded a second quarter non-
recurring contract restructuring charge of $675 million
($463 million after tax), primarily reflecting the impact of
the amended contract. Such resolution concluded all J-Block
litigation between Enron and the J-Block producers.
On June 3, 1997, the London Commercial Court ruled in
favor of the "CATS" parties in their dispute over the
availability of the CATS (Central Area Transmission System)
transportation facilities. The CATS parties sued Teesside
Gas Transportation Limited (TGTL), an Enron subsidiary, and
Enron (on the basis of its guarantee of TGTL's obligations
under the transportation agreement between TGTL and the CATS
parties) for allegedly failing to make quarterly "send-or-
pay" payments under the transportation agreement. TGTL had
refused to make these payments based upon its position that
the transportation facilities were not available as required
by the contract. The effect of the Court's decision is that
TGTL has released withheld "send-or-pay" payments to the
CATS parties in the amount of approximately 81 million
Pounds Sterling, plus interest and costs. The judgment has
no effect on the above referenced settlement of the J-Block
gas sales agreements. Enron is appealing the decision of
the London Commercial Court in the CATS litigation. Enron
believes that the ultimate resolution of this matter will
not have a materially adverse effect on its financial
position or results of operations.
In November 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, operates a
natural gas distribution system in the vicinity. Although
San Juan did not provide gas service to the building, the
investigation report of the National Transportation Safety
Board (NTSB) has tentatively concluded that the incident was
caused by gas leaking from San Juan's distribution system.
San Juan and Enron strongly disagree with the NTSB findings
principally because the NTSB investigation (i) found no path
of migration of gas from San Juan's system to the building,
and (ii) discovered no scientific evidence that propane gas
was the explosive fuel. Enron and San Juan have been named
as defendants in a number of lawsuits filed in U.S. District
Court for the district of Puerto Rico and Commonwealth
courts 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 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 Nuclear Plant. In early 1993, PGE ceased
commercial operation of Trojan. Since plant closure, PGE
has committed itself to a safe and economical transition
toward a decommissioned plant. PGE has received approval of
its decommissioning plan submitted to the Nuclear Regulatory
Commission and Oregon Energy Facilities Siting Council.
PGE's remaining cost to decommission and close Trojan of
$313 million has been reflected in "Other Liabilities" in
the Consolidated Balance Sheet.
Trojan Investment Recovery. In April 1996 a circuit
court judge in Marion County, Oregon found that the OPUC
could not authorize PGE to collect a return on its
undepreciated investment in Trojan, contradicting a November
1994 ruling from the same court. The ruling was the result
of an appeal of PGE's 1995 general rate order which granted
PGE recovery of, and a return on, 87% 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 was combined with the appeal of
the November 1994 ruling at the Oregon Court of Appeals.
Enron believes that the authorized recovery of and
return on the Trojan investment and decommissioning costs
will be upheld and that these legal challenges will not have
a materially adverse impact 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. The
EPA is interested in determining whether materials from the
plant have adversely affected subsurface soils at the
Decorah 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. To date, the EPA has identified
no other potentially responsible parties with respect to
this site. 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.
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.
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.
1997 1996
High Low Dividends High Low Dividends
First Quarter............. $45 1/8 $37 7/8 $.2250 $40 $34 5/8 $.2125
Second Quarter............ 42 3/8 35 5/8 .2250 42 3/8 36 3/8 .2125
Third Quarter............. 42 35 .2250 43 39 1/8 .2125
Fourth Quarter............ 41 15/16 35 15/16 .2375 47 1/2 40 1/4 .2250
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.
1997 1996
High Low Dividends High Low Dividends
First Quarter............. $600 $600 $3.0717 $496 1/2 $481 1/4 $2.9010
Second Quarter............ 555 496 3.0717 525 525 2.9010
Third Quarter............. 540 535 3.0717 525 525 2.9010
Fourth Quarter............ 523 523 3.2424 620 555 3.0717
At December 31, 1997, there were approximately 58,041
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 1993-1997.
Item 6. SELECTED FINANCIAL DATA (UNAUDITED)
1997 1996 1995 1994 1993
Operating Revenues (millions) $20,273 $13,289 $ 9,189 $ 8,984 $ 7,986
Total Assets (millions) $23,422 $16,137 $13,239 $11,966 $11,504
Common Stock Statistics
Income from continuing operations
Total (millions) $105 $584 $520 $453 $333
Per share - basic $0.32 $2.31 $2.07 $1.80 $1.32
Per share - diluted $0.32 $2.16 $1.94 $1.70 $1.25
Earnings on common stock
Total (millions) $ 88 $568 $504 $438 $316
Per share - basic $0.32 $2.31 $2.07 $1.80 $1.32
Per share - diluted $0.32 $2.16 $1.94 $1.70 $1.25
Dividends
Total (millions) $243 $212 $205 $192 $171
Per share $0.91 $0.86 $0.81 $0.76 $0.71
Shares outstanding (millions)
Actual at year-end 307 251 245 244 242
Average for the year 272 246 244 243 239
Capitalization (millions)
Long-term debt $ 6,254 $3,349 $3,065 $2,805 $2,661
Preferred stock of subsidiary 993 592 377 377 214
Minority interest 1,147 755 549 290 196
Shareholders' equity 5,618 3,723 3,165 2,880 2,623
Total capitalization $14,012 $8,419 $7,156 $6,352 $5,694
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 1997 was $105 million compared to $584
million in 1996 and $520 million in 1995. The results of
operations discussion focuses on core businesses, the new retail
energy services business (primarily serving commercial and light
industrial end-use customers) and items impacting comparability
of operations. Core businesses include Exploration and
Production (Enron Oil & Gas Company), Transportation and
Distribution (Gas Pipeline Group and Portland General) and
Wholesale Energy Operations and Services (Enron Capital & Trade
Resources, Enron International and Enron Engineering &
Construction). 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:
(In Millions) 1997 1996 1995
After-tax results from:
Core businesses $ 585 $ 493 $ 489
Retail Energy Services:
Results(a) (70) - -
Gain on sale of 7% of Enron Energy
Services (EES) shares 61 - -
(9) - -
576 493 489
Items impacting comparability:(a)
Charge to reflect impact of amended
J-Block gas contract (463) - -
Charge to reflect depressed MTBE
margins on committed production (74) - (49)
Gains on sales of liquids and
gathering assets 66 59 43
Gains on sales of Enron Oil & Gas
Company stock - 90 161
Reserve for qualified facilities
disposition - (54) -
Miscellaneous reserves and other
items - (4) (124)
Reported net income $ 105 $ 584 $ 520
<FN>
(a) Tax affected at 35%, except where a specific tax rate
applied.
Basic and diluted earnings per share of common stock were as
follows:
1997 1996 1995
Reported basic earnings per share $0.32 $2.31 $2.07
Diluted earnings per share:
Results from core businesses $1.98 $1.82 $1.82
Retail Energy Services:
Results (0.24) - -
Gain on sale of 7% of EES shares 0.21 - -
Items impacting comparability:
Charge to reflect impact of
amended J-Block gas contract (1.57) - -
Charge to reflect depressed MTBE
margins on committed production (0.25) - (0.18)
Gains on sales of liquids and
gathering assets 0.22 0.22 0.16
Gains on sales of Enron Oil & Gas
Company stock - 0.33 0.60
Reserve for qualified facilities
disposition - (0.20) -
Miscellaneous reserves and other
items - (0.01) (0.46)
Effect of anti-dilution(a) (0.03) - -
Reported diluted earnings per share $0.32 $2.16 $1.94
<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.
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):
(In Millions) 1997 1996 1995
Exploration and Production $ 183 $ 200 $ 241
Transportation and Distribution:
Gas Pipeline Group 466 524 359
Portland General 114 - -
Wholesale Energy Operations
and Services 654 466 401
Retail Energy Services (107) - -
Corporate and Other (745) 48 164
Reported income before interest,
minority interests and taxes $ 565 $1,238 $1,165
Exploration and Production
Enron's exploration and production operations are conducted by
Enron Oil & Gas Company (EOG). IBIT of Exploration and
Production totaled $183 million, $200 million and $241 million
for 1997, 1996 and 1995, respectively.
Wellhead volume and price statistics (including intercompany
amounts) are as follows:
1997 1996 1995
Natural gas volumes (MMcf/d)(a)
North America(b) 758 706 636
Trinidad 113 124 107
India 18 - -
Total 889 830 743
Average natural gas prices ($/Mcf)
North America(c) $2.20 $1.92 $1.34
Trinidad 1.05 1.00 0.97
India 2.79 - -
Composite 2.07 1.78 1.29
Crude oil/condensate volumes
(MBbl/d)(a)
North America 14.2 11.6 11.5
Trinidad 3.4 5.2 5.1
India 2.3 2.8 2.5
Total 19.9 19.6 19.1
Average crude oil/condensate prices
($/Bbl)
North America $19.33 $21.08 $17.09
Trinidad 18.68 19.76 16.07
India 20.05 20.17 16.81
Composite 19.30 20.60 16.78
<FN>
(a) Million cubic feet per day or thousand barrels per day, as
applicable.
(b) Includes an annual average of 48 MMcf/d in 1997, 1996 and
1995 delivered under the terms of a volumetric production
payment agreement effective October 1, 1992, as amended.
(c) Includes an average equivalent wellhead value of $1.73 per
Mcf in 1997, $1.17 per Mcf in 1996 and $0.80 per Mcf in 1995
for the volumes detailed in Note (b) above, net of
transportation costs.
The following analyzes the significant changes in the various
components of IBIT for Exploration and Production:
(In Millions) 1997 1996 1995
Net revenues $783 $730 $648
Corporate hedging activities (8) (4) 45
Operating expenses 150 133 126
Exploration expenses 102 89 79
Depreciation, depletion and
amortization 278 251 216
Taxes, other than income taxes 60 48 32
Operating income 185 205 240
Other income, net (2) (5) 1
Reported income before interest,
minority interests and taxes $183 $200 $241
Net Revenues
Exploration and Production's revenues, net of gas sold in
connection with natural gas marketing, increased $53 million (7%)
in 1997 and $82 million (13%) in 1996. The 1997 and 1996
increases reflected both increased average wellhead natural gas
prices and increased production volumes. The 1996 volumes
increased from 1995 primarily from the elimination of voluntary
curtailments in the United States in 1996 due to significant
increases in wellhead natural gas prices. Other marketing
activities, which include hedging, trading and natural gas
marketing transactions by EOG, reduced net revenues by $61
million in 1997, compared with increases of $4 million in 1996
and $105 million in 1995. Net revenues also include gains on
sales of crude oil and gas reserves and related assets of $9
million in 1997, $20 million in 1996 and $63 million in 1995.
Costs and Expenses
Operating expenses, depreciation, depletion and amortization
and taxes other than income taxes increased in 1997 and 1996 due
primarily to the increased production activity.
Exploration expenses increased 15% in 1997 and 13% in 1996 as
compared to the prior year, primarily as a result of increased
exploratory drilling activities and lease acquisitions in North
America.
Outlook
EOG plans to continue its significant investments in
development and certain exploration expenditures in its major
producing areas in North America. In addition, EOG anticipates
increased spending for the continued development of its
significant international projects in India, Venezuela, Trinidad
and China. Enron has hedged its net exposure to EOG's natural
gas prices for 1998 production and will continue to assess
opportunities for hedging future production.
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)
and Enron's 50% interest in Florida Gas Transmission Company
(Florida Gas). Portland General primarily reflects the results
of Portland General Electric Company (PGE) since the July 1, 1997
merger (see Note 2 to the Consolidated Financial Statements).
Gas Pipeline Group. Significant components of IBIT are as
follows:
(In Millions) 1997 1996 1995
Net revenues $665 $719 $745
Operating expenses 310 316 343
Depreciation and amortization 69 66 82
Equity in earnings 40 35 46
Other income, net 38 44 9
IBIT before items impacting
comparability 364 416 375
Gains on sales of liquids and
gathering assets 102 90 67
Miscellaneous reserves and other items - 18 (83)
Reported income before interest
and taxes $466 $524 $359
Net Revenues
Revenues, net of cost of sales, of Gas Pipeline Group declined
$54 million (8%) during 1997 and $26 million (3%) during 1996 as
compared to the applicable preceding year. 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. The decrease in net
revenues from 1995 to 1996 was primarily a result of the sale of
gathering facilities in 1995 and the first quarter of 1996. In
addition, revenues decreased at Northern in 1996 as a result of a
planned reduction of transition cost recoveries related to the
termination of its merchant function pursuant to the Federal
Energy Regulatory Commission's (FERC) Order 636.
Operating Expenses
Operating expenses of Gas Pipeline Group declined $6 million
(2%) during 1997, primarily due to a reduction of transition
costs to be recovered in regulatory surcharges at Northern. Gas
Pipeline Group's operating expenses declined $27 million (8%) in
1996 compared with 1995 due primarily to the favorable resolution
of environmental contingencies previously accrued, combined with
reduced expenses related to the gathering facilities sold in 1995
and early 1996 and a decrease in amortization of deferred
contract reformation costs by Northern.
Depreciation and amortization declined $16 million (20%) in
1996 compared with 1995 due primarily to the sale of gathering
facilities in 1995 and the first quarter of 1996.
Equity in Earnings
Equity in earnings of unconsolidated subsidiaries increased $5
million (14%) during 1997 as compared to 1996 after decreasing
$11 million (24%) during 1996 as compared to 1995. The increase
in 1997 was primarily due to increased equity earnings related to
Enron's interest in Citrus Corp., which holds Enron's 50%
interest in Florida Gas. The decrease in equity earnings in 1996
was primarily due to lower earnings from Enron's interest in
Trailblazer Pipeline Company due to the recognition in 1995 of
income from a settlement with a transportation customer.
Items Impacting Comparability
During 1997, gains of $102 million were recognized related to
the sales of liquids assets, including processing plants and
Enron's interest in the Enron Liquids Pipeline L.P. Gains of $90
million related to the disposition of non-strategic natural gas
gathering facilities were recognized in 1996, and gains of $67
million were recorded from the sale of gathering assets and a
processing facility in 1995. In 1996, reported IBIT included $18
million as a result of favorable resolution of litigation.
Regulatory and contingency adjustments totaling $83 million were
recorded in 1995.
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 of
$114 million, as follows:
(In Millions) 1997
Revenues $746
Purchased power and fuel 389
Operating expenses 154
Depreciation and amortization 91
Other income, net 2
Reported income before interest and taxes $114
Statistics for PGE for the period from July 1 through December
31, 1997 and 1996 (including amounts for 1996 for comparative
purposes only) are as follows:
1997 1996
Electricity Sales (Thousand MWh)(a)
Residential 3,379 3,421
Commercial 3,618 3,450
Industrial 2,166 2,020
Total Retail 9,163 8,891
Wholesale 15,041 5,949
Total Electricity Sales 24,204 14,840
Resource Mix
Coal 10% 15%
Combustion Turbine 5 11
Hydro 5 8
Total Generation 20 34
Firm Purchases 74 55
Secondary Purchases 6 11
Total Resources 100% 100%
Average Variable Power Cost (Mills/KWh)(b)
Generation 8.7 7.7
Firm Purchases 18.9 16.5
Secondary Purchases 13.2 12.3
Total Average Variable Power Cost 16.5 13.1
Retail Customers (end of period, thousands) 685 668
<FN>
(a) Thousand megawatt-hours.
(b) Mills (1/10 cent) per kilowatt-hour.
Outlook
Transportation and Distribution should continue to provide
stable earnings and cash flows during 1998, including steady
growth over 1997 levels.
Various expansion projects underway or proposed by Gas
Pipeline Group should contribute future earnings when completed.
Over the next three years, Northern is planning expansions which
would add 300-400 million cubic feet of gas per day (MMcf/d) of
incremental capacity. Transwestern plans to expand its pipeline
capacity and access new gas supplies by approximately 200-300
MMcf/d. Florida Gas also plans to expand its capacity by 150
MMcf/d to serve its growing markets by the year 2000.
Additionally, Gas Pipeline Group will continue to monitor its
overall cost structure.
PGE anticipates continuing retail customer growth in one of
the fastest growing service territories in the U.S. In late
1997, PGE filed a Customer Choice Plan proposal with the Oregon
Public Utility Commission (OPUC) which would give all of its
customers a choice of electricity providers as early as December
1998. Under the proposed Customer Choice Plan, PGE will separate
its generation business from its transmission and distribution
businesses and PGE will become a regulated transmission and
distribution company focused on delivering, but not selling,
electricity. The separation of the generation business is
proposed to be accomplished by selling PGE's generating assets,
either to an Enron affiliate or third parties. In preparation
for electric deregulation, PGE has begun to leverage from the
operational experiences of Enron's Gas Pipeline Group which has
previously transitioned from providing merchant services to
providing transportation services.
Enron is unable to predict what changes may be required by the
OPUC for approval or when the OPUC will approve a Customer Choice
Plan.
Wholesale Energy Operations and Services
Enron's Wholesale Energy Operations and Services businesses
are conducted primarily by Enron Capital & Trade Resources (ECT)
and Enron International (EI). These businesses provide
integrated energy-related products and services to wholesale
customers worldwide, including the development, construction and
operation of power plants, natural gas pipelines and other energy
related assets, energy commodity sales and services, risk
management products and financial services. This segment also
includes results of Enron Engineering & Construction (EE&C),
Enron Global Power and Pipelines L.L.C. (EPP) and Enron Americas,
Inc. Enron acquired the minority interest in EPP in November
1997 (see Note 2 to the Consolidated Financial Statements).
Wholesale Energy Operations and Services (Wholesale) can be
categorized into four business lines: Asset Development and
Construction, Cash and Physical, Risk Management and Finance and
Investing. The following table reflects IBIT for each business
line:
(In Millions) 1997 1996 1995
Asset Development and Construction $ 77 $ 60 $ 37
Cash and Physical 310 324 206
Risk Management 143 105 193
Finance and Investing 284 122 103
Unallocated expenses (160) (145) (138)
Reported income before interest,
minority interests and taxes $654 $466 $401
The following discussion analyzes the contributions to IBIT
and the outlook for each of the business lines.
Asset Development and Construction. This line of business
includes the development and construction of power plants,
pipelines and other energy infrastructure, including the results
of EE&C.
At December 31, 1997, the following projects were under
construction:
Estimated
Commercial
Size/Capacity Operations Date
Pipeline
Bolivia/Brazil (Phase I) 1,180 miles 1Q 1999
Power Plants
Cuiaba - Brazil (Phase I) 150 MW(a) 3Q 1998
Dabhol - India (Phase I) 826 MW 4Q 1998
Piti - Guam 80 MW 1Q 1999
Sutton Bridge - U.K. 790 MW 1Q 1999
Trakya - Turkey 478 MW 1Q 1999
EcoElectrica - Puerto Rico 507 MW 4Q 1999
Nowa Sarzyna - Poland 116 MW 4Q 1999
Sarlux - Italy 551 MW 1Q 2000
(a) Megawatts.
Earnings from the asset development and construction
business increased 28% in 1997 from 1996, primarily as a result
of fees earned on projects in the U.K. and Puerto Rico in 1997.
The earnings from this business increased 62% in 1996 compared
with 1995 primarily due to increased earnings on capital employed
related to development projects.
Cash and Physical. The cash and physical operations include
earnings from physical contracts of one year or less involving
marketing and transportation of natural gas, liquids, electricity
and other commodities, earnings from the management of Enron's
contract portfolio and earnings related to the operating assets
of this segment, including EPP operations. Also included are the
effects of actual settlements of long-term physical and notional
quantity-based contracts.
Wholesale markets and transports a substantial quantity of
energy commodities as reflected in the following table (including
intercompany amounts):
1997 1996 1995
Physical Volumes (BBtue/d)(a)(b)
Gas:
United States 7,654 6,998 6,405
Canada 2,263 1,406 803
Europe 660 289 -
10,577 8,693 7,208
Transport Volumes 460 544 580
Total Gas Volumes 11,037 9,237 7,788
Oil 690 320 439
Liquids 987 1,187 526
Total Physical Volumes 12,714 10,744 8,753
Electricity Volumes Marketed
(Thousand MWh) 192,323 60,150 7,767
Financial Settlements (Notional)
(BBtue/d) 49,069 35,259 32,938
<FN>
(a) Billion British thermal units equivalent per day.
(b) Includes third-party transactions by Enron Energy Services.
The cash and physical business includes Enron's interest in
the following operating assets:
Acquisition/
Size/Capacity Operations Date
Pipelines
Houston Pipe Line - U.S. 5,243 mi/2.5 Bcf/d 2Q 1985
Transportadora de Gas del Sur -
Argentina 4,104 mi/1.9 Bcf/d 4Q 1992
Louisiana Resources - U.S. 540 mi/750 MMcf/d 2Q 1993
Centragas - Colombia 357 mi/110 MMcf/d 1Q 1996
Transredes - Bolivia 3,093 mi/320 MMcf/d(a) 2Q 1997
Power Plants
Puerto Quetzel - Guatemala 110 MW 1Q 1993
Teesside - U.K. 1,875 MW 1Q 1993
Batangas - Philippines 110 MW 3Q 1993
Bitterfeld - Germany 125 MW 4Q 1993
Subic Bay - Philippines 116 MW 1Q 1994
Puerto Plata - Dominican Republic 185 MW 3Q 1994,
1Q 1996
Hainan Island - China 154 MW 3Q 1996
Local Distribution Companies
CEG - Brazil N/A 3Q 1997
Riogas - Brazil N/A 3Q 1997
GasPart - Brazil N/A 4Q 1997
(a) Capacity also includes 35 MB/d of liquids.
The earnings from cash and physical operations decreased 4%
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. Increased earnings from the operation of
international power plants and pipelines and domestic natural gas
assets also contributed to the results.
The earnings from this business increased 57% in 1996 as
compared to 1995 primarily due to earnings from higher natural
gas volumes and margins and increased earnings from the
management of Wholesale's commodity portfolio. Earnings from the
marketing and processing of natural gas liquids also increased in
1996. These increases were partially offset by a decrease in
earnings from natural gas assets. Electricity volumes
substantially increased as Enron continued to expand its role as
an electricity marketer.
Risk Management. Wholesale's risk management operations
consist of market origination activity on new long-term contracts
(transactions greater than one year) and restructuring of
existing long-term contracts, including development activity
related to such contracts.
Earnings from risk management increased 36% in 1997 as
compared to 1996 primarily due to strong originations and related
activities with utilities and independent power producers (IPPs)
in the European market. This increase was partially offset by
lower originations from long-term contracts in North America for
both natural gas and power.
Earnings from this business decreased 46% in 1996 as compared
to 1995 primarily due to lower originations from long-term
contracts with domestic utilities and IPPs. Earnings from the
restructuring of existing long-term contracts were also lower in
1996 as compared to 1995. These decreases were partially offset
by increased originations with IPPs in the European market.
Finance and Investing. The finance and investing operations
provide a variety of capital products to its worldwide customers,
including volumetric production payments, loans and equity
investments. These products are offered directly or through
joint ventures. Financings arranged and production payments were
$561 million, $755 million and $382 million in 1997, 1996 and
1995, respectively.
Additionally, the finance and investing business includes the
management of Wholesale's capital investments, both operating and
financial, as well as certain of Enron's equity investments.
Accordingly, the results of this business include earnings from
changes in the composition and market value of these investments.
Market value changes result from both underlying operating
strengths and favorable conditions in the equity markets.
Exposures related to these investments are managed through
certain hedging transactions as well as through the overall
diversity of the investments.
Earnings from the finance and investing operations increased
133% 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.
Earnings from the finance and investing operations increased
18% in 1996 compared to 1995 primarily due to increases in the
market value of its investments.
Unallocated Expenses. Net unallocated expenses such as rent,
systems expenses and other support group costs increased in both
1997 and 1996 due to continued expansion into new markets and
system upgrades.
Outlook
Enron anticipates continued growth in Wholesale during 1998.
Asset development and construction earnings are expected to
increase as a result of Enron's extensive portfolio of projects
in various stages of development. In the cash and physical
business, volumes are expected to continue to increase. In
addition, the existence of a substantial portfolio of contracts
as well as the ability to benefit from the relationships between
the financial and physical markets and the natural gas and
electricity markets provide substantial opportunities for
earnings. Earnings from risk management are expected to increase
as Enron continues to pursue opportunities in the European
marketplace and continues to increase integration of financial
products and its energy commodity portfolio worldwide. In the
finance and investing business, Enron will continue to expand its
products and services in its role as a full-service provider of
various types of capital. Further expansion into new products
and international markets is expected to increase results in all
of these businesses.
Earnings from Wholesale are dependent on the completion of
transactions, some of which are individually significant, which
are impacted by market conditions, the regulatory environment and
customer relations. Wholesale's transactions have historically
been based on a diverse product portfolio, providing a solid base
of earnings. The outlook for potential future transactions is
currently very favorable. Enron's strengths, including its
ability to identify and respond to customer needs, access to
extensive physical assets and its integrated approach to
international business, are expected to result in continued
earnings growth. In addition, earnings are expected from
Wholesale's commodity portfolio and investments, which are
subject to market fluctuations; risk related to these activities
is managed using hedge transactions. See "Financial Risk
Management" for a discussion of market risk related to Wholesale.
Retail Energy Services
Enron Energy Services (EES) was formed in late 1996 to provide
direct energy sales and services to end-use customers in the U.S.
natural gas and electricity markets, particularly in the
commercial and light industrial sectors. EES has participated
successfully in selected natural gas and electric retail
marketing pilots and continues to make significant progress in
expanding its customer base and contracting activities. EES
reported losses before interest, minority interests and taxes of
$107 million in 1997 related to significant investments in
building its sales force, developing products and services,
establishing a support system to service its contracts and
supporting EES's regulatory efforts.
In late 1997, Enron sold approximately 7% of its ownership of
EES for $130 million, to defray startup costs and establish a
valuation for this new business. The transaction resulted in a
gain of $61 million, which has been reflected in Corporate and
Other. This sale of EES ownership was based on a total
enterprise value of $1.9 billion.
Outlook
During 1998, EES will continue its focus on commercial and
light industrial customers in the energy market, while developing
new energy products and expanding its customer base. EES also
plans to continue its efforts to improve the regulatory
environment for retail gas and electricity, both on state and
federal levels, strengthen its marketing and sales organization
and continue to enhance its transaction support capabilities.
EES expects that 1998 losses will approximate those incurred in
1997.
Corporate and Other
Corporate and Other includes results of Enron Renewable Energy
Corp., EOTT Energy Corp. (EOTT) and the operations of Enron's
methanol and MTBE plants. Significant components of IBIT are as
follows:
(In Millions) 1997 1996 1995
IBIT before items impacting comparability $ (31) $ (22) $ (35)
Gain on sale of 7% of EES shares 61 - -
Items impacting comparability:
Charge to reflect impact of amended
J-Block gas contract (675) - -
Charge to reflect depressed MTBE
margins on committed production (100) - (75)
Gains on sales of Enron Oil & Gas
Company stock - 178 367
Reserve for qualified facilities
disposition - (83) -
Charge primarily related to conversion of
compensation plan - - (74)
Miscellaneous reserves and other items - (25) (19)
Reported income before interest and taxes $(745) $ 48 $ 164
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. (see Note 14 to the Consolidated
Financial Statements), and a $100 million charge primarily to
reflect depressed MTBE margins on committed production. In 1996
and 1995, respectively, gains of $178 million and $367 million
were recognized, primarily related to the sale of 12 million and
31 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. The 1995 results included a $75
million charge to reflect depressed MTBE margins on committed
production and $74 million of charges primarily related to the
conversion of a compensation plan to more closely align
employees' interests to Enron common stock.
Enron continues to assess and modify its computer systems to
ensure they will operate properly in the year 2000. Enron
management anticipates that these Year 2000 costs, which will be
incurred over the next two years, will not have a material impact
on Enron's financial position or results of operations.
Interest and Related Charges, net
Interest and related charges, net, is reported net of interest
capitalized of $18 million, $12 million and $10 million for 1997,
1996 and 1995, respectively. The net expense increased $127
million in 1997 after decreasing $10 million in 1996. The 1997
increase was primarily due to higher debt levels, including debt
of $1.1 billion from PGE following the merger on July 1, 1997
(see Note 2 to the Consolidated Financial Statements). The 1996
decrease was primarily due to lower average interest rates
combined with lower average debt balances.
Dividends on Company-Obligated Preferred Securities of Subsidiaries
Dividends on company-obligated preferred securities of
subsidiaries increased from $32 million in 1995 to $34 million in
1996 and $69 million in 1997, 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 at July 1, 1997 for securities of PGE.
See Notes 2 and 9 to the Consolidated Financial Statements.
Minority Interests
Minority interests increased $31 million to $75 million in
1996 compared to 1995, primarily due to the reduction of Enron's
interest in EOG following the sales in 1996 and December 1995 of
an aggregate 43 million shares of EOG common stock held by Enron.
Income Tax Expense
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
depressed MTBE margins on committed production. In addition, the
1997 tax provision was reduced for differences between the book
and tax basis of certain asset and stock sales. Income tax
expense decreased in 1996 compared with 1995 as a result of
benefits from the reduction of the deferred tax liability due to
the reevaluation of federal and state deferred tax requirements.
FINANCIAL CONDITION
Cash Flows
(In Millions) 1997 1996 1995
Cash provided by (used in):
Operating activities $ 501 $ 1,040 $(15)
Investing activiti es (2,436) (1,230) 13
Financing activities 1,849 331 (15)
Net cash provided by operating activities decreased $539
million in 1997 primarily as a result of a cash payment of $440
million made in connection with the resolution of the J-Block gas
contract. Cash provided by operating activities increased in
1996 primarily as a result of reduced working capital
requirements reflecting increased trade payables combined with an
increase in the sale of trade receivables under Enron's
receivables sales program at year-end 1996 as compared to 1995.
Net cash used in investing activities in 1997 primarily
reflects increased capital expenditures, which total $1,413
million. See "Capital Expenditures and Equity Investments"
below. Equity investments of $944 million in 1997 primarily
include investments in international power and pipeline projects.
Partially offsetting these uses of cash were proceeds of $473
million from the sales of assets, primarily from the sales of
liquids assets. Net cash used in investing activities in 1996
reflects equity investments of $761 million and capital
expenditures of $878 million. Equity investments in 1996
primarily include investments in international power and pipeline
projects, EOTT and Joint Energy Development Investments, L.P.
(JEDI). These uses of cash were offset by proceeds of $477
million from sales of assets, including 12 million shares of EOG
common stock held by Enron and non-strategic gathering and
processing assets.
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 7 to
the Consolidated Financial Statements). These inflows were
partially offset by payments of $354 million for cash dividends
and $422 million for the purchase of 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 included cash dividend payments of $281
million.
Working Capital
At December 31, 1997, Enron had working capital of $257
million. If a working capital deficit should occur, Enron has
credit facilities in place to fund working capital requirements.
At December 31, 1997, those credit lines provided for up to $3.7
billion of committed and uncommitted credit, of which $35 million
was outstanding at December 31, 1997. Certain of the credit
agreements contain prefunding covenants. However, such covenants
are not expected to materially 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:
1998
(In Millions) Estimate 1997 1996 1995
Exploration and Production(a) $ 660 $ 626 $540 $464
Transportation and Distribution 480 337 175 127
Wholesale Energy Operations
and Services 220 339 150 152
Retail Energy Services 70 36 - -
Corporate and Other 70 75 13 34
Total $1,500 $1,413 $878 $777
<FN>
(a) Excludes exploration expenses of $75 million (estimate),
$75 million, $68 million and $55 million for 1998, 1997, 1996
and 1995, respectively.
Capital expenditures increased $535 million during 1997 as
compared to 1996. 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 1997 in Wholesale were send-or-pay payments totaling
$167 million related to a transportation agreement in the United
Kingdom.
Equity investments by the operating segments are as follows:
1998
(In Millions) Estimate 1997 1996 1995
Exploration and Production $ - $ - $ - $ -
Transportation and Distribution 10 3 - -
Wholesale Energy Operations
and Services 440 824 653 143
Retail Energy Services - - - -
Corporate and Other 350 117 108 27
Total $800 $944 $761 $170
Equity investments increased $183 million in 1997 compared
with 1996 primarily due to investments by Wholesale in Brazilian
gas distribution companies.
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 and short-
and long-term borrowings.
FINANCIAL RISK MANAGEMENT
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.
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.
Enron measures the market risk in its portfolios 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 portfolios assuming
hypothetical movements in future market rates and is not
necessarily indicative of actual results which may occur.
In addition to using value at risk measures, Enron performs
regular scenario analyses to estimate the economic impact of a
sudden market movement on the value of its portfolios (stress
testing). The results of the stress testing, along with the
professional judgments of experienced business and risk managers,
are used to supplement the value at risk methodology and capture
additional market-related risks, including liquidity, event,
concentration and correlation reliance risk.
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 price risk management
portfolio, 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 alter
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 minimize 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 reduce Enron's risk profile.
Equity Risk. Equity risk arises from the finance and investing
operations of Wholesale, which provides capital to customers
through equity participations in various investment activities.
Enron manages this risk on an overall basis, including the use of
futures, forwards, swaps and options, to ensure compliance with
Enron's stated risk management policies.
Accounting Policies
Accounting policies for price risk management and hedging
activities are described in Note 1 to the Consolidated Financial
Statements.
Value at Risk
Enron has performed an entity-wide value at risk analysis of
virtually all of Enron's financial assets and liabilities. The
value at risk for commodity, interest rate and foreign currency
exposures described above is calculated using a "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 RiskMetrics(TM) 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 following table illustrates the value at risk for each
component of market risk at December 31, 1997:
(In Millions) Wholesale Non-Trading
Market Risk
Commodity price $25 $9(a)
Interest rate - -
Foreign currency exchange rate 1 1
Equity 4 -
<FN>
(a) Includes only the risk related to the financial
instruments that serve as hedges and does not include the
related underlying hedged production.
CAPITALIZATION
Total capitalization at December 31, 1997 was $14.0 billion.
Debt as a percentage of total capitalization increased to 44.6%
at December 31, 1997 as compared to 39.8% at December 31, 1996.
The increase primarily reflects increased debt, partially offset
by the issuance during 1997 of approximately 50.5 million and
11.5 million shares of common stock in connection with the
acquisitions of Portland General Corporation and the minority
interest in EPP, respectively (see Note 2 to the Consolidated
Financial Statements). Assuming the conversion in late 1998 of
10.5 million Exchangeable Notes into EOG shares held by Enron,
the pro-forma debt to capitalization percentage would be
approximately 43.5% at December 31, 1997.
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 to penetrate new retail natural gas and electricity
markets in the United States and Europe, the timing and extent of
changes in commodity prices for crude oil, natural gas,
electricity and interest rates, the extent of EOG's success in
acquiring oil and gas properties and in discovering, developing
and producing reserves, the timing and success of Enron's efforts
to develop international power, pipeline and other infrastructure
projects and conditions of the capital markets and equity markets
during the periods covered by the forward looking statements.
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.
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 5, 1998 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 1997, 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 one report containing one transaction.
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 1997; Aggregated Stock Option/SAR Exercises During
1997 and Stock Option/SAR Values as of December 31, 1997;
Long-Term Incentive Plan - Awards in 1997; 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, 1998", 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.
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).
*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 10.45
*10.01 - Enron Executive Supplemental
Survivor Benefits Plan, effective January 1,
1987 (Exhibit 10.01 to Enron Form 10-K for
1992, File No. 1-3423).
*10.02 - First Amendment to Enron Executive Supplemental
Survivor Benefits Plan (Exhibit 10.02 to Enron
Form 10-K for 1995, File No. 1-3423).
*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 Corp.
Form 10-K for 1996, File No. 1-3423).
*10.05 - Enron Corp. 1988 Deferral Plan
(Exhibit 10.19 to Enron Form 10-K for 1987,
File No. 1-3423).
*10.06 - First Amendment to Enron Corp. 1988
Deferral Plan (Exhibit 10.06 to Enron Form
10-K for 1995, File No. 1-3423).
*10.07 - Second Amendment to Enron Corp. 1988
Deferral Plan (Exhibit 10.07 to Enron
Form 10-K for 1995, File No. 1-3423).
*10.08 - Third Amendment to Enron Corp. 1988
Deferral Plan (Exhibit 10.09 to Enron Form
10-K for 1996, File No. 1-3423).
*10.09 - Fourth Amendment to Enron Corp.
1988 Deferral Plan (Exhibit 10.10 to Enron
Form 10-K for 1996, File No. 1-3423).
*10.10 - Fifth Amendment to Enron Corp. 1988
Deferral Plan (Exhibit 10.11 to Enron Form
10-K for 1996, File No. 1-3423).
*10.11 - Enron Corp. 1991 Stock Plan
(Exhibit 10.08 to Enron Form 10-K for 1991,
File No. 1-3423).
*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.
10.14 - Second Amendment to Enron Corp.
Amended and Restated 1991 Stock Plan.
*10.15 - Enron Corp. 1992 Deferral Plan
(Exhibit 10.09 to Enron Form 10-K for 1991,
File No. 1-3423).
*10.16 - First Amendment to Enron Corp. 1992
Deferral Plan (Exhibit 10.10 to Enron Form
10-K for 1995, File No. 1-3423).
*10.17 - Second Amendment to Enron Corp.
1992 Deferral Plan (Exhibit 10.11 to Enron
Form 10-K for 1995, File No. 1-3423).
*10.18 - Enron Corp. Directors' Deferred Income
Plan (Exhibit 10.09 to Enron Form 10-K
for 1992, File No. 1-3423).
*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, File No. 1-3423).
*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, File No. 1-3423).
*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, File No. 1-3423).
*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, File No. 1-
3423).
*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, File No.
1-3423).
*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, File No.
1-3423).
*10.25 - Fifth Amendment to Consulting Services
Agreement between Enron and John A.
Urquhart (Exhibit 10.36 to Enron Form 10-K
for 1995, File No. 1-3423).
*10.26 - Sixth Amendment to Consulting Services
Agreement between Enron and John A.
Urquhart (Exhibit 10.37 to Enron Form 10-K
for 1995, File No. 1-3423).
10.27 - Seventh Amendment to Consulting Services
Agreement between Enron and John A.
Urquhart, dated October 27, 1997.
*10.28 - Employment Agreement between Enron
and James V. Derrick, Jr., dated June 11,
1991 (Exhibit 10.40 to Enron Form 10-K for
1992, File No. 1-3423).
*10.29 - First Amendment to Employment Agreement
between Enron and James V. Derrick, Jr.,
dated May 2, 1994 (Exhibit 10.53 to
Enron Form 10-K for 1994, File No. 1-3423).
*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, File No. 1-3423).
*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
Power Corp. and Thomas E. White dated July 1,
1990 (Exhibit 10.59 to Enron Form 10-K for
1996, File No. 1-3423).
*10.36 - First Amendment, dated September 9, 1991,
to Employment Agreement between Enron
Power Corp. and Thomas E. White dated July 1,
1990 (Exhibit 10.60 to Enron Form 10-K for
1996, File No. 1-3423).
*10.37 - Second Amendment, dated May 2, 1994,
to Employment Agreement between Enron
Power Corp. and Thomas E. White dated July 1,
1990 (Exhibit 10.61 to Enron Form 10-K for
1996, File No. 1-3423).
*10.38 - Third Amendment, dated January 3, 1997,
to Employment Agreement between Enron
Power Corp. and Thomas E. White dated July 1,
1990 (Exhibit 10.62 to Enron Form 10-K for
1996, File No. 1-3423).
*10.39 - 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, File No. 1-
3423).
*10.40 - 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,
File No. 1-3423).
10.41 - Split Dollar Agreement between Enron and
Jeffrey K. Skilling dated May 23, 1997.
10.42 - Second Amendment effective October 13,
1997, to Employment Agreement between
Enron Corp. and Jeffrey K. Skilling.
10.43 - Loan Agreement effective October 13,
1997, between Enron Corp. and Jeffrey K.
Skilling.
*10.44 - 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).
10.45 - Executive Employment Agreement between
Stanley C. Horton and Enron Operations
Corp., effective as of October 1, 1996.
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 13, 1998.
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
No reports on Form 8-K were filed by Enron during the
last quarter of 1997.
INDEX TO FINANCIAL STATEMENTS
ENRON CORP.
Page No.
Consolidated Financial Statements
Report of Independent Public Accountants F-2
Consolidated Income Statement for the years ended
December 31, 1997, 1996 and 1995 F-3
Consolidated Balance Sheet as of December 31, 1997
and 1996 F-4
Consolidated Statement of Cash Flows for the years
ended December 31, 1997, 1996 and 1995 F-6
Consolidated Statement of Changes in Shareholders'
Equity Accounts for the years ended December 31,
1997, 1996 and 1995 F-7
Notes to the Consolidated Financial Statements F-8
Financial Statements Schedule
Report of Independent Public Accountants on
Financial Statements 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.
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, 1997 and 1996, and the related consolidated
statements of income, cash flows and changes in shareholders'
equity for each of the three years in the period ended December
31, 1997. 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, 1997 and 1996,
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, 1997, in conformity with generally accepted
accounting principles.
Arthur Andersen LLP
Houston, Texas
February 23, 1998
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENT
(In Millions, Year Ended December 31,
except Per Share Amounts) 1997 1996 1995
Revenues
Natural gas and other products $13,211 $11,157 $7,529
Electricity 5,101 980 179
Transportation 652 707 692
Other 1,309 445 789
Total Revenues 20,273 13,289 9,189
Costs and Expenses
Cost of gas, electricity and
other products 17,311 10,478 6,733
Operating expenses 1,406 1,421 1,218
Oil and gas exploration expenses 102 89 79
Depreciation, depletion and
amortization 600 474 432
Taxes, other than income taxes 164 137 109
Contract restructuring charge 675 - -
Total Costs and Expenses 20,258 12,599 8,571
Operating Income 15 690 618
Other Income and Deductions
Equity in earnings of
unconsolidated subsidiaries 216 215 86
Gains on sales of assets and
investments 186 274 467
Other income, net 148 59 (6)
Income Before Interest, Minority
Interests and Income Taxes 565 1,238 1,165
Interest and Related Charges, net 401 274 284
Dividends on Company-Obligated
Preferred Securities of Subsidiaries 69 34 32
Minority Interests 80 75 44
Income Tax Expense (Benefit) (90) 271 285
Net Income 105 584 520
Preferred Stock Dividends 17 16 16
Earnings on Common Stock $ 88 $ 568 $ 504
Earnings Per Share of Common Stock
Basic $ 0.32 $ 2.31 $ 2.07
Diluted $ 0.32 $ 2.16 $ 1.94
Average Number of Common Shares
Used in Computation
Basic 272 246 244
Diluted 277 270 268
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31,
(In Millions) 1997 1996
ASSETS
Current Assets
Cash and cash equivalents $ 170 $ 256
Trade receivables (net of allowance
for doubtful accounts of $11 and
$6, respectively) 1,697 1,841
Other receivables 454 414
Assets from price risk management
activities 1,577 841
Other 771 627
Total Current Assets 4,669 3,979
Investments and Other Assets
Investments in and advances to
unconsolidated subsidiaries 2,656 1,701
Assets from price risk management
activities 1,352 1,632
Goodwill 1,910 87
Other 3,665 1,626
Total Investments and Other Assets 9,583 5,046
Property, Plant and Equipment, at cost
Exploration and Production, successful
efforts accounting 4,291 3,753
Transportation and Distribution 5,279 3,494
Wholesale Energy Operations and
Services 3,879 3,967
Retail Energy Services 44 -
Corporate and Other 249 134
13,742 11,348
Less accumulated depreciation,
depletion and amortization 4,572 4,236
Property, Plant and Equipment, net 9,170 7,112
Total Assets $23,422 $16,137
<FN>
The accompanying notes are an integral part of these
consolidated financial statements.
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Millions, except Per December 31,
Share Amounts and Shares) 1997 1996
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 2,119 $ 2,035
Liabilities from price risk
management activities 1,476 1,029
Other 817 644
Total Current Liabilities 4,412 3,708
Long-Term Debt 6,254 3,349
Deferred Credits and Other Liabilities
Deferred income taxes 2,039 2,290
Liabilities from price risk
management activities 1,190 980
Other 1,769 740
Total Deferred Credits and
Other Liabilities 4,998 4,010
Commitments and Contingencies
(Notes 3, 13, 14 and 15)
Minority Interests 1,147 755
Company-Obligated Preferred Securities
of Subsidiaries 993 592
Shareholders' Equity
Second preferred stock, cumulative, no par
value and $1 par value, respectively,
1,370,000 shares and 5,000,000 shares
authorized, 1,337,645 shares and 1,370,714
shares of Cumulative Second Preferred
Convertible Stock issued, respectively 134 137
Common stock, no par value and $0.10 par
value, respectively, 600,000,000 shares
authorized, 318,297,276 shares and
255,945,304 shares issued, respectively 4,224 26
Additional paid-in capital - 1,870
Retained earnings 1,852 2,007
Cumulative foreign currency translation
adjustment (148) (127)
Common stock held in treasury, 7,050,965
shares and 821,155 shares, respectively (269) (30)
Other (including Flexible Equity Trust) (175) (160)
Total Shareholders' Equity 5,618 3,723
Total Liabilities and Shareholders' Equity $23,422 $16,137
<FN>
The accompanying notes are an integral part of these
consolidated financial statements.
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In Millions) 1997 1996 1995
Cash Flows From Operating Activities
Reconciliation of net income to net
cash provided by (used in) operating
activities
Net income $ 105 $ 584 $ 520
Depreciation, depletion and
amortization 600 474 432
Oil and gas exploration expenses 102 89 79
Deferred income taxes (174) 207 216
Gains on sales of assets and investments (195) (274) (530)
Changes in components of working
capital (65) 142 (834)
Net assets from price risk management
activities 201 15 (98)
Amortization of production payment
transaction (43) (43) (43)
Other, net (30) (154) 243
Net Cash Provided by (Used in) Operating
Activities 501 1,040 (15)
Cash Flows From Investing Activities
Proceeds from sales of investments and
other assets 473 477 996
Capital expenditures (1,413) (878) (777)
Equity investments (944) (761) (170)
Business acquisitions, net of cash acquired
(see Note 2) (82) - -
Other, net (470) (68) (36)
Net Cash Provided by (Used in)
Investing Activities (2,436) (1,230) 13
Cash Flows From Financing Activities
Net increase (decrease) in
short-term borrowings 464 217 (250)
Issuance of long-term debt 1,817 359 967
Repayment of long-term debt (607) (294) (448)
Issuance of company-obligated preferred
securities of subsidiaries 372 215 -
Issuance of common stock - 102 20
Issuance of subsidiary equity 555 - -
Dividends paid (354) (281) (254)
Net (acquisition) disposition of
treasury stock (422) 5 (64)
Other, net 24 8 14
Net Cash Provided by (Used in)
Financing Activities 1,849 331 (15)
Increase (Decrease) in Cash and Cash
Equivalents (86) 141 (17)
Cash and Cash Equivalents, Beginning
of Year 256 115 132
Cash and Cash Equivalents, End of Year $ 170 $ 256 $ 115
Changes in Components of Working Capital
Receivables $ 26 $ (678) $(639)
Payables (41) 870 126
Other (50) (50) (321)
Total $ (65) $ 142 $(834)
<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
(In Millions, except Per Share 1997 1996 1995
Amounts; Shares in Thousands) Shares Amount Shares Amount Shares Amount
Cumulative Second Preferred
Convertible Stock
Balance, beginning of year 1,371 $ 137 1,375 $ 138 1,405 $ 141
Exchange of common stock
for convertible preferred stock (33) (3) (4) (1) (30) (3)
Balance, end of year 1,338 $ 134 1,371 $ 137 1,375 $ 138
Common Stock
Balance, beginning of year 255,945 $ 26 253,860 $ 25 253,070 $ 25
Exchange of common stock
for convertible preferred stock 382 - 19 - 219 -
Issuances related to benefit
and dividend reinvestment plans - (3) - - 197 -
Sales of common stock - - 2,066 1 374 -
Issuances of common stock in business
acquisitions (see Note 2) 61,970 2,281 - - - -
Issuance of no par stock in
reincorporation merger (see
Note 2) - 1,881 - - - -
Other - 39 - - - -
Balance, end of year 318,297 $4,224 255,945 $ 26 253,860 $ 25
Additional Paid-in Capital
Balance, beginning of year $1,870 $1,791 $1,788
Exchange of common stock
for convertible preferred stock 1 (1) (3)
Issuances related to benefit
and dividend reinvestment plans (9) (16) (5)
Sales of common stock 18 109 15
Issuance of no par stock in
reincorporation merger (see
Note 2) (1,881) - -
Other 1 (13) (4)
Balance, end of year $ - $1,870 $1,791
Retained Earnings
Balance, beginning of year $2,007 $1,651 $1,351
Net income 105 584 520
Cash dividends
Common stock ($0.9125, $0.8625 and
$0.8125 per share in 1997,
1996 and 1995, respectively) (243) (212) (204)
Preferred stock ($12.4584, $11.7750,
and $11.0922 per share in 1997,
1996 and 1995, respectively) (17) (16) (16)
Balance, end of year $1,852 $2,007 $1,651
Cumulative Foreign Currency
Translation Adjustment
Balance, beginning of year $ (127) $ (153) $ (159)
Translation adjustments (21) 26 6
Balance, end of year $ (148) $ (127) $ (153)
Treasury Stock
Balance, beginning of year (821) $ (30) (2,618) $ (93) (1,395) $ (41)
Shares acquired (9,790) (374) (2,226) (85) (3,496) (118)
Exchange of common stock
for convertible preferred stock 70 3 46 2 183 5
Issuances related to benefit
and dividend reinvestment plans 2,838 106 2,249 81 2,090 61
Sales of treasury stock - - 1,728 65 - -
Issuances of treasury stock in
business acquisitions (see Note 2) 652 26 - - - -
Balance, end of year (7,051) $ (269) (821) $ (30) (2,618) $ (93)
Other
Balance, beginning of year $ (160) $ (194) $ (225)
Issuances related to benefit
and dividend reinvestment plans (15) 34 30
Other - - 1
Balance, end of year $ (175) $ (160) $ (194)
Total Shareholders' Equity $5,618 $3,723 $3,165
<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
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.
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 4).
Earnings Per Share. In accordance with Statement of Financial
Accounting Standards (SFAS) No. 128 - "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. Common shares
held by the Enron Corp. Flexible Equity Trust are not included in
the computation of earnings per share until such shares are
released to fund employee benefits. See Note 10 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 servicing costs,
with resulting unrealized gains and losses recorded as "Assets
and Liabilities From Price Risk Management Activities" in the
Consolidated Balance Sheet. Terms regarding cash settlements of
these contracts vary with respect to the actual timing of cash
receipts and payments. The amounts shown in the Consolidated
Balance Sheet related to price risk management activities also
include assets or liabilities which arise as a result of the
actual timing of settlements related to these contracts. Current
period changes in the assets and liabilities from price risk
management activities (resulting primarily from newly originated
transactions, restructuring and the impact of price movements)
are recognized as net gains or losses in "Other Revenues." 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. Prepaid transportation costs
are included in "Other Assets" in the Consolidated Balance Sheet.
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 and are recognized in the Consolidated Balance Sheet
as "Other Assets" or "Other Liabilities".
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 as appropriate. 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.
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.
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.
Investments in Unconsolidated Subsidiaries. Investments in
unconsolidated subsidiaries are accounted for by the equity
method, except for certain equity investments resulting from
Enron's merchant banking activities which are included at market
value in "Other Investments" in the Consolidated Balance Sheet.
The valuation methodologies utilize market values of publicly-
traded securities, independent appraisals and cash flow analyses.
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. PGC, through
its wholly-owned subsidiary Portland General Electric Company
(PGE), serves retail electric customers in northwest Oregon as
well as wholesale electricity customers throughout the western
United States. 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. In connection with the merger, Enron
reincorporated in Oregon and reissued its capital stock without
par value.
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. Additionally, during 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,
approximately $1.8 billion, has been reflected as goodwill in the
Consolidated Financial Statements and is being amortized on a
straight-line basis over 30 to 40 years. Assets acquired,
liabilities assumed and consideration paid as a result of
businesses acquired were as follows:
(In Millions)
Fair value of assets acquired, other than cash $ 3,829
Goodwill 1,847
Fair value of liabilities assumed (3,235)
Common stock of Enron and subsidiary issued (2,359)
Net cash paid $ 82
The allocation of purchase price related to the determination
of reserves for certain contractual and legal contingencies for
the PGC merger is preliminary pending completion of Enron's final
studies and evaluations. Enron does not anticipate that the
final evaluation of these issues will materially affect the
allocation of the purchase price.
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.
(In Millions, except Per Share Amounts) 1997 1996
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
3 PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Trading Activities. Enron, through its Wholesale Energy
Operations and Services segment (Wholesale), offers price risk
management services to the energy sector 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, 1997 are shown below
(volumes in trillions of British thermal units equivalent
(TBtue), dollars in millions):
Fixed Price Fixed Price Maximum
Payor Receiver Terms in years
Energy commodities
Natural gas 4,515 3,927 26
Crude oil and liquids 3,405 3,169 9
Electricity 1,456 2,637 22
Financial products
Interest rate(a) $4,094 $7,174 25
Foreign currency 3,006 1,950 18
Equity investments 972 487 4
<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.
Wholesale includes sales and purchase commitments associated
with contracts based on market prices totaling 3,725 TBtue, with
terms extending up to 18 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, 1997 was approximately 2.7
years.
Fair Value. The fair value of the financial instruments
related to price risk management activities as of December 31,
1997, 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:
Average Fair Value
Fair Value for the Year Ended
as of 12/31/97 12/31/97(a)
(In Millions) Assets Liabilities Assets Liabilities
Natural gas $2,173 $1,655 $2,196 $1,538
Crude oil and liquids 337 395 323 431
Electricity 641 560 578 423
Equity 60 56 62 72
Total $3,211 $2,666 $3,159 $2,464
<FN>
(a) Computed using the ending balance at each month end.
The net gain arising from price risk management activities for
1997 was $360 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, 1997 and 1996 are
summarized as follows:
1997 1996
Investment Investment
(In Millions) Grade(a) Total Grade(a) Total
Independent power producers $ 353 $ 529 $ 358 $ 461
Oil and gas producers 351 529 422 791
Energy marketers 403 585 466 598
Gas and electric utilities 747 815 495 524
Financial institutions 483 486 191 191
Industrials 76 128 35 48
Other 137 139 108 109
Total $2,550 3,211 $2,075 2,722
Credit and other reserves (282) (249)
Assets from price risk
management activities(b) $2,929 $2,473
<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) One and two customers' exposures at December 31, 1997 and
1996, respectively, comprise greater than 5% of Assets From
Price Risk Management Activities. All are included above as
Investment Grade.
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.
Interest Rate Swaps. At December 31, 1997, Enron had entered
into interest rate swap agreements with a notional principal
amount of $2.8 billion to manage interest rate exposure. Swap
agreements relating to notional amounts of $1.0 billion and $1.8
billion are scheduled to terminate in 1998 and thereafter,
respectively.
Energy Commodity Price Swaps. At December 31, 1997, Enron was
a party to energy commodity price swaps covering 141 TBtu, 4 TBtu
and 42 TBtu of natural gas for the years 1998, 1999 and the
period 2000 through 2005, respectively, and 2 million and 1
million barrels of crude oil for the years 1998 and 1999,
respectively.
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, 1997 and
1996 were as follows:
1997 1996
Carrying Estimated Carrying Estimated
(In Millions) Amount Fair Value Amount Fair Value
Long-term debt (Note 6) $6,254 $6,501 $3,349 $3,508
Company-obligated preferred
securities of subsidiaries
(Note 9) 993 1,024 592 607
Interest rate swaps - 13 - (11)
Energy commodity price swaps - (31) - (64)
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; and (c) interest rate swaps and energy
commodity price swaps - 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 INCOME TAXES
The components of income before income taxes are as follows:
(In Millions) 1997 1996 1995
United States $96 $551 $622
Foreign (81) 304 183
$15 $855 $805
Total income tax expense (benefit) is summarized as follows:
(In Millions) 1997 1996 1995
Payable currently -
Federal $ 29 $ 16 $ 29
State 9 11 26
Foreign 46 37 14
84 64 69
Payment deferred -
Federal (39) 174 158
State (42) (1) 30
Foreign (93) 34 28
(174) 207 216
Total income tax expense (benefit) $ (90) $271 $285
The differences between taxes computed at the U.S. federal
statutory tax rate and Enron's effective income tax rate are as
follows:
(In Millions, except Percentages) 1997 1996 1995
Statutory federal income tax provision $ 5 35.0% 35.0% 35.0%
Net state income taxes (21) (140.0) 0.8 4.5
Tight gas sands tax credit (12) (80.0) (1.8) (2.8)
Equity earnings (38) (253.3) (3.3) (3.8)
Minority interest 28 186.7 3.1 1.9
Asset and stock sale differences (79) (526.7) 1.8 2.1
Cash value in life insurance (7) (46.7) (3.2) -
Goodwill amortization 9 60.0 - -
Other 25 166.7 (0.7) (1.4)
$(90) (598.3)% 31.7% 35.5%
The principal components of Enron's net deferred income tax
liability are as follows:
December 31,
(In Millions) 1997 1996
Deferred income tax assets -
Alternative minimum tax credit
carryforward $ 247 $ 235
Net operating loss carryforward 361 78
Other 218 65
826 378
Deferred income tax liabilities -
Depreciation, depletion and
amortization 2,036 1,622
Price risk management activities 457 536
Other 588 638
3,081 2,796
Net deferred income tax liabilities(a) $2,255 $2,418
<FN>
(a) Includes $216 million and $128 million in other current
liabilities for 1997 and 1996, respectively.
Enron has an alternative minimum tax (AMT) credit carryforward
of approximately $247 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 consolidated net operating loss carryforward for
federal tax purposes of approximately $745 million which will
begin to expire in 2011. Enron has a net operating loss
carryforward applicable to non-U.S. subsidiaries of approximately
$300 million that can be carried forward indefinitely. The
benefits of these net operating losses have been recognized as a
deferred tax asset.
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 $300 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.
5 SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for income taxes and interest expense, including
fees incurred on sales of accounts receivable, is as follows:
(In Millions) 1997 1996 1995
Income taxes (net of refunds) $ 68 $ 89 $ 13
Interest (net of amounts capitalized) 420 290 296
During 1997, Enron issued common stock in connection with
business acquisitions. See Note 2.
In March 1995, a subsidiary of Enron Oil & Gas Company (EOG)
issued redeemable preferred stock with a liquidation/redemption
value of $19 million in exchange for certain oil and gas
properties. These preferred shares were exchanged in 1995 for
633,333 shares of Enron's common stock.
6 CREDIT FACILITIES AND DEBT
Enron has credit facilities with domestic and foreign banks
which provide for an aggregate of $1.5 billion in long-term
committed credit and $1.4 billion in short-term committed credit.
Expiration dates of the committed facilities range from May 1998
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. During 1997, $25 million was
outstanding under these facilities.
Enron has also entered into agreements which provide for
uncommitted lines of credit totaling $817 million at December 31,
1997. 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,
1997, $10 million was 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, 1997 and 1996, short-term borrowings of $825 million and $298
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, 1997 and
1996, $462 million and $175 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, 1997 and 1996 were 6.0% and 7.0%, respectively.
Detailed information on long-term debt is as follows:
December 31,
(In Millions) 1997 1996
Enron Corp.
Debentures
6.75% to 8.25% due 2005 to 2012 $ 350 $ 350
Notes payable
6.25% - exchangeable notes due 1998 228 228
6.45% to 10.00% due 1998 to 2023 2,492 1,542
Floating rate notes due 1999 to 2037 350 -
Other 67 4
Northern Natural Gas Company
Notes payable
6.875% to 8.00% due 1999 to 2005 350 350
Transwestern Pipeline Company
Notes payable
7.55% to 9.20% due 1998 to 2004 150 150
Portland General Electric Company
First mortgage bonds
5.65% to 9.46% due 1998 to 2023 564 -
Pollution control bonds
Variable rate due 2010 to 2031 192 -
Other 172 -
Enron Oil & Gas Company
Notes payable
Floating rate notes due 1998 to 2001 120 190
5.44% to 9.10% due 1998 to 2007 390 210
Enron Europe Limited
Other 37 41
Amount reclassified from short-term debt 825 298
Unamortized debt discount and premium (33) (14)
Total long-term debt $6,254 $3,349
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 are mandatorily
exchangeable in December 1998 into shares of EOG common stock at
a specified exchange rate or, at Enron's option, for cash with an
equal value. Enron currently intends to satisfy the exchange
obligation with shares of EOG common stock.
The aggregate annual maturities of long-term debt outstanding
at December 31, 1997 were $462 million, $508 million, $161
million, $664 million and $180 million for 1998 through 2002,
respectively.
7 MINORITY INTEREST
Enron's minority interest primarily includes EOG and EPP prior
to Enron's acquisition of the EPP minority interest in November
1997 (see Note 2).
Also 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 and made demand loans to 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. The joint venture is a separate legal entity from
Enron and has separate assets and liabilities. Absent certain
defaults or other specified events, Enron has the option to
acquire the investor's interest in the joint venture. If Enron
does not acquire the investor's interest before December 2002, or
earlier upon certain specified events, the joint venture will
liquidate its assets and dissolve. The joint venture is included
in Enron's consolidated financial statements and the third-party
investor's investment in the joint venture is included in
minority interest.
8 UNCONSOLIDATED SUBSIDIARIES
Enron's investment in and advances to unconsolidated
subsidiaries which are accounted for by the equity method is as
follows:
Ownership December 31,
(In Millions) Interest 1997 1996
Citrus Corp.(a) 50% $ 432 $ 405
Compania Estadual de Gas do Rio de
Janeiro, S.A.(b) 25% 194 -
EOTT Energy Partners, L.P. (EOTT)(c) 49% 143 130
Joint Energy Development Investments
L.P. (JEDI)(b)(d) 50% 392 320
Teesside Power Limited(b) 50%(e) 151 106
Transportadora de Gas del Sur S.A.(b) 35% 472 188
Transredes Transporte de
Hidrocarburos S.A.(b) 25% 137 -
Other 735 552
$2,656 $1,701
<FN>
(a) Included in the Transportation and Distribution segment.
(b) Included in the Wholesale Energy Operations and Services
segment.
(c) Included in the Corporate and Other segment.
(d) JEDI accounts for its investments at fair value.
(e) Net of minority interests, the ownership is 31%.
Enron's equity in earnings (losses) of unconsolidated
subsidiaries is as follows:
(In Millions) 1997 1996 1995
Citrus Corp. $ 27 $ 22 $ 27
Compania Estadual de Gas do Rio de
Janeiro, S.A. 1 - -
EOTT Energy Partners, L.P. (2) 9 (23)
Joint Energy Development Investments L.P. 68 71 4
Teesside Power Limited 20 29 18
Transportadora de Gas del Sur S.A. 45 29 22
Transredes Transporte de Hidrocarburos S.A. 5 - -
Other 52 55 38
$216 $215 $ 86
Summarized combined financial information of Enron's
unconsolidated subsidiaries is presented below:
December 31,
(In Millions) 1997 1996
Balance sheet
Current assets $2,481 $2,587
Property, plant and equipment, net 8,851 8,064
Other noncurrent assets 1,356 902
Current liabilities 1,855 2,381
Long-term debt 5,234 5,230
Other noncurrent liabilities 1,295 1,139
Owners' equity 4,304 2,803
(In Millions) 1997 1996 1995
Income statement
Operating revenues $11,183 $11,676 $8,258
Operating expenses 10,246 10,567 7,335
Net income 336 464 226
Distributions paid to Enron 68 84 68
9 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, 1997, Enron had
outstanding 1,337,645 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 1997,
1996 and 1995, 33,069 shares, 4,780 shares and 29,489 shares,
respectively, of the Convertible Preferred Stock were converted
into common stock.
Company-Obligated Preferred Securities of Subsidiaries. Summar
ized information for Enron's Company-Obligated Preferred
Securities of Subsidiaries is as follows:
Liquidation
(In Millions, except December 31, Value
Per Share Amounts and Shares) 1997 1996 Per Share
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 - 25
Enron Capital Trust III
Adjustable-Rate Capital Trust Securities
(200,000 preferred securities)(b) 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 51 -
$993 $592
<FN>
(a) Redeemable under certain circumstances after specified
dates.
(b) Mature in 2046.
(c) Mandatorily redeemable in 2006.
10 COMMON STOCK
Earnings Per Share. The computation of basic and diluted
earnings per share is as follows:
Year Ended December 31,
(In Millions, except per share amounts) 1997 1996 1995
Numerator:
Net income $ 105 $ 584 $ 520
Preferred stock dividends (17) (16) (16)
Numerator for basic earnings per
share - income available to common
shareholders 88 568 504
Effect of dilutive securities:
Preferred stock dividends(a) - 16 16
Numerator for diluted earnings per
share - income available to common
shareholders after assumed conversions $ 88 $ 584 $ 520
Denominator:
Denominator for basic earnings per
share - weighted-average shares 272 246 244
Effect of dilutive securities:
Preferred stock (a) - 19 19
Stock options 5 5 5
Dilutive potential common shares 5 24 24
Denominator for diluted earnings per
share - adjusted weighted-average
shares and assumed conversions 277 270 268
Basic earnings per share $0.32 $2.31 $2.07
Diluted earnings per share $0.32 $2.16 $1.94
<FN>
(a) For 1997, the dividends and conversion of preferred stock
have been excluded from the computation because it is
antidilutive.
Forward Contracts and Options. At December 31, 1997, Enron
had forward contracts to purchase 6.7 million shares of Enron
Corp. common stock at an average price of $42.00 per share.
Enron may settle the forward contracts in 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.
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 1997, 1996 and 1995 was $14
million, $4 million and $2 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 consistent with SFAS No. 123 -
"Accounting for Stock-Based Compensation," Enron's net income and
earnings per share would have been $66 million ($0.18 per share
basic, $0.18 per share diluted) in 1997, $562 million ($2.22 per
share basic, $2.07 per share diluted) in 1996 and $514 million
($2.05 per share basic, $1.92 per share diluted) in 1995.
Because the SFAS No. 123 method of accounting has not been
applied to options granted prior to January 1, 1995, the
resulting pro forma compensation cost may not be representative
of the pro forma amounts to be expected in future years.
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 1997, 1996 and 1995,
respectively: (i) dividend yield of 2.5%, 2.3% and 2.4%; (ii)
expected volatility of 17.4%, 23.8% and 24.3%; (iii) risk-free
interest rates of 5.9%, 5.9% and 6.4%; and (iv) expected lives of
3.7 years, 4.0 years and 3.7 years.
Enron has four 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:
1997 1996 1995
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
(Shares in Thousands) Shares Price Shares Price Shares Price
Outstanding,
beginning of year 25,476 $32.69 22,493 $29.02 24,246 $27.38
Granted(a) 17,658 38.63 7,370 39.71 2,971 34.27
Exercised (2,165) 41.06 (3,615) 24.41 (3,137) 20.91
Forfeited (1,514) 35.25 (749) 31.66 (1,586) 29.89
Expired (26) 34.59 (23) 30.65 (1) 23.42
Outstanding,
end of year 39,429 $35.77 25,476 $32.69 22,493 $29.02
Exercisable,
end of year 21,252 $33.55 12,883 $30.65 9,599 $26.11
Available for grant,
end of year(b) 13,047 6,505 7,831
Weighted average
fair value of
options granted $7.10 $9.44 $7.86
<FN>
(a) Includes 1,768,074 shares issued in connection with business
acquisitions discussed in Note 2.
(b) Includes up to 12,246,040 shares, 5,232,218 shares and
5,209,620 shares as of December 31, 1997, 1996 and 1995,
respectively, which may be issued either as restricted stock
or pursuant to stock options.
The following table summarizes information about stock options
outstanding at December 31, 1997 (shares in thousands):
Options Outstanding Options Exercisable
Weighted
Average Weighted Weighted
Number Remaining Average Number Average
Range of Outstanding Contractual Exercise Exercisable Exercise
Exercise Prices at 12/31/97 Life Price at 12/31/97 Price
$ 9.13 to $29.75 5,421 5 years $24.17 5,044 $23.86
30.13 to 34.75 10,143 6 years 31.56 5,798 31.67
35.38 to 39.88 11,397 8 years 37.59 5,239 37.86
40.00 to 45.00 12,468 7 years 42.55 5,171 42.79
$ 9.13 to $45.00 39,429 7 years $35.77 21,252 $33.55
Restricted Stock Plan. Under Enron's Restricted Stock Plan,
participants may be granted stock without cost to the
participant. The shares issued under this plan vest to the
participants at various times ranging from immediate vesting to
vesting at the end of a five-year period. The following
summarizes shares of restricted stock under this plan:
(Shares in Thousands) 1997 1996 1995
Outstanding, beginning of year 825 159 194
Granted 2,088 1,772 45
Issued (321) (1,062) (70)
Forfeited or expired (55) (44) (10)
Outstanding, end of year 2,537 825 159
Available for grant, end of year 12,246 5,232 5,210
Weighted average fair value of
restricted stock granted $38.26 $37.04 $31.36
Flexible Equity Trust (the Trust). In December 1993, Enron
established the Trust to fund a portion of its obligations
arising from its various employee compensation and benefit plans.
Enron issued 7.5 million shares of common stock to the Trust in
exchange for cash and an interest bearing promissory note. The
note held by Enron is reflected as a reduction of shareholders'
equity. During 1997, 1996 and 1995, respectively, 258,658
shares, 2,233,867 shares and 1,049,403 shares were released to
fund employee benefits.
11 RETIREMENT BENEFITS PLAN AND ESOP
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 beginning January 1, 1996. Prior to
1996, the benefit formula was based on final average pay and
years of service.
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, 1997 and 1996, 13,508,794
shares and 15,976,195 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.
The components of pension expense are as follows:
(In Millions) 1997 1996 1995
Service cost - benefits earned
during the year $ 22 $14 $ 1
Interest cost on projected
benefit obligation 32 23 21
Actual return on plan assets (84) (34) (32)
Amortization and deferrals 42 9 9
Pension expense (income) $ 12 $ 12 $ (1)
The measurement date of the Enron Plan and the ESOP is
September 30, and the measurement date of the Portland General
Plan is December 31. The funded status as of the valuation date
of the Enron Plan, the Portland General Plan and the ESOP
reconciles with the amount detailed below which is included in
"Other Assets" on the Consolidated Balance Sheet.
(In Millions) 1997 1996
Actuarial present value of
accumulated benefit obligation
Vested $(552) $(301)
Nonvested (20) (4)
Additional amounts related
to projected wage increases (45) (5)
Projected benefit obligation (617) (310)
Plan assets at fair value(a) 727 315
Plan assets in excess of
projected benefit obligation 110 5
Unrecognized net loss 34 46
Unrecognized prior service cost 35 36
Unrecognized net asset at transition (24) (30)
Contributions - 1
Prepaid pension cost at December 31 $ 155 $ 58
Discount rate 7.25% 7.5%
Long-term rate of return on assets (b) 10.5%
Rate of increase in wages (c) 4.0%
<FN>
(a) Includes plan assets of the ESOP of $135 million and $137
million for the years 1997 and 1996, respectively.
(b) Long-term rate of return on assets is assumed to be 10.5%
for the Enron Plan and 9.0% for the Portland General Plan.
(c) Rate of increase in wages is assumed to be 4.0% for the
Enron Plan and 4.0% to 9.5% for the Portland General 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.
12 BENEFITS OTHER THAN PENSIONS
Enron provides certain 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 its 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.
The following table sets forth the plan's funded status
reconciled with the amounts reported in the Consolidated Balance
Sheet.
(In Millions) 1997 1996
Actuarial present value of accumulated
postretirement benefit obligation (APBO)
Retirees $(121) $(126)
Fully eligible active plan
participants (5) (2)
Other employees (22) (16)
Total APBO (148) (144)
Plan assets at fair value 54 15
APBO in excess of plan assets (94) (129)
Unrecognized transition obligation 62 66
Unrecognized prior service costs 22 20
Unrecognized net loss 6 33
Accrued postretirement benefit obligation $ (4) $ (10)
Discount rate 7.25% 7.5%
Long-term rate of return on assets,
before taxes (a) 7.5%
Health care cost trend rate (b) 11.0%
<FN>
(a) Long-term rate of return on assets, before taxes, is
assumed to be 7.5% for the Enron assets and 9.5% for the
Portland General assets.
(b) Health care cost trend rate is assumed to be 8.0% for
Enron and 7.5% for Portland General. These rates are assumed
to decrease to 5.0% by 2003.
The components of net periodic postretirement benefit expense
are as follows:
(In Millions) 1997 1996 1995
Service costs $ 2 $ 1 $ 1
Interest costs 10 10 9
Amortization and deferrals 4 6 6
Postretirement benefit expense $16 $17 $16
A 1% increase in the health care cost trend rate would have
the effect of increasing the APBO and the net periodic expense by
approximately $9 million and $1 million, respectively.
Additionally, Enron maintains various incentive based
compensation plans for which participants may receive a
combination of cash, restricted stock or stock options 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 Utilities 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 at
December 31, 1997 and 1996, respectively, were $283 million and
$312 million, which included transition costs incurred related to
FERC Order 636 of $41 million and $86 million. The regulatory
assets related to the FERC Order 636 transition costs are
scheduled to be primarily recovered from customers by the end of
1998, while the remaining assets are expected to be recovered
over varying time periods.
The electric utility operations' net regulatory assets at
December 31, 1997, were $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. Enron's regulated pipelines have all
successfully completed their transitions under FERC Order 636.
Any future transition costs not recoverable through the
pipelines' FERC tariffs are not expected to be substantial.
Electric Utility Operations. On September 2, 1997 and
December 1, 1997, pursuant to the OPUC's condition to its
approval of the Enron/PGC merger, PGE submitted to the OPUC a
Customer Choice Plan and rate case to open its service territory
to competition. This plan will separate PGE's potentially
competitive businesses, primarily the generation of electricity,
from its regulated businesses and allow customers to choose their
energy provider. The separation of the generation business is
proposed to be accomplished by selling PGE's generating assets,
either to an Enron affiliate or third parties. Enron is unable
to predict what changes may be required by the OPUC for approval
or when the OPUC will approve a Customer Choice Plan.
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, 1997,
PGE's regulatory asset related to recovery of Trojan costs from
customers was $488 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
Court of Appeals has affirmed the trial court's order granting
class certification. An appeal to the Texas Supreme Court will
be pursued. 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 June 2, 1997, Enron announced the resolution of all
contractual issues involving the J-Block contract in the U.K.
North Sea with the J-Block producers, Phillips Petroleum Company
United Kingdom Limited, BG Exploration & Production Limited and
Agip (U.K.) Limited. The J-Block contracts are long-term gas
contracts that an Enron subsidiary entered into in March 1993
with the J-Block producers. As consideration for amending the
contract, Enron made a cash payment of approximately $440 million
to the producers. Enron recorded a second quarter non-recurring
contract restructuring charge of $675 million ($463 million after
tax), primarily reflecting the impact of the amended contract.
Such resolution concluded all J-Block litigation between Enron
and the J-Block producers.
On June 3, 1997, the London Commercial Court ruled in favor of
the "CATS" parties in their dispute over the availability of the
CATS (Central Area Transmission System) transportation
facilities. The CATS parties sued Teesside Gas Transportation
Limited (TGTL), an Enron subsidiary, and Enron (on the basis of
its guarantee of TGTL's obligations under the transportation
agreement between TGTL and the CATS parties) for allegedly
failing to make quarterly "send-or-pay" payments under the
transportation agreement. TGTL had refused to make these
payments based upon its position that the transportation
facilities were not available as required by the contract. The
effect of the Court's decision is that TGTL has released withheld
"send-or-pay" payments to the CATS parties in the amount of
approximately 81 million Pounds Sterling, plus interest and
costs. The judgment has no effect on the above referenced
settlement of the J-Block gas sales agreements. Enron is
appealing the decision of the London Commercial Court in the CATS
litigation. Enron believes that the ultimate resolution of this
matter 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, operates a natural gas
distribution system in the vicinity. Although San Juan did not
provide gas service to the building, the investigation report of
the National Transportation Safety Board (NTSB) has tentatively
concluded that the incident was caused by gas leaking from San
Juan's distribution system. San Juan and Enron strongly disagree
with the NTSB findings principally because the NTSB investigation
(i) found no path of migration of gas from San Juan's system to
the building and (ii) discovered no scientific evidence that
propane gas was the explosive fuel. Enron and San Juan have been
named as defendants in a number of lawsuits filed in U.S. District
Court for the district of Puerto Rico and Commonwealth courts 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 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 Nuclear Plant. In early 1993, PGE ceased commercial
operation of Trojan. Since plant closure, PGE has committed
itself to a safe and economical transition toward a
decommissioned plant. PGE has received approval of its
decommissioning plan submitted to the Nuclear Regulatory
Commission and Oregon Energy Facilities Siting Council. PGE's
remaining cost to decommission and close Trojan of $313 million
has been reflected in "Other Liabilities" in the Consolidated
Balance Sheet.
Trojan Investment Recovery. In April 1996 a circuit court
judge in Marion County, Oregon, found that the OPUC could not
authorize PGE to collect a return on its undepreciated investment
in Trojan, contradicting a November 1994 ruling from the same
court. The ruling was the result of an appeal of PGE's 1995
general rate order which granted PGE recovery of, and a return
on, 87% of its remaining investment in Trojan.
The 1994 ruling was appealed to the Oregon Court of Appeals
and stayed pending the appeal of the Commission's March 1995
order. Both PGE and the OPUC have separately appealed the April
1996 ruling, which appeals were combined with the appeal of the
November 1994 ruling at the Oregon Court of Appeals.
Enron believes that the authorized recovery of and return on
the Trojan investment and decommissioning costs will be upheld
and that these legal challenges will not have a materially
adverse impact 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. The EPA is interested in determining whether
materials from the plant have adversely affected subsurface soils
at the Decorah 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. To date, the EPA has identified no other potentially
responsible parties with respect to this site. 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.
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, 1997, the estimated
aggregate amounts of such required future payments were $100
million, $114 million, $118 million, $122 million and $133
million for 1998 through 2002, respectively, and $942 million for
later years.
The costs recognized under firm transportation agreements,
including commodity charges on actual quantities shipped, totaled
$27 million, $25 million and $18 million in 1997, 1996 and 1995,
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, 1997 were $142 million, $117 million, $114 million,
$63 million and $46 million for 1998 through 2002, respectively,
and $228 million for later years. Guarantees under the leases
total $1,029 million at December 31, 1997.
Total rent expense incurred during 1997, 1996 and 1995 was
$156 million, $149 million and $147 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 subsidiaries in connection with
letters of credit issued on behalf of those unconsolidated
subsidiaries. At December 31, 1997, a total of $278 million of
such guarantees were outstanding, including $92 million on behalf
of EOTT. In addition, Enron is a guarantor on certain
liabilities of unconsolidated subsidiaries and other companies
totaling approximately $873 million, including $402 million
related to EOTT trade obligations. The EOTT letters of credit
and guarantees of trade obligations are fully secured by the
assets of EOTT. Enron has also guaranteed $486 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 1998 planned capital
expenditures and equity investments.
16 QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data is as follows:
(In Millions, Except First Second Third Fourth Total
Per Share Amounts) Quarter Quarter Quarter Quarter Year
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)
1996
Revenues $ 3,054 $ 2,961 $ 3,225 $ 4,049 $13,289
Income before interest,
minority interests and
income taxes 415 265 262 296 1,238
Net income 213 117 123 131 584
Earnings per share:
Basic $0.86 $0.46 $0.48 $0.52 $2.31(a)
Diluted 0.80 0.43 0.45 0.48 2.16(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.
17 GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION
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 - 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
light industrial sectors.
Corporate and Other - Includes operation of renewable energy
businesses and clean fuels plants, as well as Enron's investment
in crude oil transportation activities.
Enron's business segment information has been reclassified
from prior years to reflect the realignment of Enron's
operations. Financial information by geographic and business
segment follows for each of the three years in the period ended
December 31, 1997.
Geographic Segments
Year Ended December 31,
(In Millions) 1997 1996 1995
Operating revenues from
unaffiliated customers
United States $17,328 $11,262 $ 7,855
Foreign 2,945 2,027 1,334
$20,273 $13,289 $ 9,189
Intersegment sales
United States $ 23 $ 72 $ 24
Foreign 176 128 159
$ 199 $ 200 $ 183
Operating income (loss)
United States $ 173 $ 490 $ 487
Foreign (158) 200 131
$ 15 $ 690 $ 618
Income (loss) before interest,
minority interests and income
taxes
United States $ 601 $ 938 $ 969
Foreign (36) 300 196
$ 565 $ 1,238 $ 1,165
Identifiable assets
United States $17,003 $11,580 $10,695
Foreign 3,763 2,856 1,327
$20,766 $14,436 $12,022
Business Segments
Wholesale
Exploration Transportation Energy Retail Corporate
and and Operations Energy and
(In Millions) Production Distribution and Services Services Other(c) Total
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 subsidiaries - 40 172 (1) 5 216
Other income, net (2) 142 106 (1) 89 334
Income (loss) before interest,
minority interests and
income taxes 183 580 654 (107) (745) 565
Capital expenditures 626 337 339 36 75 1,413
Identifiable assets 2,668 7,115 9,531 322 1,130 20,766
Investments in and advances to
unconsolidated subsidiaries - 521 1,932 - 203 2,656
Total assets $2,668 $7,636 $11,463 $ 322 $1,333 $23,422
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 subsidiaries - 35 168 - 12 215
Other income, net (5) 152 11 - 175 333
Income before interest,
minority interests and
income taxes 200 524 466 - 48 1,238
Capital expenditures 540 175 150 - 13 878
Identifiable assets 2,371 2,363 8,879 - 823 14,436
Investments in and advances to
unconsolidated subsidiaries - 516 1,005 - 180 1,701
Total assets $2,371 $2,879 $ 9,884 $ - $1,003 $16,137
1995
Unaffiliated revenues(a) $ 481 $ 758 $ 7,531 $ 400 $ 19 $ 9,189
Intersegment revenues(b) 278 55 166 - (499) -
Total revenues 759 813 7,697 400 (480) 9,189
Depreciation, depletion and
amortization 216 82 132 - 2 432
Operating income (loss) 240 279 291 - (192) 618
Equity in earnings of
unconsolidated subsidiaries - 46 64 - (24) 86
Other income, net 1 34 46 - 380 461
Income before interest,
minority interests and
income taxes 241 359 401 - 164 1,165
Capital expenditures 464 127 152 - 34 777
Identifiable assets 2,067 2,305 6,741 - 909 12,022
Investments in and advances to
unconsolidated subsidiaries - 495 625 - 97 1,217
Total assets $2,067 $2,800 $ 7,366 $ - $1,006 $13,239
<FN>
(a) Unaffiliated revenues include sales to unconsolidated subsidiaries.
(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.
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 45%, 47%, 39% and 20% at December 31, 1997, 1996,
1995 and 1994, respectively.
Capitalized Costs Relating to Oil and Gas Producing Activities
December 31,
(In Millions) 1997 1996
Proved properties $ 4,070 $ 3,593
Unproved properties 221 160
Total 4,291 3,753
Accumulated depreciation,
depletion and amortization (1,904) (1,653)
Net capitalized costs $ 2,387 $ 2,100
Costs Incurred in Oil and Gas Property Acquisition, Exploration
and Development Activities(a)
(In Millions) United States Foreign Total
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
1995
Acquisition of properties
Unproved $ 16 $ 6 $ 22
Proved 123 5 128
Total 139 11 150
Exploration 48 25 73
Development 217 79 296
Total $404 $115 $519
<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.
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, 1997:
(In Millions) United States Foreign Total
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
1995
Operating revenues
Associated companies $224 $ 7 $231
Trade 122 124 246
Gains on sales of
reserves and related
assets 63 - 63
Total 409 131 540
Exploration expenses,
including dry hole costs 35 20 55
Production costs 64 32 96
Impairment of unproved
oil and gas properties 22 2 24
Depreciation, depletion and
amortization 181 35 216
Income before income taxes 107 42 149
Income tax expense 1 29 30
Results of operations $106 $ 13 $119
<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.
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, 1997, 1996 and 1995 were based on studies performed by
Enron's engineering staff for reserves in the United States,
Canada, Trinidad and India. Opinions by DeGolyer and
MacNaughton, independent petroleum consultants, for the years
ended December 31, 1997, 1996 and 1995 covering producing areas,
in the United States and Canada, containing 54%, 64% and 60%,
respectively, of proved reserves, excluding deep Paleozoic
reserves, of Enron on a net-equivalent-cubic-feet-of-gas basis,
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.
Enron's presentation of estimated proved oil and gas reserves
excludes, for each of the years presented, those quantities
attributable to future deliveries required under a volumetric
production payment. In order to calculate such amounts, Enron
has assumed that deliveries under the volumetric production
payment are made as scheduled at expected British thermal unit
factors, and that delivery commitments are satisfied through
delivery of actual volumes as opposed to cash settlements.
Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves
(In Millions) United States Foreign Total
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(b) $ 751 $ 2,301(b)
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(b) $ 577 $ 3,069(b)
1995
Future cash inflows(a) $ 3,996 $1,294 $ 5,290
Future production costs (747) (558) (1,305)
Future development costs (298) (24) (322)
Future net cash flows before
income taxes 2,951 712 3,663
Future income taxes (696) (233) (929)
Future net cash flows 2,255 479 2,734
Discount to present value at
10% annual rate (1,015) (134) (1,149)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 1,240(b) $ 345 $ 1,585(b)
<FN>
(a) Based on year-end market prices determined at the point
of delivery from the producing unit.
(b) Excludes $18 million, $75 million and $36 million at
December 31, 1997, 1996 and 1995, respectively, associated
with a volumetric production payment sold effective October 1,
1992, as amended, to be delivered over a 78 month period
beginning October 1, 1992.
Changes in Standardized Measure of Discounted Future Net Cash
Flows
(In Millions) United States Foreign Total
December 31, 1994 $ 963 $281 $1,244
Sales and transfers of oil
and gas produced, net
of production costs (268) (99) (367)
Net changes in prices and
production costs 12 (35) (23)
Extensions, discoveries, additions
and improved recovery, net of
related costs 376(a) 138 514(a)
Development costs incurred 29 5 34
Revisions of estimated development
costs 1 33 34
Revisions of previous quantity
estimates 6 5 11
Accretion of discount 97 38 135
Net change in income taxes (133) (25) (158)
Purchases of reserves in place 194 - 194
Sales of reserves in place (54) (1) (55)
Changes in timing and other 17 5 22
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)
<FN>
(a) Includes approximately $86 million, $344 million and $77
million related to the reserves in the Big Piney deep
Paleozoic formations at December 31, 1997, 1996 and 1995,
respectively.
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:
United States Foreign Total
Net proved developed
reserves
Natural gas (Bcf)
December 31, 1994 1,128.2(a) 494.5 1,622.7(a)
December 31, 1995 1,218.1(a)(b) 544.0 1,762.1(a)(b)
December 31, 1996 1,325.7(a)(b) 814.3 2,140.0(a)(b)
December 31, 1997 1,349.0(a)(b) 986.3 2,335.3(a)(b)
Liquids (MBbl)(c)
December 31, 1994 16,770(a) 19,087 35,857(a)
December 31, 1995 19,977(a) 23,654 43,631(a)
December 31, 1996 24,868(a) 26,411 51,279(a)
December 31, 1997 27,707(a) 39,108 66,815(a)
Natural gas (Bcf)
Net proved reserves at
December 31, 1994 1,307.4(a) 532.1 1,839.5(a)
Revisions of previous
estimates 10.1 (19.9) (9.8)
Purchases in place 174.8 - 174.8
Extensions, discoveries
and other additions 1,391.6(b) 190.6 1,582.2(b)
Sales in place (38.1) (1.7) (39.8)
Production (191.7) (66.7) (258.4)
Net proved reserves at
December 31, 1995 2,654.1(a)(b) 634.4 3,288.5(a)(b)
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)(b) 890.7 3,637.2(a)(b)
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 1,195.5 3,980.3
United States Foreign Total
Liquids (MBbl)(c)
Net proved reserves at
December 31, 1994 17,787 19,251 37,038
Revisions of previous
estimates (413) 4,919 4,506
Purchases in place 4,264 - 4,264
Extensions, discoveries
and other additions 8,703 4,625 13,328
Sales in place (1,241) (9) (1,250)
Production (3,701) (3,789) (7,490)
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
<FN>
(a) Excludes approximately 21 Bcf, 38 Bcf, 54 Bcf and 71 Bcf
at December 31, 1997, 1996, 1995 and 1994, respectively,
associated with a volumetric production payment sold effective
October 1, 1992, as amended, to be delivered over a 78 month
period beginning October 1, 1992.
(b) Includes 1,180 Bcf related to net proved deep Paleozoic
natural gas reserves.
(c) Includes crude oil, condensate and natural gas liquids.
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 February 23, 1998. Our
audits were 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 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
February 23, 1998
SCHEDULE II
ENRON CORP. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(In Millions)
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
1997
Reserves deducted from
assets to which they apply
Allowance for doubtful
accounts $ 6 $ 3 $ 3 $ 1 $ 11
Assets from price risk
management activities $249 $ 50 $ 6 $23 $282
Reserve for regulatory issues
Current $ 2 $ - $ - $ 1 $ 1
Noncurrent $ 6 $ 28 $249 $22 $261
Reserve for insurance claims
and losses - noncurrent $ 29 $ 10 $ - $ 5 $ 34
Reserve for depressed MTBE
margin on committed
production $ 20 $100 $ - $64 $ 56
1996
Reserves deducted from
assets to which they apply
Allowance for doubtful
accounts $ 12 $ 3 $ - $ 9 $ 6
Assets from price risk
management activities $207 $ 87 $(8) $37 $249
Reserve for regulatory issues
Current $ 14 $ 1 $ - $13 $ 2
Noncurrent $ 37 $ - $ - $31 $ 6
Reserve for insurance claims
and losses - noncurrent $ 24 $ 12 $ - $ 7 $ 29
Reserve for depressed MTBE
margin on committed
production $ 75 $ - $ - $55 $ 20
1995
Reserves deducted from
assets to which they apply
Allowance for doubtful
accounts $ 13 $ 4 $ - $ 5 $ 12
Assets from price risk
management activities $130 $ 50 $ 45 $18 $207
Reserve for regulatory issues
Current $ 6 $ 13 $ - $ 5 $ 14
Noncurrent $ - $ 37 $ - $ - $ 37
Reserve for insurance claims
and losses - noncurrent $ 25 $ 8 $ - $ 9 $ 24
Reserve for depressed MTBE
margin on committed
production $ - $ 75 $ - $ - $ 75
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 27th day of
March, 1998.
ENRON CORP.
(Registrant)
By: RICHARD A. CAUSEY
(Richard A. Causey)
Senior Vice President and
Chief Accounting and
Information Officer
Pursuant to the requirements of the Securities Exchange
Act of 1934, this Report has been signed below on March 27,
1998 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 and
(Richard A. Causey) Chief Accounting and Information
Officer (Principal Accounting Officer)
ANDREW S. FASTOW Senior Vice President and
(Andrew S. Fastow) Chief 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
(Jeffrey K. Skilling) Chief Operating Officer
JOHN A. URQUHART* Director
(John A. Urquhart)
JOHN WAKEHAM* Director
(John Wakeham)
CHARLS E. WALKER* Director
(Charls E. Walker)
BRUCE G. WILLISON* Director
(Bruce G. Willison)
HERBERT S. WINOKUR, JR.* Director
(Herbert S. Winokur, Jr.)
*By: PEGGY B. MENCHACA
(Peggy B. Menchaca)
(Attorney-in-fact for persons indicated)
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
______________________
EXHIBITS TO
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997 Commission File Number 1-13159
ENRON CORP.
(Exact name of Registrant as specified in its charter)
OREGON 47-0255140
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification
No.)
1400 Smith Street
Houston, Texas 77002
(Address of principal executive offices)
Registrant's Telephone Number, Including Area Code (713) 853-6161
_____________________________
EXHIBIT INDEX
Exhibit
Number Description
*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).
*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 10.45
*10.01 - Enron Executive Supplemental Survivor
Benefits Plan, effective January 1, 1987
(Exhibit 10.01 to Enron Form 10-K for 1992,
File No. 1-3423).
*10.02 - First Amendment to Enron Executive
Supplemental Survivor Benefits Plan (Exhibit
10.02 to Enron Form 10-K for 1995, File No.
1-3423).
*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 Corp. Form
10-K for 1996, File No. 1-3423).
*10.05 - Enron Corp. 1988 Deferral Plan (Exhibit
10.19 to Enron Form 10-K for 1987, File No.
1-3423).
*10.06 - First Amendment to Enron Corp. 1988
Deferral Plan (Exhibit 10.06 to Enron Form
10-K for 1995, File No. 1-3423).
*10.07 - Second Amendment to Enron Corp. 1988
Deferral Plan (Exhibit 10.07 to Enron Form
10-K for 1995, File No. 1-3423).
*10.08 - Third Amendment to Enron Corp. 1988
Deferral Plan (Exhibit 10.09 to Enron
Form 10-K for 1996, File No. 1-3423).
*10.09 - Fourth Amendment to Enron Corp. 1988
Deferral Plan (Exhibit 10.10 to Enron
Form 10-K for 1996, File No. 1-3423).
*10.10 - Fifth Amendment to Enron Corp. 1988
Deferral Plan (Exhibit 10.11 to Enron
Form 10-K for 1996, File No. 1-3423).
*10.11 - Enron Corp. 1991 Stock Plan (Exhibit
10.08 to Enron Form 10-K for 1991, File No. 1-
3423).
*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.
10.14 - Second Amendment to Enron Corp. Amended
and Restated 1991 Stock Plan.
*10.15 - Enron Corp. 1992 Deferral Plan (Exhibit
10.09 to Enron Form 10-K for 1991, File No.
1-3423).
*10.16 - First Amendment to Enron Corp. 1992
Deferral Plan (Exhibit 10.10 to Enron Form
10-K for 1995, File No. 1-3423).
*10.17 - Second Amendment to Enron Corp. 1992
Deferral Plan (Exhibit 10.11 to Enron Form
10-K for 1995, File No. 1-3423).
*10.18 - Enron Corp. Directors' Deferred Income
Plan (Exhibit 10.09 to Enron Form 10-K for
1992, File No. 1-3423).
*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,
File No. 1-3423).
*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, File No. 1-3423).
*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, File No. 1-3423).
*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, File No. 1-3423).
*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, File No.
1-3423).
*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, File No. 1-3423).
*10.25 - Fifth Amendment to Consulting Services
Agreement between Enron and John A. Urquhart
(Exhibit 10.36 to Enron Form 10-K for 1995,
File No. 1-3423).
*10.26 - Sixth Amendment to Consulting Services
Agreement between Enron and John A. Urquhart
(Exhibit 10.37 to Enron Form 10-K for 1995,
File No. 1-3423).
10.27 - Seventh Amendment to Consulting Services
Agreement between Enron and John A. Urquhart,
dated October 27, 1997.
*10.28 - Employment Agreement between Enron and
James V. Derrick, Jr., dated June 11, 1991
(Exhibit 10.40 to Enron Form 10-K for 1992,
File No. 1-3423).
*10.29 - First Amendment to Employment Agreement
between Enron and James V. Derrick, Jr.,
dated May 2, 1994 (Exhibit 10.53 to Enron
Form 10-K for 1994, File No. 1-3423).
*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, File No. 1-3423).
*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 Power
Corp. and Thomas E. White dated July 1, 1990
(Exhibit 10.59 to Enron Form 10-K for 1996,
File No. 1-3423).
*10.36 - First Amendment, dated September 9,
1991, to Employment Agreement between Enron
Power Corp. and Thomas E. White dated July 1,
1990 (Exhibit 10.60 to Enron Form 10-K for
1996, File No. 1-3423).
*10.37 - Second Amendment, dated May 2, 1994, to
Employment Agreement between Enron Power
Corp. and Thomas E. White dated July 1, 1990
(Exhibit 10.61 to Enron Form 10-K for 1996,
File No. 1-3423).
*10.38 - Third Amendment, dated January 3, 1997,
to Employment Agreement between Enron Power
Corp. and Thomas E. White dated July 1, 1990
(Exhibit 10.62 to Enron Form 10-K for 1996,
File No. 1-3423).
*10.39 - 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, File No.
1-3423).
*10.40 - 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,
File No. 1-3423).
10.41 - Split Dollar Agreement between Enron and
Jeffrey K. Skilling dated May 23, 1997.
10.42 - Second Amendment effective October 13,
1997, to Employment Agreement between Enron
Corp. and Jeffrey K. Skilling.
10.43 - Loan Agreement effective October 13,
1997, between Enron Corp. and Jeffrey K.
Skilling.
*10.44 - 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).
10.45 - Executive Employment Agreement between
Stanley C. Horton and Enron Operations Corp.,
effective as of October 1, 1996.
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 13, 1998.
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
No reports on Form 8-K were filed by Enron during the
last quarter of 1997.