Document/Exhibit Description Pages Size
1: 10-K Enron Corp. 1996 Form 10-K 121± 492K
2: EX-10.04 Second Amendment to Enron Corp. 1988 Stock Plan 1 10K
3: EX-10.09 Third Amendment to Enron Corp. 1988 Deferral Plan 1 9K
4: EX-10.10 Fourth Amendment to Enron Corp. 1988 Deferral Plan 1 9K
5: EX-10.11 Fifth Amendment to Enron Corp. 1988 Deferral Plan 2± 12K
6: EX-10.25 Employment Agreement - Enron Corp. and Kenneth L. 29± 125K
Lay
7: EX-10.34 Termination Agreement - Enron Corp. and Richard D. 8± 40K
Kinder
8: EX-10.56 Third Amendment to Enron Corp. 1994 Deferral Plan 1 9K
9: EX-10.57 Fourth Amendment to Enron Corp. 1994 Deferral Plan 2± 13K
10: EX-10.58 Fifth Amendment to Enron Corp. 1994 Deferral Plan 2± 13K
11: EX-10.59 Enron Power Corp. Employment Agreement-Thomas E. 14± 59K
White
12: EX-10.60 First Amendment to Employment Agreement-Thomas E. 1 9K
White
13: EX-10.61 Second Amendment Employment Agreement-Thomas E. 2± 13K
White
14: EX-10.62 Third Amendment to Employment Agreement-Thomas E. 2± 13K
White
15: EX-10.63 Employment Agreement Between Ect and Jeffrey K. 19± 80K
Skilling
16: EX-10.64 First Amendment to Employment Agreement-Jeffrey 2± 15K
Skilling
17: EX-11 Statement of Calculation of Earnings Per Share 1 10K
18: EX-12 Statement of Computation of Ratios of Earnings to 1 10K
Fixed Charges
19: EX-21 Enron Corp. and Subsidiary Companies 13± 53K
20: EX-23.01 Consent of Arthur Andersen 1 10K
21: EX-23.02 Consent of Degolyer & Macnaughton 1 13K
22: EX-23.03 Letter Report of Degolyer & Macnaughton - January 3± 16K
17, 1997
23: EX-24 Powers of Attorney 14 39K
24: EX-27 Article 5 FDS for 10-K 1 10K
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, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-3423
ENRON CORP.
(Exact name of registrant as specified in its charter)
Delaware 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, $.10 Par Value New York Stock
Exchange;
Chicago Stock
Exchange; and
Pacific Stock
Exchange
Cumulative Second Preferred New York Stock
Convertible Stock, Exchange and
$1 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. X
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 15, 1997, was approximately
$11,276,340,000. As of March 1, 1997, there were
255,948,170 shares of registrant's Common Stock, $.10 par
value, outstanding.
Documents incorporated by reference. Certain portions of
the registrant's definitive Proxy Statement for the May 6,
1997 Annual Meeting of Stockholders ("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
Transportation and Operation 2
Domestic Gas and Power Services 7
International Operations and Development 9
Exploration and Production 14
Regulation 19
Operating Statistics 26
Current Executive Officers of the Registrant 28
Item 2. Properties 30
Gas Transmission and Liquid Fuels 30
Oil and Gas Exploration and Production Properties
and Reserves 30
Item 3. Legal Proceedings 34
Item 4. Submission of Matters to a Vote of Security Holders 36
PART II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters 37
Item 6. Selected Financial Data (Unaudited) 38
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 39
Information Regarding Forward Looking Statements 50
Item 8. Financial Statements and Supplementary Data 51
Item 9. Disagreements on Accounting and Financial
Disclosure 51
PART III
Item 10. Directors and Executive Officers of the Registrant 52
Item 11. Executive Compensation 52
Item 12. Security Ownership of Certain Beneficial Owners
and Management 52
Item 13. Certain Relationships and Related Transactions 53
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 54
PART I
Item 1. BUSINESS
GENERAL
Enron Corp. ("Enron"), a Delaware corporation organized
in 1930, is an integrated natural gas and electricity
company with headquarters in Houston, Texas. Essentially
all of Enron's operations are conducted through its
subsidiaries and affiliates which are principally engaged in
the transportation and wholesale marketing of natural gas to
markets throughout the United States and internationally
through approximately 36,000 miles of natural gas pipelines;
the exploration for and production of natural gas and crude
oil in the United States and internationally; the
production, purchase, transportation and worldwide marketing
of natural gas liquids and refined petroleum products; the
independent (i.e., non-utility) development, promotion,
construction and operation of power plants, natural gas
liquids facilities and pipelines in the United States and
internationally; and the non-price regulated purchasing and
marketing of electricity and other energy related
commitments. As of December 31, 1996, Enron employed
approximately 11,700 persons.
Enron announced on July 22, 1996 that it had signed an
agreement to merge with Portland General Corporation ("PGC")
in a stock-for-stock transaction. PGC is an electric
utility holding company, serving retail electric customers
in northwest Oregon as well as wholesale electricity
customers throughout the western United States. Enron
proposes to issue approximately 51 million common shares to
shareholders of PGC in a one for one exchange of shares, as
a result of which Enron will be the surviving corporation.
In separate shareholder meetings held on November 12, 1996,
75% of the Enron voting stock and 77% of PGC voting shares
were voted in favor of the merger. The merger is
conditioned, among other things, upon securing regulatory
approval from the Oregon Public Utilities Commission
("OPUC") consistent with certain conditions in the Enron/PGC
merger agreement. The Federal Energy Regulatory Commission
approved the merger on February 26, 1997. A decision on
Enron's merger approval application pending before the OPUC
is expected in 1997. See Item 4, "Submission of Matters to
a Vote of Security Holders".
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
four business segments:
1) Transportation and Operation: Interstate
transmission of natural gas; construction, management and
operation of natural gas pipelines and clean fuels plants;
and investment in crude oil transportation activities.
2) Domestic Gas and Power Services: Purchasing,
marketing and financing of natural gas, natural gas liquids,
crude oil and electricity; price risk management in
connection with natural gas, natural gas liquids, crude oil
and electricity transactions; intrastate natural gas
pipelines; development, acquisition and promotion of natural
gas-fired power plants in North America; and extraction of
natural gas liquids.
3) International Operations and Development:
Independent (non-utility) development, acquisition and
promotion of power plants, natural gas liquids facilities
and pipelines outside of North America.
4) Exploration and Production: Natural gas and crude
oil exploration and production primarily in the United
States, Canada, Trinidad and India.
For financial information by business segment for the
fiscal years ended December 31, 1994 through December 31,
1996, please see Note 18 to the Consolidated Financial
Statements on page F-31.
TRANSPORTATION AND OPERATION
Interstate Natural Gas Pipelines
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 ("FGT") (indirectly 50%
owned by Enron). Northern, Transwestern and FGT 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 FGT, the State of Florida. In addition, Enron holds a
13% 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. During the first
quarter of 1997, Enron completed the sale of the stock of
Enron Liquids Pipeline Company, a wholly owned subsidiary
and the general partner and 15% owner and operator of Enron
Liquids Pipeline, L.P. The sale of this non-strategic asset
is not material to Enron's operations.
Northern Natural Gas Company. Through its
approximately 17,000-mile natural gas pipeline system
stretching from Texas to Michigan's Upper Peninsula,
Northern transports 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 end-users. 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 1,675
trillion British thermal units ("Tbtu") in 1996, compared to
2,001 Tbtu in 1995. In its traditional market area,
Northern's throughput increased to 888 Tbtu in 1996 from 836
Tbtu in 1995. Northern's jurisdictional sales ceased in
1994 as a result of the shift from sales to transportation
volumes due to the implementation of open access
transportation service. The volume of gas delivered by
Northern in its non-traditional market area decreased from
1,165 Tbtu in 1995 to 788 Tbtu in 1996 due to the transfer
and sale of its gathering facilities in 1995.
Northern completed two significant expansion projects
in 1996. The expansion of its "East Leg" expanded capacity
on the system in Iowa, Illinois and Wisconsin. The total
increase in capacity on the East Leg is 354 million cubic
feet ("Mmcf") per day. Northern also added 464 Mmcf per day
of firm capacity in its Minnesota market. In addition,
Northern filed an application with the FERC for an expansion
project to increase peak day firm transportation service
into the U.S. upper midwest markets by approximately 350
Mmcf of gas per day over the next five years. This
comprehensive five year market project supports the growing
residential, commercial and industrial sectors in Northern's
market area.
Northern competes with other interstate pipelines in
the transportation and storage of 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 open-
access 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
northwest 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 Permian
Basin in West Texas and eastern New Mexico, the San Juan
Basin in northwestern New Mexico and southern Colorado, and
the Anadarko Basin in the Texas and Oklahoma Panhandles.
Substantially all of Transwestern's total of approximately
1.1 billion cubic feet ("Bcf") per day of delivery capacity
to California was held by shippers on a firm basis until
November 1, 1996, when approximately 450 Mmcf 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 will be 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 for five years. 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 in northwestern New Mexico and southern
Colorado 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 414 MMcf per day in 1996,
compared to 463 MMcf per day in 1995. 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.
During 1996, Transwestern 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 773 Mmcf per day off
the east end of its system in 1996, as compared 625 MMcf per
day in 1995 and 388 MMcf per day in 1994.
In 1996, Transwestern expanded the capacity of its San
Juan lateral pipeline by 255 MMcf per day. Transwestern
also acquired an approximately 78% ownership interest in
Northwest Pipeline Company's ("Northwest") La Plata
facilities, which consists of a compressor station and
approximately 33 miles of 30-inch pipeline located on the
southern end of the Northwest system. These facilities tie
into Transwestern's system at the Blanco Hub in northwestern
New Mexico. This project gives Transwestern direct access to
additional gas supplies in the San Juan Basin.
Transwestern is subject to competition from other
transporters into the southern California market, including
El Paso Natural Gas Company, Kern River Gas Transmission
Company, Pacific Gas Transmission Company, and intrastate
producers and affiliates of Southern California Gas Company.
Florida Gas Transmission Company. An Enron subsidiary
owns a 50% interest in FGT by virtue of its 50% interest in
Citrus Corp., which owns all of the capital stock of FGT.
Another Enron subsidiary operates the FGT pipeline.
FGT is an open access interstate pipeline company that
transports natural gas for third parties. Its approximately
5,051-mile dual pipeline system extends from South Texas to
a point near Miami, Florida. FGT 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.
FGT has periodically expanded its system capacity to
keep pace with the growing demand for natural gas in
Florida. FGT placed its Phase III expansion in service on
March 1, 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
FGT's firm average delivery capacity into Florida by 532
billion British thermal units ("BBtu") per day to 1,455 BBtu
per day. The Phase III expansion includes in excess of 800
miles of additional FGT pipeline, seven additional delivery
points and approximately 114,000 additional horsepower of
compression. As part of Phase III, FGT also purchased an
interest in facilities that link its system to the Mobile
Bay producing area and contracted for 100 BBtu per day of
capacity on another interstate pipeline system to provide
its customers with additional sources of supply. FGT's
customers have reserved over 99% of the existing capacity on
the FGT system pursuant to firm long-term transportation
service agreements.
FGT is the only interstate natural gas pipeline serving
peninsular Florida. FGT 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 FGT will
recover substantially all of its fixed costs regardless of
levels of usage by its customers. See "Regulation - Natural
Gas Rates and Regulations".
Northern Border Partners, L.P.. Northern Border
Partners, L.P., a Delaware limited partnership, owns 70% of
Northern Border Pipeline Company, a Texas general
partnership ("Northern Border"). An Enron subsidiary holds
a 13% 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 United States. 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 United States by transportation, displacement and
exchange agreements. Therefore, Northern Border is
strategically situated to transport significant quantities
of natural gas to major gas consuming markets.
Northern Border has focused its efforts primarily on
being a low cost transporter of Canadian gas exported to the
United States. As of December 31, 1996, Northern Border had
firm transportation service agreements, other than those
under temporary releases, with four interstate pipeline
companies, 17 domestic and Canadian producers and marketers,
including Enron Capital & Trade Resources Corp., and ten
local distribution companies. Since 1988, Northern Border
has been transporting volumes at or near its maximum
capacity. 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. At the present time, 6% of the firm capacity
(based on annual cost of service obligations) is contracted
by interstate pipelines. The remaining firm capacity is
contracted to producers, marketers and local distribution
companies. Enron Capital & Trade Resources Corp., along
with marketing affiliates of the other general partners in
Northern Border, hold approximately 9% of the contracted
capacity. Northern Border competes with two other
interstate pipeline systems that transport gas from Canada
to the Midwest.
Northern Border is currently pursuing opportunities to
increase its capacity. Northern Border has filed
applications with the FERC for a proposed project to extend
and expand its existing system by installing approximately
(a) 224 miles of 36-inch pipeline from Northern Border's
current terminus near Harper, Iowa, to a point near
Manhattan, Illinois (Chicago area); (b) 19 miles of 30-inch
pipeline from the end of the proposed 36-inch pipeline
extension to two points of interconnection with the
facilities of the Peoples Gas Light and Coke Company
(Chicago area); (c) 147 miles of 36-inch pipeline loop; (d)
a total of 303,500 horsepower of compression at twelve
compressor stations; and (e) nine meter stations and one
meter station upgrade. The estimated cost of the facilities
proposed to be constructed is approximately $837 million.
New receipts into the Northern Border pipeline system are
proposed to be 700 MMcf per day, and 648 MMcf per day is
proposed to be transported through the pipeline extension.
Subject to regulatory approvals, the project is expected to
be ready for service in November 1998.
Construction, Operation and Management of Power and Pipeline
Facilities
Enron's subsidiary companies are involved in the
independent power and natural gas pipeline industries. In
the independent power industry, Enron is involved both as an
operator of and as an equity partner in independent (i.e.,
non-utility) natural gas-fired power plants, some of which
use combined cycle and cogeneration technology to generate
electricity and steam. In addition, Enron subsidiaries have
developed diesel-fired power plants for projects in
developing countries, where the development, engineering
design and construction are done on an accelerated basis in
order to address severe power shortages in such countries.
Enron Ventures Corp. ("EVC"), a wholly owned subsidiary,
provides power plant and natural gas pipeline engineering
expertise, construction management, technical support and
consulting services to pipelines and power plants worldwide.
EVC also has engineering and construction or construction
management projects underway in India, Turkey, the United
Kingdom, Italy, Argentina and Russia, and is negotiating
contracts for proposed projects in Puerto Rico, Guam,
Poland, Vietnam, Croatia, East Java and Russia. It also
offers services for third party construction services,
operation and maintenance. (See "International Operations
and Development" for a general description of Enron's
international power and pipeline businesses). EVC is also
engaged in the management of Enron's investments in its
"clean fuels" businesses which consist of the production and
marketing of methanol and methyl tertiary butyl ether
(MTBE).
Crude Oil Transportation Services
EVC also manages Enron's investment in the crude oil
transportation and trading business. EOTT Energy Partners,
L.P. ("EOTT"), a Delaware limited partnership formed in
March 1994, owns and operates the former businesses and
assets of EOTT Energy Corp. EOTT 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. Within the
United States, EOTT transports most of the lease crude oil
it purchases by means of a fleet of more than 309 owned or
leased trucks, and by pipeline, including approximately
1,727 miles of intrastate and interstate pipeline and
gathering systems owned by EOTT and common carrier pipeline
systems owned by third parties. In addition, EOTT provides
transportation and trading services for third party
purchasers of crude oil. These pipeline systems and
trucking operations cover 17 states. EOTT also purchases
crude oil from integrated and independent producers in the
United States and Canada. EOTT markets the crude oil to
major integrated oil companies and independent refiners
throughout the United States and Canada. In its North
American crude oil gathering and marketing operations, EOTT
purchased approximately 303,000 barrels per day of lease
crude oil during 1996. In its various businesses, EOTT is
in competition with major oil companies and a number of
smaller entities. The crude oil gathering and marketing
business is characterized by narrow, volatile margins and
intense competition for supplies of lease crude oil.
Competitive factors include price, quality of service,
transportation facilities, and knowledge of products and
markets.
Sale of Liquids Assets
In addition to the sale of the stock of Enron Liquids
Pipeline Company mentioned previously, during the first
quarter of 1997 Enron also completed the sale of the stock
of Enron Louisiana Energy Company, a natural gas processor
and natural gas liquids producer and fractionator, which
owns or holds majority interests in five processing plants,
two liquids pipelines and a salt dome storage facility in
Louisiana. Enron also completed the sale of its wholesale
propane business. The sale of these non-strategic North
American assets is consistent with Enron's previously
announced strategy of focusing on core businesses and is not
material to Enron's operations.
DOMESTIC GAS AND POWER SERVICES
The domestic gas and power activities are conducted
primarily by Enron Capital & Trade Resources Corp. and
affiliated companies ("ECT"). ECT includes the marketing,
purchasing and financing of natural gas, natural gas liquids
("NGL"), crude oil, electricity and other energy commodities
and the management of the portfolio of commitments arising
from these activities.
Enron Capital & Trade Resources Corp.
ECT is responsible for Enron's marketing activities in
North America and provides financial services for producers
and end-users of energy commodities. ECT offers a broad
range of services to provide predictable pricing, reliable
delivery and low cost capital to its customers. These
services are provided through a variety of products
including forward contracts, swap agreements and other
contractual commitments. ECT's operations can be
categorized into three business lines: cash and physical,
risk management and finance.
Cash and Physical. The cash and physical operations
include the day-to-day purchase, sale, marketing and
transportation of physical natural gas, liquids, electricity
and other commodities under contracts of one year or less
and the management of ECT's contract portfolios. ECT's cash
and physical business is augmented by its ownership of or
access to physical assets consisting of intrastate
pipelines, numerous storage facilities, liquids assets and
ownership interests in domestic power generation facilities.
The day-to-day buying, selling and transporting of
commodities is facilitated by using the New York Mercantile
Exchange. This allows ECT to manage its portfolio of
contracts and to benefit from the relationship between the
financial and physical prices for natural gas. Total
physical and notional volumes for 1996 averaged 44.8 Tbtu of
natural gas equivalents per day compared to 41.2 Tbtu of
natural gas equivalents per day in 1995. Included in these
amounts are physical volumes of approximately 9.6 Tbtu of
natural gas equivalents per day in 1996 and 8.2 Tbtu of
natural gas equivalents per day in 1995.
The intrastate pipelines included in ECT are Houston
Pipe Line Company ("HPL") and Louisiana Resources Company.
HPL owns an approximately 5,300-mile pipeline in Texas which
interconnects with Northern, Transwestern, FGT and numerous
other interstate and intrastate pipelines. HPL's intrastate
natural gas sales, transportation and storage services are
subject to seasonal variation because many of its customers
have weather-sensitive 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 and
has numerous interconnections with both interstate and
intrastate pipelines.
ECT'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 ECT'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.
ECT's electric power business consists of various
activities associated with the North American power market,
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. ECT marketed 60.1 million megawatt
hours and 7.8 million megawatt hours of electricity during
1996 and 1995, respectively. ECT 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 ECT's risk management operations). ECT
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.
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. ECT provides risk management
products and services that hedge movements in price and
location-based price differentials. ECT's risk management
services are designed to provide stability in markets
impacted by high price volatility. ECT 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. ECT originates new contracts for customers in
the energy industry and evaluates and restructures its
existing contracts on an on-going basis to develop
additional products and services to meet its customers'
changing needs. ECT's fixed price contract originations
were 3,671 Tbtu of natural gas equivalents in 1996, and
5,952 Tbtu of natural gas equivalents in 1995. The risk
management activities also include the origination of
liquids 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. ECT's financing and funding activities
support independent exploration and production companies and
other energy-related businesses seeking equity financing.
ECT's finance operations provide a variety of capital
products including volumetric production payments, loans and
equity investments. These products are offered by ECT
directly or through ECT ventures such as Joint Energy
Development Investments Limited Partnership, a limited
partnership 50% owned by Enron which was formed to acquire
and own energy investments. Financings arranged and
production payments purchased totalled $755 million and $382
million in 1996 and 1995, respectively. In addition to
capital, ECT provides marketing and risk management
capabilities to help customers capitalize on growth
opportunities while maximizing the value of their current
assets. In 1997, ECT expects to continue to expand its
products and services in its role as a full-service provider
of various types of capital, including leveraging existing
assets, restructuring existing debt, building equity
partnerships, and arranging producer funding through
volumetric production payments.
Enron Energy Services. ECT recently established Enron
Energy Services ("EES") to pursue the significant growth
opportunities in anticipation of a fully competitive retail
natural gas and electricity market. As states begin to
deregulate their natural gas and electricity markets, and as
these markets continue to converge, EES's goal is to provide
end-users with a broad range of energy choices at more
competitive prices. EES has participated in selected
natural gas and electric retail marketing pilot programs,
including a state-wide electricity pilot in New Hampshire,
where individual customers are free to select the power
provider of their choice. EES will continue to participate
in such programs.
INTERNATIONAL OPERATIONS AND DEVELOPMENT
Enron's international operations and development
activities are conducted by Enron International Inc. ("EI"),
and principally involve the development, acquisition,
financing, promotion, and operation of natural gas and power
projects in emerging markets and the marketing of natural
gas liquids and other liquid fuels. Enron has expanded its
traditional international asset and infrastructure
development business by also offering merchant, finance and
risk management products and services to third parties in
emerging markets. In addition, ECT has established
commercial marketing offices in London, Buenos Aires, Norway
and Singapore to offer the same type of physical commodity
products, financial services and risk management services
currently available through ECT in North America.
Development projects are focused on power plants, gas
processing and terminaling facilities, and gas pipelines,
while marketing activities center on fuels used by or
transported through such facilities. The objective of EI is
to develop, finance, own and operate integrated energy
projects worldwide through the utilization of Enron's
extensive portfolio of products and services.
Enron's international activities include management of
direct and indirect ownership interests in and/or operation
of power plants in England, Germany, Guatemala, the
Philippines, China and the Dominican Republic; pipeline
systems in southern Argentina and Colombia; retail gas and
propane sales in the Caribbean basin; processing of natural
gas liquids at Teesside, England; and marketing of natural
gas liquids and other liquid fuels worldwide.
At December 31, 1996, Enron had an approximately 28%
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, 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 Global Power & Pipelines L.L.C. In November
1994, Enron Global Power & Pipelines L.L.C., a Delaware
limited liability company ("EPP"), was formed by Enron to
acquire, own and manage operating power plants and natural
gas pipelines around the world. EPP's assets consist of
interests in two power plants in the Philippines, power
plants in Guatemala and the Dominican Republic, and natural
gas pipeline systems in Argentina and Colombia (see below).
Enron owns approximately 52% of EPP.
In order to provide EPP with a long-term source of
project acquisition opportunities, Enron and EPP have
entered into a Purchase Right Agreement pursuant to which
Enron has agreed to offer to sell to EPP, at prices lower
than those that Enron may make available to third parties,
all of Enron's ownership interests in power plants and
natural gas pipeline projects developed or acquired by Enron
outside the United States, Canada and Western Europe, but
only those projects that commence commercial operations
prior to the year 2005, subject to certain exceptions. In
addition to evaluating projects under the Purchase Right
Agreement, EPP seeks opportunities to purchase power plants,
pipelines and related assets from parties other than Enron.
EPP 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 EPP
and sell power to the National Power Corporation of the
Philippines.
EPP 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.
In June 1996, EPP acquired from Enron 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.
As part of the privatization of Argentina's state-owned
industries, in 1992 Enron acquired an indirect interest in
Transportadora de Gas del Sur ("TGS"), the formerly state-
owned natural gas pipeline in southern Argentina. In
November 1994, Enron sold its net 17.5% interest to EPP.
The 4,104-mile pipeline system has a capacity of
approximately 1.9 Bcf per day and serves four distribution
companies under long-term firm transportation contracts. In
1996, EPP increased its interest in TGS to approximately
23%. In addition, Enron purchased an approximate 11.6%
interest in TGS during 1996.
In May 1996, EPP acquired from Enron a 49% 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 International Inc.
Enron International Inc. is involved in power and
pipeline projects in varying stages of development,
financing or construction in India, Turkey, Italy, Puerto
Rico, Bolivia, Brazil, Indonesia, Guam, Vietnam, Mozambique
and elsewhere. The following is a brief description of
Enron's power and natural gas pipeline projects which are in
varying stages of development, financing or construction,
thus the information set forth below is subject to change.
In addition, 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. Other than as noted below,
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 began developing Phase I of an
electricity generating power plant south of Bombay, State of
Maharashtra, India. In August 1995, after construction had
begun, a new coalition government in the State of
Maharashtra announced the State government's intention to
terminate the project, and construction ceased on August 8,
1995. In response to these actions, Dabhol Power Company
initiated arbitration proceedings in London against the
State government for the actions it had taken to terminate
the project, seeking to recover all of its construction and
other expenses in addition to lost profits. After the
arbitration proceedings had begun, Dabhol Power Company
began renegotiating the Power Purchase Agreement with the
MSEB and the Maharashtra State government. Such
renegotiations, which have been successfully completed, have
resulted in a restructured transaction (that includes both
Phase I and Phase II and that increases the planned capacity
of the facility) on terms that are acceptable to Enron. All
approvals for the restructured transaction have been
received and, in December 1996, construction resumed on the
project and Dabhol Power Company terminated the arbitration
proceedings. The power plant will have an initial capacity
of 740-megawatts (or 826 megawatts gross) (Phase I), with
potential expansion up to 2,184-megawatts (or 2,450
megawatts gross). Phase I is expected to begin commercial
operations in late December 1998. The project will provide
electricity for the growing Maharashtra State economy.
China. In January 1996, Enron completed construction
of a 154-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. In
March 1996, Enron sold a 50% interest in the facility to
Singapore Power Pte. Ltd., the electricity and gas supplier
in Singapore. A 12-year power purchase agreement was signed
with Hainan Electric Power Company in September 1994.
Italy. 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 the government
utility. Financing was completed and construction began in
December 1996, with commercial operation anticipated in
early 2000.
Turkey. 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, and construction began
in September 1996, with commercial operation expected in
1999.
Puerto Rico. Enron has a 50% interest in a 507-
megawatt combined cycle power plant, including a liquefied
natural gas terminal and desalination facility, to be built
in Penuelas, Puerto Rico. Enron will be the turnkey
contractor and operator of the project, construction of
which is expected to commence in 1997, with commercial
operation anticipated in 1999.
Bolivia/Brazil. As a partner with the national gas
company of Bolivia, Enron is developing, along with
Petrobras, the national oil and gas company of Brazil, and
others, a pipeline from Bolivia to Brazil. The pipeline
project includes an approximately 1,875-mile natural gas
pipeline from Santa Cruz, Bolivia to Porto Alegre, Brazil.
Enron is also negotiating the development of certain power
projects with Sao Paulo utilities. Enron will own 29.75% of
the Bolivia segment of the pipeline and 7% of the Brazilian
segment of the pipeline. Commercial operation of the
pipeline is expected in 1999.
East Java, Indonesia. Enron has a 50% interest in a
500-megawatt gas-fired combined-cycle power plant to be
located near Jakarta, Indonesia. A 20-year power purchase
agreement has been signed with PLN, the government operated
utility. Enron will be the turnkey contractor and plant
operator. Financing arrangements are expected to be
completed in late 1997, with commercial operation
anticipated in 1999.
Guam. Enron has a 50% interest in an 85-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 under a fast track schedule to meet critical
power needs, with construction expected to begin in July
1997, and operations targeted for year-end 1998.
In addition to the projects referenced above, EI is
involved in projects in varying stages of development in
Vietnam, Poland, Croatia, Mozambique, Qatar, China, and
Honduras, and is pursuing projects elsewhere.
Caribbean Basin. Enron's operations in the Caribbean
area are conducted through Enron Americas, Inc. and its
subsidiary companies. Enron Americas' subsidiary Industrias
Ventane ("Ventane"), organized in 1953, operates the leading
natural gas liquids transportation and distribution business
in Venezuela. In Venezuela, Enron Americas is also engaged
in the manufacture and distribution of appliances in a joint
venture with General Electric and local investors. Enron
Americas has a gas pipeline operation in Puerto Rico, and
liquid fuels businesses in both Puerto Rico and Jamaica.
Liquids Marketing. Enron's international liquids
marketing business is consolidated with the corresponding
domestic activities to take advantage of techniques to
enhance profitability and manage risks that have proven
effective for Enron in the U.S. International liquids
marketing volumes increased from 779 million gallons in 1995
to 1,102 million gallons in 1996.
EXPLORATION AND PRODUCTION
Enron's natural gas and crude oil exploration and
production operations are conducted by its subsidiary, Enron
Oil & Gas Company ("EOG"). Enron currently owns
approximately 53% 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, India and, to a lesser extent,
selected other international areas. At December 31, 1996,
EOG had estimated net proved natural gas reserves of 3,675
Bcf, including 1,180 Bcf of proved undeveloped methane
reserves in the deep Paleozoic formations of the Big Piney
area of Wyoming, and estimated net proved crude oil,
condensate and natural gas liquids reserves of 55 million
barrels, and at such date, approximately 74% of EOG's
reserves (on a natural gas equivalent basis) were located in
the United States, 9% in Canada, 10% in Trinidad and 7% 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 located in West Texas, the Sand Tank area and the
Pitchfork Ranch area in New Mexico, and the Vernal area in
Utah. Properties in these areas comprised approximately 79%
of EOG's U.S. reserves (on a natural gas equivalent basis)
and 81% of EOG's U.S. net natural gas deliverability as of
December 31, 1996 and 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, Mississippi, California and
Kansas.
At December 31, 1996, 94% of EOG's proved United States
reserves, including the reserves in the Big Piney deep
Paleozoic formations (on a natural gas equivalent basis),
was natural gas and 6% was crude oil, condensate and natural
gas liquids. A substantial portion of EOG's United States
natural gas reserves is in long-lived fields with well-
established production histories. EOG believes that
opportunities exist to increase production in many of these
fields through continued infill and other development
drilling.
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. Canadian natural gas
deliverability net to EOG at December 31, 1996 was
approximately 102 MMcf per day, and EOG held approximately
321,000 net undeveloped acres in Canada.
EOG also has producing operations offshore Trinidad and
India. In early 1996, EOG was awarded by the government of
Venezuela the rights to pursue exploration, exploitation and
development of reserves in the Gulf of Paria East Block
offshore the eastern State of Soucre. EOG is conducting
exploration in selected other international areas.
Properties offshore Trinidad and India comprised 100% of
EOG's proved reserves and production outside of North
America at year end 1996.
In November 1992, EOG was awarded a 95% working
interest concession 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
three to five 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 1996, deliveries net to EOG
averaged 124 MMcf per day of natural gas and 5.2 thousand
barrels ("MBbl") per day of crude oil and condensate. At
December 31, 1996, natural gas deliverability net to EOG was
approximately 182 MMcf per day, and 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 is currently underway, and initial drilling may
occur later in 1997 or early 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 Bombay,
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 gas accumulations
delineated by 22 expendable exploration wells that have been
plugged. EOG has initiated a development plan for the Tapti
Block accumulations. The 106,000 acre Panna Block and the
192,000 acre Mukta Block are partially developed with 24
wells producing from five production platforms located in
the Panna and Mukta fields. The fields were producing
approximately 3.3 MBbl per day of crude oil net to EOG as of
December 31, 1996; currently, all associated gas is flared.
EOG intends to continue development of the accumulations and
to expand processing capacity to allow crude oil production
at full deliverability as well as to permit natural gas
sales.
EOG was awarded exploration, exploitation and
development rights for a block offshore the eastern State of
Soucre, Venezuela in early 1996. EOG holds an initial 90%
working interest in the joint venture. A 3-D seismic data
gathering project is currently underway and drilling is
anticipated to begin in 1998.
EOG continues to evaluate other selected conventional
natural gas and crude oil opportunities outside North
America. EOG is 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 cogeneration 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.
In June 1996, EOG signed a cooperative agreement with the
Chinese National Petroleum Corporation ("CNPC") to evaluate
the potential for increasing production of crude oil in the
Sichuan Basin of the People's Republic of China. If
successful, the project could culminate in a joint
development agreement with CNPC covering the Chuanzhong
Block. EOG has also entered into a Memorandum of
Understanding with Uzbekneftigaz covering the pursuit of
marketing opportunities for proven hydrocarbon reserves in
eleven fields in the Surhandarya and Bukhara regions of
Uzbekistan as well as the field's joint venture development.
EOG is also participating in discussions concerning the
potential for conventional oil and gas development
opportunities in Mozambique and Algeria, as well as other
opportunities in Trinidad, India and Venezuela.
EOG continues evaluation and assessment of its
international opportunity portfolio in the coalbed methane
recovery arena, including projects in South Wales in the
United Kingdom, the Lorraine Basin in France, Galilee Basin
in Australia and the San Jiao area and Hedong Basin in
China.
EOG actively competes for reserve acquisitions and
exploration leases, licenses and concessions, frequently
against companies with substantially larger financial and
other resources. To the extent EOG's exploration budget is
lower than that of certain of its competitors, EOG may be
disadvantaged in effectively competing for certain reserves,
leases, licenses and concessions. 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, 1996:
[Download Table]
Year Ended December 31,
1996 1995 1994
Volumes (per day)
Natural Gas (MMcf)
United States(1) 608 560 614
Canada 98 76 72
Trinidad 124 107 63
Total 830 743 749
Crude Oil and Condensate (MBbl)
United States 9.2 9.1 8.0
Canada 2.4 2.4 2.0
Trinidad 5.2 5.1 2.5
India 2.8 2.5 .1
Total 19.6 19.1 12.6
Natural Gas Liquids (MBbl)
United States 1.3 1.0 .3
Canada 1.2 .4 .4
Total 2.5 1.4 .7
Average Prices
Natural Gas ($/Mcf)
United States(2) $ 2.04 $ 1.39 1.71
Canada 1.15 .97 1.42
Trinidad 1.00 .97 .93
Composite 1.78 1.29 1.62
Crude Oil and Condensate
($/Bbl)
United States $21.88 $17.32 $16.06
Canada 18.01 16.22 14.05
Trinidad 19.76 16.07 15.50
India 20.17 16.81 15.70
Composite 20.60 16.78 15.62
Natural Gas Liquids ($/Bbl)
United States $14.67 $11.88 $12.45
Canada 9.14 9.74 8.45
Composite 11.99 11.31 9.90
Lease and Well Expenses ($/Mcfe)
United States $ .19 $ .19 $ .19
Canada .34 .35 .34
Trinidad .16 .15 .17
India .99 1.25(3) .13(3)
Composite .22 .22 .20
___________________
<FN>
(1) Includes an annual average of 48 MMcf per day in 1996,
1995 and 1994 delivered under the terms of a volumetric
production payment agreement effective October 1, 1992,
as amended.
(2) Includes an average equivalent wellhead value of $1.17
per Mcf in 1996, $.80 per Mcf in 1995 and $1.27 per Mcf
in 1994 for the volumes described in note (1), net of
transportation costs.
(3) Based on expense estimates for nine days of production
for 1994. Expenses for 1995 include certain non-
recurring startup costs.
The following table sets forth certain information
regarding EOG's volumes of natural gas delivered under other
marketing and volumetric production payment arrangements,
and resulting average per unit gross revenue and per unit
amortization of deferred revenues along with associated
costs during each of the three years in the period ended
December 31, 1996.
[Download Table]
Year Ended December 31,
1996 1995 1994
Volumes (MMcf per day)(1) 285 264 324
Average Gross Revenue ($/Mcf)(2) $ 2.24 $ 1.88 $ 2.38
Associated Costs ($/Mcf)(3)(4) 2.07 1.51 2.06
Margin ($/Mcf) $ .17 $ .37 $ .32
___________________
<FN>
(1) Includes an annual average of 48 MMcf per day in 1996,
1995 and 1994 delivered under the terms of a volumetric
production payment agreement effective October 1, 1992,
as amended.
(2) Includes per unit deferred revenue amortization for the
volumes detailed in note (1) at an equivalent of $2.46
per Mcf ($2.36 per million British thermal units) in
1996, 1995 and 1994.
(3) Includes an average value of $2.12 per Mcf in 1996,
$1.57 per Mcf in 1995 and $1.92 per Mcf in 1994 for the
volumes detailed in note (1) including average wellhead
value and any transportation costs and exchange
differentials.
(4) Including transportation and exchange differentials.
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 company is 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 company's 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 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
the 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 non-domestic 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, 1996 are approximately $312 million,
which include transition costs incurred related to FERC
Order No. 636 of approximately $86 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. Transmitting utilities are required to submit
revised tariffs to FERC in the summer of 1997 to reflect
FERC's orders on rehearing.
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.
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 and other potentially responsible
parties with respect to the cleanup of two Superfund sites.
Enron has received requests for information from the EPA and
state agencies concerning what wastes Enron may have sent to
certain sites, and it has also received requests for
contribution from other parties with respect to the cleanup
of other sites. However, management does not believe that
any costs incurred in connection with these sites (either
individually or in the aggregate) will have a material
impact on Enron's financial position or results of
operations. (See Item 3, "Legal Proceedings").
OPERATING STATISTICS
The following table presents selected statistical information
for Enron's domestic gas and power services business segment as
well as revenue data for all of Enron's businesses. Revenue
amounts are in millions of dollars.
[Download Table]
Year Ended December 31,
1996 1995 1994
ECT Natural Gas and Crude Oil
Physical/Notional Quantities (BBtue/d)*
Firm 6,435 5,392 4,895
Interruptible 2,578 2,255 2,039
Transport Volumes 544 580 538
Subtotal 9,557 8,227 7,472
Financial Settlements (notional) 35,259 32,938 16,459
Total 44,816 41,165 23,931
Electricity (Thousand megawatt hours)
Owned Production 3,122 3,441 3,481
Transaction Volumes Marketed 60,150 7,767 1,221
Fixed Price Contract
Market Activity (TBtue) 3,671 5,952 6,615
Financings Arranged and Production
Payments (Millions) $755 $382 $503
*Includes intercompany amounts
[Download Table]
Revenues by Business Segment
Year Ended December 31,
1996 1995 1994
Transportation and Operation
Natural Gas and Other Products
Unaffiliated $ 11 $ 49 $ 88
Intersegment 6 5 9
17 54 97
Transportation Services
Unaffiliated 682 680 740
Intersegment 15 21 26
697 701 766
Other Revenues
Unaffiliated 55 76 109
Intersegment 37 - 4
92 76 113
TOTAL 806 831 976
[Download Table]
Year Ended December 31,
1996 1995 1994
Domestic Gas and Power Services
Natural Gas and Other Products
Unaffiliated $10,421 $6,290 $6,633
Intersegment 138 10 60
10,559 6,300 6,693
Transportation Services
Unaffiliated 25 12 14
Intersegment 2 - 1
27 12 15
Other Revenues
Unaffiliated 1,235 762 519
Intersegment 27 (113) (48)
1,262 649 471
TOTAL 11,848 6,961 7,179
International Operations and Development
Natural Gas and Other Products
Unaffiliated 105 780 338
Intersegment - 4 1
105 784 339
Other Revenues
Unaffiliated 108 59 54
Intersegment - 40 6
108 99 60
TOTAL 213 883 399
Exploration and Production
Natural Gas and Other Products
Unaffiliated 620 410 432
Intersegment 197 165 242
817 575 674
Other Revenues
Unaffiliated 27 71 57
Intersegment (20) 113 48
7 184 105
TOTAL 824 759 779
Intersegment Eliminations (402) (245) (349)
Total Revenues $13,289 $9,189 $8,984
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
Name and Age Present Principal Position and Other Material
Positions Held During Last Five Years
Kenneth L. Lay (54) Chairman of the Board and Chief
Executive Officer, Enron Corp., since
February 1986.
Jeffrey K. Skilling (43) 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.
Rodney L. Gray (44) President of Enron Global Power &
Pipelines L.L.C. from November 1995 to
February 1997. Chairman and Chief
Executive Officer of Enron Global Power
& Pipelines L.L.C. since June 1995.
Managing Director, Enron Development
Corp., from August 1995 to December
1996. Chairman and Chief Executive
Officer, Enron International Inc., from
June 1993 to December 1996. Senior Vice
President, Finance and Treasurer, Enron
Corp., from October 1992 to June 1993.
Vice President, Finance and Treasurer,
Enron Corp., from 1988 to October 1992.
Stanley C. Horton (47) 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 (42) 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 (53) 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.
John A. Urquhart (68) Vice Chairman, Enron Corp., since August
1991.
Edmund P. Segner,III (43) Executive Vice President and Chief
of Staff, Enron Corp., since October
1992. Senior Vice President, Investor,
Public & Government Relations from
October 1990 to October 1992.
J. Clifford Baxter (38) 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 (37) 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.(52) Senior Vice President and General
Counsel, Enron Corp., since June 1991.
Partner, Vinson & Elkins from January
1977 until June 1991.
Andrew S. Fastow (35) Senior Vice President, Finance, Enron
Corp., since January 1997. 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
Gas Transmission and Liquid Fuels
Enron's natural gas facilities include approximately
36,000 miles of transmission lines, 105 mainline compressor
stations, 4 underground gas storage fields and 2 liquefied
natural gas storage facilities. Other properties in which
Enron and its affiliates have an ownership interest or lease
include 10 natural gas liquids extraction plants in Texas,
Louisiana, Wyoming, Kansas, Florida, New Mexico and North
Dakota. A large number of railroad tank and hopper cars,
truck transports and bulk vehicles are owned or leased and
used for the delivery of liquids products. 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.
Most of 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 gas processing plants, regulator and compressor
stations, clean fuel facilities and offices are located on
tracts of land owned by it in fee or leased from others.
In the case of oil and gas leases, definitive
examination and curing of title defects are usually deferred
until such time as funds are expended in connection with
drilling of such properties.
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.
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 19
to the Consolidated Financial Statements.
Estimates of proved and proved developed reserves at
December 31, 1996, 1995 and 1994 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, 1996, 1995 and 1994
covering producing areas containing 64%, 60% and 59%,
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 19 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 19 to
the Consolidated Financial Statements.
Producing Oil and Gas Wells
The following table reflects EOG's ownership at
December 31, 1996 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 200 with
multiple completions.
Productive Productive Total
Gas Wells Oil Wells Productive Wells
Gross Net Gross Net Gross Net
5,021 3,427 886 516 5,907 3,943
Acreage
The following table summarizes EOG's developed and
undeveloped acreage at December 31, 1996. Excluded is acreage
in which EOG's interest is limited to owned royalty,
overriding royalty and other similar interests.
[Download Table]
Developed Undeveloped Total
Gross Net Gross Net Gross Net
United States
California 13,030 8,341 658,089 654,054 671,119 662,395
Offshore
Gulf of Mexico 310,886 147,446 463,408 356,346 774,294 503,792
Texas 285,706 198,579 232,543 205,704 518,249 404,283
Wyoming 154,736 111,979 302,474 235,762 457,210 347,741
Oklahoma 176,218 94,222 68,270 58,944 244,488 153,166
New Mexico 72,278 35,328 82,962 48,611 155,240 83,939
Utah 57,819 46,511 32,437 26,939 90,256 73,450
Kansas 10,418 8,875 15,974 14,670 26,392 23,545
Colorado 8,313 1,219 26,485 13,697 34,798 14,916
Mississippi 1,942 1,853 12,695 12,498 14,637 14,351
Louisiana 6,054 5,909 1,360 1,295 7,414 7,204
Pennsylvania 1,443 962 6,749 4,538 8,192 5,500
Other 5,385 3,352 7,719 5,741 13,104 9,093
Total 1,104,228 664,576 1,911,165 1,638,799 3,015,393 2,303,375
Canada
Alberta 365,797 174,932 196,936 157,639 562,733 332,571
Saskatchewan 180,623 156,548 184,504 160,013 365,127 316,561
Manitoba 11,371 9,622 4,213 3,333 15,584 12,955
British Columbia 656 164 -- -- 656 164
Total Canada 558,447 341,266 385,653 320,985 944,100 662,251
Other International
Australia -- -- 7,680,000 3,840,000 7,680,000 3,840,000
China -- -- 1,208,805 604,403 1,208,805 604,403
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
United Kingdom -- -- 173,600 86,000 173,600 86,000
Total Other
International 102,500 33,480 10,234,616 5,277,015 10,337,116 5,310,495
Total 1,765,175 1,039,322 12,531,434 7,236,799 14,296,609 8,276,121
Drilling and Acquisition Activities
During each of the years ended December 31, 1996, 1995 and
1994, EOG spent approximately $599 million, $514 million and
$494 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:
[Download Table]
Year Ended December 31,
1996 1995 1994
Gross Net Gross Net Gross Net
Development Wells Completed
North America
Gas 396 325.04 334 251.06 554 430.73
Oil 80 57.46 69 55.16 45 34.67
Dry 80 68.77 61 49.21 54 43.65
Total 556 451.27 464 355.43 653 509.05
Outside North America
Gas - - 3 2.85 4 3.80
Oil 1 .30 3 2.85 - -
Dry - - 1 .95 - -
Total 1 .30 7 6.65 4 3.80
Total Development 557 451.57 471 362.08 657 512.85
Exploratory Wells Completed
North America
Gas 14 10.36 5 4.13 22 17.70
Oil 1 .78 8 3.61 4 3.07
Dry 26 19.00 21 13.28 37 30.67
Total 41 30.14 34 21.02 63 51.44
Outside North America
Gas - - 6 4.90 - -
Oil - - - - - -
Dry 1 .50 - - - -
Total 1 .50 6 4.90 - -
Total Exploratory 42 30.64 40 25.92 63 51.44
Total 599 482.21 511 388.00 720 564.29
Wells in Progress at
End of Period 87 61.08 52 32.71 45 28.79
Total 686 543.29 563 420.71 765 593.08
Wells Acquired
Gas 350 148.20* 277 101.70* 41 40.90*
Oil 5 .65 5 .46 60 38.99*
Total 355 148.85 282 102.16 101 79.89
<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.
Item 3. LEGAL PROCEEDINGS
Enron is a party to various claims and litigation
arising in the ordinary course of its business, the
significant items of which are discussed below. Management
recognizes the uncertainties of litigation and the
possibility that one or more adverse rulings could
materially impact operating results. However, although no
assurances can be given, Enron believes, based on the nature
of and Enron's understanding of the facts and circumstances
which give rise to such actions and claims, 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 effect
on Enron's financial position or, except as discussed below,
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 these ratability claims. The Enron Defendants
have appealed the court's decision to certify a class action.
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 March 29, 1996, Enron and two of its wholly-owned
subsidiaries filed suit in the state district court of Harris
County, Texas seeking a ruling that the Capacity Reservation
and Transportation Agreement (CRTA) dated September 10, 1990
between Teesside Gas Transportation Limited (TGTL), an Enron
subsidiary, and the "CATS" parties has terminated due to
consistent material breaches of that agreement by the CATS
parties. The suit was removed to the federal district court
in Houston, Texas. Proceedings in the Houston lawsuit have
been enjoined by an English court and Enron is appealing the
injunction. In April 1996, TGTL, reserving its position in
the Houston lawsuit, notified the CATS parties in accordance
with the provisions of the CRTA that as a result of their
failure to make available the Transportation Service (as
defined in the contract) by April 1, 1996, the CRTA was
terminated. The CATS parties were to have provided
transportation under the CRTA to ship gas through the Central
Area Transmission System (CATS) pipeline, owned by the CATS
parties. In a separate lawsuit filed in the English court,
the CATS parties are suing TGTL and Enron (on the basis of
its guarantee of TGTL's obligations under the CRTA) for
allegedly failing to make quarterly "send-or-pay" payments
under the CRTA. TGTL refused to make these payments for the
same reasons that it terminated the CRTA: its position is
that the Transportation Service (as defined in the CRTA) was
not available. Termination of the CRTA may lead to
termination of the "J-Block Contracts." Trial on these
matters commenced in the English court on October 28, 1996.
The trial concluded in early March 1997, and a decision is
expected in June 1997.
The "J-Block Contracts" are long-term gas contracts that
Enron entered into in March 1993 with Phillips Petroleum
Company United Kingdom Limited, British Gas Exploration and
Production Limited and Agip (U.K.) Limited to purchase future
gas production from the J-Block field which is located in the
North Sea offshore the United Kingdom. Such agreements
provide for Enron to take or pay for certain quantities of
gas at a fixed price (with possible escalations throughout
the contract period) on an annual basis. The contract price
is in excess of market prices as of February 1997, however
United Kingdom natural gas prices have been volatile. The
agreements provide that gas paid for, but not taken, can be
recovered in later contract years. In September 1995, Enron
announced that, in accordance with its contractual rights, it
had notified the J-Block sellers that Enron's nominations for
gas from the J-Block fields were estimated to be zero from
the first delivery date of September 25, 1996 through
September 30, 1997. In addition, in accordance with its
contractual rights, Enron made no estimated nominations for J-
Block gas under the J-Block Contracts for the contract year
ending September 30, 1998. While not challenging these
actions, the J-Block sellers have, in a proceeding commenced
in English court on March 29, 1996, sought a declaration that
Enron should have agreed to a "Commissioning Date" (which
might trigger Enron's take-or-pay obligations) of earlier
than September 25, 1996, the date set forth in the J-Block
Contracts as the Commissioning Date in the absence of an
agreement on an earlier date. In October 1996, an English
Court of Appeal ruled that Enron was not obligated to agree
on an earlier Commissioning Date, thus making the contract
period ending September 30, 1997 the first year in which
Enron has a potential take-or-pay obligation. This ruling is
being appealed to the House of Lords by the J-Block sellers.
Enron continues to believe that there are many reasons for
the parties to resolve any contract issues commercially, but
efforts have not been successful to date. Unsuccessful
settlement discussions, adverse litigation outcomes or market
conditions could result in a material adverse impact on
earnings in any given period. However, although no
assurances can be given, based upon information currently
available and Enron's expectation of the ultimate outcome of
the matters discussed above, Enron anticipates that the J-
Block and CRTA contracts will not have a materially adverse
effect on its financial position.
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 expenditures. The related future cost is
indeterminable, as many of the rules implementing the Clean
Air Act's requirements have not yet been finalized.
However, any increased operating expenses are not expected
to have a material adverse effect on Enron's financial
position or results of operations.
During May 1992, Enron entered into a Consent Decree
with the EPA concerning the cleanup of the Peoples Natural
Gas Superfund Site in Dubuque, Iowa, where a coal
gasification plant had operated during the first half of
this century. The EPA had claimed that Enron was a
potentially responsible party because a predecessor company
of Enron had purchased the site in the late 1950's after
coal gas operations ceased, and had conducted surface
operations there, including the dismantling of buildings.
In 1992, Enron recorded the expense and related liability
for these cleanup costs and under the Consent Decree agreed
to make five equal, annual payments of $590,000. The final
installment was paid in June 1996.
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 to connect its
natural gas pipeline to the local distribution pipeline
system servicing the city of Decorah. 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 in certain areas of the tract where
the plant was formerly located and to take deep soil samples
in those areas where subsurface contamination would most
likely be 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
A Special Meeting of Stockholders of Enron was held on
November 12, 1996 to consider and vote upon a proposal to
approve and adopt an Amended and Restated Agreement and Plan
of Merger dated as of July 20, 1996 and amended and restated
as of September 24, 1996 (the "Merger Agreement") providing
for (i) the merger (the "Reincorporation Merger") of Enron
Corp. with and into its wholly-owned subsidiary, Enron
Oregon Corp. ("New Enron"), to effect the reincorporation of
Enron as an Oregon corporation, and (ii) immediately after
the Reincorporation Merger, the merger of Portland General
Corporation ("PGC") with and into New Enron (the "PGC
Merger"). In the reincorporation Merger, each issued and
outstanding share of the common stock, par value $.10 per
share, of Enron ("Enron Common Stock") will be converted
into one share of the common stock, without par value, of
New Enron ("New Enron Common Stock"), and each issued and
outstanding share of Cumulative Second Preferred Convertible
Stock ("Enron Convertible Preferred Stock") and 9.142%
Perpetual Second Preferred Stock of Enron (as well as any
share of any other class or series of Enron preferred stock,
second preferred stock or preference stock issued and
outstanding at the effective time of the Reincorporation
Merger) will be converted into one share of an equivalent
series of New Enron's preferred stock. In the PGC Merger,
each share of common stock, par value $3.75 per share, of
PGC issued and outstanding at the effective time of the PGC
Merger will be converted into one share of New Enron Common
Stock (subject to adjustment in certain circumstances). The
Merger Agreement provides that if certain regulatory reforms
are enacted, the structure of the transactions contemplated
by the Merger Agreement will be revised to eliminate the
Reincorporation Merger.
At the Special Meeting on November 12, 1996, 75% of the
Enron voting stock was voted in favor of the Merger
Agreement. The merger remains conditioned, among other
things, upon the completion of regulatory procedures and
approvals from the Oregon Public Utilities Commission,
consistent with certain conditions in the Merger Agreement.
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER 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.
[Download Table]
1996 1995
High Low Dividends High Low Dividends
First Quarter............. 40 34 5/8 $.2125 34 28 $.20
Second Quarter............ 42 3/8 36 3/8 .2125 36 7/8 32 1/2 .20
Third Quarter............. 43 39 1/8 .2125 36 3/8 31 5/8 .20
Fourth Quarter............ 47 1/2 40 1/4 .2250 39 3/8 33 .2125
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.
[Download Table]
1996 1995
High Low Dividends High Low Dividends
First Quarter............. $496 1/2 $481 1/4 $2.901 $398 $393 $2.7304
Second Quarter............ 525 525 2.901 491 454 2.7304
Third Quarter............. 525 525 2.901 477 454 2.7304
Fourth Quarter............ 620 555 3.072 502 462 2.901
At December 31, 1996, there were approximately 26,300 record
holders of common stock and 228 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 1991-1996.
[Enlarge/Download Table]
Item 6. SELECTED FINANCIAL DATA (UNAUDITED)
1996 1995 1994 1993 1992 1991
Operating Revenues (millions) $13,289 $ 9,189 $ 8,984 $ 7,986 $ 6,415 $ 5,698
Total Assets (millions) $16,137 $13,239 $11,966 $11,504 $10,312 $10,070
Common Stock Statistics
Income from continuing operations(a)
Total (millions) $584 $520 $453 $387 $329 $232
Per share - primary $2.31 $2.07 $1.80 $1.55 $1.39 $1.03
Per share - fully diluted $2.16 $1.94 $1.70 $1.46 $1.30 $0.98
Earnings on common stock(a)
Total (millions) $568 $504 $438 $370 $284 $207
Per share - primary $2.31 $2.07 $1.80 $1.55 $1.29 $1.03
Per share - fully diluted $2.16 $1.94 $1.70 $1.46 $1.21 $0.98
Dividends
Total (millions) $212 $205 $192 $171 $148 $127
Per share $0.86 $0.81 $0.76 $0.71 $0.66 $0.63
Shares outstanding (millions)
Actual at year-end 251 245 244 242 237 202
Average for the year 246 244 243 239 220 202
Capitalization (millions)
Long-term debt $3,349 $3,065 $2,805 $2,661 $2,459 $3,109
Preferred stock of subsidiary 592 377 377 214 - -
Minority interest 755 549 290 196 179 101
Shareholders' equity 3,723 3,165 2,880 2,623 2,518 1,901
Total capitalization $8,419 $7,156 $6,352 $5,694 $5,156 $5,111
<FN>
(a) The 1993 amounts exclude effects of a $54 million ($0.23 per share)
primarily non-cash charge to income for the increase in the corporate
Federal income tax rate from 34% to 35%.
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 1996 was $584 million compared to $520
million in 1995 and $453 million in 1994. Net income for all
three years reflects improved income before interest, minority
interests and income taxes as compared to the applicable
preceding year, partially offset by higher minority interests.
Primary earnings per share of common stock was $2.31 in 1996
as compared to $2.07 in 1995 and $1.80 in 1994.
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:
[Download Table]
(In Millions) 1996 1995 1994
Transportation and Operation $ 570 $ 359 $403
Domestic Gas and Power Services 280 157 202
International Operations and Development 152 142 148
Exploration and Production 200 241 198
Corporate and Other 36 266 (7)
Total $1,238 $1,165 $944
Transportation and Operation
The transportation and operation segment is comprised of the
Enron Gas Pipeline Group, which includes results of Northern
Natural Gas Company (Northern), Transwestern Pipeline Company
(Transwestern) and Enron's 50% interest in Florida Gas
Transmission Company (Florida Gas); and Enron Ventures Corp.,
which includes results of Enron Engineering & Construction and
the operation of clean fuels plants. Results from Enron's
investment in crude oil marketing and transportation operations
conducted by EOTT Energy Partners, L.P. (EOTT) are also included
in this segment.
The transportation and operation segment's IBIT increased $211
million in 1996 as compared to 1995 due to higher earnings from
the Enron Gas Pipeline Group, increased equity earnings from EOTT
and an increase in gains from the sale of non-strategic gas
gathering and processing assets ($94 million in 1996 compared
with $67 million in 1995). IBIT decreased in 1995 as compared to
1994 primarily as a result of lower earnings from the Enron Gas
Pipeline Group, primarily due to charges in 1995 of $83 million
related to regulatory reserves and other contingencies, and lower
equity earnings from EOTT following a $19 million charge to
reflect the discontinuance of EOTT's West Coast processing and
asphalt marketing operations, partially offset by the gains of
$67 million from the sale of non-strategic gathering and
processing assets. The following discussion analyzes the
significant changes in the various components of IBIT for this
segment:
[Download Table]
(In Millions) 1996 1995 1994
Revenues
Enron Gas Pipeline Group $760 $787 $901
Enron Ventures Corp. 46 44 47
EOTT - - 28
Total Revenues 806 831 976
Cost of gas and other products 4 41 72
Operating expenses 301 361 442
Depreciation and amortization 82 83 88
Taxes, other than income taxes 52 47 47
Equity in earnings of unconsolidated
subsidiaries 47 23 49
Other income, net 156 37 27
Income before interest, minority
interests and income taxes $570 $359 $403
Revenues
Enron Gas Pipeline Group. Revenues of the interstate natural
gas pipelines declined $27 million (3%) during 1996 and $114
million (13%) during 1995 as compared to the applicable preceding
year. The decrease in revenues from 1995 to 1996 was primarily a
result of the sale of gathering facilities in 1995 and the first
quarter of 1996 and reduced sales revenue 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. The
decrease in revenues from 1994 to 1995 primarily reflects
completion of the recovery of certain transition costs by
Northern. Transport revenues were virtually unchanged in 1996
after declining 9% in 1995 as compared to the prior year.
Transport volumes for Northern and Transwestern totaled 5.9
trillion British thermal units per day (TBtu/d) in 1996, 5.6
TBtu/d in 1995 and 5.5 TBtu/d in 1994. Higher revenues from
increased transport volumes were more than offset by the
reduction in average transport rates due in part to the reduction
of certain transition cost recoveries.
EOTT. Net revenues from EOTT decreased $28 million in 1995
as a result of the reduced ownership interest effective in March
1994. See Note 8 to the Consolidated Financial Statements.
Cost of Gas and Other Products Sold
The cost of gas and other products sold by the transportation
and operation segment decreased by $37 million (90%) during 1996
as compared to 1995 and $31 million (43%) during 1995 as compared
to 1994 primarily as a result of decreased gas purchases
following the termination of the merchant function by Northern.
Operating Expenses
Operating expenses of the transportation and operation segment
declined $60 million (17%) during 1996 and $81 million (18%)
during 1995. The 1996 decline primarily reflects lower operating
expenses on the interstate pipelines primarily as a result of
favorable resolution of environmental contingencies previously
accrued, combined with reduced expenses related to gathering
facilities sold during 1995 and the first quarter of 1996 and a
decrease in amortization of deferred contract reformation costs
by Northern. The 1995 decline primarily reflects a decrease of
$64 million in amortization of deferred contract reformation
costs due to the completion by Northern of the recovery of
certain transition costs in early 1995, combined with lower
transmission, compression and storage transition costs.
Additionally, operating expenses decreased as a result of the
decreased ownership interest in EOTT. These declines were
partially offset by $39 million in regulatory and contingency
adjustments in 1995.
Other Income and Deductions
Equity in earnings of unconsolidated subsidiaries increased by
$24 million to $47 million during 1996 as compared to 1995 after
decreasing by $26 million (53%) during 1995 as compared to 1994.
Earnings from EOTT increased to $9 million in 1996 compared with
a loss of $23 million in 1995, which included a $19 million
charge to reflect the discontinuance of EOTT's West Coast
processing and asphalt marketing operations in 1995. The
increase in equity earnings in 1996 was partially offset by
decreased earnings from Enron's interest in Trailblazer Pipeline
Company due to the recognition in 1995 of income from a
settlement with a transportation customer.
Other income, net, of $156 million was realized in 1996 as
compared to $37 million in 1995 and $27 million in 1994. The
1996 amount includes $94 million in gains related to the
disposition of non-strategic natural gas gathering facilities and
$18 million of income from the favorable resolution of
litigation. The 1995 amount includes $67 million in gains from
the sale of gathering assets and a processing facility, partially
offset by $42 million in regulatory and contingency adjustments.
Outlook
The transportation and operation segment should continue to
provide stable earnings and cash flows during 1997. Various
expansion projects underway or proposed by the Enron Gas Pipeline
Group should enhance future earnings when completed. Northern
filed with the FERC for an expansion project that will increase
peak day firm transportation service into the U.S. upper midwest
markets by approximately 350 million cubic feet of gas per day
(MMcf/d) over the next five years. Additionally, Enron Gas
Pipeline Group will continue to concentrate on reducing its
overall cost structure and Enron Ventures Corp. will actively
promote engineering and construction services to provide
incremental earnings.
During the first quarter of 1997, Enron completed sales of the
stock of Enron Liquids Pipeline Company, the general partner and
15% owner and operator of Enron Liquids Pipeline, L.P., and the
stock of Enron Louisiana Energy Company. Also during the first
quarter of 1997, Enron announced that it had agreed to sell its
Bushton, Kansas natural gas processing facility and its Hugoton
Basin gathering assets in Kansas. This transaction is expected
to close during the first half of 1997.
Domestic Gas and Power Services
The domestic gas and power activities are conducted primarily
by Enron Capital & Trade Resources (ECT) and include the
marketing, purchasing and financing of natural gas, natural gas
liquids, crude oil, electricity and other energy commodities and
the management of the portfolio of commitments arising from these
activities. In addition, Enron Energy Services has been created
to serve the retail natural gas and electricity markets.
ECT's services can be categorized into three business lines:
Cash and Physical, Risk Management and Finance. The following
table reflects IBIT for each business line:
[Download Table]
(In Millions) 1996 1995 1994
Cash and Physical $243 $146 $170
Risk Management 105 193 151
Finance 77 31 13
Unallocated expenses (145) (138) (132)
Total before non-recurring charge 280 232 202
Charge for clean fuels plant operations - (75) -
Total $280 $157 $202
The following discussion analyzes the contributions to IBIT
and the outlook for each of the business lines.
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 ECT's
contract portfolio and earnings related to the physical assets of
ECT. Also included in this line of business are the effects of
actual settlements of ECT's long-term physical and notional
quantity based contracts.
ECT markets a substantial quantity of energy commodities as
reflected in the following table (including intercompany
amounts):
[Download Table]
1996 1995 1994
Natural gas and crude oil
Physical/notional quantities (BBtue/d)(a)
Firm(b) 6,435 5,392 4,895
Interruptible 2,578 2,255 2,039
Transport volumes 544 580 538
Subtotal 9,557 8,227 7,472
Financial settlements (notional) 35,259 32,938 16,459
Total 44,816 41,165 23,931
Electricity (Thousand megawatt hours)
Owned production 3,122 3,441 3,481
Transaction volumes marketed 60,150 7,767 1,221
<FN>
(a) Billion British thermal units equivalent per day.
(b) Commitments to deliver a specified volume of gas at a fixed
or market responsive price.
The earnings from this business increased 66% in 1996
primarily due to earnings from higher natural gas volumes and
margins and increased earnings from the management of ECT's
portfolio of contracts. 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 ECT continued to expand its role as an electricity marketer.
The earnings from cash and physical operations decreased 14%
in 1995 as compared to 1994 as a result of lower margins in
liquids marketing and an increase in clean fuels operating
expenses. Earnings from the marketing of physical natural gas
also declined in 1995 as compared to 1994 due to lower margins in
all but the fourth quarter. Partially offsetting these declines
in earnings were increased earnings from electricity marketing,
the sale of certain physical assets and the management of ECT's
contract portfolio.
During 1997, ECT anticipates continued growth in the cash and
physical business over the 1996 results. The existence of its
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. Continued seasonal
volatility of natural gas prices will provide additional
opportunities for increased earnings.
Risk Management. ECT's risk management operations consist of
long-term energy commodity contracts (transactions greater than
one year). ECT originates new contracts for customers in the
energy industry and evaluates and restructures its existing
contracts on an on-going basis to develop additional products and
services to meet its customers' changing needs. Fixed price
contract market activity totaled 3,671 trillion British thermal
units equivalent (TBtue), 5,952 TBtue and 6,615 TBtue for 1996,
1995 and 1994, respectively.
Earnings from this business decreased 46% in 1996 as compared
to 1995 primarily due to lower originations from long-term
contracts with utilities and independent power producers (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.
Earnings from risk management increased 28% in 1995 as
compared to 1994 due primarily to earnings related to the
restructuring of existing long-term contracts with IPPs and local
distribution companies. Growth in originations from the Canadian
operations also contributed to the earnings increase. For 1995,
originations with utilities were lower than in 1994.
ECT expects earnings from risk management to increase in 1997
as compared to 1996 as it continues to pursue opportunities in
the European marketplace and continues to increase integration of
financial products and its energy commodity portfolio, resulting
in highly structured transactions.
Finance. ECT's finance operations provide a variety of
capital products to the energy sector including volumetric
production payments, loans and equity investments. These
products are offered by ECT directly or through ECT ventures such
as Joint Energy Development Investments Limited Partnership
(JEDI). JEDI is a limited partnership 50% owned by Enron which
was formed to acquire and own energy investments. Financings
arranged and production payments were $755 million, $382 million
and $503 million in 1996, 1995 and 1994, respectively.
Earnings from the finance operations increased 148% in 1996
compared to 1995 primarily due to increased earnings from its
equity investment in JEDI, which benefited from favorable
conditions in the equity markets.
Earnings from the finance operations increased 138% in 1995
compared with 1994 due primarily to the partial sale of ECT's
interests in certain equity investments and earnings associated
with the restructuring of long-term gas supply contracts with an
IPP. This was partially offset by lower earnings from production
payments arranged.
In 1997, ECT will continue to expand its products and services
in its role as a full-service provider of various types of
capital. In addition, earnings are expected from equity-based
investments which are carried by JEDI at fair value and are
therefore subject to market fluctuations.
Unallocated Expenses. ECT's net unallocated expenses such as
rent, systems expenses and other support group costs increased in
both 1996 and 1995 due to continued expansion into new markets
and system upgrades. ECT expects its unallocated expenses to
increase during 1997 as it continues to expand into new markets.
Charge for Clean Fuels Plant Operations. During the fourth
quarter of 1995, ECT provided for expected losses of $75 million
on its clean fuels plant operations resulting from higher natural
gas prices and lower MTBE prices because of soft demand for MTBE.
International Operations and Development
Enron's international operations and development activities
are conducted by Enron International (EI). Such activities
include the development of power, pipeline and other energy
infrastructure in emerging markets. Additionally, EI manages and
operates the projects once commercial operation has been
achieved. The segment includes results of Enron Global Power &
Pipelines L.L.C. (EPP) and Enron Americas, Inc. IBIT for this
group totaled $152 million in 1996, $142 million during 1995 and
$148 million in 1994. The following discussion analyzes the
significant changes in the various components of IBIT for this
segment.
Net Revenues
Revenues net of cost of sales for the international operations
and development segment decreased by $55 million (27%) in 1996 as
compared to 1995 after increasing $32 million (19%) during 1995.
The decline in net revenues in 1996 primarily reflects the
inclusion in 1995 of $48 million of revenues realized as a result
of the satisfaction of Enron's support obligations related to the
formation of EPP as well as the effect of transferring certain
liquids marketing operations to the domestic gas and power
services segment in January 1996. In addition to revenues from
asset management and operations and international development
activities, net revenues in 1996 included $31 million from the
promotion of a portion of Enron's interest in its power assets at
Teesside in the United Kingdom, compared with $24 million and $28
million recognized on similar transactions related to power and
liquids processing assets at Teesside in 1995 and 1994,
respectively. The increase in net revenues in 1995 primarily
reflects marketing revenues and increased international
development and asset management revenues, partially offset by
lower revenues recognized in connection with the formation of
EPP.
Costs and Expenses
Operating expenses for this segment decreased $26 million
(27%) during 1996 after increasing $16 million (21%) during 1995.
The decrease in 1996 was primarily due to the transfer of
marketing operations previously discussed, partially offset by
increased international activities. The increase in 1995 was
primarily a result of higher operating expenses incurred in
connection with increased activities in the power operations
area.
Depreciation expense of this segment decreased $12 million
(44%) in 1996 as compared to 1995 primarily due to the transfer
of marketing operations. Depreciation expense increased $12
million (80%) during 1995 as compared to 1994 as a result of
increased international project activities.
Other Income and Deductions
Equity in earnings of unconsolidated subsidiaries of the
international operations and development segment increased $26
million to $84 million in 1996, primarily as a result of
increased earnings from Teesside and international power and
pipeline projects which became operational in 1996. Equity in
earnings of unconsolidated subsidiaries increased $13 million
(29%) during 1995 as compared to 1994 primarily as a result of
increased earnings from Teesside and improved results from Enron
Americas' Venezuelan manufacturing operations.
Other income, net, was $10 million in 1996, $9 million in 1995
and $30 million in 1994. The 1994 amount included foreign
currency gains realized by Enron Americas.
Outlook
The objective of EI is to develop, finance, own and operate
integrated energy projects in emerging markets through the
utilization of Enron's extensive portfolio of products and
services. Growth opportunities in the emerging international
markets are expected to result from the current and projected
demand for energy infrastructure and merchant, finance and risk
management services.
Exploration and Production
Enron's exploration and production operations are conducted by
Enron Oil & Gas Company (EOG). IBIT of the exploration and
production segment totaled $200 million during 1996 as compared
to $241 million during 1995 and $198 million during 1994.
Wellhead volume and price statistics (including intercompany
amounts) are as follows:
[Download Table]
1996 1995 1994
Natural gas volumes (MMcf/d)(a)
North America(b) 706 636 686
Trinidad 124 107 63
Total 830 743 749
Average natural gas prices ($/Mcf)
North America(c) $1.92 $1.34 $1.68
Trinidad 1.00 0.97 0.93
Composite 1.78 1.29 1.62
Crude oil/condensate volumes (MBbl/d)(a)
North America 11.6 11.5 10.0
Trinidad 5.2 5.1 2.5
India 2.8 2.5 0.1
Total 19.6 19.1 12.6
Average crude oil/condensate prices ($/Bbl)
North America $21.08 $17.09 $15.65
Trinidad 19.76 16.07 15.50
India 20.17 16.81 15.70
Composite 20.60 16.78 15.62
<FN>
(a) Million cubic feet per day or thousand barrels per day, as
applicable.
(b) Includes an annual average of 48 MMcf/d in 1996, 1995 and
1994 delivered under the terms of a volumetric production
payment agreement effective October 1, 1992, as amended.
(c) Includes an average equivalent wellhead value of $1.17 per
Mcf in 1996, $0.80 per Mcf in 1995 and $1.27 per Mcf in 1994
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 the exploration and production segment:
[Download Table]
(In Millions) 1996 1995 1994
Net revenues $726 $693 $661
Operating expenses 133 126 112
Exploration expenses 89 79 84
Depreciation, depletion and
amortization 251 216 242
Taxes, other than income taxes 48 32 28
Operating income 205 240 195
Other income, net (5) 1 3
IBIT $200 $241 $198
Net Revenues
The exploration and production segment's revenues net of gas
sold in connection with natural gas marketing increased $33
million (5%) in 1996 and $32 million (5%) in 1995. The 1996
increase was primarily as a result of increased wellhead natural
gas prices and volumes. These volumes increased primarily as a
result of eliminating 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, provided
$4 million in net revenues in 1996, compared with $105 million in
1995.
During 1995, the impact of reduced wellhead natural gas prices
and volumes, due primarily to voluntary curtailments of wellhead
natural gas volumes, was more than offset by increased earnings
from other marketing activities. Wellhead crude oil and
condensate average prices and volumes increased in 1995,
primarily reflecting new production onstream offshore India and
higher volumes offshore Trinidad and in North America. Other
marketing activities provided $105 million in net revenues in
1995, compared with $50 million in 1994.
Hedges placed by Enron on commodity positions not hedged by
EOG resulted in a loss of $4 million in 1996 compared with gains
of $45 million in 1995 and $35 million in 1994. Net revenues also
include gains on sales of oil and gas reserves and related assets
of $20 million in 1996, $63 million in 1995 and $54 million in
1994.
Costs and Expenses
Operating expense, depreciation, depletion and amortization
(DD&A) and taxes other than income taxes increased in 1996 due
primarily to the increased production activity. Operating
expenses and taxes other than income taxes were higher in 1995
compared to 1994 due to international production activity, while
DD&A declined in that period due to the decline in North America
volumes, which have a higher DD&A rate.
Outlook
EOG plans to continue to focus a substantial portion of its
development and certain exploration expenditures in its major
producing areas in North America. However, EOG anticipates
spending an increasing part of its available funds in the further
development of opportunities in India, Venezuela and Trinidad.
In addition, EOG will continue limited exploratory expenditures
in new areas outside of North America.
Corporate and Other
The corporate and other segment's IBIT was $36 million in 1996
and $266 million in 1995 as compared to expense of $7 million in
1994. Results from this segment in 1996 and 1995 reflect income
of $178 million and $367 million, respectively, primarily related
to the sale of 12 million and 31 million outstanding shares of
EOG stock held by Enron, which reduced Enron's interest in EOG
from 80% to 53% (see Note 16 to the Consolidated Financial
Statements). In a separate transaction, Enron entered into a
total return equity swap on 7.8 million shares of EOG. The
effect of this transaction is to expose Enron to future changes
in EOG's market value related to the 7.8 million shares.
The 1996 results included an $83 million reserve related to the
required disposition of certain assets in connection with the
planned merger with Portland General Corporation. See
"Capitalization" below. The 1995 results also included amounts
recognized following the resolution of certain litigation,
partially offset by $74 million of charges primarily related to
the conversion of a compensation plan to more closely align
employees' interests to Enron common stock.
Interest and Related Charges, net
Interest and related charges, net, is shown on the
Consolidated Income Statement net of interest capitalized of $12
million, $10 million and $10 million during 1996, 1995 and 1994,
respectively. The net expense decreased $10 million in 1996
after increasing $11 million in 1995. The 1996 decrease was
primarily due to lower average interest rates combined with lower
average debt balances. The 1995 increase was primarily due to
higher debt levels and increased interest rates.
Dividends on Company-Obligated Preferred Stock of Subsidiaries
Dividends on company-obligated preferred stock of subsidiaries
increased from $20 million in 1994 to $32 million in 1995 and $34
million in 1996, primarily due to the issuance of $215 million of
additional preferred stock by Enron subsidiaries. See Note 9 to
the Consolidated Financial Statements.
Minority Interests
Minority interests increased $31 million in 1996 compared to
1995, primarily due to the reduction of Enron's interest in EOG
from 80% in late 1995 to 53% in December 1996 following the sales
in 1996 and December 1995 of an aggregate 43 million shares of
EOG common stock held by Enron. Minority interests increased $13
million during 1995 as compared to 1994 primarily as a result of
the sale in the fourth quarter of 1994 of approximately 48% of
Enron's interest in EPP.
Income Tax Expense
Income tax expense decreased during 1996 as compared to 1995
after increasing during 1995 as compared to 1994. The 1996
income tax provision includes benefits from the reduction of the
deferred income tax liability due to the reevaluation of Federal
and state deferred tax requirements. Income tax expense
increased during 1995 compared to the prior year due to increased
pretax income, a decrease in tight gas sand Federal tax credits
and the higher effective tax rate on the sale of EOG shares by
Enron in 1995.
FINANCIAL CONDITION
[Download Table]
Cash Flows
(In Millions) 1996 1995 1994
Cash provided by (used in):
Operating activities $ 1,040 $(15) $ 460
Investing activities (1,230) 13 (560)
Financing activities 331 (15) 92
Net 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 at year end 1996 as compared to
1995. Cash from operating activities declined during 1995 as a
result of increased working capital requirements. The change in
working capital requirements in 1995 primarily reflects a higher
level of year-end receivables as a result of reduced sales of
receivables under Enron's receivables sales program and increased
customer receivables due to a higher level of year-end activity.
The impact of higher receivables was partially offset by
increased year-end trade payables.
Net cash used in investing activities in 1996 reflects equity
investments of $761 million and property additions of $855
million. Equity investments in 1996 primarily include
investments in international power and pipeline projects, EOTT
and 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. Net cash provided by investing activities in
1995 reflects proceeds from asset sales of $996 million largely
offset by property additions of $731 million and equity
investments of $170 million. Asset sales during 1995 included
the sale of 31 million shares of EOG common stock held by Enron
as well as sales of oil and gas properties and non-strategic
processing and gathering assets. Equity investments primarily
include investments in international power and pipeline projects
and in JEDI.
Primary cash inflows from financing activities during 1996
included $576 million from the issuance of short- and long-term
debt, $215 million from the issuance of preferred stock by
subsidiary companies and $102 million from the issuance of Enron
common stock. Cash outflows included $294 million for the
repayment of debt combined with cash dividend payments of $281
million. During 1995 cash inflows from the issuance of long-term
debt totaled $967 million. These inflows were more than offset
by a $698 million decrease in combined short- and long-term debt,
cash dividend payments of $254 million and a net $64 million
repurchase of Enron Corp. common stock under the terms of Enron's
stock repurchase authorization.
Working Capital
At December 31, 1996, Enron had working capital of $271
million. Should a working capital deficit occur, Enron would be
able to fund such a deficit through the utilization of credit
facilities which, at December 31, 1996, provided for up to $1.9
billion of committed and uncommitted credit, of which $191
million was outstanding at December 31, 1996. 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
Capital expenditures by operating segment are detailed as
follows:
[Download Table]
1997
(In Millions) Estimate 1996 1995 1994
Transportation and Operation $260 $187 $129 $125
Domestic Gas and Power Services 140 112 118 83
International Operations and
Development 10 33 58 14
Exploration and Production(a) 500 540 464 442
Corporate and Other 30 6 8 5
Total $940 $878 $777 $669
<FN>
(a) Excludes exploration expenses of $100 million (estimate),
$68 million, $55 million and $59 million for 1997, 1996, 1995
and 1994, respectively.
Capital expenditures increased $101 million during 1996 as
compared to 1995 primarily as a result of increased expenditures
in the exploration and production segment reflecting increased
development expenditures in the United States and India,
partially offset by reduced development expenditures in Trinidad.
Capital expenditures during 1997 are expected to total
approximately $940 million. However, the overall level of
capital spending as well as spending by individual business
segments will vary depending upon conditions in the energy
markets and other related economic conditions. In addition,
equity investments are expected to be approximately $660 million,
primarily relating to equity financing activities by ECT and
expenditures in the international segment in connection with
power and pipeline projects. Management believes that the
capital spending program will be funded by a combination of
internally generated funds, proceeds from dispositions of
selected assets and long- and short-term borrowings.
Capitalization
Total capitalization at December 31, 1996 was $8.4 billion.
Debt as a percentage of total capitalization decreased to 39.8%
at December 31, 1996 as compared to 42.8% at December 31, 1995.
The improvement primarily reflects increased retained earnings.
Assuming the mandatory 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 37.8% at
December 31, 1996.
Enron has signed an agreement to merge with Portland General
Corporation (PGC) in a stock-for-stock transaction. Enron
proposes to issue approximately 51 million common shares to
shareholders of PGC in a one for one exchange of shares, as a
result of which Enron will be the surviving corporation. The
merger is conditioned, among other things, upon securing certain
regulatory approvals. See Note 2 to the Consolidated Financial
Statements.
INFORMATION REGARDING
FORWARD LOOKING STATEMENTS
This Annual Report includes forward looking statements within
the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Although
Enron believes that its expectations are based on reasonable
assumptions, it can give no assurance that its goals will be
achieved. Important factors that could cause actual results to
differ materially from those in the forward looking statements
herein include political developments in foreign countries, the
pace of deregulation of retail natural gas and electricity
markets in the United States, 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 Stockholders to be
held on May 6, 1997 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 1996, its executive officers, directors and
greater than 10% stockholders complied with all
applicable filing requirements.
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 Stockholders, 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 1996; Aggregated Stock Option/SAR
Exercises During 1996 and Stock Option/SAR Values as of
December 31, 1996; Long-Term Incentive Plan - Awards in
1996; 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, 1997",
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 "Compensation of Directors and
Executive Officers - 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 - Restated Certificate of Incorporation of
Enron Corp., as amended (Exhibit 3.01 to
Enron Form 10-K for 1994, File No. 1-3423).
*3.02 - Bylaws of Enron Corp. as currently in effect
(Exhibit 3.02 to Enron Form 10-K for 1995,
File No. 1-3423).
*3.03 - Amended and Restated Agreement and Plan of
Merger dated as of July 20, 1996 and
amended and restated as of September 24, 1996
among Enron, new Enron (Enron Oregon Corp.)
and Portland General Corporation (Exhibit 2.1
to Enron Form S-4 Registration Statement No.
333-13791 filed October 9, 1996).
*3.04 - Restated Articles of Incorporation of New Enron
(Exhibit 3.1 to Enron Form S-4 Registration
Statement No. 333-13791 filed October 9, 1996).
*3.05 - Form of Bylaws of New Enron (Exhibit 3.2 to
Enron Form S-4 Registration Statement
No. 333-13791 filed October 9, 1996).
*3.06 - Form of Series Designation for the New Enron
Convertible Preferred Stock (Exhibit
3.3 to Enron Form S-4 Registration Statement
No. 333-13791 filed October 9, 1996).
*3.07 - Form of Series Designation for the New Enron
9.142% Preferred Stock (Exhibit 3.4
to Enron Form S-4 Registration Statement No.
333-13791 filed October 9, 1996).
*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 - 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).
*4.03 - 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).
*4.04 - 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).
*4.05 - Articles of Association of Enron Capital LLC
(Exhibit 9 to Enron Corp. Form 8-K
dated November 12, 1993).
*4.06 - 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).
*4.07 - 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 10.64
*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.
*10.05 - Executive Incentive Plan (Exhibit 10.13 to
Enron Form 10-K for 1987, File No. 1-3423).
*10.06 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19
to Enron Form 10-K for 1987, File No. 1-3423).
*10.07 - First Amendment to Enron Corp. 1988 Deferral Plan
(Exhibit 10.06 to Enron Form 10-K for 1995,
File No. 1-3423).
*10.08 - Second Amendment to Enron Corp. 1988 Deferral Plan
(Exhibit 10.07 to Enron Form 10-K for 1995,
File No. 1-3423).
10.09 - Third Amendment to Enron Corp. 1988 Deferral Plan.
10.10 - Fourth Amendment to Enron Corp. 1988 Deferral Plan.
10.11 - Fifth Amendment to Enron Corp. 1988 Deferral Plan.
*10.12 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to
Enron Form 10-K for 1991, File No. 1-3423).
*10.13 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09
to Enron Form 10-K for 1991, File No. 1-3423).
*10.14 - First Amendment to Enron Corp. 1992 Deferral Plan
(Exhibit 10.10 to Enron Form 10-K for 1995,
File No. 1-3423).
*10.15 - Second Amendment to Enron Corp. 1992 Deferral Plan
(Exhibit 10.11 to Enron Form 10-K for 1995,
File No. 1-3423).
*10.16 - Enron Corp. Directors' Deferred Income Plan
(Exhibit 10.09 to Enron Form 10-K for 1992,
File No. 1-3423).
*10.17 - Employment Agreement between Enron and
Kenneth L. Lay dated as of September 1, 1989
(Exhibit 10.12 to Enron Form 10-K for 1989,
File No. 1-3423).
*10.18 - First Amendment to Employment Agreement between
Enron and Kenneth L. Lay, dated August 21, 1990
(Exhibit 10.11 to Enron Form 10-K for 1993).
*10.19 - Second Amendment to Employment Agreement between
Enron and Kenneth L. Lay, dated March 5, 1992
(Exhibit 10.12 to Enron Form 10-K for 1993).
*10.20 - Third Amendment to Employment Agreement between
Enron and Kenneth L. Lay, dated August 10, 1993
(Exhibit 10.13 to Enron Form 10-K for 1993).
*10.21 - Fourth Amendment to Employment Agreement between
Enron and Kenneth L. Lay, dated October 15, 1993
(Exhibit 10.14 to Enron Form 10-K for 1993).
*10.22 - Fifth Amendment to Employment Agreement between
Enron and Kenneth L. Lay, dated February 28, 1994
(Exhibit 10.15 to Enron Form 10-K for 1993).
*10.23 - Sixth Amendment to Employment Agreement between
Enron and Kenneth L. Lay, dated April 27, 1994
(Exhibit 10.16 to Enron Form 10-K for 1994).
*10.24 - Split Dollar Life Insurance Agreement between
Enron and the KLL and LPL Family Partnership, Ltd.,
dated April 22, 1994 (Exhibit 10.17 to Enron
Form 10-K for 1994).
10.25 - Employment Agreement between Enron Corp. and
Kenneth L. Lay, executed December 18, 1996.
*10.26 - Employment Agreement between Enron and
Richard D. Kinder dated as of September 1, 1989
(Exhibit 10.14 to Enron Form 10-K for 1989,
File No. 1-3423).
*10.27 - First Amendment to Employment Agreement between
Enron and Richard D. Kinder dated August 13, 1990
(Exhibit 10.17 to Enron Form 10-K for 1991,
File No. 1-3423).
*10.28 - Second Amendment to Employment Agreement between
Enron and Richard D. Kinder dated September 10, 1991
(Exhibit 10.18 to Enron Form 10-K for 1991,
File No. 1-3423).
*10.29 - Third Amendment to Employment Agreement between
Enron and Richard D. Kinder dated March 5, 1992
(Exhibit 10.19 to Enron Form 10-K for 1992,
File No. 1-3423).
*10.30 - Fourth Amendment to Employment Agreement between
Enron and Richard D. Kinder dated August 16, 1993
(Exhibit 10.20 to Enron Form 10-K for 1993).
*10.31 - Fifth Amendment to Employment Agreement between
Enron and Richard D. Kinder, dated October 15, 1993
(Exhibit 10.21 to Enron Form 10-K for 1993).
*10.32 - Sixth Amendment to Employment Agreement between
Enron and Richard D. Kinder, dated February 28, 1994
(Exhibit 10.22 to Enron Form 10-K for 1993).
*10.33 - Seventh Amendment to Employment Agreement between
Enron and Richard D. Kinder, dated November 30, 1994
(Exhibit 10.25 to Enron Form 10-K for 1994).
10.34 - Agreement dated November 25, 1996, between Enron
and Richard D. Kinder.
*10.35 - Employment Agreement between Enron International Inc.
and Rodney L. Gray, dated as of July 1, 1993
(Exhibit 10.23 to Enron Form 10-K for 1993).
*10.36 - First Amendment to Employment Agreement between
Enron International Inc. and Rodney L. Gray,
dated May 2, 1994 (Exhibit 10.27 to Enron
Form 10-K for 1994).
*10.37 - Second Amendment to Employment Agreement between
Enron International Inc. and Rodney L. Gray,
dated as of January 1, 1995 (Exhibit 10.31 to
Enron Form 10-K for 1995, File No. 1-3423).
*10.38 - 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).
*10.39 - 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).
*10.40 - 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).
*10.41 - 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).
*10.42 - 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).
*10.43 - 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).
*10.44 - Employment Agreement between Enron and
Edmund P. Segner, III dated October 1, 1991
(Exhibit 10.24 to Enron Form 10-K for 1991,
File No. 1-3423).
*10.45 - First Amendment to Employment Agreement between
Enron and Edmund P. Segner, III dated
February 12, 1993 (Exhibit 10.28 to
Enron Form 10-K for 1992, File No. 1-3423).
*10.46 - Second Amendment to Employment Agreement between
Enron and Edmund P. Segner, III, dated May 2, 1994
(Exhibit 10.39 to Enron Form 10-K for 1994).
*10.47 - 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).
*10.48 - 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).
*10.49 - Enron Corp. Performance Unit Plan (Exhibit A to
Enron Proxy Statement filed pursuant to Section 14(a)
on March 25, 1994).
*10.50 - Enron Corp. Annual Incentive Plan (Exhibit B to
Enron Proxy Statement filed pursuant to Section 14(a)
on March 25, 1994).
*10.51 - 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).
*10.52 - First Amendment to Enron Corp. Performance Unit Plan
(Exhibit 10.46 to Enron Form 10-K for 1995,
File No. 1-3423).
*10.53 - Form of Enron Corp. 1994 Deferral Plan
(Exhibit 10.59 to Enron Form 10-K for 1994).
*10.54 - First Amendment to Enron Corp. 1994 Deferral Plan
(Exhibit 10.48 to Enron Form 10-K for 1995,
File No. 1-3423).
*10.55 - Second Amendment to Enron Corp. 1994 Deferral Plan
(Exhibit 10.49 to Enron Form 10-K for 1995,
File No. 1-3423).
10.56 - Third Amendment to Enron Corp. 1994 Deferral Plan.
10.57 - Fourth Amendment to Enron Corp. 1994 Deferral Plan.
10.58 - Fifth Amendment to Enron Corp. 1994 Deferral Plan.
10.59 - Employment Agreement between Enron Power Corp.
and Thomas E. White dated July 1, 1990.
10.60 - First Amendment, dated September 9, 1991,
to Employment Agreement between Enron Power
Corp. and Thomas E. White dated July 1, 1990.
10.61 - Second Amendment, dated May 2, 1994, to
Employment Agreement between Enron Power
Corp. and Thomas E. White dated July 1, 1990.
10.62 - Third Amendment, dated January 3, 1997, to
Employment Agreement between Enron Power Corp.
and Thomas E. White dated July 1, 1990.
10.63 - Employment Agreement between Enron Capital
Trade & Resources Corp. and Jeffrey K. Skilling,
dated January 1, 1996.
10.64 - 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.
11 - Statement re calculation of earnings per share.
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 17, 1997.
24 - Powers of Attorney for the officers and
directors signing this Form 10-K.
27 - Financial Data Schedule.
* Asterisk indicates exhibits incorporated by
reference as indicated.
(b) Reports on Form 8-K
No reports on Form 8-K were filed by Enron during
the last quarter of 1996.
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, 1996, 1995 and 1994 F-3
Consolidated Balance Sheet as of December 31, 1996
and 1995 F-4
Consolidated Statement of Cash Flows for the years
ended December 31, 1996, 1995 and 1994 F-6
Consolidated Statement of Changes in Shareholders'
Equity Accounts for the years ended December 31,
1996, 1995 and 1994 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. (a Delaware corporation) and subsidiaries as
of December 31, 1996 and 1995, and the related consolidated
statements of income, cash flows and changes in shareholders'
equity accounts for each of the three years in the period
ended December 31, 1996. 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 statemetns. An
audit also includes assessing the accounting principles used
and significant estimates made by management, as well as
evaluating the overall financial statement presentationl. 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, 1996 and 1995,
and the results of their operations, cash flows and changes in
shareholders' equity accounts for each of the three years in the
period ended December 31, 1996, in conformity with generally
accepted accounting principles.
Arthur Andersen LLP
Houston, Texas
February 17, 1997
[Download Table]
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENT
Year Ended December 31,
(In Millions, Except Per Share Amounts) 1996 1995 1994
Revenues
Natural gas, electricity and other
products $12,137 $7,708 $7,519
Transportation 707 692 754
Other 445 789 711
Total Revenues 13,289 9,189 8,984
Costs and Expenses
Cost of gas, electricity and
other products 10,478 6,733 6,517
Operating expenses 1,421 1,218 1,124
Oil and gas exploration expenses 89 79 84
Depreciation, depletion and
amortization 474 432 441
Taxes, other than income taxes 137 109 102
Total Costs and Expenses 12,599 8,571 8,268
Operating Income 690 618 716
Other Income and Deductions
Equity in earnings of unconsolidated
subsidiaries 215 86 112
Other income, net 333 461 116
Income Before Interest, Minority
Interests and Income Taxes 1,238 1,165 944
Interest and Related Charges, net 274 284 273
Dividends on Company-Obligated Preferred
Stock of Subsidiaries 34 32 20
Minority Interests 75 44 31
Income Taxes 271 285 167
Net Income 584 520 453
Preferred Stock Dividends 16 16 15
Earnings on Common Stock $ 568 $ 504 $ 438
Earnings Per Share of Common Stock
Primary $ 2.31 $ 2.07 $ 1.80
Fully Diluted $ 2.16 $ 1.94 $ 1.70
Average Number of Common Shares Used
in Primary Computation 246 244 243
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
[Download Table]
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31,
(In Millions) 1996 1995
ASSETS
Current Assets
Cash and cash equivalents $ 256 $ 115
Trade receivables (net of allowance
for doubtful accounts of $6 and
$12, respectively) 1,841 1,116
Other receivables 328 311
Transportation and exchange gas
receivable 86 150
Inventories 164 111
Assets from price risk management
activities 841 580
Other 463 344
Total Current Assets 3,979 2,727
Investments and Other Assets
Investments in and advances to
unconsolidated subsidiaries 1,701 1,217
Assets from price risk management
activities 1,632 1,197
Other 1,713 1,230
Total Investments and Other Assets 5,046 3,644
Property, Plant and Equipment, at cost
Transportation and operation 3,554 3,640
Domestic gas and power services 3,853 3,797
International operations and
development 104 182
Exploration and production, successful
efforts accounting 3,753 3,381
Corporate and other 84 107
11,348 11,107
Less accumulated depreciation,
depletion and amortization 4,236 4,239
Net Property, Plant and Equipment 7,112 6,868
Total Assets $16,137 $13,239
<FN>
The accompanying notes are an integral part of these
consolidated financial statements.
[Download Table]
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Millions, Except Per December 31,
Share Amounts and Shares) 1996 1995
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 1,955 $ 1,021
Transportation and exchange gas
payable 80 144
Accrued taxes 70 121
Accrued interest 56 52
Liabilities from price risk
management activities 1,029 708
Other 518 386
Total Current Liabilities 3,708 2,432
Long-Term Debt 3,349 3,065
Deferred Credits and Other Liabilities
Deferred income taxes 2,290 2,186
Liabilities from price risk
management activities 980 590
Other 740 875
Total Deferred Credits and
Other Liabilities 4,010 3,651
Commitments and Contingencies
(Notes 2, 3, 8, 13, 14 and 15)
Minority Interests 755 549
Company-Obligated Preferred Stock
of Subsidiaries 592 377
Shareholders' Equity
Preferred stock, cumulative, $100 par
value, 1,500,000 shares authorized,
no shares issued - -
Second preferred stock, cumulative, $1 par
value, 5,000,000 shares authorized,
1,370,714 shares and 1,375,494 shares
of Cumulative Second Preferred Convertible
Stock issued, respectively 137 138
Preference stock, cumulative, $1 par value,
10,000,000 shares authorized, no shares
issued - -
Common stock, $0.10 par value, 600,000,000
shares authorized, 255,945,304 shares and
253,860,360 shares issued, respectively 26 25
Additional paid-in capital 1,870 1,791
Retained earnings 2,007 1,651
Cumulative foreign currency translation
adjustment (127) (153)
Common stock held in treasury, 821,155
shares and 2,618,034 shares, respectively (30) (93)
Other (including Flexible Equity Trust) (160) (194)
Total Shareholders' Equity 3,723 3,165
Total Liabilities and Shareholders' Equity $16,137 $13,239
<FN>
The accompanying notes are an integral part of these
consolidated financial statements.
[Download Table]
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In Millions) 1996 1995 1994
Cash Flows From Operating Activities
Reconciliation of net income to net
cash provided by (used in) operating
activities
Net income $ 584 $ 520 $ 453
Depreciation, depletion and
amortization 474 432 441
Oil and gas exploration expenses 89 79 84
Deferred income taxes 207 216 93
Gains on sales of assets (274) (530) (91)
Regulatory, litigation and other
contingency adjustments 23 112 (25)
Changes in components of working
capital 142 (834) (142)
Net assets from price risk management
activities 15 (98) (153)
Amortization of production payment
transaction (43) (43) (43)
Other, net (177) 131 (157)
Net Cash Provided by (Used in) Operating
Activities 1,040 (15) 460
Cash Flows From Investing Activities
Proceeds from sales of investments and
other assets 477 996 440
Additions to property, plant and
equipment (855) (731) (661)
Equity investments (761) (170) (272)
Other, net (91) (82) (67)
Net Cash Provided by (Used in)
Investing Activities (1,230) 13 (560)
Cash Flows From Financing Activities
Net increase (decrease) in
short-term borrowings 217 (250) 115
Issuance of long-term debt 359 967 190
Repayment of long-term debt (294) (448) (162)
Issuance of company-obligated
preferred stock of subsidiaries 215 - 163
Issuance of common stock 102 20 67
Dividends paid (281) (254) (231)
Net acquisition (disposition) of
treasury stock 5 (64) (41)
Other, net 8 14 (9)
Net Cash Provided by (Used in)
Financing Activities 331 (15) 92
Increase (Decrease) in Cash and Cash
Equivalents 141 (17) (8)
Cash and Cash Equivalents, Beginning
of Year 115 132 140
Cash and Cash Equivalents, End of Year $ 256 $ 115 $ 132
Changes in Components of Working Capital
Receivables $ (678) $(639) $(250)
Inventories (53) 27 (25)
Payables 870 126 (92)
Accrued taxes (51) 30 12
Accrued interest 4 (7) 5
Other 50 (371) 208
Total $ 142 $(834) $(142)
<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
[Enlarge/Download Table]
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY ACCOUNTS
(Dollars in Millions, Except Per 1996 1995 1994
Share Amounts; Shares in Thousands) Shares Amount Shares Amount Shares Amount
Cumulative Second Preferred
Convertible Stock
Balance, beginning of year 1,375 $ 138 1,405 $ 141 1,497 $ 150
Exchange of common stock
for convertible preferred stock (4) (1) (30) (3) (92) (9)
Balance, end of year 1,371 $ 137 1,375 $ 138 1,405 $ 141
Common Stock
Balance, beginning of year 253,860 $ 25 253,070 $ 25 249,095 $ 25
Exchange of common stock
for convertible preferred stock 19 - 219 - 1,252 -
Issuances related to benefit
and dividend reinvestment plans - - 197 - 1,303 -
Sales of common stock 2,066 1 374 - 1,420 -
Balance, end of year 255,945 $ 26 253,860 $ 25 253,070 $ 25
Additional Paid-in Capital
Balance, beginning of year $1,791 $1,788 $1,708
Exchange of common stock
for convertible preferred stock (1) (3) 9
Issuances related to benefit
and dividend reinvestment plans (16) (5) 30
Sales of common stock 109 15 51
Other (13) (4) (10)
Balance, end of year $1,870 $1,791 $1,788
Retained Earnings
Balance, beginning of year $1,651 $1,351 $1,105
Net income 584 520 453
Cash dividends
Common stock ($0.8625, $0.8125
and $0.7625 per share, in 1996,
1995 and 1994, respectively) (212) (204) (192)
Preferred stock ($11.7750,
$11.0922 and $10.6054 per
share in 1996, 1995 and 1994,
respectively) (16) (16) (15)
Balance, end of year $2,007 $1,651 $1,351
Cumulative Foreign Currency
Translation Adjustment
Balance, beginning of year $ (153) $ (159) $ (139)
Translation adjustments 26 6 (20)
Balance, end of year $ (127) $ (153) $ (159)
Treasury Stock
Balance, beginning of year (2,618) $ (93) (1,395) $ (41) - $ -
Shares acquired (2,226) (85) (3,496) (118) (1,898) (56)
Exchange of common stock
for convertible preferred stock 46 2 183 5 - -
Issuances related to benefit
and dividend reinvestment plans 2,249 81 2,090 61 48 1
Sales of treasury stock 1,728 65 - - 455 14
Balance, end of year (821) $ (30) (2,618) $ (93) (1,395) $ (41)
Other
Balance, beginning of year $ (194) $ (225) $ (226)
Issuances related to benefit
and dividend reinvestment plans 34 30 1
Other - 1 -
Balance, end of year $ (160) $ (194) $ (225)
Total Shareholders' Equity $3,723 $3,165 $2,880
<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. Investments in unconsolidated subsidiaries are
accounted for by the equity method.
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. In
material respects, the businesses of Enron are conducted by Enron
Corp.'s subsidiaries and affiliates whose operations are managed
by their respective officers.
Cash Equivalents. Enron records as cash equivalents all
highly liquid short-term investments with original maturities of
three months or less.
Inventories. Inventories consisting primarily of natural gas
in storage of $73 million and $55 million and crude oil and
liquid petroleum products of $84 million and $50 million at
December 31, 1996 and 1995, respectively, are priced at the lower
of cost or market.
Depreciation, Depletion and Amortization. The provision for
depreciation and amortization with respect to operations other
than oil and gas producing activities (see below) is computed
using the straight-line or Federal Energy Regulatory Commission
(FERC) mandated method based on estimated economic lives.
Composite depreciation rates are applied to functional groups of
property having similar economic characteristics.
Provisions for depreciation, depletion and amortization of
proved oil and gas properties are calculated using the units-of-
production method. Estimated future dismantlement, restoration
and abandonment costs, net of salvage credits, are taken into
account in determining depreciation, depletion and amortization.
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. Primary earnings per share is computed on
the basis of the average number of common shares outstanding
during the periods. 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). Dilutive common stock
equivalents are not material and are not included in the
computation of primary earnings per share. Fully diluted
earnings per share is computed based upon the average number of
common stock and common stock equivalent shares outstanding plus
the average number of common shares issuable upon the assumed
conversion of convertible securities.
Accounting for Price Risk Management. Enron engages in price
risk management activities for both trading and non-trading
purposes. Activities for trading purposes, generally consisting
of services provided to the energy sector through Enron Capital &
Trade Resources (ECT), are accounted for using the mark-to-market
method. Under such method, changes in the market value of
outstanding financial instruments are recognized as gain or loss
in the period of change. 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.
Activities for non-trading purposes consist of transactions
entered into by Enron's other business units to hedge the impact
of market fluctuations on assets, liabilities, production or
other contractual commitments. Changes in the market value of
these transactions are deferred until the gain or loss on the
hedged item is recognized. 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. Under such
method, oil and gas lease acquisition costs are capitalized when
incurred. Unproved properties with significant acquisition costs
are assessed quarterly on a property-by-property basis and any
impairment in value is recognized. Amortization of any remaining
costs of such leases begins at a point prior to the end of the
lease term depending upon the length of such term. Unproved
properties with acquisition costs that are not individually
significant are aggregated, and the portion of such costs
estimated to be nonproductive, based on historical experience, is
amortized over the average holding period. If the unproved
properties are determined to be productive, the appropriate
related costs are transferred to proved oil and gas properties.
Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of
drilling exploratory wells, are charged to expense as incurred.
The costs of drilling exploratory wells are capitalized pending
determination of whether the wells have discovered proved
commercial reserves. If proved commercial reserves are not
discovered, such drilling costs are expensed. The costs of all
development wells and related equipment used in the production of
crude oil and natural gas are capitalized.
Gains and losses associated with the sale of crude oil and
natural gas reserves in place with related assets are classified
as "Other Revenues" in the Consolidated Income Statement.
Accounting for Development Activity. Enron's project
development costs consist of fees, licenses and permits, site
testing, bid costs and other charges, including salaries and
employee expenses, incurred in developing domestic and
international projects. These costs may be recovered through
development cost reimbursements from joint venture partners or
other third parties, written off against development fees
received, or may be included as part of an investment in those
ventures where Enron continues to participate. Accumulated costs
of project development are otherwise expensed in the period that
management determines it is probable that the costs will not be
recovered.
Development revenue results from Enron's participation in the
development, construction, operation and ownership of various
projects. Revenue from development fees is recognized when
realizable under the development agreement. Revenue from long-
term construction contracts is recognized using the percentage-of-
completion method and is primarily based on project costs
incurred compared with total estimated costs. Estimated contract
earnings are reviewed and revised periodically as the work
progresses. Development and construction revenues earned from
joint ventures in which Enron holds an equity interest are
deferred to the extent of Enron's ownership interest and
recognized over the life of the facility owned by the joint
venture on a straight-line basis. 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.
Foreign Currency Translation. For international subsidiaries,
asset and liability accounts are translated at year-end rates of
exchange and revenue and expenses are translated at average
exchange rates prevailing during the year. For subsidiaries
whose functional currency is deemed to be other than the U.S.
dollar, translation adjustments are included as a separate
component of shareholders' equity. Currency transaction gains
and losses are recorded in income.
Reclassifications. Certain reclassifications have been made
to the consolidated financial statements for prior years to
conform with the current presentation.
2 PROPOSED MERGER
Enron announced on July 22, 1996 that it had signed an
agreement to merge with Portland General Corporation (PGC) in a
stock-for-stock transaction. PGC is an electric utility holding
company, serving retail electric customers in northwest Oregon as
well as wholesale electricity customers throughout the western
United States. Enron proposes to issue approximately 51 million
common shares to shareholders of PGC in a one for one exchange of
shares, as a result of which Enron will be the surviving
corporation. Enron will consolidate PGC's debt of approximately
$1.1 billion and account for the transaction on a purchase
accounting basis.
In separate shareholder meetings held on November 12, 1996,
75% of the Enron common shares and 77% of PGC common shares were
voted in favor of the merger. The merger is conditioned, among
other things, upon securing regulatory approval from the
Oregon Public Utilities Commission (OPUC) consistent with certain
conditions in the Enron/PGC merger agreement. The FERC approved
the merger on February 26, 1997. A decision on Enron's merger
approval application pending before the OPUC is expected in 1997.
3 PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Trading Activities. Enron, through ECT, offers price risk
management services to the energy sector. These services
primarily relate to commodities associated with the energy sector
(natural gas, crude oil, natural gas liquids and electricity).
ECT provides these services through a variety of financial
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. ECT also
manages interest rate risks and foreign currency risks associated
with the fair value of its energy commodities portfolio. A
variety of financial instruments, including financial futures,
are used for this purpose.
ECT accounts for these activities using the mark-to-market
method of accounting. Under mark-to-market 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."
Notional Amounts and Terms. The notional amounts and terms
of these financial instruments at December 31, 1996 are set forth
below (volumes in trillions of British thermal units equivalent
(TBtue), dollars in millions):
[Download Table]
Fixed Price Fixed Price Maximum
Payor Receiver Terms in years
Energy commodities
Natural gas 7,562 7,017 18
Crude oil and liquids 889 556 11
Electricity 852 2,127 15
Financial products
Interest rate(a) $12,530 $1,915 19
Foreign currency 412 422 18
Equity investments(b) 432 809 5
<FN>
(a) The interest rate fixed price receiver represents the net
notional dollar value of the interest rate sensitive component
of the combined commodity portfolio. The interest rate fixed
price payor represents 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. For example,
approximately $730 million notional strip of Eurodollar
futures contracts are equivalent to $100 million of two year
U.S. Treasury notes. Although the notional amounts vary, the
two instruments offer essentially the same price behavior for
a given move in interest rates. Similarly, the Fixed Price
Payor and Fixed Price Receiver notional amounts listed above
are significantly different but offer the same price risk
behavior. Further, because these positions are offsetting,
little financial exposure occurs to movements in interest
rates.
(b) Includes equity swaps entered into by all of Enron.
ECT also has sales and purchase commitments associated with
contracts based on market prices totaling 4,477 TBtue, with terms
extending up to 19 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 ECT'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 ECT's entire
portfolio of price risk management activities as of December 31,
1996 was approximately 2.8 years.
Fair Value. The fair value of the financial instruments as of
December 31, 1996, 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:
[Download Table]
Fair Value Average Fair Value
as of for the Year Ended
12/31/96 12/31/96(a)
(In Millions) Assets Liabilities Assets Liabilities
Natural gas $1,959 $1,248 $1,750 $923
Crude oil and liquids 443 578 361 420
Electricity 320 183 182 98
<FN>
(a) Computed using the ending balance at each month end.
The net change in the value of ECT's portfolio of price risk
management activities for the year ended December 31, 1996,
exclusive of the effects of monetizing certain assets from price
risk management activities and primarily attributable to
financial instruments fixing energy commodity pricing, was $208
million and is included in "Other Revenues". Essentially all of
ECT's operations relate to providing price risk management
services. Accordingly, earnings for this operating segment
appropriately reflect the net gain arising from trading
activities for the year ended December 31, 1996.
Market Risk. To provide solutions to energy problems
worldwide, ECT serves a diverse customer group that includes
independent power producers, industrials, gas and electric
utilities, oil and gas producers, financial institutions and
other energy marketers. This broad customer mix generates a need
for a variety of financial structures, products and terms. This
diversity requires ECT to manage, on a portfolio basis, the
resulting market risks inherent in these transactions subject to
parameters established by Enron's Board of Directors. Market
risks are monitored by a 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 at both the corporate and subsidiary levels.
Risk measurement is also supplemented with stress testing and
scenario analysis. ECT's fixed price contract portfolio is
typically balanced to within an annual average of 1% of the total
notional physical and financial transaction volumes marketed.
ECT measures the risk in its portfolio on a daily basis in
accordance with value-at-risk and other methodologies, which
simulate forward price curves in the energy markets to estimate
the size and probability of future potential losses. The
quantification of market risk using value-at-risk provides a
consistent measure of risk across diverse energy markets and
products. The use of this methodology requires a number of key
assumptions including the selection of a confidence level for
losses, the holding period chosen for the value-at-risk
calculation and the treatment of risks outside the value-at-risk
methodologies, including liquidity risk and event risk.
ECT expresses value-at-risk as a percentage of Enron's
earnings based on a 95% confidence level using one day holding
periods. On a one day basis as of December 31, 1996, ECT's value-
at-risk for its price risk management activities was less than 2%
(unaudited) of Enron's total income before interest, minority
interests and income taxes. Since this is not an absolute
measure of risk under all conditions for all products, ECT
performs alternative scenario analyses to estimate the economic
impact of a sudden market movement on the value of the trading
portfolio (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.
Based upon the ongoing policies and controls discussed above,
Enron does not anticipate a materially adverse effect on
financial position or results of operations as a result of market
fluctuations.
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. The
counterparties associated with ECT's assets from price risk
management activities as of December 31, 1996 and 1995 are
summarized as follows:
[Download Table]
Assets from Price Risk Management Activities
December 31, 1996
Investment Below
(In Millions) Grade(a) Investment Grade Total
Independent power producers $ 358 $103 $ 461
Oil and gas producers 422 369 791
Energy marketers 466 132 598
Gas and electric utilities 495 29 524
Financial institutions 191 - 191
Industrials 35 13 48
Other 108 1 109
Total $2,075 $647 2,722
Credit and other reserves (249)
Assets from price risk
management activities(b) $2,473
[Download Table]
Assets from Price Risk Management Activities
December 31, 1995
Investment Below
(In Millions) Grade(a) Investment Grade Total
Independent power producers $ 573 $105 $ 678
Oil and gas producers 318 109 427
Energy marketers 132 103 235
Gas and electric utilities 234 45 279
Financial institutions 38 5 43
Industrials 35 43 78
Other 202 42 244
Total $1,532 $452 1,984
Credit and other reserves (207)
Assets from price risk
management activities(b) $1,777
<FN>
(a) "Investment Grade" is primarily determined using publicly
available credit ratings along with consideration of
collateral, which encompass standby letters of credit, parent
company guarantees and property interests, including oil and
gas reserves. Included in "Investment Grade" are
counterparties with a minimum Standard & Poor's or Moody's
rating of BBB- or Baa3, respectively.
(b) Two and three customers' exposures at December 31, 1996
and 1995, 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 ECT'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.
ECT 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.
ECT maintains a credit reserve which is based on management's
evaluation of the credit risk of the overall portfolio. This
reserve is objectively determined using an implied risk profile
based on the difference between risk-free rates of return and
each counterparty's cost of borrowing. This implied risk is then
used to evaluate the exposure (based on current market value) to
each counterparty adjusted for collateral provisions and overall
concentration of exposure. Based on ECT's policies, its
exposures and the credit reserve, 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 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.
For example, interest rate swaps and options are utilized to
synthetically convert floating rate liabilities to fixed and to
convert fixed rate liabilities to floating. Natural gas and
crude oil swaps and options are utilized to alter Enron's
consolidated exposure to price fluctuations in the exploration
and production segment of the business.
Interest Rate Swaps. At December 31, 1996, Enron had entered
into interest rate swap agreements with a notional principal
amount of $3.6 billion to manage interest rate exposure. Swap
agreements relating to notional amounts of $1.9 billion and $1.7
billion are scheduled to terminate in 1998 and thereafter,
respectively.
Energy Commodity Price Swaps. At December 31, 1996, Enron was
a party to energy commodity price swaps covering 10 TBtu, 100
TBtu and 161 TBtu of natural gas for the years 1997, 1998 and the
period 1999 through 2004, respectively, and 2 million, 2 million
and 1 million barrels of crude oil for the years 1997, 1998 and
the period 1999 through 2000, respectively.
Credit Risk. While notional amounts are used to express the
volume of various derivative financial instruments, the amounts
potentially subject to credit risk, in the event of
nonperformance by the third parties, are substantially smaller.
Counterparties to the forwards, futures and other contracts
discussed above are 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.
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, 1996 and
1995 were as follows:
[Download Table]
1996 1995
Carrying Estimated Carrying Estimated
(In Millions) Amount Fair Value Amount Fair Value
Long-term debt (Note 6) $3,349 $3,508 $3,065 $3,360
Company-obligated preferred
stock of subsidiaries (Note 9) 592 607 377 386
Interest rate swaps - (11) - (18)
Energy commodity price swaps - (64) - 90
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 stock 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 by 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 (see "Non-Trading Activities" above).
The fair market value of cash and cash equivalents, accounts
receivable and accounts payable 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:
[Download Table]
(In Millions) 1996 1995 1994
U.S. $551 $622 $415
Foreign 304 183 205
$855 $805 $620
Total income tax expense is summarized as follows:
[Download Table]
(In Millions) 1996 1995 1994
Payable currently -
Federal $ 16 $ 29 $ 49
State 11 26 14
Foreign 37 14 11
64 69 74
Payment deferred -
Federal 174 158 78
State (1) 30 (6)
Foreign 34 28 21
207 216 93
Total Income Tax Expense $271 $285 $167
The differences between taxes computed at the U.S. Federal
statutory tax rate and Enron's effective income tax rate are as
follows:
[Download Table]
1996 1995 1994
Statutory Federal income tax rate 35.0 % 35.0 % 35.0 %
Net state income taxes 0.8 % 4.5 % 0.8 %
Tight gas sands tax credit (1.8)% (2.8)% (5.9)%
Equity earnings (3.3)% (3.8)% (3.7)%
Minority interest 3.1 % 1.9 % 1.7 %
Asset and stock sale differences 1.8 % 2.1 % -
Cash value in life insurance (3.2)% - -
Other (0.7)% (1.4)% (1.0)%
Effective income tax rate 31.7 % 35.5 % 26.9 %
The principal components of Enron's net deferred income tax
liability at December 31, 1996 and 1995 were as follows:
[Download Table]
(In Millions) 1996 1995
Deferred income tax assets -
Alternative minimum tax credit
carryforward $ 235 $ 231
Other 143 84
378 315
Deferred income tax liabilities -
Depreciation, depletion and
amortization 1,622 1,617
Price risk management activities 536 427
Other 638 470
2,796 2,514
Net deferred income tax liabilities(a) $2,418 $2,199
<FN>
(a) Includes $128 million and $13 million in other current
liabilities for 1996 and 1995, respectively.
Enron has an alternative minimum tax (AMT) credit carryforward
of approximately $235 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 $222 million. The loss
carryforward will be available in full until 2011. The benefit
of this net operating loss has been recognized as a deferred tax
asset.
U.S. and foreign taxes have been provided for earnings of
foreign subsidiary companies that are expected to be remitted to
the parent company. Foreign subsidiaries' cumulative
undistributed earnings of approximately $475 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:
[Download Table]
(In Millions) 1996 1995 1994
Income taxes (net of refunds) $ 89 $ 13 $ 57
Interest (net of amounts capitalized) 290 296 268
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 $1.2 billion in long-term
committed credit. Expiration dates of the committed facilities
range from June 2001 to November 2001. 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 1996, no
amounts were outstanding under these facilities.
Enron has also entered into agreements which provide for
uncommitted lines of credit totaling $720 million at December 31,
1996. 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,
1996, $191 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, 1996 and 1995, short-term borrowings of $298 million and $15
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, 1996 and
1995, $175 million and $286 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, 1996 and 1995 were 7.0% and 6.3%, respectively.
Detailed information on long-term debt is as follows:
[Download Table]
December 31,
(In Millions) 1996 1995
Enron Corp.
Debentures
6.75% due 2005 - senior subordinated $ 200 $ 200
8.25% due 2012 - senior subordinated 150 150
Notes payable
8.10% to 9.25% due 1996 - 250
6.25% - exchangeable notes due 1998 228 228
8.50% to 10.00% due from 1998 to 2001 450 450
6.75% to 9.875% due from 2003 to 2007 992 992
7% due 2023 100 100
Other 4 10
Northern Natural Gas Company
Notes payable
8.00% due 1999 250 250
6.875% due 2005 100 100
Transwestern Pipeline Company
Notes payable
7.55% to 9.10% due 2000 123 123
9.20% due from 1998 to 2004 27 27
Enron Oil & Gas Company
Notes payable
9.10% due 1998 40 70
5.86% to 6.70% due from 2001 to 2006 255 -
Other 105 78
Enron Europe Limited
Other 41 39
Amount reclassified from short-term debt 298 15
Unamortized debt discount and premium (14) (17)
Total long-term debt $3,349 $3,065
The Enron 6.25% Exchangeable Notes are mandatorily
exchangeable in 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 by delivering shares of EOG common stock.
The aggregate annual maturities of long-term debt outstanding
at December 31, 1996 were $175 million, $391 million, $328
million, $131 million and $314 million for 1997 through 2001,
respectively.
7 ACCOUNTS RECEIVABLE SALES
Enron has entered into an agreement which provides for the
sale of trade accounts receivable with limited recourse
provisions and the rights to certain recoverable pipeline
transition surcharges expiring January 31, 1999. Sales of trade
receivables under these agreements totaled $250 million and $100
million at December 31, 1996 and 1995, respectively.
The fees incurred on the sales of accounts receivable totaled
$8 million, $23 million and $20 million for 1996, 1995 and 1994,
respectively, and are included in "Interest and Related Charges,
net."
Enron affiliates have 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 the portfolio of receivables is well
diversified and that such diversification minimizes any potential
credit risk. Receivables are generally not collateralized.
8 UNCONSOLIDATED SUBSIDIARIES
Summarized combined financial information of Enron's
unconsolidated subsidiaries is presented below:
[Download Table]
December 31,
(In Millions) 1996 1995
Balance sheet
Current assets $2,587 $1,777
Property, plant and equipment, net 8,064 7,814
Other noncurrent assets 902 968
Current liabilities 2,381 2,050
Long-term debt 5,230 4,982
Other noncurrent liabilities 1,139 1,142
Owners' equity 2,803 2,385
[Download Table]
Year Ended December 31,
(In Millions) 1996 1995 1994
Income statement
Operating revenues $11,676 $8,258 $7,103
Operating expenses 10,567 7,335 6,422
Net income 464 226 290
Distributions paid to Enron 84 68 81
Enron's equity in earnings (losses) of unconsolidated
subsidiaries is as follows:
[Download Table]
Ownership Year Ended December 31,
(In Millions) Interest 1996 1995 1994
Citrus Corp. 50% $ 22 $27 $ 27
EOTT Energy Partners, L.P. 49% 9 (23) 5
Joint Energy Development
Investments L.P. 50% 71 4 7
Teesside Power Limited 50%(a) 29 18 13
Transportadora de Gas del Sur S.A. 35%(a) 29 22 23
Other 55 38 37
$215 $86 $112
<FN>
(a) Net of minority interests, the ownership is 28% for
Teesside Power Limited and 24% for Transportadora de Gas del
Sur S.A.
Citrus Corp. Enron has a 50% indirect ownership interest in
and provides services to Citrus Corp. (Citrus), a joint venture
to transport and market natural gas to Florida. Effective March
1, 1995, Citrus' wholly-owned subsidiary, Florida Gas
Transmission Company (Florida Gas), placed into service its Phase
III pipeline expansion. The Phase III expansion increased
Florida Gas' firm average delivery capacity by 530 million cubic
feet per day to 1.5 billion cubic feet per day.
EOTT Energy Partners, L.P. During March 1994, EOTT Energy
Corp., a wholly-owned subsidiary of Enron, exchanged its crude
oil marketing and transportation operations with EOTT Energy
Partners, L.P. (EOTT) for common and subordinated units and a 2%
general partnership interest. The common units were subsequently
sold in an underwritten public offering. Enron purchased
additional units during 1995 and 1996 to increase its ownership
from 42% to 49%.
Enron is committed to provide support for EOTT's common unit
distributions, if needed, up to a total of $29 million through
March 1998 through the purchase of Additional Partnership
Interests. Letters of credit and trade guarantees issued on
behalf of EOTT which were outstanding at December 31, 1996 are
discussed in Note 15.
Joint Energy Development Investments L.P. (JEDI). JEDI, a
limited partnership which acquires and owns energy investments,
was formed in 1993 with an Enron subsidiary and the California
Public Employee Retirement System (CalPERS) each owning a 50%
interest. Enron and CalPERS committed to each invest $250
million of capital in JEDI through 1996, all of which has been
contributed as of December 31, 1996.
JEDI's capital investments are carried at fair value. For
publicly traded securities, fair value is based upon quoted
market prices. For securities that are not publicly traded,
estimates of the fair value are made based upon review of the
investee's financial results, condition and prospects.
Teesside Power Limited (Teesside). Enron has reduced its
effective interest in Teesside, a joint venture cogeneration
company which owns a 1,875 megawatt independent power facility in
northeast England, from 50% in 1994 to 28% in 1996. An affiliate
of Enron operates the facility. Enron has guaranteed Teesside's
obligation for certain grid charges and other amounts which could
become due under certain power sales agreements. The notional
amount of such guarantees is included in Note 15.
Under the terms of certain gas supply agreements extending
through 2008, Teesside is obligated to take-or-pay for an average
of up to 240 billion British thermal units (BBtu) of natural gas
per day at indexed prices. Enron has guaranteed 70% of
Teesside's payment obligation under the gas supply agreements.
Enron believes there are alternative markets for such gas should
the gas not be taken by Teesside.
Transportadora de Gas del Sur S.A. Enron holds an effective
35% interest, including 18% through Enron Global Power &
Pipelines L.L.C., in Compania de Inversiones de Energia S.A., an
Argentine corporation which owns 70% of Transportadora de Gas del
Sur S.A. (TGS). TGS is the owner and operator of a 4,104 mile
natural gas pipeline system in Argentina which connects major gas
fields in southern and western Argentina with distributors of gas
in those areas and in the greater Buenos Aires area, the
principal population center of Argentina. TGS is one of two
transmission systems in Argentina.
9 PREFERRED STOCK
Preferred and Preference Stock. At December 31, 1996, Enron
had outstanding 1,370,714 shares of Cumulative Second Preferred
Convertible Stock (the Convertible Preferred Stock), $1 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 1996,
1995 and 1994, 4,780 shares, 29,489 shares, and 91,694 shares,
respectively, of the Convertible Preferred Stock were converted
into common stock.
Company-Obligated Preferred Stock of Subsidiaries. Summarized
information for Enron's Company-Obligated Preferred Stock of
Subsidiaries is as follows:
[Download Table]
Liquidation
(In Millions, Except Per Share December 31, Value
Amounts and Shares) 1996 1995 Per Share
Enron Capital Trust I(a)
8.3% Trust Originated Preferred Securities
(8,000,000 shares)(b) $200 $ - $ 25
Enron Capital Resources, L.P.(c)
9% Cumulative Preferred Securities, Series A
(3,000,000 shares)(b) 75 75 25
Enron Capital LLC(d)
8% Cumulative Monthly Income Preferred
Shares (MIPS) (8,550,000 shares)(b) 214 214 25
Enron Equity Corp.(d)
8.57% Preferred Stock (880 shares)(b) 88 88 100,000
7.39% Preferred Stock (150 shares)(b)(e) 15 - 100,000
$592 $377
<FN>
(a) Delaware grantor trust.
(b) Redeemable at Enron's option under certain circumstances
after specified dates.
(c) Enron is sole general partner.
(d) Wholly-owned subsidiary of Enron.
(e) Mandatorily redeemable on April 30, 2006.
10 COMMON STOCK
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,
compensation expense charged against income for the restricted
stock plan for 1996, 1995 and 1994 was immaterial and no
compensation expense has been recognized for the fixed stock
option plans. 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 the
method of the Statement of Financial Accounting Standards (SFAS)
No. 123 - "Accounting for Stock-Based Compensation," Enron's net
income and earnings per share would have been $562 million ($2.22
per share primary, $2.07 per share fully diluted) in 1996 and
$514 million ($2.05 per share primary, $1.92 per share fully
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.
For purposes of the SFAS No. 123 disclosure, 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 1996 and 1995, respectively: (i)
dividend yield of 2.3% and 2.4%; (ii) expected volatility of
23.8% and 24.3%; (iii) risk-free interest rates of 5.9% and 6.4%;
and (iv) expected lives of 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:
[Download Table]
1996 1995 1994
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
(Shares in Thousands) Shares Price Shares Price Shares Price
Outstanding,
beginning of year 22,493 $29.02 24,246 $27.38 9,680 $19.64
Granted(a) 7,370 39.71 2,971 34.27 15,806 31.19
Exercised (3,615) 24.41 (3,137) 20.91 (1,019) 13.50
Forfeited (749) 31.66 (1,586) 29.89 (221) 24.82
Expired (23) 30.65 (1) 23.42 - -
Outstanding,
end of year 25,476 $32.69 22,493 $29.02 24,246 $27.38
Exercisable,
end of year 12,883 $30.65 9,599 $26.11 7,184 $22.22
Available for grant,
end of year(b) 6,505 7,831 9,252
Weighted average
fair value of
options granted $9.44 $7.86
<FN>
(a) Includes options granted on December 31, 1996, December 29,
1995 and December 30, 1994 for 815,650 shares, 997,095 shares
and 9,717,750 shares, respectively, under all-employee stock
option grants for the years 1995 through 2000.
(b) Includes up to 5,232,218 shares, 5,209,620 shares and
5,245,100 shares as of December 31, 1996, 1995 and 1994,
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, 1996 (shares in thousands):
[Download Table]
Options Outstanding Options Exercisable
Weighted
Average Weighted Weighted
Number Remaining Average Number Average
Range of Outstanding Contractual Exercise Exercisable Exercise
Exercise Prices at 12/31/96 Life Price at 12/31/96 Price
$ 9.13 to $28.50 3,725 5 years $22.10 3,064 $20.96
29.00 to 30.25 2,258 6 years 29.67 1,364 29.53
30.50 to 30.50 7,477 8 years 30.50 2,727 30.50
30.88 to 34.00 3,413 4 years 33.83 2,613 33.81
34.25 to 38.13 4,827 7 years 37.21 2,475 37.04
39.13 to 40.88 1,099 9 years 39.64 208 39.65
43.13 to 45.00 2,677 7 years 43.13 432 43.70
$ 9.13 to $45.00 25,476 7 years $32.69 12,883 $30.65
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:
[Download Table]
(Shares in Thousands) 1996 1995 1994
Outstanding, beginning of year 159 194 222
Granted 1,772 45 30
Issued (1,062) (70) (56)
Forfeited or expired (44) (10) (2)
Outstanding, end of year 825 159 194
Available for grant, end of year 5,232 5,210 5,245
Weighted average fair value of
restricted stock granted $37.04 $31.36 $32.89
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. Common shares held by the Trust are not included in the
computation of earnings per share until such shares are released
to fund employee benefits. During 1996 and 1995, respectively,
2,233,867 shares and 1,049,403 shares were released to fund
employee benefits.
Forward Contracts. At December 31, 1996, Enron has forward
contracts to purchase 4.3 million shares of Enron Corp. common
stock at an average price of $39.25 per share. Enron has the
option to settle the forward contracts in cash or an equivalent
value of Enron common stock over the next five years. Shares
potentially deliverable to the counterparty under the contracts
are treated as common stock equivalents for purposes of
determining earnings per share.
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. Through December 31, 1994, participants in the Enron
Plan with five years or more of service were entitled to
retirement benefits in the form of an annuity based on a formula
that uses a percentage of final average pay and years of service.
In connection with a change to the retirement benefit formula,
Enron amended the Enron Plan providing, among other things, that
all employees became fully vested in retirement benefits earned
through December 31, 1994. The formula in place prior to January
1, 1995 was suspended and replaced with a benefit accrual in the
form of a cash balance of 5% of annual base pay beginning January
1, 1996.
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, 1996 and 1995, 15,976,195 shares
and 20,895,553 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:
[Download Table]
(In Millions) 1996 1995 1994
Service cost - benefits earned
during the year $ 14 $ 1 $ 16
Interest cost on projected
benefit obligation 23 21 26
Actual return on plan assets (34) (32) (22)
Amortization and deferrals 9 9 (12)
Pension expense (income) $ 12 $(1) $ 8
The measurement date of the Enron Plan and the ESOP is
September 30. The funded status as of the valuation date of the
Enron Plan and the ESOP reconciles with the amount detailed below
which is included in "Other Assets" on the Consolidated Balance
Sheet.
[Download Table]
(In Millions) 1996 1995
Actuarial present value of accumulated
benefit obligation
Vested $(301) $(276)
Nonvested (4) (27)
Additional amounts related
to projected wage increases (5) (11)
Projected benefit obligation (310) (314)
Plan assets at fair value(a) 315 295
Plan assets in excess of (less than)
projected benefit obligation 5 (19)
Unrecognized net loss 46 53
Unrecognized prior service cost 36 44
Unrecognized net asset at transition (30) (36)
Contributions 1 1
Prepaid pension cost at December 31 $ 58 $ 43
Discount rate 7.5% 7.5%
Long-term rate of return on assets 10.5% 10.5%
Rate of increase in wages 4.0% 4.0%
<FN>
(a) Includes plan assets of the ESOP of $137 million and $152
million for the years 1996 and 1995, respectively.
Assets of the Enron 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 plan
which is expected to be recoverable through rates by its
regulated pipelines.
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.
[Download Table]
(In Millions) 1996 1995
Actuarial present value of accumulated
postretirement benefit obligation (APBO)
Retirees $(126) $(114)
Fully eligible active plan
participants (2) (2)
Other employees (16) (15)
Total APBO (144) (131)
Plan assets at fair value 15 10
APBO in excess of plan assets (129) (121)
Unrecognized transition obligation 66 70
Unrecognized prior service costs 20 19
Unrecognized net loss 33 26
Accrued postretirement benefit obligation $ (10) $ (6)
Discount rate 7.5% 7.5%
Health care cost trend rate(a) 11.0% 11.7%
<FN>
(a) This rate is assumed to decrease to 5.0% over 9 years.
The components of net periodic postretirement benefit expense
are as follows:
[Download Table]
(In Millions) 1996 1995 1994
Service costs $ 1 $ 1 $ 1
Interest costs 10 9 8
Amortization and deferrals 6 6 6
Postretirement benefit expense $17 $16 $15
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.
13 NATURAL GAS RATES AND REGULATORY ISSUES
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, 1996 and 1995, respectively, were $312
million and $291 million, which included transition costs
incurred related to FERC Order 636 of $86 million and $125
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.
Enron's regulated pipelines have all successfully completed
their transitions under FERC Order 636 although future transition
costs may be incurred subject to ongoing negotiations and market
factors. On March 1, 1995, Northern filed a general rate case
proceeding with the FERC which fulfilled a commitment made during
its FERC Order 636 restructuring proceeding. On March 15, 1996,
Northern filed a settlement which resulted in Northern
withdrawing the general rate case, thus leaving the previously
effective rates in effect. The Commission approved this
settlement on July 31, 1996.
Transwestern filed a settlement on May 21, 1996 (the May 21
Settlement) which modified, in part, the 1995 Global Settlement
in which Transwestern and its customers resolved, among other
things, the turnback of approximately 450,000 MMBtu/d of capacity
by Southern California Gas Company, effective November 1, 1996.
The May 21 Settlement resolved all matters regarding pending
transition costs and provided for a rate reduction of settled
transportation rates, which are subject to escalation, effective
on November 1, 1998. The Commission approved the May 21
Settlement on October 16, 1996.
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 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, except as
discussed below, 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 issues. The
Enron Defendants have appealed the court's decision to certify a
class action. 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 March 29, 1996, Enron and two of its wholly-owned
subsidiaries filed suit in the state district court of Harris
County, Texas seeking a ruling that the Capacity Reservation and
Transportation Agreement (CRTA) dated September 10, 1990 between
Teesside Gas Transportation Limited (TGTL), an Enron subsidiary,
and the "CATS" parties has terminated due to consistent material
breaches of that agreement by the CATS parties. The suit was
removed to the federal district court in Houston, Texas.
Proceedings in the Houston lawsuit have been enjoined by an
English court. Enron is appealing the injunction. In April
1996, TGTL, reserving its position in the Houston lawsuit,
notified the CATS parties in accordance with the provisions of
the CRTA that as a result of their failure to make available the
Transportation Service (as defined in the contract) by April 1,
1996, the CRTA was terminated. The CATS parties were to have
provided transportation under the CRTA to ship gas through the
Central Area Transmission System (CATS) pipeline, owned by the
CATS parties. In a separate lawsuit filed in the English court,
the CATS parties are suing TGTL and Enron (on the basis of its
guarantee of TGTL's obligations under the CRTA) for allegedly
failing to make quarterly "send-or-pay" payments under the CRTA.
TGTL refused to make these payments for the same reasons that it
terminated the CRTA: its position is that the Transportation
Service (as defined in the CRTA) was not available. Termination
of the CRTA may lead to termination of the "J-Block Contracts."
Trial on these matters commenced in the English court on
October 28, 1996. The trial concluded in early March 1997, and a
decision is anticipated in June 1997.
The J-Block Contracts are long-term gas contracts that Enron
entered into in March 1993 with Phillips Petroleum Company United
Kingdom Limited, British Gas Exploration and Production Limited
and Agip (U.K.) Limited to purchase future gas production from
the J-Block field which is located in the North Sea offshore the
United Kingdom. Such agreements provide for Enron to take or pay
for certain quantities of gas at a fixed price (with possible
escalations throughout the contract period) on an annual basis.
The contract price is in excess of market prices as of February
1997, however, United Kingdom natural gas prices have been volatile.
The agreements provide that gas paid for, but not taken, can be
recovered in later contract years. In September 1995, Enron
announced that, in accordance with its contractual rights, it had
notified the J-Block sellers that Enron's nominations for gas
from the J-Block fields were estimated to be zero from the first
delivery date of September 25, 1996 through September 30, 1997.
In addition, in accordance with its contractual rights, Enron
made no estimated nominations for J-Block gas under the J-Block
Contracts for the contract year ending September 30, 1998. While
not challenging these actions, the J-Block sellers have, in a
proceeding commenced in English court on March 29, 1996, sought a
declaration that Enron should have agreed to a "Commissioning
Date" (which might trigger Enron's take-or-pay obligations) of
earlier than September 25, 1996, the date set forth in the J-
Block Contracts as the Commissioning Date in the absence of an
agreement on a earlier date. In October 1996, an English Court
of Appeal ruled that Enron was not obligated to agree on an
earlier Commissioning Date, thus making the contract period
ending September 30, 1997 the first year in which Enron has a
potential take-or-pay obligation. This ruling is being appealed
to the House of Lords by the J-Block sellers.
Enron continues to believe that there are many reasons for
the parties to resolve any contract issues commercially, but
efforts have not been successful to date. Unsuccessful settlement
discussions, adverse litigation outcomes or market conditions could
result in a material adverse impact on earnings in any given period.
However, although no assurances can be given, based upon information
currently available and Enron's expectation of the ultimate outcome
of the matters discussed above, Enron anticipates that the J-Block
and CRTA contracts will not have a materially adverse effect on its
financial position.
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 to connect its natural gas
pipeline to the local distribution pipeline system servicing the
city of Decorah. 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 in certain areas of the tract where the plant was
formerly located and to take deep soil samples in those areas
where subsurface contamination would most likely be 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.
Other. In connection with a Power Purchase Agreement between
Dabhol Power Company, Enron's 80%-owned subsidiary, and the
Maharashtra State Electricity Board (MSEB), Dabhol Power Company
began developing Phase I of an electricity generating power plant
south of Bombay, State of Maharashtra, India (the Project). On
August 3, 1995, after construction had begun, a new coalition
government in the State of Maharashtra announced the State
government's intention to terminate the Project, and construction
ceased on August 8, 1995. In response to these actions, Dabhol
Power Company commenced arbitration proceedings in London against
the State government for the actions it had taken to terminate
the Project, seeking to recover all of its construction and other
expenses in addition to lost profits. After the arbitration
proceedings had begun, Dabhol Power Company began renegotiating
the Power Purchase Agreement with MSEB and the Maharashtra state
government. Such renegotiations, which have been successfully
completed, have resulted in a restructured transaction (that
includes both Phase I and Phase II and that increases the planned
capacity of the facility) on terms that are acceptable to Enron.
All approvals for the restructured transaction have been received
and, in December 1996, construction resumed on the project and
Dabhol Power Company terminated the arbitration proceedings.
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, 1996, the estimated
aggregate amounts of such required future payments were $33
million, $33 million, $33 million, $34 million and $35 million
for 1997 through 2001, respectively, and $335 million for later
years. These amounts exclude disputed payments allegedly due in
1996 and future years totaling $994 million related to the CRTA
which Enron believes has terminated. See Note 14.
The costs incurred under firm transportation agreements,
including commodity charges on actual quantities shipped, totaled
$30 million, $18 million and $20 million in 1996, 1995 and 1994,
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 $35
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, 1996 were $141 million, $108 million, $80 million,
$72 million and $69 million for 1997 through 2001, respectively,
and $255 million for later years. Guarantees under the leases
total $982 million at December 31, 1996.
Total rent expense incurred during 1996, 1995 and 1994 was
$149 million, $147 million and $125 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, 1996, a total of $449 million of
such guarantees were outstanding, including $182 million on
behalf of EOTT. In addition, Enron is a guarantor on certain
liabilities of unconsolidated subsidiaries and other companies
totaling approximately $820 million, including $424 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 $187 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 1997 planned capital
expenditures and equity investments.
16 OTHER INCOME, NET
The components of Other income, net are as follows:
[Download Table]
Year Ended December 31,
(In Millions) 1996 1995 1994
Sales of assets and investments $274 $467 $ 37
Regulatory, contingency
and other adjustments 25 (20) 18
Foreign currency - (1) 8
Litigation adjustments and
settlements, net 19 (8) (1)
Interest income 40 27 39
Other (25) (4) 15
$333 $461 $116
During 1996, Enron sold approximately 12 million shares of EOG
common stock. Proceeds from the sales totaled $307 million.
Enron's ownership interest in EOG at December 31, 1996 was 53%.
In December 1995, Enron sold 31 million outstanding shares of its
EOG common stock, reducing its ownership interest from 80% to
61%. Enron received net proceeds totaling $650 million.
17 QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows:
[Enlarge/Download Table]
(In Millions, Except First Second Third Fourth Total
Per Share Amounts) Quarter Quarter Quarter Quarter Year
Quarterly Results
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:
Primary $0.86 $0.46 $0.48 $0.52 $2.31(a)
Fully diluted 0.80 0.43 0.45 0.48 2.16(a)
1995
Revenues $ 2,304 $ 2,149 $ 2,186 $ 2,550 $ 9,189
Income before interest,
minority interests and
income taxes 371 230 239 325 1,165
Net income 195 94 101 130 520
Earnings per share:
Primary $0.79 $0.37 $0.40 $0.52 $2.07(a)
Fully diluted 0.73 0.35 0.37 0.49 1.94(a)
<FN>
(a) The sum of earnings per share for the four quarters may not equal the
total earnings per share for the year due to changes in the average
number of common shares outstanding.
18 GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION
Enron's operations are classified into four business segments:
Transportation and Operation - Interstate transmission of
natural gas. Construction, management and operation of pipelines
and clean fuels plants. Investment in crude oil transportation
activities.
Domestic Gas and Power Services - Purchasing, marketing and
financing of natural gas, natural gas liquids, crude oil and
electricity. Price risk management in connection with natural
gas, natural gas liquids, crude oil and electricity transactions.
Intrastate natural gas pipelines. Development, acquisition and
promotion of natural gas fired power plants in North America.
Extraction of natural gas liquids.
International Operations and Development - Independent (non-
utility) development, acquisition and promotion of power plants,
natural gas liquids facilities and pipelines outside of North
America.
Exploration and Production - Natural gas and crude oil
exploration and production primarily in the United States,
Canada, Trinidad and India.
Financial information by geographic and business segment
follows for each of the three years in the period ended December
31, 1996.
Geographic Segments
[Download Table]
Year Ended December 31,
(In Millions) 1996 1995 1994
Operating revenues from
unaffiliated customers
United States $11,262 $ 7,855 $ 7,604
Foreign 2,027 1,334 1,380
$13,289 $ 9,189 $ 8,984
Intersegment sales
United States $ 72 $ 24 $ 49
Foreign 128 159 116
$ 200 $ 183 $ 165
Operating income
United States $ 490 $ 487 $ 609
Foreign 200 131 107
$ 690 $ 618 $ 716
Income before interest, minority
interests and income taxes
United States $ 938 $ 969 $ 755
Foreign 300 196 189
$ 1,238 $ 1,165 $ 944
Identifiable assets
United States $11,580 $10,695 $ 9,597
Foreign 2,856 1,327 1,304
$14,436 $12,022 $10,901
Business Segments
[Enlarge/Download Table]
Domestic International
Transportation Gas Operations Exploration Corporate
and and Power and and and
(In Millions) Operation Services Development Production Other(c)(d) Total
1996
Unaffiliated revenues(a) $ 748 $11,681 $ 213 $ 647 $ - $13,289
Intersegment revenues(b) 58 167 - 177 (402) -
Total revenues 806 11,848 213 824 (402) 13,289
Depreciation, depletion and
amortization 82 123 15 251 3 474
Operating income (loss) 367 197 58 205 (137) 690
Equity in earnings of
unconsolidated subsidiaries 47 84 84 - - 215
Other income, net 156 (1) 10 (5) 173 333
Income before interest,
minority interests and
income taxes 570 280 152 200 36 1,238
Additions to property, plant
and equipment 181 112 16 540 6 855
Identifiable assets 2,569 7,958 827 2,371 711 14,436
Investments in and advances to
unconsolidated subsidiaries 563 484 521 - 133 1,701
Total assets $3,132 $ 8,442 $1,348 $2,371 $ 844 $16,137
1995
Unaffiliated revenues(a) $ 805 $ 7,064 $ 839 $ 481 $ - $ 9,189
Intersegment revenues(b) 26 (103) 44 278 (245) -
Total revenues 831 6,961 883 759 (245) 9,189
Depreciation, depletion and
amortization 83 104 27 216 2 432
Operating income (loss) 299 115 75 240 (111) 618
Equity in earnings of
unconsolidated subsidiaries 23 6 58 - (1) 86
Other income, net 37 36 9 1 378 461
Income before interest,
minority interests and
income taxes 359 157 142 241 266 1,165
Additions to property, plant
and equipment 121 98 58 464 8 749
Identifiable assets 2,361 5,991 814 2,067 789 12,022
Investments in and advances to
unconsolidated subsidiaries 533 157 468 - 59 1,217
Total assets $2,894 $ 6,148 $1,282 $2,067 $ 848 $13,239
1994
Unaffiliated revenues(a) $ 937 $ 7,166 $ 392 $ 489 $ - $ 8,984
Intersegment revenues(b) 39 13 7 290 (349) -
Total revenues 976 7,179 399 779 (349) 8,984
Depreciation, depletion and
amortization 88 94 15 242 2 441
Operating income (loss) 327 164 73 195 (43) 716
Equity in earnings of
unconsolidated subsidiaries 49 18 45 - - 112
Other income, net 27 20 30 3 36 116
Income before interest,
minority interests and
income taxes 403 202 148 198 (7) 944
Additions to property, plant
and equipment 117 83 14 442 5 661
Identifiable assets 2,388 5,803 450 1,824 436 10,901
Investments in and advances to
unconsolidated subsidiaries 528 162 351 - 24 1,065
Total assets $2,916 $ 5,965 $ 801 $1,824 $ 460 $11,966
<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) Corporate and Other assets consist of cash and cash equivalents,
investments in marketable securities, receivables transferred from
subsidiaries in connection with the receivables sale program and
miscellaneous other assets.
(d) Includes consolidating eliminations.
19 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 47% at December 31, 1996, 39% at December 31, 1995
and 20% at December 31, 1994 and 1993.
Capitalized Costs Relating to Oil and Gas Producing Activities
[Download Table]
December 31,
(In Millions) 1996 1995
Proved properties $ 3,593 $ 3,254
Unproved properties 160 127
Total 3,753 3,381
Accumulated depreciation,
depletion and amortization (1,653) (1,499)
Net capitalized costs $ 2,100 $ 1,882
Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities(a)
[Download Table]
Foreign
(In Millions) United States Canada Trinidad India Other Total
1996
Acquisition of properties
Unproved $ 39 $ 4 $ 2 $ - $ - $ 45
Proved 69 - - - - 69
Total 108 4 2 - - 114
Exploration 61 8 2 4 17 92
Development 283 26 7 79 7 402
Total $452 $38 $11 $83 $24 $608
1995
Acquisition of properties
Unproved $ 16 $ 5 $ - $ - $ 1 $ 22
Proved 123 - - 5 - 128
Total 139 5 - 5 1 150
Exploration 48 7 - - 18 73
Development 217 28 33 17 1 296
Total $404 $40 $33 $22 $20 $519
1994
Acquisition of properties
Unproved $ 46 $ 6 $ - $ - $ - $ 52
Proved 17 5 - 13 - 35
Total 63 11 - 13 - 87
Exploration 71 8 1 2 11 93
Development 223 36 61 - 1 321
Total $357 $55 $62 $15 $12 $501
<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,
1996:
[Download Table]
Foreign
(In Millions) United States Canada Trinidad India Other Total
1996
Operating revenues
Associated companies $253 $14 $ - $ - $ - $267
Trade 282 48 84 21 - 435
Gains on sales of
reserves and related
assets 19 1 - - - 20
Total 554 63 84 21 - 722
Exploration expenses,
including dry hole costs 45 5 2 1 15 68
Production costs 77 17 15 10 - 119
Impairment of unproved
oil and gas properties 19 2 - - - 21
Depreciation, depletion and
amortization 209 25 15 1 1 251
Income (loss) before
income taxes 204 14 52 9 (16) 263
Income tax expense (benefit) 54 6 29 4 - 93
Results of operations $150 $ 8 $23 $ 5 $(16) $170
1995
Operating revenues
Associated companies $224 $ 7 $ - $ - $ - $231
Trade 122 37 72 15 - 246
Gains on sales of
reserves and related
assets 63 - - - - 63
Total 409 44 72 15 - 540
Exploration expenses,
including dry hole costs 35 4 - - 16 55
Production costs 64 13 8 11 - 96
Impairment of unproved
oil and gas properties 22 2 - - - 24
Depreciation, depletion and
amortization 181 20 15 - - 216
Income (loss) before
income taxes 107 5 49 4 (16) 149
Income tax expense (benefit) 1 1 27 2 (1) 30
Results of operations $106 $ 4 $22 $ 2 $(15) $119
1994
Operating revenues
Associated companies $316 $ 8 $ - $ - $ - $324
Trade 115 42 36 1 - 194
Gains on sales of
reserves and related
assets 54 - - - - 54
Total 485 50 36 1 - 572
Exploration expenses,
including dry hole costs 42 4 1 3 9 59
Production costs 69 13 5 - - 87
Impairment of unproved
oil and gas properties 24 1 - - - 25
Depreciation, depletion and
amortization 218 17 7 - - 242
Income (loss) before
income taxes 132 15 23 (2) (9) 159
Income tax expense (benefit) (8) 6 12 (1) (3) 6
Results of operations $140 $ 9 $11 $(1) $(6) $153
<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, 1996, 1995 and 1994 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, 1996, 1995 and 1994 covering producing areas,
in the United States and Canada, containing 64%, 60% and 59%,
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 McNaughton 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
[Enlarge/Download Table]
(In Millions) United States Canada Trinidad India Total
1996
Future cash inflows(a) $ 9,391 $ 715 $ 709 $ 864 $11,679
Future production costs (1,640) (281) (237) (338) (2,496)
Future development costs (306) (9) (1) - (316)
Future net cash flows before
income taxes 7,445 425 471 526 8,867
Future income taxes (2,260) (99) (246) (227) (2,832)
Future net cash flows 5,185 326 225 299 6,035
Discount to present value at
10% annual rate (2,693) (100) (68) (105) (2,966)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 2,492(b) $ 226 $ 157 $ 194 $ 3,069(b)
1995
Future cash inflows(a) $3,996 $ 503 $ 395 $ 396 $ 5,290
Future production costs (747) (204) (152) (202) (1,305)
Future development costs (298) (7) (4) (13) (322)
Future net cash flows before
income taxes 2,951 292 239 181 3,663
Future income taxes (696) (46) (105) (82) (929)
Future net cash flows 2,255 246 134 99 2,734
Discount to present value at
10% annual rate (1,015) (69) (19) (46) (1,149)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $1,240(b) $ 177 $ 115 $ 53 $ 1,585(b)
1994
Future cash inflows(a) $2,315 $ 487 $ 318 $ 168 $ 3,288
Future production costs (607) (196) (87) (106) (996)
Future development costs (136) (10) (2) (4) (152)
Future net cash flows before
income taxes 1,572 281 229 58 2,140
Future income taxes (208) (57) (103) (22) (390)
Future net cash flows 1,364 224 126 36 1,750
Discount to present value at
10% annual rate (401) (67) (23) (15) (506)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 963(b) $ 157 $ 103 $ 21 $ 1,244(b)
<FN>
(a) Based on year-end market prices determined at the point of delivery
from the producing unit.
(b) Excludes $75 million, $36 million and $60 million at December 31,
1996, 1995 and 1994, respectively, associated with a volumetric
production payment sold effective October 1, 1992, as amended, to be
delivered over a seventy-eight month period beginning October 1, 1992.
Changes in Standardized Measure of Discounted Future Net Cash Flows
[Enlarge/Download Table]
(In Millions) United States Canada Trinidad India Total
December 31, 1993 $1,262 $160 $ 50 $ - $1,472
Sales and transfers of oil
and gas produced, net
of production costs (340) (38) (31) - (409)
Net changes in prices and
production costs (506) (66) 11 - (561)
Extensions, discoveries, additions
and improved recovery, net of
related costs 225 51 97 - 373
Development costs incurred 70 7 7 - 84
Revisions of estimated development
costs 7 6 - - 13
Revisions of previous quantity
estimates (3) (3) 14 - 8
Accretion of discount 145 20 7 - 172
Net change in income taxes 168 20 (46) (8) 134
Purchases of reserves in place 17 3 - 29 49
Sales of reserves in place (28) - - - (28)
Changes in timing and other (54) (3) (6) - (63)
December 31, 1994 $ 963 $157 $103 $ 21 $1,244
Sales and transfers of oil
and gas produced, net
of production costs (268) (30) (64) (5) (367)
Net changes in prices and
production costs 12 (6) (37) 8 (23)
Extensions, discoveries, additions
and improved recovery, net of
related costs 376(a) 38 54 46 514(a)
Development costs incurred 29 3 2 - 34
Revisions of estimated development
costs 1 - 29 4 34
Revisions of previous quantity
estimates 6 (5) 10 - 11
Accretion of discount 97 18 17 3 135
Net change in income taxes (133) 11 (8) (28) (158)
Purchases of reserves in place 194 - - - 194
Sales of reserves in place (54) (1) - - (55)
Changes in timing and other 17 (8) 9 4 22
December 31, 1995 $1,240(a) $177 $115 $ 53 $1,585(a)
Sales and transfers of oil
and gas produced, net
of production costs (437) (46) (69) (11) (563)
Net changes in prices and
production costs 1,817 58 60 54 1,989
Extensions, discoveries, additions
and improved recovery, net of
related costs 581 63 62 150 856
Development costs incurred 58 2 2 - 62
Revisions of estimated development
costs (14) (3) 1 14 (2)
Revisions of previous quantity
estimates 7 (1) 80 - 86
Accretion of discount 137 18 20 9 184
Net change in income taxes (656) (30) (74) (87) (847)
Purchases of reserves in place 162 - - - 162
Sales of reserves in place (103) (3) - - (106)
Changes in timing and other (300) (9) (40) 12 (337)
December 31, 1996 $2,492(a) $226 $157 $194 $3,069(a)
<FN>
(a) Includes approximately $344 million and $77 million related to the
reserves in the Big Piney deep Paleozoic formations at December 31, 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:
[Enlarge/Download Table]
United States Canada Trinidad India Total
Net proved developed reserves
Natural gas (Bcf)
December 31, 1993 1,079.8(a) 250.6 71.4 - 1,401.8(a)
December 31, 1994 1,128.2(a) 288.3 206.2 - 1,622.7(a)
December 31, 1995 1,218.1(a)(b) 310.1 233.9 - 1,762.1(a)(b)
December 31, 1996 1,325.7(a)(b) 319.5 370.2 124.6 2,140.0(a)(b)
Liquids (MBbl)(c)
December 31, 1993 11,165(a) 5,409 1,591 - 18,165(a)
December 31, 1994 16,770(a) 7,073 4,429 7,585 35,857(a)
December 31, 1995 19,977(a) 6,505 5,607 11,542 43,631(a)
December 31, 1996 24,868(a) 7,452 8,168 10,791 51,279(a)
Natural gas (Bcf)
Net proved reserves at
December 31, 1993 1,313.2(a) 271.0 100.5 - 1,684.7(a)
Revisions of previous
estimates (17.1) (6.5) 15.0 - (8.6)
Purchases in place 18.8 9.2 - 29.3 57.3
Extensions, discoveries and
other additions 233.8 50.2 113.9 - 397.9
Sales in place (29.3) (1.0) - - (30.3)
Production (212.0) (26.3) (23.2) - (261.5)
Net proved reserves at
December 31, 1994 1,307.4(a) 296.6 206.2 29.3 1,839.5(a)
Revisions of previous
estimates 10.1 (8.1) 17.5 (29.3) (9.8)
Purchases in place 174.8 - - - 174.8
Extensions, discoveries and
other additions 1,391.6(b) 54.8 60.8 75.0 1,582.2(b)
Sales in place (38.1) (1.7) - - (39.8)
Production (191.7) (27.7) (39.0) - (258.4)
Net proved reserves at
December 31, 1995 2,654.1(a)(b) 313.9 245.5 75.0 3,288.5(a)(b)
Revisions of previous
estimates 3.6 (2.9) 79.6 - 80.3
Purchases in place 100.6 0.9 - - 101.5
Extensions, discoveries and
other additions 256.8 49.2 90.7 124.6 521.3
Sales in place (58.4) (4.3) - - (62.7)
Production (210.2) (35.9) (45.6) - (291.7)
Net proved reserves at
December 31, 1996 2,746.5(a)(b) 320.9 370.2 199.6 3,637.2(a)(b)
[Download Table]
United States Canada Trinidad India Total
Liquids (MBbl)(c)
Net proved reserves at
December 31, 1993 13,172 5,471 2,218 - 20,861
Revisions of previous
estimates 2,179 (177) 455 - 2,457
Purchases in place 358 - - 7,617 7,975
Extensions, discoveries and
other additions 5,332 2,848 2,687 - 10,867
Sales in place (257) - - - (257)
Production (2,997) (905) (931) (32) (4,865)
Net proved reserves at
December 31, 1994 17,787 7,237 4,429 7,585 37,038
Revisions of previous
estimates (413) (351) 396 4,874 4,506
Purchases in place 4,264 - - - 4,264
Extensions, discoveries and
other additions 8,703 729 3,896 - 13,328
Sales in place (1,241) (9) - - (1,250)
Production (3,701) (1,021) (1,851) (917) (7,490)
Net proved reserves at
December 31, 1995 25,399 6,585 6,870 11,542 50,396
Revisions of previous
estimates 339 191 1,835 - 2,365
Purchases in place 312 2 - - 314
Extensions, discoveries and
other additions 7,103 2,116 1,388 275 10,882
Sales in place (447) (121) - - (568)
Production (3,830) (1,321) (1,925) (1,026) (8,102)
Net proved reserves at
December 31, 1996 28,876 7,452 8,168 10,791 55,287
<FN>
(a) Excludes approximately 37.5 Bcf, 54.2 Bcf, 70.9 Bcf and 87.5 Bcf at
December 31, 1996, 1995, 1994 and 1993, respectively, associated with a
volumetric production payment sold effective October 1, 1992, as
amended, to be delivered over a seventy-eight month period beginning
October 1, 1992.
(b) Includes 1,180.0 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 17, 1997. 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 17, 1997
[Enlarge/Download Table]
SCHEDULE II
ENRON CORP. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(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
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 Clean Fuels
Plant Operations $ 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 Clean Fuels
Plant Operations $ - $75 $ - $ - $ 75
1994
Reserves deducted from
assets to which they apply
Allowance for doubtful
accounts $ 22 $ 5 $ - $14(1) $ 13
Assets from price risk
management activities $103 $13 $ 19 $ 5 $130
Reserve for regulatory issues
Current $ 22 $15 $ 5 $36 $ 6
Noncurrent $ 21 $ 1 $ - $22 $ -
Reserve for insurance claims
and losses - noncurrent $ 28 $ 2 $ - $ 5 $ 25
<FN>
(1) Includes $11 million resulting from the sale of a majority interest in
Enron's crude oil trading and transportation assets.
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 28th day of
March, 1997.
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 28,
1997 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 Chief
(Richard A. Causey) Accounting and Information Officer
(Principal Accounting Officer)
ANDREW S. FASTOW Senior Vice President, Finance
(Andrew S. Fastow) (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)
ROBERT K. JAEDICKE* Director
(Robert K. Jaedicke)
CHARLES A. LeMAISTRE* Director
(Charles A. LeMaistre)
JEFFREY K. SKILLING* Director and President and Chief
(Jeffrey K. Skilling) Operating Officer
JOHN A. URQUHART* Director
(John A. Urquhart)
JOHN WAKEHAM* Director
(John Wakeham)
CHARLS E. WALKER* Director
(Charls E. Walker)
HERBERT S. WINOKUR, JR.* Director
(Herbert S. Winokur, Jr.)
*By: PEGGY B. MENCHACA
(Peggy B. Menchaca)
(Attorney-in-fact for persons indicated)
Dates Referenced Herein and Documents Incorporated by Reference
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