Document/Exhibit Description Pages Size
1: 10-K Enron Corp. 1995 Form 10-K 121± 514K
2: EX-3.02 Bylaws of Enron Corp. 22± 91K
3: EX-10.02 First Amendment to Enron Executive Supplemental 1 10K
Survivor Benefits Plan
4: EX-10.06 First Amendment to Enron Corp. 1988 Deferral Plan 1 9K
5: EX-10.07 Second Amendment to Enron Corp. 1988 Deferral Plan 2± 11K
6: EX-10.10 First Amendment to Enron Corp. 1992 Deferral Plan 2± 11K
7: EX-10.11 Second Amendment to Enron Corp. 1992 Deferral Plan 3± 16K
8: EX-10.31 Second Amendment to Employment Agreement of Rodney 3 21K
L. Gray
9: EX-10.35 Fourth Amendment to Consulting Services Agreement 3± 14K
of John A. Urquhart
10: EX-10.36 Fifth Amendment to Consulting Services Agreement 3± 14K
of John A. Urquhart
11: EX-10.37 Sixth Amendment to Consulting Services Agreement 1 10K
of John A. Urquhart
12: EX-10.46 First Amendment to Enron Corp. Performance Unit 1 10K
Plan
13: EX-10.48 First Amendment to Enron Corp. 1994 Deferral Plan 1 10K
14: EX-10.49 Second Amendment to Enron Corp. 1994 Deferral Plan 3± 15K
15: EX-11 Statement Re Computation of Per Share Earnings 1 10K
16: EX-12 Statement Re Computation or Ratios 1 9K
17: EX-21 Subsidiaries of Registrant 11± 44K
18: EX-23.01 Consent of Independent Public Accountants 1 10K
19: EX-23.02 Consent of Degolyer and Macnaughton 1 12K
20: EX-23.03 Letter Report of Degolyer and Macnaughton 3± 15K
21: EX-24 Powers of Attorney 13 37K
22: EX-27 Article 5 FDS for Year End 1995 1 9K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1995
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.)
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
Convertible Stock, New York Stock Exchange
$1 Par Value and Chicago Stock Exchange
6-1/4% Exchangeable Notes due New York Stock Exchange
December 13, 1998
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
_____
Aggregate market value of the voting stock held by non-affiliates of the
registrant, based on closing prices in the daily composite list for
transactions on the New York Stock Exchange on January 1, 1996, was
approximately $9,641,146,000. As of March 1, 1996, there were 251,456,233
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 7, 1996 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 Gas and Power Services . . . . . . . . . . . 9
Exploration and Production . . . . . . . . . . . . . . . . 13
Regulation . . . . . . . . . . . . . . . . . . . . . . . . 17
Operating Statistics . . . . . . . . . . . . . . . . . . . 22
Current Executive Officers of the Registrant . . . . . . . 24
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . 25
Gas Transmission and Liquid Fuels. . . . . . . . . . . . . 25
Oil and Gas Exploration and Production Properties
and Reserves . . . . . . . . . . . . . . . . . . . . . 26
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . 28
Item 4. Submission of Matters to a Vote of Security Holders . . . . . 32
PART II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters. . . . . . . . . . . . . 33
Item 6. Selected Financial Data (Unaudited) . . . . . . . . . . . . . 34
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations . . . . . . . 35
Information Regarding Forward Looking Statements . . . . . . . 42
Item 8. Financial Statements and Supplementary Data. . . . . . . . . . 43
Item 9. Disagreements on Accounting and Financial Disclosure . . . . . 43
PART III
Item 10. Directors and Executive Officers of the Registrant. . . . . . 44
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . 44
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . 44
Item 13. Certain Relationships and Related Transactions. . . . . . . . 44
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K. . . . . . . . . . . . . . . . . . . 45
PART I
Item 1. BUSINESS
GENERAL
Enron Corp. ("Enron"), a Delaware corporation organized in 1930, is
an integrated natural gas 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
gathering, transportation and wholesale marketing of natural gas to
markets throughout the United States and internationally through
approximately 37,000 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 energy related commitments. As of December
31, 1995, Enron employed approximately 6,700 persons.
As used herein, unless the context indicates otherwise, "Enron"
refers to Enron Corp. and its subsidiaries and affiliates.
BUSINESS SEGMENTS
Enron's operations are classified into the following four business
segments:
1) Transportation and Operation: Interstate transmission of natural
gas; construction, management and operation of natural gas and natural
gas liquids pipelines, liquids plants, clean fuels plants and power
facilities; and investment in crude oil transportation activities and
liquids pipeline operations.
2) Domestic Gas and Power Services: Purchasing, marketing and
financing of natural gas, natural gas liquids, crude oil and electric
power; price risk management in connection with natural gas, natural gas
liquids, crude oil and electric power transactions; intrastate natural
gas pipelines; development, acquisition and promotion of natural gas-
fired power plants in North America; and extraction of natural gas
liquids in North America.
3) International Gas and Power Services: 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, 1993 through December 31, 1995, please see Note 17 to
the Consolidated Financial Statements on page F-21.
TRANSPORTATION AND OPERATION
Interstate Pipelines
Enron and its subsidiaries operate domestic interstate 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; FGT, the State of
Florida; and Transwestern, principally the California market and pipeline
interconnects on the east end of the Transwestern system. 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. Also, Enron has an approximately 15% interest in Enron Liquids
Pipeline, L.P., which is engaged in pipeline transportation of natural
gas liquids, refined petroleum products and carbon dioxide, operates coal
terminalling, gas processing and natural gas liquids fractionation
facilities, and is operated by a wholly-owned subsidiary of Enron.
Northern Natural Gas Company. Through its approximately 17,000-mile
natural gas pipeline system stretching from Texas to Michigan's Upper
Peninsula and the Canadian Border, 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 2,001 trillion British thermal units ("Tbtu") in 1995,
compared to 1,996 Tbtu in 1994. In its traditional market area,
Northern's throughput increased to 836 Tbtu in 1995 from 819 Tbtu in
1994. 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 1,177 Tbtu in
1994 to 1,165 Tbtu in 1995 due to lower gathering volumes.
Gas gathering is no longer an activity that is needed to support
Northern's former merchant service nor is it a means necessary to attach
gas supplies to support Northern's other transportation and storage
services. In 1994 Northern filed an application with the FERC requesting
authority to abandon its gathering assets in the Anadarko, Permian,
Hugoton and Rocky Mountain areas by sale to certain non-jurisdictional
affiliates pursuant to certain provisions of the Natural Gas Act. On
November 29, 1995, Northern's FERC application was granted, and shortly
thereafter Northern completed the transfer of all of its gathering assets
to non-jurisdictional affiliates. Sales of a substantial portion of
these gathering assets were made by Enron affiliates to third parties at
year-end 1995.
Northern's application with the FERC filed in December 1994 for
authority to construct, operate and modify certain compressor stations
and town border stations in Iowa, Illinois and Wisconsin to expand
capacity on Northern's system in those areas was granted in June 1995.
These facilities were designed to provide incremental firm capacity on a
portion of Northern's mainline system extending east from the Ogden, Iowa
compressor station through the Waterloo, Iowa and Galena, Illinois
compressor stations terminating near Eagle, Wisconsin (Northern's "East
Leg") in order to transport gas which is to be utilized for natural gas
requirements in various shippers' market areas in Iowa, Illinois and
Wisconsin. These facilities increase the daily flow rate on the East Leg
by approximately 72,200 million British thermal units per day ("MMBtu")
for the 1995-1996 heating season and approximately 35,400 MMBtu per day
for delivery to markets in 1996, for a total increase in capacity on the
East Leg of 107,600 MMBtu per day. The 1995-1996 facilities were
completed in November 1995.
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 2,660-mile pipeline system, Transwestern
transports natural gas from West Texas, Oklahoma, eastern New Mexico and
the San Juan Basin in northwest New Mexico 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 is currently held by shippers
on a firm basis, although approximately 457 million cubic feet ("Mmcf")
of firm capacity will be turned back to Transwestern on November 1, 1996.
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. The
settlement also included approval of Transwestern's proposal to transfer
its production and gathering facilities to Transwestern Gathering Company
("TGC"), a wholly-owned, non-regulated subsidiary of Transwestern. The
FERC approved Transwestern's settlement on July 27, 1995, and the
transfer of production and gathering facilities to TGC occurred on
September 1, 1995. Subsequently, most of these facilities have been sold
by TGC to third parties.
Transwestern's mainline capacity includes a lateral pipeline to the
San Juan Basin in northwestern New Mexico which allows Transwestern to
(i) access the San Juan Basin for gas supply, (ii) service northern
California markets, (iii) access the central California enhanced oil
recovery market and (iv) enhance its ability to deliver to markets east
of California. Total throughput volumes to California averaged
approximately 463 Mmcf per day in 1995, compared to 706 MMcf per day in
1994.
Transwestern has firm transportation service on the east end of its
system and transports Permian and San Juan Basin supplies into Texas,
Oklahoma and the midwestern United States. During 1995, Transwestern
made certain modifications to its mainline system which for the first
time allowed San Juan Basin volumes to physically flow from the San Juan
Basin to the east end of the Transwestern system. Transwestern
transported an average of 625 Mmcf per day off the east end of its system
in 1995, as compared 388 MMcf per day in 1994 and 312 MMcf per day in
1993.
On October 4, 1995 Transwestern filed an application with the FERC
seeking authorization to expand the capacity of its San Juan lateral
pipeline from 520 MMcf per day to 795 MMcf per day on a peak day basis.
In its application, Transwestern also proposed to acquire a 78% ownership
interest in Northwest Pipeline Company's ("Northwest") La Plata
facilities, which consist 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. If approved by the FERC, this project
will give Transwestern direct access to additional gas supplies in the
San Juan Basin. Regulatory approval is expected to be received in time
to meet a projected January 1, 1997 in-service date.
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 5,300-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. In July 1987, FGT placed
its Phase I expansion in service, increasing its firm average delivery
capacity from 725 billion British thermal units ("BBtu") per day to 825
Bbtu per day. In December 1991, FGT placed its Phase II expansion in
service, increasing its firm average delivery capacity by 100 BBtu per
day to a total of 925 BBtu per day. In response to continued growth in
demand for natural gas, 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. These measures
were a continuation of FGT's efforts to meet increased natural gas demand
in Florida through expansions of its system. The Phase III expansion
increased FGT's firm average delivery capacity into Florida by 532 BBtu
per day to 1,457 BBtu per day. The Phase III expansion includes in
excess of 800 miles of new FGT pipeline facilities, 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. The construction of a new pipeline serving peninsular Florida
would require significant capital expenditures and appropriate
environmental and other regulatory approvals. While these hurdles are
significant, FGT's market is attractive and may be sought by competitors.
Because of the firm transportation agreements in effect for the existing
capacity and the Phase III facilities, FGT does not believe that any new
pipelines, if they are proposed and built, will affect usage of its
existing capacity in the near term. Any proposed pipelines could have a
negative effect on FGT's ability to expand beyond Phase III and could
result in competition for the Phase III facilities when the Phase III
transportation agreements begin to expire.
FGT also 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".
In 1995, FGT held an "open season" for a Phase IV expansion and
received a number of requests. FGT is currently contemplating a minor
expansion in 1998 in view of the large portion of the requested capacity
that has been acquired by shippers in the secondary market.
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 a 969-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's revenues are derived
from agreements for the receipt and delivery of gas at points along the
pipeline system as specified in each shipper's individual transportation
contract. Northern Border transports gas for shippers under a tariff
regulated by the FERC that allows it to recover operations and
maintenance costs of the pipeline system, taxes other than income taxes,
interest, depreciation and amortization, an allowance for income taxes
and a regulated equity return.
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, 1995, Northern Border had firm transportation service
agreements, other than those under temporary release, 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 capacity is
contracted by interstate pipelines. The remaining capacity is contracted
to producers, marketers and local distribution companies. Enron Capital
& Trade Resources Corp., along with other marketing affiliates of the
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. In February 1995, Northern Border filed a certificate
application with the FERC for a proposed project that would expand the
current pipeline system and extend 263 miles of pipeline from Harper,
Iowa, to Griffith, Indiana. On October 13, 1995, Northern Border filed
an amendment to its application 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) 35 miles of 42-inch and 147 miles of 36-inch
pipeline loop; (d) a total of 293,000 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 $800 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. The
application seeks FERC authorization for a projected in-service date of
the facilities of the spring of 1998. Numerous parties have intervened
in this proceeding, six of which have filed protests on business issues.
Enron Liquids Pipeline, L.P. Enron owns approximately 15% of Enron
Liquids Pipeline, L.P., a Delaware limited partnership formed in 1992.
An Enron subsidiary serves as general partner and operates the
partnership's two interstate common carrier natural gas liquids ("NGL")
pipeline systems, and one carbon dioxide pipeline system. The
partnership also owns and operates a gas processing plant and the Cora
Terminal, a high speed, rail to barge coal transfer facility, and also
owns a 25% interest in an NGL fractionator. The North System of Enron
Liquids Pipeline, a 1,600-mile interstate common carrier NGL and refined
petroleum products pipeline system, transports, stores and delivers a
full range of NGLs and refined products from south central Kansas to
markets in the Midwest and has interconnects, using third party
pipelines, to the eastern United States. The Cypress Pipeline transports
ethane from Mont Belvieu, Texas to the Lake Charles, Louisiana area. The
Central Basin Pipeline transports carbon dioxide in West Texas for use in
enhanced oil recovery operations in the Permian Basin of West Texas. The
Painter gas processing plant, located in southwestern Wyoming, processes
natural gas for the extraction of natural gas liquids. The Cora Terminal
stores coal and transfers coal mined in southern Illinois from railcars
to barges that transport it to end users, principally for electricity
generation.
The North System and the Cypress Pipeline are interstate common
carrier pipelines, subject to regulation by the FERC. As an interstate
common carrier, the partnership offers interstate transportation services
by means of the North System and Cypress Pipeline to any shipper of NGLs
who requests such services, provided that the products tendered for
transportation satisfy the conditions and specifications contained in the
applicable tariff. The Central Basin Pipeline is not subject to rate
regulation.
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. Cogeneration is the simultaneous production of
thermal energy (primarily steam) and electricity from a single fuel
source, such as natural gas. A conventional electric power plant
produces electricity and discharges resulting exhaust heat as waste.
Cogeneration uses this previously wasted heat to create steam for
industrial use and electricity, requiring less fuel than other methods
using separate electric and thermal energy plants. 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 Operations Corp. ("EOC"), a
wholly owned subsidiary, provides worldwide power plant and natural gas
pipeline engineering expertise, construction management and technical
support and currently operates plants in the United Kingdom, the
Philippines and Guatemala. Among these facilities is the 1,875 megawatt
Teesside, U.K. power facility. EOC also has projects underway in India,
Colombia, China and Russia, and is negotiating contracts for proposed
projects in Turkey, Puerto Rico, Pakistan, Indonesia and the U.K. It
also offers services for third party start-up, operation and maintenance.
(See "International Gas and Power Services" for a general description of
Enron's international power and pipeline businesses).
In North America, Enron subsidiary companies manage the physical
operation of a 340-megawatt facility located in Pasadena, Texas, a 450-
megawatt facility located in Texas City, Texas, a 250-megawatt facility
located in Richmond, Virginia, and a 149-megawatt facility located in
Milford, Massachusetts. EOC also operates Houston Pipe Line Company and
Louisiana Resource Company, both intrastate pipelines. See "Domestic Gas
and Power Services".
Crude Oil Transportation Services
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 50%
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 285 owned or
leased trucks, and by pipeline, including approximately 1,650 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 251,000
barrels per day of lease crude oil during 1995. On January 1, 1996, EOTT
purchased for approximately $54 million certain pipeline, transportation,
storage and crude oil gathering assets (and related crude oil inventory)
in Alabama and Mississippi from Amerada Hess Corporation.
In 1995, EOTT discontinued its West Coast processing and asphalt
marketing businesses and recorded a charge in the second quarter of 1995
to reflect the estimated cost of exiting this business segment. EOTT is
still engaged in the marketing of refined petroleum products and natural
gas liquids on the West Coast.
DOMESTIC GAS AND POWER SERVICES
The domestic gas and power services segment includes Enron Capital &
Trade Resources Corp. and affiliated companies ("ECT") and the domestic
gas processing operations. ECT includes the marketing, purchasing and
financing of natural gas, natural gas liquids ("NGL") and electric power
and the management of the portfolio of commitments arising from these
activities. The domestic gas processing operations consist of the
extraction and fractionation of NGLs.
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 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 sales volumes for 1995 averaged 41.2 trillion
British thermal units ("Tbtu") of natural gas equivalents per day
compared to 23.9 Tbtu of natural gas equivalents per day in 1994.
Included in these amounts are physical volumes of approximately 8.2 Tbtu
per day in 1995 and 7.5 Tbtu per day in 1994.
The intrastate pipelines included in ECT are Houston Pipe Line
Company ("HPL") and Louisiana Resources Company. HPL owns an
approximately 5,500-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 four 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 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.
ECT's power business is responsible for the commercial management of
the 340-megawatt facility located in Pasadena, Texas, the 450-megawatt
facility located in Texas City, Texas, the 250-megawatt facility located
in Richmond, Virginia, and the 149-megawatt facility located in Milford,
Massachusetts. Enron has an indirect 50% ownership interest in each of
these facilities.
ECT's operations also include the North American NGL marketing
activities and the "clean fuels" business which consists of the methanol
and methyl tertiary butyl ether (MTBE) businesses. ECT affiliates market
the output of Enron's NGL and clean fuels plants as well as product
purchased from third parties.
Risk Management. The risk management activities consist of market
origination activity on long-term contracts (transactions greater than
one year) and restructuring of existing long-term contracts. ECT works
closely with utilities, local distribution companies and independent
power producers to restructure contracts for gas supply. ECT's fixed
price contract originations were 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 finance operations provide capital to customers
through various product offerings including volumetric production
payments. The finance business offers debt and equity capital for the
energy industry and develops capital funding vehicles that support its
financial product offerings. It also manages ECT's relationship in the
gas supply area. In 1995, ECT provided $382 million in funding. Of this
amount, Joint Energy Development Investments Limited Partnership, a Delaware
limited partnership formed in 1993, comprised of an ECT subsidiary as general
partner and the California Public Employees Retirement System as limited
partner, has provided approximately $271 million for energy investments.
Domestic Gas Processing
Certain Enron subsidiaries are engaged domestically in the extraction
of NGLs (ethane, propane, normal butane, isobutane and natural gasoline).
NGLs are typically extracted from natural gas in liquid form under low
temperature and high pressure conditions. Among other uses, ethane,
propane, normal butane, isobutane and natural gasoline are used as
feedstocks for petrochemical plants in the production of plastics,
synthetic rubber and other products. Normal butane and natural gasoline
are used by refineries in the blending of motor gasoline. Isobutane is
used in the alkylation process to enhance the octane content of motor
gasoline and is also used in the production of MTBE, which is used to
produce cleaner burning motor gasoline. Propane is used as fuel for home
heating and cooking, crop drying and industrial facilities and as an
engine fuel for vehicles, and ethane is used as a feedstock for synthetic
fuels production. Enron's subsidiaries engaged in gas processing
operations extracted as NGLs the equivalent of an estimated 39 Bcf of
natural gas during 1995. At December 31, 1995, Enron's gas processing
businesses had an interest in 14 hydrocarbon extraction and fractionation
facilities, 12 of which are operated by Enron, which generally are
located along Enron's natural gas pipeline systems. During 1995, Enron's
plants extracted 1.1 billion gallons of NGLs. A total of 242 million
gallons of product were fractionated for affiliates and others.
INTERNATIONAL GAS AND POWER SERVICES
Enron's international activities principally involve the development,
acquisition, promotion, and operation of natural gas and power projects
and the marketing of natural gas liquids and other liquid fuels. In
addition, ECT has established commercial marketing offices in London and
Buenos Aires to offer the same type of physical commodity products,
financial services and risk management services currently available
through ECT in North America. As is the case in the United States,
Enron's emphasis is on businesses in which natural gas or its components
play a significant role. 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.
Enron's international activities include management of direct and
indirect ownership interests in and operation of power plants in England,
Germany, Guatemala, the Philippines and China; a pipeline system in southern
Argentina; 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, 1995, Enron had a 42.5% ownership interest in an
independent power facility with a capacity of approximately 1,875
megawatts at ICI Chemicals & Polymers Limited's Wilton Works Plant on
Teesside in northeast England. The gas-fired combined cycle project was
originated, 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 contributed by Enron in two power plants in the Philippines, a
power plant in Guatemala and a natural gas pipeline system in Argentina
(see below). Upon completion of a public offering of 10 million Common
Shares of EPP in November 1994, Enron owned approximately 52% of the
Common Shares. Enron formed EPP to attract public equity capital to
emerging market infrastructure projects, to enable public investors to
better evaluate and participate directly in the growth of Enron's
operating power plant and natural gas pipeline activities in emerging
markets and to generate additional capital for Enron to reinvest in
future development efforts and for other corporate purposes.
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 any power plant 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.
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.
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.
Enron Development Corp.
Enron Development Corp. is involved in power and pipeline projects in
varying stages of development, financing or construction in India, China,
the Dominican Republic, Colombia, Puerto Rico, Turkey, Bolivia and Brazil
and elsewhere. The following is a brief description of power and natural
gas pipeline projects which, upon commencement of commercial operations
and completion of financing arrangements, may be offered for sale to EPP
subject to the terms of the Enron/EPP Purchase Right Agreement. These
projects 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 dated December
8, 1993, as amended, between Dabhol Power Company, Enron's 80%-owned
subsidiary, and the Maharashtra State Electricity Board (the MSEB),
Dabhol Power Company has been developing Phase I electricity generating
power plant south of Bombay, State of Maharashtra, India. Financial
closing occurred and project construction began on March 1, 1995.
In August 1995, after a new governing coalition was elected in the State
of Maharashtra, the State government of Maharashtra took steps to stop
construction and cancel the project. Dabhol Power Company initiated
arbitration procedures in London, and renegotiation efforts began in
Bombay. In February 1996, Dabhol Power Company, the State government
and the MSEB reached a preliminary agreement, subject to full governmental
and lender approvals which are currently being sought, to go forward
with an expanded project. Phase I will now have an initial capacity of
826 megawatts and will burn naptha (or distillate if naptha is not available)
as fuel, with potential expansion up to 2,450 megawatts. It is anticipated
that the final phase will be fueled with imported liquefied natural gas.
Enron has an 80% equity interest in the project, while Bechtel
Enterprises Inc. and GE Capital Corp. each have a 10% equity interest.
At or before completion of the project, Enron expects to sell 30% of
its interest in the project to a third party, and has offered such 30%
interest to the MSEB. See Item 3, "Legal Proceedings".
China. In January 1996, Enron completed construction of a 154-megawatt
diesel or gas-fired 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. Enron 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. Under the terms of the
power purchase agreement signed with Hainan Electric Power Company in
September 1994, the facility has begun to sell 80 megawatts of
combined-cycle power to the utility. The remaining 74 megawatts from the
facility is expected to be sold to the utility in two phases during 1996.
Dominican Republic. A limited partnership in which Enron affiliated
companies have a 50% ownership interest has signed a 19-year power
purchase agreement with the Dominican Republic government utility in
connection with the development of a 185-megawatt barge-mounted combined
cycle power plant on the north coast of the Dominican Republic. The
partnership serves as operator and fuel manager of the plant. Commercial
operation commenced in January 1996.
Colombia. Construction has been completed and commercial operations
commenced in February 1996 on Enron's approximately 357-mile natural
gas pipeline and related facilities project, which pipeline runs from
the northern coast of Colombia to the central region of the country.
Ecopetrol, the state-owned oil company of Colombia, has contracted to be
the sole customer for the transportation services and has a 15-year
commitment to pay for all of the initial capacity.
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 is
the turnkey contractor and operator of the project, construction of
which is expected to commence in 1996, with commercial operation
anticipated in early 1998.
Turkey. Enron holds a 50% interest in a 478-megawatt gas-fired
power plant to be located in Marmara, Turkey. Enron will be operator
and turnkey contractor of the plant. A power purchase agreement
has been signed with the state power utility, and subject to financing,
construction is expected to begin in 1996, with commercial operation
expected 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 a 1,120-mile natural gas pipeline from
Santa Cruz, Bolivia to Sao Paulo, Brazil. Enron is also negotiating
the development of up to 1,600 megawatts of power projects with
Sao Paulo utilities. Enron will own 34% of the Bolivia segment of
the pipeline, 8% of the Brazilian segment of the pipeline and will
hold a significant interest in the power plants.
In addition to the projects referenced above, EDC is involved in
projects in varying stages of development in Pakistan, Italy and
Indonesia. EDC also has signed preliminary agreements on power and
pipeline projects in Bolivia, Brazil, Poland and Mozambique, and is
pursuing projects in Vietnam, Thailand, the Philippines and elsewhere.
Caribbean Basin. Enron's operations in the Caribbean area are
conducted through Enron Americas 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. In late 1993 Enron consolidated the management of
its international liquids marketing business with the corresponding
domestic activities, in order 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 464
million gallons in 1994 to 779 million gallons in 1995.
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 60% 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, 1995, EOG
had estimated net proved natural gas reserves of 3,343 Bcf, including
1,180 Bcf of proved undeveloped methane reserves in the Big Piney
(Wyoming) deep Paleozoic formations and amounts related to a volumetric
production payment, and estimated net proved crude oil, condensate and
natural gas liquids reserves of 50 million barrels, and at such date,
approximately 78% of EOG's reserves (on a natural gas equivalent basis)
was located in the United States, 10% in Canada, 8% in Trinidad and 4% in
India.
EOG's seven principal U.S. producing areas are the Big Piney area in
Wyoming, the South Texas area, the East Texas area, offshore Gulf of
Mexico area, the Canyon Trend area located in West Texas, the Pitchfork
Ranch area in southwestern New Mexico, and the Vernal area in Utah.
Properties in these areas comprised approximately 67% of EOG's U.S.
reserves (on a natural gas equivalent basis) and 90% of EOG's maximum
U.S. net natural gas deliverability as of December 31, 1995 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, California and Kansas.
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
operations from offices in Calgary. Canadian natural gas deliverability
net to EOG at December 31, 1995 was approximately 95 Mmcf per day, and
EOG held approximately 347,000 net undeveloped acres in Canada.
EOG also has producing operations offshore Trinidad and India and was
recently 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, and 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 1995.
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 1995,
deliveries net to EOG averaged 107 MMcf per day of natural gas and 5.1
MBbl per day of crude oil and condensate. At December 31, 1995, natural
gas deliverability net to EOG was approximately 170 MMcf per day and EOG
held approximately 71,000 net undeveloped acres in Trinidad.
In 1995, EOG was awarded the right to develop the U(a) block adjacent
to the SECC Block and is presently negotiating the terms of a production
sharing contract with the Government of Trinidad and Tobago.
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. EOG is designated operator of all
three areas. 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 Black 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 30 wells producing from five producing
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, 1995; all associated gas was being 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. Plans
include the completion of a 3-D seismic survey over the most prospective
portions of the block in 1996 and initiation of drilling in 1997, with
production targeted for mid-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 indigenous 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 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 may jointly hold up to a 40% equity interest in the joint venture and
EOG would drill and develop to-be-agreed-upon reserves. In addition, EOG
signed nonbinding letters of intent in early 1995 with Uzbekneftigaz, the
national oil and gas company of Uzbekistan, and Gazprom, the Russian
natural gas company, to pursue the feasibility of joint venture
development and marketing of previously discovered hydrocarbon reserves
in Uzbekistan. EOG is also participating in discussions concerning the
potential for conventional oil and gas development opportunities in
China, Mozambique, Jordan and Algeria. EOG also holds non-operating
working interests in two conventional oil and gas exploration prospects
in the U.K. North Sea.
EOG continues evaluation and assessment of its international
opportunity portfolio in the coalbed methane recovery arena, including
projects in South Wales in the U.K., 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, as well as increased competition from
Canadian natural gas.
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, 1995:
[Download Table]
Year Ended December 31,
1995 1994 1993
Volumes (per day)
Natural Gas (MMcf)
United States(1) 560 614 649
Canada 76 72 58
Trinidad 107 63 2
Total 743 749 709
Crude Oil and Condensate (MBbl)
United States 9.1 8.0 6.6
Canada 2.4 2.0 2.2
Trinidad 5.1 2.5 .1
India 2.5 .1 -
Total 19.1 12.6 8.9
Natural Gas Liquids (MBbl)
United States 1.0 .3 .2
Canada .4 .4 .4
Total 1.4 .7 .6
Average Prices
Natural Gas ($/Mcf)
United States(2) $ 1.39 $ 1.71 $ 1.97
Canada .97 1.42 1.34
Trinidad .97 .93 .89
Composite 1.29 1.62 1.92
Crude Oil and Condensate ($/Bbl)
United States $17.32 $16.06 $ 16.96
Canada 16.22 14.05 14.63
Trinidad 16.07 15.50 14.36
India 16.81 15.70 -
Composite 16.78 15.62 16.37
Natural Gas Liquids ($/Bbl)
United States $11.88 $12.45 $ 13.85
Canada 9.74 8.45 9.46
Composite 11.31 9.90 11.12
Lease and Well Expenses ($/Mcfe)
United States $ .19 $ .19 $ .18
Canada .35 .34 .48
Trinidad .15 .17 1.46
India(3) 1.25 .13 -
Composite .22 .20 .21
___________________
<FN>
(1) Includes 48 MMcf per day in 1995 and 1994, and 81 MMcf per day in 1993
delivered under the terms of a volumetric production payment agreement
effective October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of $.80 per Mcf in 1995,
$1.27 per Mcf in 1994, and $1.57 per Mcf in 1993 for the volumes
described in note (1), net of transportation costs.
(3) Based on expense estimates for nine days of production for 1994.
Expenses for 1995 include certain non-recurring startup costs.
The following table sets forth certain information regarding EOG's
volumes of natural gas delivered under other marketing and volumetric
production payment arrangements, and resulting average per unit gross revenue
and per unit amortization of deferred revenues along with associated costs
during each of the three years in the period ended December 31, 1995.
[Download Table]
Year Ended December 31,
1995 1994 1993
Volumes (MMcf per day)(1) . . . . . 264 324 293
Average Gross Revenue ($/Mcf)(2) . . $ 1.88 $ 2.38 $ 2.57
Associated Costs ($/Mcf)(3)(4) . . 1.51 2.06 2.32
Margin ($/Mcf) . . . . . . . . . . $ .37 $ 0.32 $ 0.25
___________________
<FN>
(1) Includes 48 MMcf per day in 1995 and 1994 and 81 MMcf per day in 1993
delivered under the terms of volumetric production payment and exchange
agreements 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 1995 and 1994 and $2.50 per Mcf ($2.40 per million
British thermal units) in 1993.
(3) Includes an average value of $1.57 per Mcf in 1995, $1.92 per Mcf in
1994 and $2.20 per Mcf in 1993 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, 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.
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.
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.
In June 1988, the FERC issued Order No. 497 ("Order 497") which
imposes requirements on interstate pipelines with marketing affiliates,
intended to eliminate an interstate pipeline's ability to give its
marketing affiliates preferential treatment. Among other things, Order
497 requires interstate pipelines to separate their operating personnel
and facilities from those of their marketing affiliates to the maximum
extent practicable. In 1994, the FERC issued Order Nos. 566, 566-A and
566-B, in which it extended indefinitely its Order No. 497 regulations
governing relationships between interstate pipelines and their marketing
affiliates, subject to revisions to delete an out of date standard and
revise certain reporting and record keeping requirements. Among other
matters, these new rules require pipelines to post on their electronic
bulletin boards, within 24 hours of gas flow, information concerning
discounted transportation provided to marketing affiliates to enable
competing marketers to request comparable discounts. The rules retain
existing standards, as revised by Order No. 497-E, requiring the
contemporaneous disclosure to all shippers of transportation related
information provided to a marketing affiliate, and prohibiting disclosure
of certain information to marketing affiliates.
Since 1985, the FERC has endeavored to make 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. Various aspects of Order
No. 636 were challenged, including alleged shifts of costs between
pipeline customer groups and the continuing reliability of unbundled
services. In two subsequent orders on rehearing of Order No. 636 (Order
Nos. 636-A and 636-B), the FERC modified the original order in response
to these and other concerns. Numerous parties filed petitions for court
review of Order Nos. 636, 636-A and 636-B, as well as orders in
individual pipeline restructuring proceedings. Oral arguments before the
District of Columbia Circuit Court of Appeals were heard in late February
1996. Upon judicial review, these orders may be reversed in whole or in
part. With Order No. 636 subject to court review, it is difficult to
predict with precision its ultimate effects.
Order Nos. 636, 636-A and 636-B 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 Order Nos.
636, 636-A and 636-B 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 Order Nos. 636, 636-A, and 636-B.
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, 1995 are approximately $291
million, which include transition costs incurred related to FERC Order
No. 636 of approximately $125 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.
Natural gas gathering may receive greater regulatory scrutiny
at both the state and federal levels as the pipeline restructuring under
Order No. 636 is fully completed and implemented. In late 1993, the FERC
convened a conference to consider issues relating to gathering services
performed by interstate pipelines or their affiliates. Commencing in May
1994, the FERC issued a series of orders in individual cases that
delineate its gathering policy as a result of the comments received.
Among other matters, the FERC slightly narrowed its statutory tests for
establishing gathering status and reaffirmed that, except in situations
in which the gatherer acts in concert with an interstate pipeline
affiliate to frustrate the FERC's transportation policies, it does not
have jurisdiction over natural gas gathering facilities and services and
that such facilities and services are properly regulated by state
authorities. This FERC action may further encourage regulatory scrutiny
of natural gas gathering by state agencies. In addition, the FERC has
approved several transfers by interstate pipelines, including certain of
Enron's pipeline subsidiaries, of gathering facilities to unregulated
independent or affiliated gathering companies. This could increase
competition among gatherers in the affected areas. Certain of the FERC's
orders delineating its new gathering policy are subject to pending court
appeals.
Enron cannot predict the effect that any of the aforementioned
orders or the challenges to such orders will ultimately have on Enron's
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. It should also be noted that the
natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less regulated approach
currently being pursued by the FERC will continue indefinitely. Thus,
Enron cannot predict the ultimate outcome or durability of the unbundled
regulatory regime mandated by Order No. 636.
The rates at which natural gas is sold in Texas to gas utilities
serving customers within an incorporated area and directly to customers
in rural and unincorporated areas 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.
Oil Pipeline Rates and Regulations
The North System and Cypress Pipeline of Enron Liquids Pipeline
Operating Limited Partnership (the "Partnership") are interstate common
carrier pipelines, subject to regulation by the FERC under the Interstate
Commerce Act ("ICA"). The ICA requires the Partnership to maintain
tariffs on file with the FERC, which tariffs set forth the rates the
Partnership charges for providing transportation services on the
interstate common carrier pipelines, as well as the rules and regulations
governing these services.
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 ("PRPs") with respect to the cleanup of
one Superfund site. 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 thousands of dollars.
[Download Table]
Year Ended December 31,
1995 1994 1993
ECT Natural Gas and Crude Oil
Physical/Notional Quantities (BBtue/d)*
Firm 5,392 4,895 4,558
Interruptible 2,255 2,039 828
Transport Volumes 580 538 571
Subtotal 8,227 7,472 5,957
Financial Settlements (notional) 32,938 16,459 5,027
Total 41,165 23,931 10,984
Electricity (Thousand megawatt hours)
Owned Production 3,441 3,481 2,883
Transaction Volumes Marketed 7,767 1,221 -
<FN>
*Includes intercompany amounts
[Download Table]
Revenues by Business Segment
Year Ended December 31,
1995 1994 1993
Transportation and Operation
Natural Gas and Other Products
Unaffiliated $ 49,223 $ 87,670 $ 453,621
Intersegment 4,409 9,455 22,779
53,632 97,125 476,400
Transportation Services
Unaffiliated 680,338 740,606 751,896
Intersegment 20,353 25,395 35,841
700,691 766,001 787,737
Other Revenues
Unaffiliated 75,384 109,248 180,408
Intersegment 848 3,906 21,461
76,232 113,154 201,869
TOTAL 830,555 976,280 1,466,006
Domestic Gas and Power Services
Natural Gas and Other Products
Unaffiliated 6,289,982 6,633,039 5,214,870
Intersegment 9,715 59,684 95,934
6,299,697 6,692,723 5,310,804
Transportation Services
Unaffiliated 11,364 13,511 16,015
Intersegment 352 1,041 506
11,716 14,552 16,521
Other Revenues
Unaffiliated 762,405 519,032 219,061
Intersegment (113,043) (47,333) 37,718
649,362 471,699 256,779
TOTAL 6,960,775 7,178,974 5,584,104
International Gas and Power Services
Natural Gas and Other Products
Unaffiliated 779,605 337,917 598,472
Intersegment 4,275 983 12,697
783,880 338,900 611,169
Other Revenues
Unaffiliated 59,520 54,002 152,903
Intersegment 39,482 6,001 6,516
99,002 60,003 159,419
TOTAL 882,882 398,903 770,588
Exploration and Production
Natural Gas and Other Products
Unaffiliated 410,548 431,907 364,643
Intersegment 164,818 242,008 280,363
575,366 673,915 645,006
Other Revenues
Unaffiliated 70,629 56,791 33,911
Intersegment 113,373 48,082 28,208
184,002 104,873 62,119
TOTAL 759,368 778,788 707,125
Intersegment Eliminations (244,583) (349,222) (542,023)
Total Revenues $9,188,997 $8,983,723 $7,985,800
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
Name and Age Present Principal Position and Other Material
Positions Held During Last Five Years
Kenneth L. Lay (53) Chairman of the Board and Chief Executive Officer
since February 1986.
Richard D. Kinder (51) President and Chief Operating Officer since October
1990.
Rodney L. Gray (43) President of Enron Global Power & Pipelines L.L.C.
since November 1995. Chairman and Chief Executive
Officer of Enron Global Power & Pipelines L.L.C.
since June 1995. Managing Director, Enron
Development Corp., since August 1995. Chairman and
Chief Executive Officer, Enron International Inc.,
since June 1993. 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 (46) Co-Chairman and Chief Executive Officer of Enron
Operations Corp. since February 1996. 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.
Jeffrey K. Skilling (42) Chairman, Chief Executive Officer and Managing
Director of Enron Capital & Trade Resources Corp.
since June 1995. Managing Director, Development,
Enron Capital & Trade Resources Corp., from
December 1994 to June 1995. Chairman and Chief
Executive Officer (Risk Management and Power),
Enron Gas Services Corp., from June 1993 to
December 1994. Chairman and Chief Executive
Officer of Enron Gas Services Corp. from January
1991 to June 1993. Chairman and Chief Executive
Officer of Enron Finance Corp. since August 1990;
Partner, McKinsey & Company, Consultants, from 1979
to August 1990.
Thomas E. White (52) Co-Chairman and Chief Executive Officer of Enron
Operations Corp. since February 1996. Chairman and
Chief Executive Officer of Enron Operations Corp.
from June 1993 to February 1996. Chairman and
Chief Executive Officer of Enron Power Corp. since
July 1991. Brigadier General, United States Army,
from 1988 to 1990. Executive Assistant to Chairman
of the Joint Chiefs of Staff from 1989 to 1990.
Edmund P. Segner,III(42) Executive Vice President and Chief of Staff since
October 1992. Senior Vice President, Investor,
Public & Government Relations from October 1990 to
October 1992.
James V. Derrick, Jr.(51) Senior Vice President and General Counsel since
June 1991. Partner, Vinson & Elkins from January
1977 until June 1991.
Jack I. Tompkins (50) Senior Vice President and Chief Information,
Administrative and Accounting Officer since October
1992. Senior Vice President and Chief Financial
Officer from January 1988 to October 1992.
Partner, Arthur Andersen & Co. from September 1981
until January 1988.
Kurt S. Huneke (42) Vice President, Finance and Treasurer since July
1993. Executive Vice President, Finance and
Administration, Enron International Inc., from July
1992 to July 1993. Senior Vice President and Chief
Financial Officer, Enron Europe Limited, from
January 1991 to July 1992. Assistant Treasurer,
Enron Corp., from February 1989 to January 1991.
Item 2. PROPERTIES
Gas Transmission and Liquid Fuels
Enron's natural gas facilities include approximately 37,000 miles of
transmission and gathering lines, 110 mainline compressor stations, four
underground gas storage fields and two liquefied natural gas storage
facilities. Other properties in which Enron and its affiliates have an
ownership interest or lease include 14 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 gathering and 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 18 to the Consolidated Financial Statements.
Estimates of proved and proved developed reserves at December 31, 1995,
1994 and 1993 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, 1995, 1994 and 1993 covering producing areas containing
73%, 59% and 65%, respectively, of proved 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. Such estimates by DeGolyer and MacNaughton in the aggregate
varied by not more than 5% from those prepared by EOG's engineering staff.
All reports by DeGolyer and MacNaughton were developed utilizing geological
and engineering data provided by EOG.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data set forth in Note 18 to the Consolidated Financial
Statements represents only estimates. Reserve engineering is a subjective
process of estimating underground accumulations of natural gas and liquids,
including crude oil, condensate and natural gas liquids, that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a
function of the amount and quality of available data and of engineering and
geological interpretation and judgment. As a result, estimates of different
engineers normally vary. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revision of such
estimate. Accordingly, reserve estimates are often different from the
quantities ultimately recovered. The meaningfulness of such estimates is
highly dependent upon the accuracy of the assumptions upon which they were
based.
In general, the volume of production from oil and gas properties owned
by EOG declines as reserves are depleted. Except to the extent EOG acquires
additional properties containing proved reserves or conducts successful
exploration and development activities, or both, the proved reserves of EOG
will decline as reserves are produced. Volumes generated from future
activities of EOG are therefore highly dependent upon the level of success in
acquiring or finding additional reserves and the costs incurred in doing so.
EOG's estimates of reserves filed with other federal agencies agree with
the information set forth in Note 18.
Producing Oil and Gas Wells
The following table reflects EOG's ownership at December 31, 1995 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 oil and gas wells include 205 with multiple completions.
[Download Table]
Productive Productive Total
Gas Wells Oil Wells Productive Wells
Gross Net Gross Net Gross Net
4,627 3,170 774 435 5,401 3,605
Acreage
The following table summarizes EOG's developed and undeveloped acreage at
December 31, 1995. Excluded is acreage in which EOG's interest is limited to
owned royalty, overriding royalty and other similar interests.
[Enlarge/Download Table]
Developed Undeveloped Total
Gross Net Gross Net Gross Net
United States
California 10,215 6,368 638,199 637,454 648,414 643,822
Offshore
Gulf of Mexico 315,745 132,505 455,133 352,577 770,878 485,082
Texas 454,256 221,207 272,990 214,233 727,246 435,440
Wyoming 161,867 117,815 316,330 246,758 478,197 364,573
Oklahoma 214,363 72,279 106,074 58,162 320,437 130,441
New Mexico 75,487 35,056 88,013 47,924 163,500 82,980
Utah 57,820 46,512 35,863 30,365 93,683 76,877
Kansas 14,176 9,498 25,055 22,766 39,231 32,264
Colorado 9,153 1,447 35,006 16,755 44,159 18,202
Michigan 11 10 14,213 13,650 14,224 13,660
Mississippi 2,490 1,853 12,171 8,445 14,661 10,298
Montana 1,301 1,169 2,082 1,075 3,383 2,244
Other 15,225 2,831 10,986 5,204 26,211 8,035
Total 1,332,109 648,550 2,012,115 1,655,368 3,344,224 2,303,918
Canada
Alberta 364,328 168,503 192,429 146,739 556,757 315,242
Saskatchew 179,343 155,588 222,975 199,604 402,318 355,192
Manitoba 11,531 9,702 480 480 12,011 10,182
British Columbia 656 164 -- -- 656 164
Total Canada 555,858 333,957 415,884 346,823 971,742 680,780
Other International
Australia -- -- 9,600,000 4,800,000 9,600,000 4,800,000
China -- -- 1,208,805 604,403 1,208,805 604,403
Russia -- -- 1,425,000 712,500 1,425,000 712,500
France -- -- 1,063,925 1,063,925 1,063,925 1,063,925
India 60,000 18,000 602,207 180,662 662,207 198,662
Trinidad 4,200 3,990 74,851 71,108 79,051 75,098
United Kingdom -- -- 173,600 86,800 173,600 86,800
Total Other
International 64,200 21,900 14,148,388 7,519,398 14,212,588 7,541,388
Total 1,952,167 1,004,497 16,576,387 9,521,589 18,528,554 10,526,086
Drilling and Acquisition Activities
During each of the years ended December 31, 1995, 1994 and 1993, EOG
spent approximately $513.8 million, $493.9 million, and $430.1 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:
[Enlarge/Download Table]
Year Ended December 31,
1995 1994 1993
Gross Net Gross Net Gross Net
Development Wells Completed
Gas 337 253.91 558 434.53 579 469.10
Oil 72 58.01 45 34.67 49 22.51
Dry 62 50.16 54 43.65 70 54.43
Exploratory Wells Completed
Gas 11 9.03 22 17.70 28 21.43
Oil 8 3.61 4 3.07 5 3.40
Dry 21 13.28 37 30.67 42 29.43
Total 511 388.00 720 564.29 773 600.30
Wells in Progress at End of
Period 52 32.71 45 28.79 82 61.09
Total 563 420.71 765 593.08 855 661.39
Wells Acquired
Gas 277 101.70* 41 40.90* 44 26.44
Oil 5 .46 60 38.99* - 12.80*
Total 282 102.16 101 79.89 44 39.24
<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 results of operations.
Litigation
In November 1992, TransAmerican Natural Gas Corporation
(TransAmerican) filed a suit in the 93rd District Court, Hidalgo County,
Texas, against Enron Corp. and EOG alleging breach of confidentiality
agreements, misappropriation of trade secrets and unfair competition,
with specific reference to four tracts in Webb County, Texas, which EOG
leased for their oil and gas exploration and development potential.
TransAmerican sought actual damages of $100 million and exemplary damages
of $300 million. EOG filed claims against TransAmerican and its sole
shareholder alleging common law fraud, negligent misrepresentation and
breach of state antitrust laws. On April 6, 1994, Enron Corp. was
granted summary judgment, wherein the court ordered that TransAmerican
take nothing on its claims against Enron Corp. On October 16, 1995, EOG,
TransAmerican and its sole shareholder entered into an agreement which
resolved all claims. The settlement terms did not have a materially
adverse effect on Enron's financial position or results of operations.
The suit was dismissed with prejudice as to all parties by court order
entered November 28, 1995.
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 also sued certain other unaffiliated
third parties (collectively, the Other Defendants). 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 that will be tried (or
otherwise resolved) separately. In the first matter, the Plaintiffs sued
only the Enron Defendants, alleging that they committed fraud and
negligent misrepresentation in connection with the "Panhandle program," a
special marketing program established in the early 1980s. In the second
matter, the Plaintiffs allege that Intratex and the Other 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. In both matters, the Plaintiffs
seek actual and punitive damages, plus prejudgment interest and attorneys
fees. All Defendants deny the Plaintiffs' claims and have asserted
various affirmative defenses, including the statute of limitations. The
Enron Defendants believe they have strong legal and factual defenses, and
intend to vigorously contest the claims brought in each matter. 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.
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.
In connection with FGT's Phase III pipeline expansion, on September
16, 1994, the Florida Department of Environmental Protection (FDEP)
entered an order suspending FGT's construction activities in wetland
areas in Florida alleging that certain construction activities failed to
conform with permits previously issued by that agency. The FDEP also
instituted administrative proceedings for the imposition of civil
penalties for such alleged violations. On September 23, 1994, FGT and
the FDEP entered into a consent order in which the FDEP lifted its
suspension of construction south of Suwannee County, Florida and agreed
to lift its suspension on northern Florida wetlands areas construction
upon FGT's adoption of certain oversight, training and wetlands
restoration and mitigation practices, payment of $210,000 into the FDEP's
Pollution Recovery Fund and reimbursement of another $16,000 in
administrative expenses. The consent order was effective as of September
23, 1994.
On October 7, 1994, the FDEP issued notice of its intention to
assess FGT with an additional civil penalty of $365,400 for alleged
violations of wetlands permits and regulations in northern Florida. FGT
did not contest the alleged violations or civil penalties assessed by the
FDEP, and FGT has paid such penalty. FGT subsequently retrained
construction personnel and took other actions to increase its efforts to
comply with all requirements for construction in wetlands areas. On
November 23, 1994, the FDEP dissolved the September 16 suspension order,
and FGT was authorized to recommence construction in northern Florida.
The Phase III expansion was placed in-service on March 1, 1995.
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 PRP
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. Four of such installments have been paid and the fifth
installment is due and payable in June 1996.
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.
Other
In October 1994, an explosion occurred at Enron's methanol plant
in Pasadena, Texas. Before the explosion, the plant was producing
approximately 420,000 gallons of methanol per day, approximately half of
which was being used at Enron's MTBE plant. There were no fatalities or
serious injuries as a result of the explosion. The plant was placed back
in commercial operation in June 1995. Taking into account business
interruption and casualty insurance coverages, Enron currently
anticipates that the explosion did not and will not have a material
adverse effect on its financial position or results of operations.
In connection with a Power Purchase Agreement dated December 8,
1993, as amended, between Dabhol Power Company, Enron's 80%-owned
subsidiary, and the Maharashtra State Electricity Board (the MSEB),
Dabhol Power Company has been developing Phase I of an electricity
generating power plant south of Bombay, State of Maharashtra, India (the
Project). Financial closing occurred and Project construction began on
March 1, 1995. After construction had begun, and following elections to
the Maharashtra Legislative Assembly, a new coalition government took
office in the State of Maharashtra. The new coalition government
appointed a review committee to study the Project, and on August 3, 1995,
announced the State government's intention to terminate the Project.
Work on the Project was ordered stopped by the MSEB, and construction
ceased on August 8, 1995. Enron believes that such actions were in clear
violation of the contract and in response to these actions, Dabhol Power
Company, pursuant to its remedies in the agreements with the State
government, commenced arbitration proceedings in London against the State
government for the actions it has taken to terminate the Project. Dabhol
Power Company seeks to recover all of its construction and other
expenses, in addition to lost profits. The arbitration tribunal has been
appointed and several arbitration hearings have occurred in London. On
February 7, 1996, the arbitration tribunal issued an interim award on
jurisdiction in favor of Dabhol Power Company. In addition, renegotiation
efforts were begun and in February 1996, Dabhol Power Company, the State
government and the MSEB reached a preliminary agreement, subject to full
governmental and lender approvals which are currently being sought, to
go forward with an expanded project. The arbitration proceedings have
been stayed until May 1, 1996 to allow the parties time to focus on
renegotiation efforts. While the parties are working together in good
faith and Enron anticipates construction to resume in the near future,
various approvals remain outstanding from government agencies and
lenders. Although the outcomes of the arbitration and the renegotiation
processes cannot be predicted with certainty, based on currently
available information, Enron believes that the ultimate outcome of the
Project will not have a materially adverse effect on its financial
position.
In March 1993, Enron entered into long-term gas contracts with
Phillips Petroleum Company United Kingdom Limited, British Gas
Exploration and Production Limited and Agip (U.K.) Limited to purchase
all of the future gas production from the J-Block field which is located
in the North Sea offshore the United Kingdom (the J-Block Contracts).
Such agreements provide for Enron to take or pay for the gas at a fixed
price (with possible escalations throughout the contract period). Gas
paid for, but not taken, may be recovered in later contract years. The
J-Block Contracts provide for a first delivery date of not later than
October 1, 1996. The contract price for such natural gas is in excess of
current spot market prices in the United Kingdom. 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
through September 30, 1997. In addition, in accordance with its
contractual rights, Enron has made no estimated nominations for J-Block
gas to date under the J-Block Contracts for the contract year ending
September 30, 1998. Enron continues its good faith efforts to develop
mutually beneficial solutions regarding pricing terms so that production
from J-Block can begin as soon as possible. Enron believes that there
are many commercial reasons for the parties to resolve any contract
issues, but efforts have not been successful to date. Enron has advised
the J-Block sellers that it intends to assert all legal rights, exercise
all available commercial flexibility and pursue all available commercial
and legal remedies under the J-Block Contracts, and stands ready and
able to perform all legal obligations under the J-Block Contracts,
including potential prepayments for gas to be taken in later years.
The long-term market demand for J-Block gas supply remains favorable
and Enron anticipates being able to meet all of its various short-
and long-term market commitments. Although no assurances can be given,
based upon the foregoing and other information currently available,
Enron does not anticipate that the J-Block Contracts will have a
materially adverse effect on its financial position.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during
the fourth quarter of 1995.
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]
1995 1994
High Low Dividends High Low Dividends
First Quarter............. 34 28 $.20 $34 1/4 $27 3/8 $.1875
Second Quarter............ 36 7/8 32 1/2 .20 34 5/8 28 5/8 .1875
Third Quarter............. 36 3/8 31 5/8 .20 34 28 5/8 .1875
Fourth Quarter............ 39 3/8 33 .2125 33 26 3/4 .20
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]
1995 1994
High Low Dividends High Low Dividends
First Quarter............. $398 $393 $2.7304 $450 $376 3/4 $2.625
Second Quarter............ 491 454 2.7304 455 450 2.625
Third Quarter............. 477 454 2.7304 450 427 2.625
Fourth Quarter............ 502 462 2.901 410 410 2.7304
At December 31, 1995, there were approximately 25,600 record holders of
common stock and 245 record holders of Second Preferred Stock.
Other information required by this item is set forth on page 34 under
Item 6 -- "Selected Financial Data (Unaudited) - Common Stock Statistics" for
the years 1990-1995.
Item 6. SELECTED FINANCIAL DATA (UNAUDITED)
[Enlarge/Download Table]
1995 1994 1993 1992 1991 1990
Operating Revenues (millions) $ 9,189 $ 8,984 $ 7,986 $ 6,415 $ 5,698 $5,460
Total Assets (millions) $13,239 $11,966 $11,504 $10,312 $10,070 $9,849
Common Stock Statistics
Income from continuing operations(a)
Total (millions) $519.7 $453.4 $386.5 $328.8 $232.1 $202.2
Per share - primary $2.07 $1.80 $1.55 $1.39 $1.03 $0.88
Per share - fully diluted $1.94 $1.70 $1.46 $1.30 $0.98 $0.86
Earnings on common stock(a)
Total (millions) $504.3 $438.4 $369.6 $284.1 $207.4 $177.2
Per share - primary $2.07 $1.80 $1.55 $1.29 $1.03 $0.88
Per share - fully diluted $1.94 $1.70 $1.46 $1.21 $0.98 $0.86
Dividends
Total (millions) $204.6 $191.8 $170.5 $148.2 $127.0 $125.0
Per share $0.81 $0.76 $0.71 $0.66 $0.63 $0.62
Shares outstanding (millions)
Actual at year-end 244.8 244.2 241.6 237.2 202.4 201.8
Average for the year 243.7 243.4 239.0 220.0 202.1 201.6
Capitalization (millions)
Long-term debt $3,065 $2,805 $2,661 $2,459 $3,109 $2,983
Preferred stock of subsidiary 377 377 214 - - -
Minority interest 549 290 196 179 101 97
Shareholders' equity 3,165 2,880 2,623 2,518 1,901 1,838
Total capitalization $7,156 $6,352 $5,694 $5,156 $5,111 $4,918
<FN>
(a) The 1993 amounts exclude effects of a $54.0 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%.
Enron Corp. and Subsidiaries
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 1995 was $520 million compared to
$453 million in 1994 and $387 million in 1993 (exclusive of
a primarily non-cash charge of $54 million in 1993 to adjust
the deferred tax liability for the increase in the corporate
Federal statutory income tax rate from 34% to 35%). Net
income for all three years reflects improved income before
interest, minority interest and income taxes as compared to
the applicable preceding year, partially offset by higher
dividends on preferred stock of subsidiaries and income tax
expense.
Primary earnings per share of common stock was $2.07 in 1995
as compared to $1.80 in 1994 and $1.32 in 1993, after a
$0.23 per share charge applicable to the $54 million tax
rate change adjustment.
Income Before Interest, Minority
Interest and Income Taxes
The following table presents income before interest,
minority interest and income taxes (IBIT) for each of
Enron's operating segments:
[Download Table]
(In Millions) 1995 1994 1993
Transportation and Operation $ 359 $403 $382
Domestic Gas and Power Services 157 202 197
International Gas and Power Services 142 148 132
Exploration and Production 241 198 129
Corporate and Other 266 (7) (42)
Total $1,165 $944 $798
Transportation and Operation
The transportation and operation segment includes Enron's
interstate natural gas pipelines, including results of
Northern Natural Gas Company (Northern), Transwestern
Pipeline Company (Transwestern) and Florida Gas Transmission
(Florida Gas), and construction, management and operation of
pipelines, clean fuels plants and power facilities,
including results of Enron Engineering & Construction.
Enron's investment in crude oil marketing and transportation
operations conducted by EOTT Energy Partners, L.P. (EOTT)
and Enron's investment in liquids pipeline operations are
also in this segment.
The following reflects revenues and IBIT for each of these
groups:
[Download Table]
(In Millions) 1995 1994 1993
Revenues
Interstate Natural Gas Pipelines $787 $901 $1,306
Construction, Management and Operation 44 47 37
EOTT - 28 123
Total 831 976 1,466
Cost of gas and other products 39 72 409
Operating expenses 322 442 551
Depreciation and amortization 83 88 116
Taxes, other than income taxes 47 47 49
Equity in earnings of unconsolidated
subsidiaries 23 49 23
Other income, net 79 27 18
Total before fourth quarter charges 442 403 382
Fourth quarter regulatory and
contingency adjustments (83) - -
Income before interest, minority
interest and income taxes $359 $403 $ 382
The segment's IBIT decreased $44 million in 1995 as compared
to 1994 primarily due to lower earnings from the interstate
natural gas pipelines and EOTT and a $19 million charge to
reflect the discontinuance of EOTT's West Coast processing
and asphalt marketing operations, partially offset by gains
of $67 million from the sale of non-strategic gathering and
processing assets. The decrease in earnings from the
interstate natural gas pipelines was primarily due to fourth
quarter charges of $83 million related to regulatory
reserves and other contingencies. The segment realized a $21
million increase in IBIT in 1994 as compared to 1993
primarily due to increased IBIT from the interstate natural
gas pipelines and the construction, management and operation
of assets, partially offset by lower earnings from EOTT
primarily due to the reduced ownership interest in the first
quarter of 1994 resulting from the exchange by EOTT Energy
Corp. of its crude oil trading and transportation operations
for common and subordinated units and a 2% general partner
interest in EOTT. See Note 8 to the Consolidated Financial
Statements. The following discussion analyzes the
significant changes in the various components of IBIT for
the transportation and operation segment, prior to fourth
quarter regulatory and contingency adjustments.
Revenues
Interstate Natural Gas Pipelines. Revenues of the
interstate natural gas pipelines declined $114 million (13%)
during 1995 and $405 million (31%) during 1994 as compared
to the applicable preceding year. The decrease in revenues
from 1994 to 1995 primarily reflects completion of the
recovery of certain transition costs for Northern. The 1994
decline reflects the effect of unbundling services which
reduced sales revenues of Northern as Northern is now
primarily a transporter of natural gas. Transport revenues
declined 9% in 1995 and 2% in 1994 as compared to the prior
year. Transport volumes for Northern and Transwestern
totaled 5.6 trillion British thermal units per day (TBtu/d)
in 1995, 5.5 TBtu/d in 1994 and 5.1 TBtu/d in 1993. The
increases in volumes were more than offset by lower average
transport rates.
Construction, Management and Operation Revenues. Revenues
earned in connection with the construction, management and
operation of power and pipeline projects totaled $44 million
in 1995 as compared to $47 million and $37 million during
1994 and 1993, respectively. The 1994 increase reflects fees
earned in connection with the operation of additional
facilities offset by lower construction revenues as a result
of project completions.
EOTT. Net revenues from EOTT decreased $28 million in 1995
and $95 million in 1994 as a result of the reduced ownership
interest effective in March 1994.
Cost of Gas and Other Products Sold
The cost of gas and other products sold by the
transportation and operation segment decreased by $33
million (46%) during 1995 as compared to 1994 primarily as a
result of decreased gas purchases following the termination
of the merchant function by Northern. The cost of gas and
other products sold by the transportation and operation
segment decreased 82% during 1994 as compared to 1993 as a
result of lower sales volumes as discussed above combined
with lower average cost per unit of natural gas sold.
Operating Expenses
Operating expenses of the transportation and operation
segment declined $120 million (27%) during 1995 and $109
million (20%) during 1994. 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. The 1994 decline is primarily a result of
the decreased ownership interest in EOTT combined with lower
operating expenses of the interstate natural gas pipelines
reflecting system modernization and reduced expenses
resulting from lower sales volumes transported on other
pipelines.
Depreciation expense for the transportation and operation
segment decreased $5 million (6%) during 1995 as compared to
1994 primarily as a result of the decreased ownership
interest in EOTT. Depreciation expense decreased $28 million
(24%) in 1994 as compared to 1993 primarily as a result of
the decreased ownership interest in EOTT and the interstate
pipelines' adjustment in 1993 of accumulated depreciation in
accordance with a Federal Energy Regulatory Commission
(FERC) ruling.
Other Income and Deductions
Equity in earnings of unconsolidated subsidiaries decreased
by $26 million (53%) during 1995 as compared to 1994
primarily reflecting decreased earnings from EOTT and a $19
million charge to reflect the discontinuance of EOTT's West
Coast processing and asphalt marketing operations. Equity in
earnings of unconsolidated subsidiaries increased by $26
million during 1994 compared to 1993 reflecting a $36
million increase in earnings from the 50% owned Citrus Corp.
(Citrus), which owns Florida Gas, and $5 million of equity
earnings from EOTT. The increased earnings of Citrus reflect
improved sales margins as a result of the renegotiation of
the pricing terms of Citrus' gas sales contract with its
largest customer and allowance for funds used during
construction related to the Florida Gas Phase III pipeline
expansion. These increases were offset by reduced earnings
resulting from the decreased ownership interest in Northern
Border Pipeline Company.
Other income, net, increased $52 million (193%) in 1995 as
compared to 1994 primarily due to gains related to the
disposition of non-strategic natural gas processing and
gathering facilities. Other income increased $9 million
(50%) in 1994 as compared to 1993 primarily as a result of
the continued resolution of regulatory and contractual
matters relating to the interstate natural gas pipelines.
Outlook
The transportation and operation segment should continue to
provide stable earnings and cash flows during 1996. The
successful settlement of significant regulatory issues and
various expansion projects underway or proposed by the
interstate natural gas pipelines should provide a reliable
stream of cash flow. During 1996, the transportation and
operation segment expects to complete sales of certain
natural gas gathering facilities as a result of the
cessation of its gas merchant function following the
implementation of FERC Order 636. Additionally, the segment
will actively promote engineering and construction services
to provide incremental earnings and will continue to
concentrate on reducing its overall cost structure.
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, power and other energy
commodities and the management of the portfolio of
commitments arising from these activities. The domestic gas
processing operations are also included in this segment.
ECT's stated objective is to provide solutions to energy
problems worldwide. To meet this objective, ECT serves a
diverse customer group that includes independent power
producers, gas and electric utilities, industrials, 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. To
provide a framework to manage such risks, ECT has defined a
set of fundamental portfolio management principles,
including formal definition of portfolio management
responsibilities; continual evaluation of ECT's market risk,
communicated and managed through risk limits and controls
approved by Enron's Board of Directors; measurement of risk
in accordance with value-at-risk methodologies and
evaluation of business performance, including risk/return
relationships. ECT has established portfolio management
functions for both market and credit risk. Operating
separately from the units that create or actively manage
these risk exposures, ECT's Risk Control Group reports to an
ECT Managing Director who reports extensively to the Audit
Committee of the Enron Board of Directors. This group is
responsible for the establishment of policies, measurement
of the risks within ECT's portfolio and the communication of
these risks to senior management and the Enron Board of
Directors. This group is committed to the continuous review
of the portfolio, policies and procedures to ensure that
ECT's portfolio remains aligned with ECT's policies.
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]
1995 1994 1993
Cash and Physical $146 $170 $171
Risk Management 193 151 93
Finance 31 13 26
Unallocated expenses (138) (132) (93)
Total before Non-Recurring Charge 232 202 197
Charge for Clean Fuels Plant Operations (75) - -
Total $157 $202 $197
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. The cash and physical operations earnings before
overhead expenses and a $75 million charge in the fourth
quarter of 1995 related to the clean fuels plant operations
were $146 million in 1995, $170 million in 1994 and $171
million in 1993.
ECT markets a substantial quantity of energy commodities on
a daily basis as reflected in the following table (including
intercompany amounts):
[Download Table]
1995 1994 1993
Natural Gas and Crude Oil
Physical/Notional Quantities (BBtue/d)(a)
Firm(b) 5,392 4,895 4,558
Interruptible 2,255 2,039 828
Transport Volumes 580 538 571
Subtotal 8,227 7,472 5,957
Financial Settlements (notional) 32,938 16,459 5,027
Total 41,165 23,931 10,984
Electricity (Thousand megawatt hours)
Owned Production 3,441 3,481 2,883
Transaction Volumes Marketed 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.
Exclusive of the $75 million charge related to the clean
fuels plant operations, 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 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 low MTBE prices because of soft demand for MTBE.
Earnings for the cash and physical sector in 1994 were
virtually unchanged compared to 1993. Earnings from ECT's
management of its portfolio of contracts increased in 1994,
but were offset by lower gas processing margins. Margins
from short-term marketing in the purely physical natural gas
market also decreased slightly reflecting the more
competitive marketplace.
During 1996, ECT anticipates improvement in the cash and
physical business over the 1995 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. Additionally, opportunities for the growth in
earnings from new markets, including electricity, should
enhance future results.
Risk Management. ECT's risk management operations consist
of market activity on long-term contracts (transactions
greater than one year). ECT originates new contracts for the
energy sector 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 5,952 trillion
British thermal units equivalent (TBtue), 6,615 TBtue and
3,781 TBtue for 1995, 1994 and 1993, respectively. In 1995,
the earnings before unallocated expenses from the risk
management operations were $193 million compared to $151
million in 1994 and $93 million in 1993.
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
independent power producers 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.
Earnings from risk management increased 62% in 1994,
primarily as a result of the execution of various
electricity and new long-term gas contracts and the
restructuring of existing long-term contracts with
utilities, local distribution companies and independent
power producers.
ECT expects a strong performance from its risk management
business in 1996 as it expands further into electricity and
other new markets and pursues opportunities in the
international marketplace. The infrastructure for this
business has been established and ECT will be capitalizing
on its existing customer base, its skills and the emerging
competitive marketplace.
Finance. ECT's finance operations provide capital to
customers through various product offerings including
volumetric production payments. The finance sector
contributed $31 million of ECT's earnings in 1995 and $13
million and $26 million in 1994 and 1993, respectively.
Production payments and financings arranged were $382
million, $503 million and $470 million in 1995, 1994 and
1993, respectively.
Earnings from the finance sector 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 independent power plant. This was
partially offset by lower earnings from production payments
arranged.
Although total production payments and financings arranged
were greater in 1994 than 1993, the earnings in this
business decreased 50% in 1994 due to the difference in the
types of transactions originated in each of these periods
and the timing of income recognition from these
transactions.
In 1996, ECT will continue to expand its products and
services in its role as a full-service provider of various
types of capital. Additionally, opportunities will be
pursued in the international marketplace.
Other. ECT's net unallocated expenses such as rent,
systems expenses and other support group costs were $138
million, $132 million and $93 million in 1995, 1994 and
1993, respectively. These costs increased in both years due
to continued expansion into new markets and system upgrades.
ECT expects its unallocated expenses to increase during 1996
as it continues to expand into new markets.
International Gas and Power Services
Enron's international gas and power services segment
includes international power and pipeline development
activities and operations. IBIT for this group totaled $142
million during 1995, $148 million in 1994 and $132 million
in 1993. The decrease in 1995 was a result of decreased
earnings related to the formation of Enron Global Power &
Pipelines L.L.C. (EPP) and lower earnings from Enron
Americas, partially offset by increased earnings from Enron
Europe and increased promotion and development activities,
while the 1994 increase primarily reflects earnings from the
formation of EPP and increased earnings from power and
pipeline projects.
Net Revenues
Revenues net of cost of sales for the international segment
increased by $32 million (19%) in 1995 as compared to 1994
and $22 million (15%) during 1994. Included in 1995 were net
revenues of $24 million from the promotion of a portion of
Enron's interest in its power assets at Teesside in
Northeast England. In addition, revenues of $48 million were
recognized as a result of the satisfaction of Enron's
support obligations related to the formation of EPP. The
1994 results included $65 million of revenues earned in
connection with the formation of EPP and $28 million of net
revenues earned on the promotion of a portion of Enron's
interest in its liquids processing facilities at Teesside.
Costs and Expenses
Operating expenses for this segment increased $16 million
(21%) during 1995 and $7 million (10%) during 1994 as
compared to the preceding years primarily as a result of
higher operating expenses incurred in connection with
increased activities in the power operations area.
Depreciation expense of this segment increased $11 million
(75%) during 1995 as compared to 1994 as a result of
increased international project activities and $6 million
(68%) during 1994 as compared to 1993 primarily as a result
of increased investment in international natural gas liquids
assets.
Other Income and Deductions
Equity in earnings of unconsolidated subsidiaries of the
international gas and power services segment increased $12
million (27%) during 1995 as compared to 1994 primarily as a
result of increased earnings from Teesside and improved
results from Enron Americas' Venezuelan manufacturing
operations. Equity in earnings of unconsolidated
subsidiaries of this segment increased $3 million (8%)
during 1994 primarily as a result of earnings from two
Philippine power projects which began operations in mid-1993
and early 1994, combined with increased earnings from the
Argentina pipeline. These increases were partially offset by
lower earnings from Enron Americas' manufacturing operations
in Venezuela.
Other income, net, decreased $21 million in 1995 after
increasing $5 million during 1994, primarily as a result of
foreign currency gains realized by Enron Americas in 1994.
Outlook
The objective of the international gas and power services
segment is to deliver energy solutions worldwide through the
utilization of Enron's extensive portfolio of products and
services. Growth opportunities in the international market
are expected to result from the current and projected demand
for electrical power generation, the under-utilization of
natural gas reserves throughout the world and increased
environmental awareness.
Exploration and Production
IBIT of the exploration and production segment totaled $241
million during 1995 as compared to $198 million during 1994
and $129 million during 1993. Enron's exploration and
production activities are conducted by Enron Oil & Gas
Company (EOG). The exploration and production segment's
1995, 1994 and 1993 IBIT includes approximately $45 million,
$35 million and $7 million, respectively, of income related
to hedges placed by Enron on commodity positions not hedged
by EOG. The increase in IBIT realized by EOG primarily
reflects increased crude oil production and prices, strong
other marketing results and increased gains on sales of
reserves and related assets, combined with a reduction in
total per unit operating costs.
Wellhead volume and price statistics (including intercompany
amounts) are as follows:
[Download Table]
1995 1994 1993
Natural Gas Volumes (MMcf/d)(a)
North America(b) 636 686 707
Trinidad 107 63 2
Total 743 749 709
Average Natural Gas Prices ($/Mcf)
North America(c) $1.34 $1.68 $1.92
Trinidad 0.97 0.93 0.89
Composite $1.29 $1.62 $1.92
Crude/Condensate Volumes (MBbl/d)(a)
North America 11.5 10.0 8.8
Trinidad 5.1 2.5 0.1
India 2.5 0.1 -
Total 19.1 12.6 8.9
Average Crude/Condensate Prices ($/Bbl)
North America $17.09 $15.65 $16.39
Trinidad 16.07 15.50 14.36
India 16.81 15.70 -
Composite $16.78 $15.62 $16.37
<FN>
(a) Million cubic feet per day or thousand barrels per
day, as applicable.
(b) Includes an annual average of 48 MMcf per day in 1995
and 1994 and 81 MMcf per day in 1993 delivered under
the terms of a volumetric production payment agreement
effective October 1, 1992, as amended.
(c) Includes an average equivalent wellhead value of
$0.80 per Mcf in 1995, $1.27 per Mcf in 1994 and
$1.57 per Mcf in 1993 for the volumes detailed in Note (b)
above, net of transportation costs.
The following discussion analyzes the significant changes in
the various components of IBIT for the exploration and
production segment.
Revenues
Gross revenues of the exploration and production segment
decreased $19 million (2%) during 1995 after increasing by
$72 million (10%) in 1994. The impact of reduced wellhead
natural gas sales volumes and prices was partially offset by
the positive effects of EOG's hedging strategies which
resulted in a gain of $65 million from natural gas commodity
price hedging activities during 1995 compared to a gain of
$11 million during 1994 and a loss of $18 million in 1993.
Gains related to hedges placed by Enron on commodity
positions not hedged by EOG increased to $45 million in 1995
from $35 million in 1994 and $7 million in 1993.
Because of significantly lower average wellhead natural gas
prices beginning in the second half of 1994, U.S. wellhead
natural gas volumes were voluntarily curtailed by an average
of 105 MMcf/d during 1995 compared to an average of 70
MMcf/d during 1994. In addition, the impact of reduced
drilling for U.S. natural gas deliverability and sales of
oil and gas reserves and related assets net of purchases
resulted in a reduction of 20 MMcf/d in U.S. delivered
volumes during 1995 as compared to 1994.
Increased production of natural gas, crude oil and
condensate from Trinidad contributed to increased revenues
in both years, as did new crude oil and condensate volumes
associated with the initiation of operations in India and
increased crude oil and condensate prices during 1995.
Also included in revenues are gains on sales of oil and gas
reserves and related assets of $63 million in 1995 compared
with $54 million in 1994 and $13 million in 1993.
Costs and Expenses
The cost of natural gas sold by the exploration and
production segment in connection with other natural gas
marketing activities declined 44% in 1995 as compared to
1994 and 2% in 1994 as compared to 1993. The 1995 decline
was primarily due to lower other natural gas marketing
volumes and lower average associated costs per Mcf. The
decrease in 1994 as compared to 1993 reflects lower average
costs partially offset by higher other natural gas marketing
volumes.
Operating expenses for the exploration and production
segment increased $14 million (13%) in 1995 compared to 1994
and $7 million (7%) in 1994 compared to 1993. The increase
in 1995 is due primarily to increased lease and well and
general and administrative expenses due to expanded
international operations, including the initiation of
operations in India in late December 1994. The increase in
1994 reflects increased general and administrative expenses
associated with expanded operations.
Oil and gas exploration expenses decreased $5 million (6%)
in 1995 as compared to 1994 after increasing $8 million in
1994. The 1995 decline was a result of lower dry hole and
impairment costs, while the increase in 1994 reflects an
increased level of exploration activities and higher
impairments associated with certain offshore Gulf of Mexico
leases.
Depreciation, depletion and amortization (DD&A) expense
declined 11% in 1995 and 3% in 1994 as compared to the
applicable prior year. The 1995 decline reflects a decrease
in the average DD&A rate primarily reflecting an overall
decrease of $0.09 per thousand cubic feet equivalent (Mcfe -
natural gas equivalents are determined using the ratio of 6
Mcf of natural gas to 1 barrel of crude oil, condensate or
natural gas liquids) in certain North America DD&A rates and
an increase in the proportion of production from
international operations which have lower average DD&A rates
than incurred in North America operations. The decline
during 1994 reflects increased production from offshore
Trinidad at an average DD&A rate significantly less than the
North America operations rate including a $0.03 per Mcfe
decrease in the North America DD&A rate. On a per unit
natural gas equivalent volumes delivered basis, DD&A expense
declined 15% in 1995 to $0.68 per Mcfe as compared to $0.80
per Mcfe in 1994 and $0.89 per Mcfe in 1993.
Taxes, other than income taxes, increased $4 million (15%)
in 1995 and declined $7 million (20%) during 1994. The
increase in 1995 was primarily due to higher production
related taxes associated with new production in India. The
decline in 1994 was primarily due to lower taxable United
States wellhead volumes and prices and reductions in 1994
related to revisions of certain prior year production taxes.
Total per unit operating costs for lease and well expense,
DD&A, general and administrative expense, interest expense
and taxes other than income decreased $0.07 per Mcfe,
averaging $1.22 per Mcfe during 1995 compared to $1.29 per
Mcfe for 1994 and $1.43 per Mcfe for 1993.
Outlook
Management remains optimistic that continually increasing
recognition of natural gas as a more environmentally
friendly source of energy along with the availability of
significant domestically sourced supplies will result in
increases in demand and a strengthening of the overall
natural gas market over time.
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, based on
the continuing uncertainty associated with North America
natural gas prices and as a result of the recent success
realized in Trinidad, opportunities available to EOG in
connection with the signing of agreements in India in
December 1994 and EOG's selection as the winning bidder on a
block offshore Venezuela in January 1996, EOG anticipates
spending an increasing part of its available funds in the
further development of those opportunities. In addition, EOG
will continue limited exploratory expenditures in new areas
outside of North America, including the continued evaluation
of coalbed methane recovery potential in the United Kingdom,
China, France, Australia and certain other countries.
Corporate and Other
The corporate and other segment's IBIT was $266 million in
1995 as compared to expense of $7 million in 1994 and $42
million in 1993. Results from this segment in 1995 reflect a
gain of $367 million on the public offering of 31 million
outstanding shares of EOG stock held by Enron, which reduced
Enron's interest in EOG from 80% to 61% (see Note 16 to the
Consolidated Financial Statements), and amounts recognized
following the resolution of certain litigation. These
increases were 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. The improvement during 1994 primarily reflects a $15
million pretax gain realized on the formation of EOTT.
Interest and Related Charges, net
Interest and related charges, net, is shown on the
Consolidated Income Statement net of interest capitalized.
The net expense increased $11 million in 1995 primarily due
to higher debt levels and increased interest rates. The net
expense decreased $27 million during 1994 primarily because
of lower overall interest costs on Enron's floating rate
obligations as a result of lower rates achieved through
hedging activities. Enron periodically enters into certain
interest rate swaps to manage its overall interest costs.
Dividends on Preferred Stock of Subsidiaries
Dividends on preferred stock of subsidiaries relate to the
issuance of 8.55 million shares of 8% Cumulative Guaranteed
Monthly Income Preferred Shares by Enron Capital L.L.C. in
November 1993, the issuance by Enron Capital Resources, L.P.
of 3 million shares of 9% Cumulative Preferred Securities,
Series A in August 1994 and the issuance in December 1994 by
Enron Equity Corp. of 880 shares of 8.57% Preferred Stock,
$0.001 par value, in a private transaction. See Note 9 to
the Consolidated Financial Statements.
Minority Interests
Minority interests increased 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 increased during 1995 and 1994 compared
to the applicable 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
Cash From Operating Activities
Net cash used in operating activities totaled $15 million
during 1995 as compared to $461 million provided by
operating activities during 1994. The decline primarily
reflects increased working capital requirements, due in part
to reduced sales of accounts receivable, partially offset by
increased cash from monetization of price risk management
assets.
Cash From Investing Activities
Net cash provided by investing activities totaled $13
million during 1995 compared to $560 million used in
investing activities during 1994. Proceeds from asset sales
totaled $997 million during 1995 compared to $440 million
during 1994. The 1995 amounts reflect proceeds from the sale
of 31 million outstanding shares of EOG common stock held by
Enron, as well as sales of oil and gas properties and non-
strategic processing and gathering facilities. The 1994
amount primarily reflects proceeds realized on the formation
of EPP and the previously discussed sale of Enron's crude
oil trading and transportation operations to EOTT. As more
fully discussed below, capital expenditures (property
additions and other capital expenditures) totaled $777
million in 1995 compared to $669 million in 1994. Equity
investments totaled $170 million in 1995 compared to $273
million in 1994. Equity investments during 1995 primarily
reflect investments in international power projects. The
1994 amount primarily reflects investments in connection
with the Florida Gas Phase III pipeline expansion and
investments in Joint Energy Development Investments Limited
Partnership and in various international projects.
Cash From Financing Activities
Net cash used in financing activities totaled $16 million
during 1995 compared to cash provided of $92 million during
1994. During 1995, Enron issued $967 million of long-term
debt while retiring $448 million principal amount of long-
term borrowings. Other cash outflows during 1995 included
$254 million of cash dividend payments on common and
preferred stock and $65 million for net repurchases of Enron
Corp. common stock under Enron's stock repurchase
authorization. In addition to the debt issuances discussed
above, financing cash outflows during 1995 included a $250
million decrease in short-term borrowings.
Working Capital
At December 31, 1995, Enron had working capital of $295
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, 1995, provided for
up to $2.1 billion of committed and uncommitted credit of
which no amounts were outstanding. 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]
1996
(In Millions) Estimate 1995 1994 1993
Transportation and Operation $190 $129 $125 $152
Domestic Gas and Power Services 120 118 83 102
International Gas and Power Services 10 58 14 53
Exploration and Production* 470 464 442 383
Corporate and Other 10 8 5 5
Total $800 $777 $669 $695
<FN>
* Excludes exploration expenses of $60 million
(estimate), $55 million, $59 million, and $55 million
for 1996, 1995, 1994 and 1993, respectively.
Capital expenditures increased $108 million during 1995 as
compared to 1994 primarily as a result of increased
expenditures by ECT primarily related to upgrade of existing
facilities and systems costs, combined with higher capital
expenditures in the international operations. The increase
in international capital expenditures primarily reflects
property additions by Enron Europe and Enron Americas.
Capital expenditures during 1994 declined slightly as
compared to 1993. Reduced capital expenditures by the
transportation and operation, domestic gas and power
services and international gas and power services segments
were partially offset by higher capital spending by the
exploration and production segment. The increase in capital
expenditures by the exploration and production segment
reflects the acquisition of selected properties to
complement existing North American producing areas and the
addition of new international activities in India.
Capital expenditures during 1996 are expected to total
approximately $800 million. However, the overall level of
capital spending as well as spending by individual business
segments will vary depending upon conditions in the energy
market and other related economic conditions. In addition,
equity investments are expected to be approximately $200
million, primarily relating to international 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, 1995 was $7.2 billion.
Debt as a percentage of total capitalization decreased to
42.8% at December 31, 1995 as compared to 44.2% at December
31, 1994. The improvement primarily reflects increased
retained earnings and the utilization of proceeds from the
previously discussed sale of EOG shares to reduce long-term
debt. 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 40.5% at December 31, 1995.
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 (i)
directors who are nominees for election as directors at Enron's Annual
Meeting of Stockholders to be held on May 7, 1996, and (ii) compliance by
directors and executive officers with Section 16(a) of the Securities
Exchange Act of 1934 is set forth, respectively, under the captions
entitled "Election of Directors" and "Compensation of Directors and
Executive Officers - Certain Transactions" 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".
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 1995; Aggregated Stock Option/SAR Exercises During
1995 and Stock Option/SAR Values as of December 31, 1995; Long-Term
Incentive Plan - Awards in 1995; Retirement and Severance Plans;
Severance Pay Plan; 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 - Stock 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 January 31, 1996", 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.
*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 10.49
*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.
*10.03 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to Registration Statement
No. 33-27893).
*10.04 - Executive Incentive Plan (Exhibit 10.13 to Enron Form 10-K for
1987, File No. 1-3423).
*10.05 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to Enron Form 10-K
for 1987, File No. 1-3423).
10.06 - First Amendment to Enron Corp. 1988 Deferral Plan.
10.07 - Second Amendment to Enron Corp. 1988 Deferral Plan.
*10.08 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Form 10-K for
1991, File No. 1-3423).
*10.09 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to Enron Form 10-K
for 1991, File No. 1-3423).
10.10 - First Amendment to Enron Corp. 1992 Deferral Plan.
10.11 - Second Amendment to Enron Corp. 1992 Deferral Plan.
*10.12 - Enron Corp. Directors' Deferred Income Plan (Exhibit 10.09 to Enron
Form 10-K for 1992, File No. 1-3423).
*10.13 - 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).
*10.14 - 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).
*10.15 - 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).
*10.16 - 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).
*10.17 - 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).
*10.18 - 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).
*10.19 - 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).
*10.20 - 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).
*10.21 - 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).
*10.22 - 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).
*10.23 - 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).
*10.24 - 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).
*10.25 - 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).
*10.26 - 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).
*10.27 - 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).
*10.28 - 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).
*10.29 - 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).
*10.30 - 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).
10.31 - Second Amendment to Employment Agreement between Enron
International Inc. and Rodney L. Gray, dated as of January 1, 1995.
*10.32 - 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).
*10.33 - 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).
*10.34 - 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).
10.35 - Fourth Amendment to Consulting Services Agreement between Enron and
John A. Urquhart dated as of May 9, 1994.
10.36 - Fifth Amendment to Consulting Services Agreement between Enron and
John A. Urquhart.
10.37 - Sixth Amendment to Consulting Services Agreement between Enron and
John A. Urquhart.
*10.38 - 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).
*10.39 - 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).
*10.40 - 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).
*10.41 - 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).
*10.42 - 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).
*10.43 - Enron Corp. Performance Unit Plan (Exhibit A to Enron Proxy
Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.44 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron Proxy
Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.45 - 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).
10.46 - First Amendment to Enron Corp. Performance Unit Plan.
*10.47 - Form of Enron Corp. 1994 Deferral Plan (Exhibit 10.59 to Enron Form
10-K for 1994).
10.48 - First Amendment to Enron Corp. 1994 Deferral Plan.
10.49 - Second Amendment to Enron Corp. 1994 Deferral Plan.
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 22, 1996.
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; all
other exhibits are filed herewith.
(b) Reports on Form 8-K
No reports on Form 8-K were filed by Enron during the last quarter of
1995.
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, 1995, 1994 and 1993 F-3
Consolidated Balance Sheet as of December 31, 1994
and 1993 F-4
Consolidated Statement of Cash Flows for the years
ended December 31, 1995, 1994 and 1993 F-6
Consolidated Statement of Changes in Shareholders'
Equity Accounts for the years ended December 31,
1995, 1994 and 1993 F-7
Notes to the Consolidated Financial Statements F-8
Supplemental Financial Information (Unaudited) F-28
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, 1995 and 1994, 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, 1995. These financial statements are the
responsibility of Enron Corp.'s management. Our responsibility
is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used
and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial
position of Enron Corp. and subsidiaries as of December 31,
1995 and 1994, 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, 1995, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 16, 1996
[Download Table]
Enron Corp. and Subsidiaries
Consolidated Income Statement
Year Ended December 31,
(In Thousands, Except Per Share Amounts) 1995 1994 1993
Revenues
Natural gas and other products $7,529,357 $7,490,533 $6,652,333
Transportation 691,702 754,117 767,911
Other 967,938 739,073 565,556
9,188,997 8,983,723 7,985,800
Costs and Expenses
Cost of gas and other products 6,733,486 6,517,109 5,566,026
Operating expenses 1,218,341 1,123,448 1,146,655
Oil and gas exploration expenses 78,670 83,944 75,743
Depreciation, depletion and
amortization 431,706 441,329 458,188
Taxes, other than income taxes 108,792 102,121 108,386
8,570,995 8,267,951 7,354,998
Operating Income 618,002 715,772 630,802
Other Income and Deductions
Equity in earnings of unconsolidated
subsidiaries 86,018 112,409 73,293
Interest income 26,821 39,162 31,457
Other, net 434,241 77,049 62,115
Income Before Interest, Minority
Interest and Income Taxes 1,165,082 944,392 797,667
Interest and Related Charges, net 284,029 273,482 300,149
Dividends on Preferred Stock of
Subsidiaries 31,859 19,875 2,137
Minority Interests 44,056 31,041 27,605
Income Taxes 285,444 166,584 89,077
Income Tax Rate Adjustment - - 46,177
Net Income 519,694 453,410 332,522
Preferred Stock Dividends 15,414 15,038 16,919
Earnings on Common Stock $ 504,280 $ 438,372 $ 315,603
Earnings Per Share of Common Stock
Primary $ 2.07 $ 1.80 $ 1.32
Fully Diluted $ 1.94 $ 1.70 $ 1.25
Average Number of Common Shares Used
in Primary Computation 243,669 243,395 239,019
<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 Thousands) 1995 1994
Assets
Current Assets
Cash and cash equivalents $ 114,917 $ 132,336
Trade receivables (net of allowance
for doubtful accounts of $11,642 and
$12,729, respectively) 1,115,709 604,985
Other receivables 310,790 233,213
Transportation and exchange gas
receivable 149,659 98,787
Inventories 111,463 138,405
Assets from price risk management
activities 579,749 449,588
Other 344,620 251,679
Total Current Assets 2,726,907 1,908,993
Investments and Other Assets
Investments in and advances to
unconsolidated subsidiaries 1,216,474 1,065,189
Assets from price risk management
activities 1,197,029 1,027,945
Other 1,230,090 1,225,224
Total Investments and Other Assets 3,643,593 3,318,358
Property, Plant and Equipment, at cost
Transportation and operation 3,639,734 3,906,952
Domestic gas and power services 3,797,530 3,811,037
Exploration and production, successful
efforts accounting 3,380,924 3,015,435
International gas and power services 181,981 119,740
Corporate and other 107,012 111,237
11,107,181 10,964,401
Less accumulated depreciation,
depletion and amortization 4,238,746 4,225,741
Net Property, Plant and Equipment 6,868,435 6,738,660
Total Assets $13,238,935 $11,966,011
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
[Download Table]
Enron Corp. and Subsidiaries
Consolidated Balance Sheet
December 31,
1995 1994
Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable $ 1,020,599 $ 924,446
Transportation and exchange gas
payable 144,141 114,124
Accrued taxes 121,192 90,906
Accrued interest 51,692 58,569
Liabilities from price risk
management activities 708,353 522,070
Other 386,015 587,271
Total Current Liabilities 2,431,992 2,297,386
Long-Term Debt 3,064,839 2,805,142
Deferred Credits and Other Liabilities
Deferred income taxes 2,185,748 1,893,450
Deferred revenue 311,478 256,298
Liabilities from price risk
management activities 590,302 575,377
Other 563,962 591,134
Total Deferred Credits and
Other Liabilities 3,651,490 3,316,259
Commitments and Contingencies
(Notes 2, 8, 13, 14 and 15)
Minority Interests 548,648 290,146
Company-Obligated Preferred Stock
of Subsidiaries 376,750 376,750
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,
1,375,494 shares and 1,404,983 shares of
Cumulative Second Preferred Convertible
Stock issued, respectively 137,550 140,498
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,
253,860,360 shares and 253,069,668
shares issued, respectively 25,386 25,308
Additional paid-in capital 1,791,151 1,788,044
Retained earnings 1,650,949 1,351,297
Cumulative foreign currency translation
adjustment (153,563) (158,881)
Common stock held in treasury (2,618,034
and 1,394,833 shares, respectively) (92,642) (41,090)
Other (including Flexible Equity Trust,
Note 10) (193,615) (224,848)
Total Shareholders' Equity 3,165,216 2,880,328
Total Liabilities and Shareholders' Equity $13,238,935 $11,966,011
<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 Thousands) 1995 1994 1993
Cash Flows From Operating Activities
Reconciliation of net income to net
cash provided by (used in) operating
activities
Net income $ 519,694 $ 453,410 $ 332,522
Depreciation, depletion and amortization 431,706 441,329 458,188
Oil and gas exploration expenses 78,670 83,944 75,743
Amortization of deferred contract
reformation costs 25,858 90,617 89,240
Deferred income taxes 216,090 92,959 51,200
Gains on sales of stock by subsidiary
and other assets (529,990) (91,284) (115,586)
Regulatory, litigation and other
contingency adjustments 111,666 (25,212) 58,944
Changes in components of working
capital (833,647) (141,372) (76,513)
Deferred contract reformation costs (18,089) (54,182) (136,383)
Net assets from price risk management
activities (98,037) (152,642) (115,415)
Production payment transaction, net (43,345) (43,345) (73,867)
Other, net 124,401 (193,567) (153,651)
Net Cash Provided by (Used in) Operating
Activities (15,023) 460,655 394,422
Cash Flows From Investing Activities
Proceeds from sales of investments and
other assets 996,537 439,627 453,977
Additions to property, plant and
equipment (730,502) (660,915) (688,032)
Equity investments (170,262) (272,517) (267,097)
Other, net (82,397) (66,561) (64,224)
Net Cash Provided by (Used in)
Investing Activities 13,376 (560,366) (565,376)
Cash Flows From Financing Activities
Net increase (decrease) in
short-term borrowings (250,305) 115,326 42,767
Issuance of long-term debt 967,126 190,115 613,938
Repayment of long-term debt (447,734) (161,786) (450,161)
Decrease in other long-term obligations - - (22,757)
Issuance of company-obligated preferred
stock of subsidiaries - 163,000 213,750
Issuance of common stock 19,806 66,372 22,882
Dividends paid (254,262) (231,079) (189,769)
Net acquisition of treasury stock (64,654) (41,090) (71,145)
Other, net 14,251 (9,051) 10,000
Net Cash Provided by (Used in)
Financing Activities (15,772) 91,807 169,505
Decrease in Cash and Cash Equivalents (17,419) (7,904) (1,449)
Cash and Cash Equivalents, Beginning
of Year 132,336 140,240 141,689
Cash and Cash Equivalents, End of Year $ 114,917 $ 132,336 $ 140,240
<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
Cumulative
Foreign
Convertible Additional Currency
(In Thousands, Except Preferred Common Paid-in Retained Translation Treasury
Per Share Amounts) Stock Stock Capital Earnings Adjustment Stock Other
Balance at December 31, 1992 $182,964 $1,187,661 $ 324,944 $ 959,522 $(118,160) $ (8,100) $ (10,514)
Net income 332,522
Cash dividends
Common stock (170,457)
Preferred stock (16,919)
Purchase of treasury stock (86,301)
Exchange of common stock for
convertible preferred stock (33,296) 3,573 (25,289) 55,012
Benefit and dividend reinvestment
plans 3,881 25,426 39,788 (5,347)
Sales of stock 14 4,986
Issuance to Flexible Equity Trust 750 219,563 (219,563)
Common stock split and reduction
of par value to $0.10 (1,170,969) 1,170,969
Translation adjustments (20,544)
Other (12,661) 318 (399) 10,000
Balance at December 31, 1993 149,668 24,910 1,707,938 1,104,986 (138,704) - (225,424)
Net income 453,410
Cash dividends
Common stock (191,839)
Preferred stock (15,038)
Purchase of treasury stock (55,911)
Exchange of common stock for
convertible preferred stock (9,170) 125 9,045
Benefit and dividend reinvestment
plans 131 29,625 1,392 576
Sales of stock 142 51,594 13,366
Translation adjustments (20,177)
Other (10,158) (222) 63
Balance at December 31, 1994 140,498 25,308 1,788,044 1,351,297 (158,881) (41,090) (224,848)
Net income 519,694
Cash dividends
Common stock (204,628)
Preferred stock (15,414)
Purchase of treasury stock (118,368)
Exchange of common stock for
convertible preferred stock (2,948) 22 (2,536) 5,462
Benefit and dividend reinvestment
plans 19 (5,189) 61,381 29,569
Sales of stock 37 15,468
Translation adjustments 5,318
Other (4,636) (27) 1,664
Balance at December 31, 1995 $137,550 $ 25,386 $1,791,151 $1,650,949 $(153,563) $(92,642) $(193,615)
<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
A. Consolidation Policy and Use of Estimates
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.
B. Cash Equivalents
Enron records as cash equivalents all highly liquid short-
term investments with original maturities of three months or
less.
C. Inventories
Inventories consisting primarily of natural gas in storage
of $55.9 million and $79.1 million and crude oil and liquid
petroleum products of $50.0 million and $54.8 million at
December 31, 1995 and 1994, respectively, are priced at the
lower of cost or market.
D. 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.
In March 1995, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards (SFAS)
No. 121 - "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of," which
requires, among other things, that long-lived assets and
certain identifiable intangibles to be held and used by an
entity be reviewed for impairment whenever events or changes
in circumstances indicate that the carrying amount of an
asset may not be recoverable. Enron will adopt SFAS No. 121
in the first quarter of 1996. Enron believes that the
adoption of SFAS No. 121 will not have a material impact on
its financial position or results of operations.
E. Income Taxes
Enron accounts for income taxes under the provisions of SFAS
No. 109 - "Accounting for Income Taxes," which provides for
an asset and liability approach for accounting for income
taxes. Under this approach, 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 3).
F. 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.
G. 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 2
for further discussion of Enron's price risk management
activities.
H. 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.
I. 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. Total revenues recognized from the sale of
development projects for the years ended December 31, 1995,
1994 and 1993, exclusive of amounts discussed below, were
$11 million, $28 million and $65 million, respectively.
During November 1994, Enron sold an approximately 48%
interest in Enron Global Power & Pipelines L.L.C. (EPP) for
net proceeds totaling approximately $225 million. In
connection with the sale, Enron recognized revenues of $65
million in 1994 and $48 million in 1995 following the
satisfaction of Enron's support obligations. Pursuant to a
Purchase Right Agreement, Enron has agreed to offer to sell
to EPP Enron's ownership interests in power plant and
natural gas pipeline projects developed or acquired outside
the United States, Canada and Western Europe, prior to 2005,
subject to certain exceptions.
J. 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.
K. Reclassifications
Certain reclassifications have been made to the consolidated
financial statements for prior years to conform with the
current presentation.
2 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), but in some
instances also include financial products (interest rate
swaps and foreign currency contracts). 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 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, restructurings 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, 1995 are set
forth below (volumes in trillions of British thermal units
equivalent (TBtue), dollars in millions):
[Download Table]
Fixed Price Fixed Price Maximum
Product Payor Receiver Terms in years
Energy Commodities
Gas 3,741 4,933 19
Crude and liquids 606 743 10
Electricity 33 165 5
Financial Products
Interest rate (a) $14,364 $1,465 19
Foreign currency 1,040 1,045 19
<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.
The effectiveness of a hedge on the net present value of the
combined commodity portfolio is not a function of notional
hedge value but, rather, of cash flows resulting from the
notional hedge value. Accordingly, the notional dollar
values will not be equal. However, the portfolio is
substantially balanced from a cash flow perspective and is
not sensitive to movement in interest rates.
ECT also has sales and purchase commitments associated with
contracts based on market prices totaling 4,432 TBtue, with
terms extending up to 20 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, 1995 was approximately 2.3
years.
Fair Value. The fair value of the financial instruments as
of December 31, 1995 and the average fair value of those
instruments held during the year are set forth below
(amounts in millions):
[Download Table]
Fair Value Average Fair Value
as of for the Year Ended
12/31/95 12/31/95(a)
Product Assets Liabilities Assets Liabilities
Energy Commodities
Gas $1,217 $744 $1,190 $477
Crude and liquids 249 363 293 495
Electricity 97 62 29 14
Financial Products
Interest rate 357 92 225 60
Foreign currency 64 38 58 35
<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, 1995,
primarily attributable to financial instruments fixing
energy commodity pricing, was $98 million and is included in
"Other Revenues". 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, 1995.
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 approximately 1% of the gross position at
the end of each day.
ECT measures the risk in its portfolio on a daily basis in
accordance with value-at-risk 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, 1995,
ECT's value-at-risk for its price risk management activities
was less than 2% (unaudited) of Enron's total income before
interest, minority interest 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,
1995 and 1994 are summarized as follows (amounts in
millions):
[Download Table]
December 31, 1995
Assets from Price Risk Management Activities
Investment Below
Grade(a) Investment Grade Total
Independent Power Producers $ 573 $105 $ 678
Gas and Electric Utilities 234 45 279
Oil and Gas Producers 318 109 427
Industrials 35 43 78
Financial Institutions 38 5 43
Energy Marketers 132 103 235
Other 202 42 244
Total $1,532 $452 1,984
Credit and Other Reserves (207)
Assets from Price Risk
Management Activities(b) $1,777
[Download Table]
December 31, 1994
Assets from Price Risk Management Activities
Investment Below
Grade(a) Investment Grade Total
Independent Power Producers $ 447 $ 44 $ 491
Gas and Electric Utilities 287 37 324
Oil and Gas Producers 310 26 336
Industrials 24 21 45
Financial Institutions 176 - 176
Energy Marketers 20 25 45
Other 158 33 191
Total $1,422 $186 1,608
Credit and Other Reserves (130)
Assets from Price Risk
Management Activities(b) $1,478
<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) Three customers' exposures at December 31, 1995 and
1994 each comprise greater than 5% of Assets From Price Risk
Management Activities.
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 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 is
recognized on the hedged item.
Interest Rate Swaps. At December 31, 1995, Enron had
entered into interest rate swap agreements with a notional
principal amount of $4,005 million to manage interest rate
exposure. Swap agreements relating to notional amounts of
$1,315 million, $700 million and $1,990 million are
scheduled to terminate in 1996, 1997 and thereafter,
respectively.
Energy Commodity Price Swaps. At December 31, 1995, Enron
was a party to energy commodity price swaps covering
approximately 233 TBtu, 169 TBtu and 427 TBtu of natural gas
for the years 1996, 1997 and the period 1998 through 2004,
respectively, and 4 million, 4 million and 6 million barrels
of crude oil for the years 1996, 1997 and the period 1998
through 2000, respectively. During the first quarter of
1996, Enron removed substantially all of its natural gas
commodity price swaps for 1996 by entering into offsetting
positions.
Foreign Currency Contracts. At December 31, 1995, foreign
currency contracts with a notional principal amount of $11.9
million were outstanding. Such contracts will substantially
expire in 1996.
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, 1995 and 1994 were as
follows:
[Download Table]
1995 1994
Carrying Estimated Carrying Estimated
(In Millions) Amount Fair Value Amount Fair Value
Long-term debt (Note 5) $3,065 $3,360 $2,805 $2,752
Company-obligated preferred
stock of subsidiaries (Note 9) 377 386 377 348
Interest rate swaps - (18) - 5
Energy commodity price swaps - 90 - 80
Foreign currency contracts - - - (1)
Enron used 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, Energy commodity price
swaps and Foreign currency contracts - estimated fair values
have been determined by using available market data and
valuation methodologies. Judgement 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 book value associated with
them and the fair values of these items are not readily
determinable (see Note 15).
3 Income Taxes
The principal components of Enron's net deferred income tax
liability at December 31, 1995 and 1994 are as follows:
[Download Table]
(In Millions) 1995 1994
Deferred income tax assets -
Alternative minimum tax credit carryforward $ 231 $ 236
Other 84 51
315 287
Deferred income tax liabilities -
Depreciation, depletion and amortization 1,617 1,583
Price risk management activities 427 256
Other 470 406
2,514 2,245
Net deferred income tax liabilities* $2,199 $1,958
<FN>
* Includes $13 million and $65 million in other
current liabilities for 1995 and 1994,respectively.
The components of income before income taxes are as follows:
[Download Table]
(In Thousands) 1995 1994 1993
U.S. $621,881 $415,011 $336,445
Foreign 183,257 204,983 131,331
$805,138 $619,994 $467,776
Total income tax expense is summarized as follows:
[Download Table]
(In Thousands) 1995 1994 1993
Payable currently -
Federal $ 29,315 $ 49,021 $ 57,093
State 25,955 13,494 14,692
Foreign 14,084 11,110 12,269
69,354 73,625 84,054
Payment deferred -
Federal 157,716 77,595 (26,070)
State 30,327 (5,948) 15,724
Foreign 28,047 21,312 15,369
216,090 92,959 5,023
285,444 166,584 89,077
Effect of tax rate increase on
deferred tax liability(a) - - 46,177
Total Income Tax Expense $285,444 $166,584 $135,254
<FN>
(a) In August 1993, the U.S. corporate Federal income
tax rate increased from 34% to 35% retroactive to January 1,
1993. Under the provisions of SFAS No. 109, the effect of a
change in the tax rate is recognized in income for the
period of enactment.
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]
1995 1994 1993
Statutory Federal income tax
rate provision 35.0% 35.0% 35.0%
Net state income taxes 4.5% 0.8% 4.1%
Revision of prior years' tax estimates (1.5)% (0.8)% (5.3)%
Tax rate increase - - 9.9%
Tight gas sands tax credit (2.8)% (5.9)% (13.9)%
Earnings in foreign jurisdictions taxed
at rates different from the statutory
U.S. Federal rate 0.4% (0.2)% 1.0%
Equity earnings (3.8)% (3.7)% (2.6)%
Minority interest 1.9% 1.7% 2.1%
Asset and stock sale differences 2.1% - -
Other (0.3)% - (1.4)%
Effective income tax rate 35.5% 26.9% 28.9%
Enron has an alternative minimum tax (AMT) credit
carryforward of approximately $231 million which can be used
to offset regular income taxes payable in future years. The
AMT credit has an indefinite carryforward period.
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 $195
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.
4 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 Thousands) 1995 1994 1993
Income taxes $ 13,278 $ 56,595 $ 39,307
Interest (net of amounts
capitalized) 296,180 268,205 299,568
Non-cash investing and financing activities during 1995,
1994 and 1993 included the exchange of common stock for
convertible preferred stock in transactions valued at $2.9
million, $9.2 million and $33.3 million, respectively.
In addition, in March 1995, a subsidiary of 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
November 1995 for 633,333 shares of Enron's common stock.
Changes in components of working capital are as follows:
[Download Table]
(In Thousands) 1995 1994 1993
Receivables $(639,173) $(250,295) $(360,206)
Inventories 26,942 (25,117) 92,228
Payables 126,170 (91,329) 144,518
Accrued taxes 30,286 12,178 (11,941)
Accrued interest (6,877) 5,277 2,913
Other (370,995) 207,914 55,975
Total $(833,647) $(141,372) $ (76,513)
5 Credit Facilities, Short-Term
Borrowings and Long-Term Debt
Enron and EOG have credit facilities with domestic and
foreign banks which provide for an aggregate of $1.1 billion
in long-term committed credit. Expiration dates of the
committed facilities range from February 1998 to March 2000.
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 1995,
no amounts were borrowed under these facilities.
Enron and EOG have also entered into agreements which
provide for uncommitted lines of credit totaling $995
million at December 31, 1995. 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, 1995, no amounts
were outstanding under the uncommitted lines.
In addition to borrowing from banks on a short-term basis,
Enron and certain of its subsidiaries sell commercial paper
to provide financing for various corporate purposes. As of
December 31, 1995, 1994 and 1993, short-term borrowings of
$15.3 million, $259.1 million and $143.8 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, 1995, 1994 and 1993, $286.5 million, $171.1 million and
$132.4 million, respectively, of long-term debt due within
one year remained classified as long-term.
Detailed information on short-term borrowings by Enron is as
follows:
[Download Table]
(In Millions) 1995 1994 1993
As of end of year
Borrowings from -
Commercial paper $ - $ 206.1 $ -
Banks and other 15.3 53.0 143.8
Amount reclassified
as long-term debt (15.3) (259.1) (143.8)
Total short-term borrowings $ - $ - $ -
Weighted average interest rate
at end of year (a) 6.3% 6.2% 3.6%
For the year ended
Maximum borrowings
at any month end (a) $782.9 $1,156.0 $1,087.1
Average borrowings (a)(b) 636.2 768.1 590.9
Weighted average interest rate
during the year (a)(c) 6.1% 4.6% 3.3%
<FN>
(a) Before reclassification as long-term debt.
(b) Computed using the average daily balances
during each month.
(c) Computed using the weighted average interest
rates of debt outstanding during each month.
Detailed information on long-term debt is as follows:
[Download Table]
December 31,
(In Thousands) 1995 1994
Enron Corp.
Debentures
6.75% due 2005 - senior subordinated $ 200,000 $ 200,000
8.25% due 2012 - senior subordinated 150,000 150,000
Notes Payable
8.10% to 9.25% due 1996 250,000 250,000
6.25% due 1998 - mandatorily
exchangeable into EOG stock 228,375 -
8.50% to 10.75% due from 1998 to 2001 450,000 342,777
6.75% to 9.875% due from 2003 to 2007 992,200 692,200
7% due 2023 100,000 100,000
Other 9,678 56,508
Northern Natural Gas Company
Notes Payable
8.00% due 1999 250,000 250,000
6.875% due 2005 100,000 100,000
Houston Pipe Line Company
Notes Payable
12.125% due 1995 - 100,000
Transwestern Pipeline Company
Notes Payable
7.55% to 9.10% due 2000 123,000 123,000
9.20% due from 1998 to 2004 27,000 27,000
Enron Oil & Gas Company
Notes Payable
8.92% due 1995 - 25,000
9.10% due from 1996 to 1998 70,000 70,000
Other 77,559 67,421
Enron Europe Limited
Other 38,933 -
Amount reclassified from short-term debt 15,348 259,099
Unamortized debt discount and premium (17,254) (7,863)
Total Long-Term Debt $3,064,839 $2,805,142
The aggregate annual maturities of long-term debt
outstanding at December 31, 1995 are $286.5 million, $26.7
million, $388.9 million, $299.8 million and $281.4 million
for 1996 through 2000, respectively.
6 Accounts Receivable
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 $100.0
million and $328.0 million at December 31, 1995 and 1994,
respectively. Rights to certain recoverable pipeline
transition surcharges sold under these agreements totaled
$34.9 million and $64.2 million at December 31, 1995 and
1994, respectively.
The fees incurred on the sales of accounts receivable
totaled $23.7 million, $20.8 million and $20.6 million for
1995, 1994 and 1993, respectively, and are included in
"Interest and Related Charges, net."
Enron affiliates have concentrations of customers in the
electric and gas utility 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.
7 Production Payment Agreement
In September 1992, EOG entered into a transaction with a
limited partnership under which EOG conveyed an interest in
approximately 124 billion cubic feet equivalent (136
trillion British thermal units) of natural gas and other
hydrocarbons for consideration of $326.8 million (the
production payment agreement). EOG retains responsibility
for its working interest share of the cost of operations.
Enron has accounted for the proceeds received in the
transaction as deferred revenue which is being amortized
into revenue as natural gas and other hydrocarbons are
produced and delivered during the terms of the agreement as
amended in October 1993. Annual amortization of remaining
deferred revenue, based on scheduled deliveries under the
production payment agreement, is approximately $43.3 million
per year through 1998 and $10.7 million for 1999. See Note
18 for the estimate of proved oil and gas reserves dedicated
to the transaction.
8 Unconsolidated Subsidiaries
Enron has investments in and advances to unconsolidated
subsidiaries as follows:
[Download Table]
Ownership
Investee Interest December 31,
(In Thousands) 1995 1994
Citrus Corp. 50% $ 383,351 $ 356,538
Teesside Power Limited 50%(a) 182,937 173,461
Transportadora de Gas del Sur S.A. 18%(a) 97,608 96,451
Joint Energy Development
Investments L.P. 50% 83,952 77,024
Northern Border Partners, L.P. 13% 54,143 55,050
Enron/Dominion Cogen Corp. 50% 50,411 43,456
EOTT Energy Partners, L.P. 42% 37,847 63,044
Other(b) 326,225 200,165
$1,216,474 $1,065,189
<FN>
(a) Net of minority interests, the ownership is 42.5%
for Teesside Power Limited and 9.1% for Transportadora de
Gas del Sur S.A.
(b) Includes investments in various international
development projects which have not reached commercial
operation at December 31, 1995.
Enron's equity in earnings (losses) of unconsolidated
subsidiaries is as follows:
[Download Table]
Investee Year Ended December 31,
(In Thousands) 1995 1994 1993
Citrus Corp. $26,814 $ 27,554 $(8,066)
Teesside Power Limited 17,530 12,669 12,444
Transportadora de Gas del Sur S.A. 22,252 22,965 20,721
Joint Energy Development
Investments L.P. 4,175 7,321 -
Northern Border Partners, L.P. 6,743 6,970 1,368
Enron Dominion Cogen Corp. 6,993 6,213 6,874
EOTT Energy Partners, L.P. (22,717) 4,815 -
Other 24,228 23,902 39,952
$86,018 $112,409 $73,293
Summarized combined financial information of Enron's
unconsolidated subsidiaries is presented below:
[Download Table]
December 31,
(In Thousands) 1995 1994
Balance Sheet
Current assets $1,776,646 $1,805,050
Property, plant and equipment, net 7,813,974 6,072,820
Other noncurrent assets 968,464 1,287,790
Current liabilities 2,049,923 1,189,478
Long-term debt 4,981,680 4,623,035
Other noncurrent liabilities 1,141,911 1,243,241
Owners' equity 2,385,570 2,109,906
[Download Table]
Year Ended December 31,
(In Thousands) 1995 1994 1993
Income Statement
Operating revenues $8,258,113 $7,102,886 $2,351,177
Operating expenses 7,334,801 6,421,637 2,016,977
Net income 225,770 290,089 204,262
Distributions Paid to Enron 68,216 81,100 59,585
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 (Florida Gas), placed into service
its Phase III pipeline expansion. The Phase III expansion
increased Florida Gas' firm average delivery capacity by 530
MMcf/day to 1.5 Bcf/day.
Teesside Power Limited (Teesside). During the first
quarter of 1995, Enron reduced its effective interest in
Teesside from 50.0% to 42.5% through a sale of an effective
7.5% interest to one of the original joint venture partners
in Teesside, a joint venture cogeneration company which owns
a 1,875 megawatt independent power facility in northeast
England. An affiliate of Enron operates the facility which
was placed in commercial operation on March 27, 1993. Enron
has guaranteed Teesside's obligation for certain grid
charges and other amounts which could become due under
certain power sales agreements. The value 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. However, Enron believes there are alternative
markets for such gas should the gas not be taken by
Teesside.
Transportadora de Gas del Sur S.A. EPP holds a 25%
interest 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
4,000 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.
Joint Energy Development Investments (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 have committed
to invest a total of $500 million of capital in JEDI through
1996, of which $85 million has been contributed by Enron as
of December 31, 1995. Enron intends to meet its required
capital commitments primarily by contributing Enron common
stock.
Northern Border Partners, L.P. During October 1993,
Northern Plains Natural Gas Company (Northern Plains), a
wholly-owned subsidiary of Enron, contributed its interest
in Northern Border Pipeline Company to Northern Border
Partners, L.P., a Delaware limited partnership (the Northern
Border Partnership), in exchange for general partner
interests,subordinated units and common units in the
Northern Border Partnership. Northern Plains sold its common
units in the Northern Border Partnership in an underwritten
public offering, retaining a 13% interest in the Northern
Border Partnership.
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 resulting in net proceeds to Enron of approximately
$186 million and a pretax gain of approximately $15 million.
Enron retained seven million subordinated units of EOTT and
its general partnership interest.
In September 1995, EOTT discontinued its West Coast
processing and asphalt marketing business (other than
business from its Arizona asphalt terminals). As a result,
EOTT recorded a one-time charge of $45.8 million. Also
during 1995, Enron entered into an agreement to provide
trade credit support on a secured basis to EOTT in the form
of trade guarantees, letters of credit, loans and letters of
indemnity totaling $450 million through March 31, 1996.
Letters of credit and trade guarantees outstanding under
this agreement at December 31, 1995 are included in Note 15.
During 1995, Enron purchased 296,800 additional common units
of EOTT on the open market. In addition, Enron paid $9.1
million to EOTT in support of EOTT's common unit
distributions and in exchange received Additional
Partnership Interests (APIs). Enron is committed to provide
further support, if needed, up to a total of $29 million
through March 1998 through the purchase of additional APIs.
Subsequent to December 31, 1995, Enron increased its total
ownership in EOTT to 50% through the purchase of additional
common units.
9 Preferred Stock
Second Preferred Stock. The Cumulative Second Preferred
Convertible Stock, $1 par value, 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 Cumulative
Second Preferred Convertible Stock were converted to Common
Stock. The dividend for the fourth quarter of 1995 was
$2.901 per share. The dividend for the preceding four
quarters was $2.7304 per share. All previous quarterly
dividends had been $2.625 per share. Each share of the
Cumulative Second Preferred Convertible 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 1995, 1994 and
1993, 29,489 shares, 91,694 shares and 332,964 shares,
respectively, of the Convertible Preferred Stock were
converted into common stock.
During 1994, Enron authorized and issued to a wholly-owned
subsidiary 35.568509 shares of 9.142% Perpetual Second
Preferred Stock (a new series of the Second Preferred
Stock).
Company-Obligated Preferred Stock of Subsidiaries. During
December 1994, Enron's wholly-owned subsidiary, Enron Equity
Corp., issued 880 shares of 8.57% Preferred Stock, par value
$0.001 per share, liquidation preference $100,000 per share,
in a private transaction at a price of $100,000 per share
with net proceeds of approximately $88 million. The 8.57%
Preferred Stock is redeemable at Enron's option after
December 1999 at a price of $100,000 per share plus
accumulated and unpaid dividends. Dividends on the 8.57%
Preferred Stock are guaranteed by Enron.
During August 1994, Enron Capital Resources, L.P., a
Delaware limited partnership in which Enron is the sole
general partner, issued 3 million shares of 9% Cumulative
Preferred Securities, Series A, at a price to the public of
$25 per share with net proceeds of approximately $73
million.
During November 1993, Enron's wholly-owned subsidiary Enron
Capital LLC issued 8.55 million shares of 8% Cumulative
Guaranteed Monthly Income Preferred Shares (MIPS) at a price
of $25 per share with net proceeds of approximately $207
million.
The Series A Preferred Securities and the MIPS are
redeemable at the option of Enron in whole or in part
beginning August 31, 1999 and November 30, 1998,
respectively, at a redemption price of $25 per share plus
accumulated and unpaid dividends. The liquidation preference
of each of the Series A Preferred Securities and the MIPS is
$25 per share.
10 Common Stock and Dividends
Enron paid quarterly cash dividends on common stock of $.175
per share ($.70 per share annually) from the final quarter
of 1992 until the final quarter of 1993, at which time the
dividend was increased to $.1875 per share ($.75 per share
annually). The dividend was further increased to $.20 per
share ($.80 per share annually) for the final quarter of
1994 and was increased to $.2125 per share ($.85 per share
annually) for the final quarter of 1995. Enron's debt
agreements do not limit the payment of cash dividends on
common stock.
Common stock information is as follows:
[Download Table]
1995 1994 1993(a)
Common Stock, beginning of year 253,069,668 249,095,312 237,532,176
Issued to Benefit and Dividend
Reinvestment Plans 197,388 1,303,047 1,476,131
Issued for Conversions (b) 219,138 1,251,793 2,446,632
Issued to Flexible Equity Trust - - 7,500,000
Issued to JEDI 374,166 1,419,516 140,373
Common Stock, end of year 253,860,360 253,069,668 249,095,312
<FN>
(a) Presented as if the 1993 stock split was January 1, 1993.
(b) Conversions of convertible preferred stock.
Treasury stock information is as follows:
[Download Table]
1995 1994 1993(a)
Treasury Stock, beginning of year 1,394,833 - 349,400
Benefit and Dividend
Reinvestment Plans
Issued (2,418,216) (47,790) (1,482,927)
Returned 328,342 - 102,013
Open Market Purchases (b) 3,496,504 1,897,923 3,005,200
Issued for Conversions (c) (183,429) - (2,043,090)
Issued to JEDI - (455,300) -
Other - - 69,404
Treasury Stock, end of year 2,618,034 1,394,833 -
<FN>
(a) Presented as if the 1993 stock split was January 1, 1993.
(b) Purchased in connection with a stock repurchase
program authorized by the Board of Directors.
(c) Conversions of convertible preferred stock.
Enron has various stock 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. Under the Plans, 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. Enron accounts for
the Plans under APB Opinion No. 25, and accordingly, no
compensation expense has been recognized. Expiration dates
of the options outstanding at December 31, 1995 range from
February 8, 1998 to December 29, 2005. The Plans provide for
options to be granted with stock appreciation rights (SAR);
however, Enron does not presently intend to issue additional
options with an SAR feature. Summarized information for the
Plans is as follows:
[Download Table]
1995 1994 1993
Shares under option,
beginning of year 24,245,447 9,679,719 7,314,332
Granted (a) 2,971,210 15,805,680 4,253,233
Exercised (3,137,433) (1,019,090) (1,621,680)
Cancelled or expired (1,586,541) (220,862) (266,166)
Shares under option, end of year 22,492,683 24,245,447 9,679,719
Shares available for grant at
end of year (b) 7,830,758 4,006,833 1,500,301
Shares exercisable at end of year 9,599,245 7,183,664 3,104,722
Average price of options exercised
during the year $20.91 $13.50 $13.30
Average price of options outstanding
at end of year $29.02 $27.38 $19.64
<FN>
(a) Includes options granted on December 29, 1995 and
December 30, 1994 for 997,095 shares and 9,717,750 shares,
respectively, under all-employee stock option grants for the
years 1995 through 2000.
(b) Excludes up to 5,209,620 shares, 5,245,100 shares
and 2,528,560 shares as of December 31, 1995, 1994 and 1993,
respectively, which may be issued either as Restricted Stock
or pursuant to stock options.
Under the Plans, participants may be granted stock without
cost to the participant (restricted stock). The shares
issued under the Plans vest to the participants at various
times ranging from immediate vesting to vesting at the end
of a five year period. The following is an analysis of
shares of restricted stock:
[Download Table]
1995 1994 1993
Outstanding at beginning of year 193,505 221,658 35,588
Granted 44,900 30,190 203,700
Cancelled or expired (9,420) (2,040) (3,632)
Issued(a) (69,545) (56,303) (13,998)
Outstanding at end of year 159,440 193,505 221,658
Available for grant at end of year 5,209,620 5,245,100 2,528,560
Average price per share
on date of grant $31.36 $32.89 $27.50
<FN>
(a) Subsequent to December 31, 1995, 1,534,275 shares of
restricted stock were issued in connection with the
conversion of certain compensation plans.
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
areduction 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 1995, 1,049,403 shares were released to
fund employee benefits.
11 Retirement Benefits Plan and ESOP
Enron maintains a retirement plan (the Enron Plan) which is
a noncontributory defined benefit plan covering
substantially all employees in the United States and certain
employees in foreign countries. Through December 31, 1994,
participants in the Enron Plan with five years or more of
service were entitled to retirement benefits 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 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. At December 31, 1995, all shares included in
the ESOP had been allocated to the employee accounts.
The components of pension expense are as follows:
[Download Table]
(In Thousands) 1995 1994 1993
Service cost - benefits earned
during the year $ 1,654 $ 16,192 $ 11,709
Interest cost on projected
benefit obligation 21,172 25,996 25,230
Actual return on plan assets (32,299) (22,235) (37,507)
Amortization and deferrals 8,810 (12,225) 11,184
Pension expense (income) $ (663) $ 7,728 $ 10,616
The valuation 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 Thousands) 1995 1994
Actuarial present value of accumulated
benefit obligation
Vested $(275,668) $(253,881)
Nonvested (26,875) (25,546)
Additional amounts related
to projected wage increases (11,536) (54,260)
Projected benefit obligation (314,079) (333,687)
Plan assets at fair value (a) 294,763 352,608
Plan assets in excess of (less than)
projected benefit obligation (19,316) 18,921
Unrecognized net loss 53,524 35,563
Unrecognized prior service cost 44,476 12,416
Unrecognized net asset at transition (36,205) (42,238)
Contributions 553 548
Prepaid pension cost at December 31 $ 43,032 $ 25,210
Discount rate 7.5% 8.0%
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 $152,202
and $235,540 for the years 1995 and 1994, 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 Thousands) 1995 1994
Actuarial present value of accumulated
postretirement benefit obligation (APBO)
Retirees $(114,271) $ (88,838)
Fully eligible active plan
participants (2,342) (2,164)
Other employees (14,648) (15,712)
Total APBO (131,261) (106,714)
Plan assets at fair value 10,511 3,073
APBO in excess of plan assets (120,750) (103,641)
Unrecognized transition obligation 70,058 74,803
Unrecognized prior service costs 19,176 18,148
Unrecognized net loss 25,915 5,148
Accrued postretirement benefit obligation $ (5,601) $ (5,542)
Discount rate 7.5% 8.0%
Health care cost trend rate* 11.7% 12.3%
<FN>
* This rate is assumed to decrease to 5.0% over 10 years.
The components of net periodic postretirement benefit
expenses are as follows:
[Download Table]
(In Thousands) 1995 1994 1993
Service costs $ 1,220 $ 1,527 $ 850
Interest costs 9,025 7,964 7,374
Return on plan assets (266) (106) (39)
Amortization of transition obligation 6,386 6,003 4,744
Postretirement benefit expense $16,365 $15,388 $12,929
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 $8.8 million and $0.6 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, 1995 and 1994, respectively, are
approximately $291 million and $305 million, which include
transition costs incurred related to FERC Order 636 of
approximately $125 million and$158 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. The rate case included an increase
of $31 million to Northern's cost of service. The FERC
accepted and suspended the filing to be effective September
1, 1995 subject to refund. Northern effectuated the higher
rates January 1, 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 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 also sued certain other unaffiliated
third parties (collectively, the Other Defendants). 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 that will be tried (or otherwise
resolved) separately. In the first matter, the Plaintiffs
sued only the Enron Defendants, alleging that they committed
fraud and negligent misrepresentation in connection with the
"Panhandle program," a special marketing program established
in the early 1980s. In the second matter, the Plaintiffs
allege that Intratex and the Other 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. In
both matters, the Plaintiffs seek an unspecified amount of
actual and punitive damages, plus prejudgement interest and
attorneys fees. All Defendants deny the Plaintiffs' claims
and have asserted various affirmative defenses, including
the statute of limitations. The Enron Defendants believe
they have strong legal and factual defenses, and intend to
vigorously contest the claims brought in each matter.
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.
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.
In addition, Enron received requests for information from
the Environmental Protection Agency (EPA) and state
environmental agencies inquiring whether Enron has disposed
of materials at certain waste disposal sites. Enron has
received notices from EPA and state agencies that it is a
"potentially responsible party" (PRP) under the
Comprehensive Environmental Response, Compensation and
Liability Act and analogous state statutes, and may be
required to share in the costs of the cleanup of other,
similar sites. However, Enron believes that any potential
assessments in connection with these PRP notices and third
party claims, either taken individually or in the aggregate,
will not have a material impact on Enron's financial
position or results of operations.
Other
In October 1994, an explosion occurred at Enron's methanol
plant in Pasadena, Texas. Before the explosion, the plant
was producing approximately 420,000 gallons of methanol per
day, approximately half of which was being used at Enron's
MTBE plant. There were no fatalities or serious injuries as
a result of the explosion. The plant was placed back into
commercial operation in June 1995. Taking into account
business interruption and other insurance coverages, Enron
currently anticipates that the explosion did not and will
not have a materially adverse effect on its financial
position or results of operations.
In connection with a Power Purchase Agreement between Dabhol
Power Company, Enron's 80%-owned subsidiary, and the
Maharashtra State Electricity Board, Dabhol Power Company
has been 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. Enron believes that such actions were in clear
violation of the contract and in response to these actions,
Dabhol Power Company commenced arbitration proceedings in
London against the State government for the actions it has
taken to terminate the Project. Dabhol Power Company seeks
to recover all of its construction and other expenses, in
addition to lost profits. In addition, Dabhol Power Company
has both orally and in writing communicated to the
Maharashtra State government its desire to go forward with
construction of the Project and its willingness to resolve
any outstanding issues. In January 1996, the Maharashtra
State government notified Dabhol Power Company in writing
that it had approved a restructured transaction (that
includes both Phase I and Phase II and that increases the
planned capacity of the facility by 435 megawatts to 2,450
megawatts) on terms that are acceptable to Enron. While the
parties are working together in good faith and Enron
anticipates construction to resume in the near future,
various approvals remain outstanding from government
agencies and lenders. Although the outcomes of the
arbitration and the renegotiation processes cannot be
predicted with certainty, based on currently available
information, Enron believes that the ultimate outcome of the
Project will not have a materially adverse effect on its
financial position.
In March 1993, Enron entered into long-term gas contracts
with Phillips Petroleum Company United Kingdom Limited,
British Gas Exploration and Production Limited and Agip
(U.K.) Limited to purchase all of the future gas production
from the J-Block field which is located in the North Sea
offshore the United Kingdom (the J-Block Contracts). Such
agreements provide for Enron to take or pay for the gas at a
fixed price (with possible escalations throughout the
contract period). Gas paid for, but not taken, may be
recovered in later contract years. The J-Block Contracts
provide for a first delivery date of not later than October
1, 1996. The contract price for such natural gas is in
excess of current spot market prices in the United Kingdom.
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
through September 30, 1997. In addition, in accordance with
its contractual rights, Enron has made no estimated
nominations for J-Block gas to date under the J-Block
Contracts for the contract year ending September 30, 1998.
Enron continues its good faith efforts to develop mutually
beneficial solutions regarding pricing terms so that
production from J-Block can begin as soon as possible. Enron
believes that there are many commercial reasons for the
parties to resolve any contract issues, but efforts have not
been successful to date. Enron has advised the J-Block
sellers that it intends to assert all legal rights, exercise
all available commercial flexibility and pursue all
available commercial and legal remedies under the J-Block
Contracts, and stands ready and able to perform all legal
obligations under the J-Block Contracts, including potential
prepayments for gas to be taken in later years. The long-
term market demand for J-Block gas supply remains favorable
and Enron anticipates being able to meet all of its various
short- and long-term market commitments. Although no
assurances can be given, based upon the foregoing and other
information currently available, Enron does not anticipate
that the J-Block Contracts will have a materially adverse
effect on its financial position.
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. The estimated
aggregate amounts of such required future payments at
December 31, 1995, were:
[Download Table]
(In Millions)
1996 $ 108.5
1997 118.5
1998 122.1
1999 126.9
2000 132.1
Later years 1,194.7
Total $1,802.8
The costs incurred under these agreements, including
commodity charges on actual quantities shipped, totaled
$18.4 million, $20.8 million and $42.4 million in 1995, 1994
and 1993, respectively. Enron has assigned a firm
transportation contract with one of its joint ventures to a
third party and guaranteed minimum payments under the
contract averaging approximately $45.4 million annually
through 2001.
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.
Guarantees under the leases total $1.02 billion at December
31, 1995. Future commitments related to these items at
December 31, 1995 are as follows:
[Download Table]
(In Millions)
1996 $ 164.5
1997 139.2
1998 117.4
1999 92.6
2000 87.4
Later years 434.0
Total minimum payments $1,035.1
Total rent expense incurred during 1995, 1994 and 1993 was
$147.2 million, $125.6 million and $103.7 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,
1995, a total of $320.6 million of such guarantees were
outstanding, including $116.2 million on behalf of EOTT. In
addition, Enron is a guarantor on certain liabilities of
unconsolidated subsidiaries and other companies totaling
approximately $665.3 million, including $300.7 million
related to EOTT trade obligations. The EOTT letters of
credit and guarantees of trade obligations are fully secured
by the assets of EOTT. 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 1996
planned capital expenditures.
16 Other Income, Net
The components of Other Income, Net are as follows:
[Download Table]
Year Ended December 31,
(In Thousands) 1995 1994 1993
Gain on sale of EOG stock $366,695 $ - $ -
Gains on sales of other
assets and investments 100,476 37,270 102,268
Regulatory, contingency
and other adjustments (19,905) 17,700 (55,689)
Foreign currency gains (losses) (735) 8,188 -
Litigation adjustments and
settlements, net (7,605) (1,110) 4,282
Other (4,685) 15,001 11,254
$434,241 $77,049 $ 62,115
In December 1995, Enron completed a public offering of 31
million outstanding shares of its EOG common stock, reducing
its ownership interest from 80% to 61%. Enron recognized a
pretax gain of $367 million ($161 million after tax) on net
proceeds totaling $650 million.
Concurrently, Enron issued 6 1/4% Exchangeable Notes which
will be mandatorily exchangeable in three years into shares
of EOG common stock owned by Enron at a specified exchange
rate (or at Enron's option, for cash with an equal value).
Proceeds from the issuance of these notes totaled $221
million. At the maturity of the notes, if all of the
Exchangeable Notes are exchanged for the maximum number of
EOG common shares, Enron's interest in EOG will be reduced
to approximately 54%.
17 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, liquids, clean fuel plants and power facilities.
Investment in crude oil transportation activities and
liquids pipeline operations.
Domestic Gas and Power Services - Purchasing, marketing and
financing of natural gas, natural gas liquids, crude oil and
power. Price risk management in connection with natural gas,
natural gas liquids, crude oil and power transactions.
Intrastate natural gas pipelines. Development, acquisition
and promotion of natural gas fired power plants in North
America. Extraction of natural gas liquids.
International Gas and Power Services - 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 for
each of the three years in the period ended December 31,
1995, follows.
[Download Table]
Geographic Segments
Year Ended December 31,
(In Thousands) 1995 1994 1993
Operating Revenues from
Unaffiliated Customers
United States $ 7,855,215 $ 7,604,127 $ 7,071,406
Foreign 1,333,782 1,379,596 914,394
$ 9,188,997 $ 8,983,723 $ 7,985,800
Intersegment Sales
United States $ 23,735 $ 48,369 $ 20,785
Foreign 158,812 116,257 66,574
$ 182,547 $ 164,626 $ 87,359
Operating Income
United States $ 487,319 $ 609,008 $ 567,274
Foreign 130,683 106,764 63,528
$ 618,002 $ 715,772 $ 630,802
Income Before Interest, Minority
Interest and Income Taxes
United States $ 968,637 $ 755,686 $ 663,276
Foreign 196,445 188,706 134,391
$ 1,165,082 $ 944,392 $ 797,667
Identifiable Assets
United States $10,694,896 $ 9,597,093 $ 9,939,618
Foreign 1,327,565 1,303,729 867,613
$12,022,461 $10,900,822 $10,807,231
[Enlarge/Download Table]
Operations In Business and Geographic Segments
Business Segments
International
Transportation Domestic Gas Gas and Exploration Corporate
and and Power Power and and
(In Thousands) Operation Services Services Production Other(c)(d) Total
1995
Unaffiliated Revenues(a) $ 804,946 $7,063,750 $ 839,125 $ 481,176 $ - $ 9,188,997
Intersegment Revenues(b) 25,610 (102,975) 43,757 278,191 (244,583) -
Total Revenues 830,556 6,960,775 882,882 759,367 (244,583) 9,188,997
Depreciation, Depletion and
Amortization 82,790 103,582 26,712 216,047 2,575 431,706
Operating Income (Loss) 299,227 114,583 75,192 240,002 (111,002) 618,002
Equity in Earnings of Unconsolidated
Subsidiaries 23,156 6,325 57,245 - (708) 86,018
Other Income, net 36,803 36,590 9,531 669 377,469 461,062
Income Before Interest, Minority
Interest and Income Taxes 359,186 157,498 141,968 240,671 265,759 1,165,082
Additions to Property, Plant
and Equipment 121,208 97,781 58,212 464,045 8,255 749,501
Identifiable Assets 2,360,702 5,991,423 813,868 2,066,952 789,516 12,022,461
Investments in and Advances to
Unconsolidated Subsidiaries 533,531 156,805 467,596 - 58,542 1,216,474
Total Assets $2,894,233 $6,148,228 $1,281,464 $2,066,952 $ 848,058 $13,238,935
1994
Unaffiliated Revenues(a) $ 937,524 $7,165,582 $ 391,919 $ 488,698 $ - $ 8,983,723
Intersegment Revenues(b) 38,756 13,392 6,984 290,090 (349,222) -
Total Revenues 976,280 7,178,974 398,903 778,788 (349,222) 8,983,723
Depreciation, Depletion and
Amortization 87,555 93,795 15,226 242,182 2,571 441,329
Operating Income (Loss) 327,267 164,118 72,206 195,120 (42,939) 715,772
Equity in Earnings of Unconsolidated
Subsidiaries 48,695 18,427 45,227 - 60 112,409
Other Income, net 27,012 19,701 30,312 2,783 36,403 116,211
Income Before Interest, Minority
Interest and Income Taxes 402,974 202,246 147,745 197,903 (6,476) 944,392
Additions to Property, Plant
and Equipment 117,018 83,014 13,887 442,078 4,918 660,915
Identifiable Assets 2,388,517 5,802,989 449,988 1,823,898 435,430 10,900,822
Investments in and Advances to
Unconsolidated Subsidiaries 527,822 161,788 351,354 - 24,225 1,065,189
Total Assets $2,916,339 $5,964,777 $ 801,342 $1,823,898 $ 459,655 $11,966,011
1993
Unaffiliated Revenues(a) $1,385,925 $5,449,946 $ 751,375 $ 398,554 $ - $ 7,985,800
Intersegment Revenues(b) 80,081 134,158 19,213 308,571 (542,023) -
Total Revenues 1,466,006 5,584,104 770,588 707,125 (542,023) 7,985,800
Depreciation, Depletion and
Amortization 115,922 80,960 9,081 249,704 2,521 458,188
Operating Income (Loss) 341,272 155,573 64,582 122,439 (53,064) 630,802
Equity in Earnings of Unconsolidated
Subsidiaries 22,427 8,821 41,962 - 83 73,293
Other Income, net 18,437 32,466 24,835 6,635 11,199 93,572
Income Before Interest, Minority
Interest and Income Taxes 382,136 196,860 131,379 129,074 (41,782) 797,667
Additions to Property, Plant
and Equipment 144,835 102,518 52,545 383,064 5,070 688,032
Identifiable Assets 2,808,816 5,352,163 492,297 1,668,395 485,560 10,807,231
Investments in and Advances to
Unconsolidated Subsidiaries 278,912 83,360 315,461 - 19,351 697,084
Total Assets $3,087,728 $5,435,523 $ 807,758 $1,668,395 $ 504,911 $11,504,315
<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.
18 Oil and Gas Producing Activities
(Unaudited except for Results of Operations for Oil and Gas
Producing Activities)
The following information regarding Enron's oil and gas
producing activities should be read in conjunction with Note
1. This information includes amounts attributable to a 39%
minority interest at December 31, 1995 and a 20% minority
interest at December 31, 1994, 1993 and 1992.
[Download Table]
Capitalized Costs Relating to Oil and Gas Producing
Activities
December 31,
(In Thousands) 1995 1994
Proved properties $ 3,253,593 $ 2,889,242
Unproved properties 127,331 126,193
Total 3,380,924 3,015,435
Accumulated depreciation,
depletion and amortization (1,499,379) (1,330,624)
Net capitalized costs $ 1,881,545 $ 1,684,811
[Enlarge/Download Table]
Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities (a)
Foreign
(In Thousands) United States Canada Trinidad India Other Total
1995
Acquisition of properties
Unproved $ 16,196 $ 4,645 $ - $ - $ 1,482 $ 22,323
Proved 122,369 116 - 5,000 - 127,485
Total 138,565 4,761 - 5,000 1,482 149,808
Exploration 47,463 7,197 374 (98) 17,948 72,884
Development 217,674 28,611 32,692 16,756 577 296,310
Total $403,702 $40,569 $33,066 $21,658 $20,007 $519,002
1994
Acquisition of properties
Unproved $ 45,776 $ 6,618 $ - $ - $ (17) $ 52,377
Proved 17,367 4,523 - 12,300 - 34,190
Total 63,143 11,141 - 12,300 (17) 86,567
Exploration 70,669 8,210 850 2,302 11,242 93,273
Development 223,241 35,896 60,778 767 564 321,246
Total $357,053 $55,247 $61,628 $15,369 $11,789 $501,086
1993
Acquisition of properties
Unproved $ 23,686 $ 4,556 $ - $ - $ 887 $ 29,129
Proved 6,625 2,598 - - - 9,223
Total 30,311 7,154 - - 887 38,352
Exploration 53,918 9,096 1,367 - 18,595 82,976
Development 247,705 28,045 41,262 - - 317,012
Total $331,934 $44,295 $42,629 $ - $19,482 $438,340
<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.
[Enlarge/Download Table]
Results of Operations for Oil and Gas Producing Activities (a)
The following tables set forth results of operations for oil
and gas producing activities for the three years in the
period ended December 31, 1995:
Foreign
(In Thousands) United States Canada Trinidad India Other Total
1995
Operating revenues
Associated companies $223,652 $ 6,893 $ - $ - $ - $230,545
Trade 122,567 36,815 71,686 15,411 - 246,479
Gains on sales of reserves
and related assets 62,737 84 - - - 62,821
Total 408,956 43,792 71,686 15,411 - 539,845
Exploration expenses, including
dry hole costs 35,298 3,839 374 (98) 15,542 54,955
Production costs 63,734 13,825 8,176 10,553 - 96,288
Impairment of unproved oil and
gas properties 21,981 1,734 - - - 23,715
Depreciation, depletion and
amortization 180,788 19,533 14,633 335 368 215,657
Income (loss) before income taxes 107,155 4,861 48,503 4,621 (15,910) 149,230
Income tax expense (benefit) 1,226 1,133 26,677 2,311 (1,335) 30,012
Results of Operations $105,929 $ 3,728 $21,826 $ 2,310 $(14,575) $119,218
1994
Operating revenues
Associated companies $315,866 $ 8,452 $ - $ - $ - $324,318
Trade 115,375 42,017 35,908 509 - 193,809
Gains on sales of reserves and
related assets 54,026 (12) - - - 54,014
Total 485,267 50,457 35,908 509 - 572,141
Exploration expenses, including
dry hole costs 42,242 4,503 836 2,302 9,125 59,008
Production costs 68,998 12,776 5,083 26 - 86,883
Impairment of unproved oil and
gas properties 23,862 1,074 - - - 24,936
Depreciation, depletion and
amortization 218,433 16,572 6,572 - 281 241,858
Income (loss) before income taxes 131,732 15,532 23,417 (1,819) (9,406) 159,456
Income tax expense (benefit) (8,617) 6,175 12,804 (910) (2,873) 6,579
Results of Operations $140,349 $ 9,357 $10,613 $ (909) $ (6,533) $152,877
1993
Operating revenues
Associated companies $369,824 $ 9,637 $ - $ - $ - $379,461
Trade 140,552 33,228 1,209 - - 174,989
Gains on sales of reserves
and related assets 13,724 (406) - - - 13,318
Total 524,100 42,459 1,209 - - 567,768
Exploration expenses, including
dry hole costs 35,029 6,657 1,367 - 12,223 55,276
Production costs 75,767 14,063 1,496 - - 91,326
Impairment of unproved oil and
gas properties 19,499 968 - - - 20,467
Depreciation, depletion and
amortization 234,292 14,630 387 - 154 249,463
Income (loss) before income taxes 159,513 6,141 (2,041) - (12,377) 151,236
Income tax expense (benefit) (15,525) 2,265 (1,020) - (1,742) (16,022)
Results of Operations $175,038 $ 3,876 $(1,021) $ - $(10,635) $167,258
<FN>
(a) Excludes net revenues associated with other
marketing activities, interest charges, general corporate
expenses and certain gathering and handling fees for each of
the three years in the period ended December 31, 1995. The
gathering and handling fees and other marketing net revenues
are directly associated with oil and gas operations with
regard to required segment reporting, but 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, 1995, 1994 and 1993 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, 1995, 1994 and 1993
covering producing areas, in the United States and Canada,
containing 73%, 59% and 65%, respectively, of proved
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. 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 has been restated to exclude, 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.
[Enlarge/Download Table]
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
(In Thousands) United States Canada Trinidad India Total
1995
Future cash inflows(a) $3,996,029 $ 502,803 $ 395,328 $ 396,130 $ 5,290,290
Future production costs (747,064) (203,906) (152,287) (202,410) (1,305,667)
Future development costs (297,859) (7,153) (3,610) (13,500) (322,122)
Future net cash flows before
income taxes 2,951,106 291,744 239,431 180,220 3,662,501
Future income taxes (695,843) (46,310) (105,188) (81,349) (928,690)
Future net cash flows 2,255,263 245,434 134,243 98,871 2,733,811
Discount to present value at
10% annual rate (1,015,123) (68,861) (19,217) (45,470) (1,148,671)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $1,240,140(b) $ 176,573 $ 115,026 $ 53,401 $ 1,585,140(b)
1994
Future cash inflows(a) $2,315,215 $ 487,050 $ 317,758 $ 168,370 $ 3,288,393
Future production costs (606,932) (196,275) (87,479) (105,840) (996,526)
Future development costs (135,768) (9,596) (1,781) (4,500) (151,645)
Future net cash flows before
income taxes) 1,572,515 281,179 228,498 58,030 2,140,222
Future income taxes (208,163) (57,220) (102,171) (22,482) (390,036)
Future net cash flows 1,364,352 223,959 126,327 35,548 1,750,186
Discount to present value at
10% annual rate (401,547) (67,018) (22,897) (14,730) (506,192)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 962,805(b) $ 156,941 $ 103,430 $ 20,818 $ 1,243,994(b)
1993
Future cash inflows(a) $3,154,790 $ 592,845 $ 147,542 $ - $ 3,895,177
Future production costs (639,760) (230,230) (45,385) - (915,375)
Future development costs (165,473) (21,001) (7,582) - (194,056)
Future net cash flows before
income taxes 2,349,557 341,614 94,575 - 2,785,746
Future income taxes (487,017) (91,718) (35,477) - (614,212)
Future net cash flows 1,862,540 249,896 59,098 - 2,171,534
Discount to present value at
10% annual rate (600,172) (90,125) (9,519) - (699,816)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $1,262,368(b) $ 159,771 $ 49,579 $ - $ 1,471,718(b)
<FN>
(a) Based on year-end market prices determined at the
point of delivery from the producing unit.
(b) Excludes $36.0 million, $60.3 million, $105.3
million and $127.7 million at December 31, 1995, 1994, 1993
and 1992, 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 (see Note 7).
[Enlarge/Download Table]
Changes in Standardized Measure of Discounted Future Net
Cash Flows
(In Thousands) United States Canada Trinidad India Total
December 31, 1992 $1,183,692 $125,419 $ - $ - $1,309,111
Sales and transfers of oil
and gas produced, net of
production costs (388,251) (28,802) 287 - (416,766)
Net changes in prices and
production costs 158,102 28,400 - - 186,502
Extensions, discoveries, additions
and improved recovery, net of
related costs 275,722 27,785 74,191 - 377,698
Development costs incurred 58,500 13,900 - - 72,400
Revisions of estimated development
costs 32,196 (1,345) - - 30,851
Revisions of previous quantity
estimates (26,118) 5,668 - - (20,450)
Accretion of discount 128,461 15,348 - - 143,809
Net change in income taxes (76,755) (9,795) (24,899) - (111,449)
Purchases of reserves in place 9,462 2,707 - - 12,169
Sales of reserves in place (36,919) (1,140) - - (38,059)
Changes in timing and other (55,724) (18,374) - - (74,098)
December 31, 1993 $1,262,368 $159,771 $ 49,579 $ - $1,471,718
Sales and transfers of oil
and gas produced, net
of production costs (339,809) (37,693) (30,825) (483) (408,810)
Net changes in prices and
production costs (506,273) (65,287) 11,002 - (560,558)
Extensions, discoveries, additions
and improved recovery, net of
related costs 225,366 51,006 96,515 - 372,887
Development costs incurred 69,900 6,700 7,582 - 84,182
Revisions of estimated development
costs 6,792 5,931 - - 12,723
Revisions of previous quantity
estimates (2,909) (3,407) 14,077 - 7,761
Accretion of discount 145,119 19,762 7,448 - 172,329
Net change in income taxes 167,983 19,966 (45,789) (7,752) 134,408
Purchases of reserves in place 16,651 3,404 - 29,053 49,108
Sales of reserves in place (27,980) (461) - - (28,441)
Changes in timing and other (54,403) (2,751) (6,159) - (63,313)
December 31, 1994 $ 962,805 $156,941 $103,430 $20,818 $1,243,994
Sales and transfers of oil
and gas produced, net
of production costs (268,463) (29,883) (63,510) (4,858) (366,714)
Net changes in prices and
production costs 12,079 (5,698) (37,035) 7,857 (22,797)
Extensions, discoveries, additions
and improved recovery, net of
related costs 376,474(a) 38,028 53,674 46,180 514,356(a)
Development costs incurred 29,100 2,600 1,800 - 33,500
Revisions of estimated development
costs 920 139 28,771 4,500 34,330
Revisions of previous quantity
estimates 5,694 (5,217) 10,142 (29) 10,590
Accretion of discount 97,248 17,483 17,412 2,857 135,000
Net change in income taxes (132,614) 10,592 (8,048) (28,127) (158,197)
Purchases of reserves in place 193,711 - - - 193,711
Sales of reserves in place (54,441) (569) - - (55,010)
Changes in timing and other 17,627 (7,843) 8,390 4,203 22,377
December 31, 1995 $1,240,140 $176,573 $115,026 $53,401 $1,585,140
<FN>
(a) Includes approximately $77 million related to the
reserves in the Big Piney deep Paleozoic formations.
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, 1992 1,054.1(a) 194.4 - - 1,248.5(a)
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)
Liquids (MBbl)(c)
December 31, 1992 12,762(a) 5,329 - - 18,091(a)
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)
Natural gas (Bcf)
Net proved reserves at
December 31, 1992 1,326.1(a) 232.5 - - 1,558.6(a)
Revisions of previous estimates (31.3) 11.0 - - (20.3)
Purchases in place 9.2 2.6 - - 11.8
Extensions, discoveries and
other additions 234.9 47.7 101.3 - 383.9
Sales in place (13.7) (1.5) - - (15.2)
Production (212.0) (21.3) (0.8) - (234.1)
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)
Liquids (MBbl)(c)
Net proved reserves at
December 31, 1992 13,865 5,358 - - 19,223
Revisions of previous estimates 1,490 (536) - - 954
Purchases in place 15 489 - - 504
Extensions, discoveries and
other additions 3,552 1,115 2,251 - 6,918
Sales in place (3,230) (23) - - (3,253)
Production (2,520) (932) (33) - (3,485)
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
<FN>
(a) Excludes approximately 54.2 Bcf, 70.9 Bcf, 87.5 Bcf
and 114.3 Bcf at December 31, 1995, 1994 , 1993 and 1992,
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 (see Note 7).
(b) Includes 1,180.0 Bcf related to net proved Deep
Paleozoic natural gas reserves.
(c) Includes crude oil, condensate and natural gas
liquids.
[Enlarge/Download Table]
Enron Corp. and Subsidiaries
SUPPLEMENTAL FINANCIAL INFORMATION (UNAUDITED)
Quarterly Results
Income Before
Interest, Minority Fully
(In Thousands, Operating Gross Interest and Primary Earnings Diluted Earnings
Except Per Share Amounts) Revenues Profit Income Taxes Net Income Per Share(a) Per Share(a)
1995
First Quarter $2,303,949 $684,516 $371,442 $194,950 $.79 $.73
Second Quarter 2,149,346 598,866 230,447 94,045 .37 .35
Third Quarter 2,185,805 629,256 239,328 100,583 .40 .37
Fourth Quarter 2,549,897 542,873 323,865 130,116 .52 .49
1994
First Quarter $2,455,726 $673,333 $336,066 $173,063 $.70 $.65
Second Quarter 1,910,709 539,167 168,703 75,601 .30 .28
Third Quarter 2,030,663 553,774 204,569 95,995 .38 .36
Fourth Quarter 2,586,625 700,340 235,054 108,751 .43 .41
<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.
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 16, 1996. 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 16, 1996
[Enlarge/Download Table]
SCHEDULE II
ENRON CORP. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
(In Thousands)
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
1995
Reserves deducted from
assets to which they apply
Allowance for doubtful
accounts $ 12,730 $ 4,248 $ 179 $ 5,515 $ 11,642
Assets from price risk
management activities $129,925 $49,619 $ 45,154 $ 17,967 $206,731
Reserve for regulatory issues
Current $ 5,740 $13,559 $ 107 $ 5,319 $ 14,087
Noncurrent $ - $37,000 $ - $ - $ 37,000
Reserve for insurance claims
and losses - noncurrent $ 25,286 $ 7,510 $ - $ 9,071 $ 23,725
Reserve for Clean Fuels
Plant Operations $ - $75,000 $ - $ - $ 75,000
1994
Reserves deducted from
assets to which they apply
Allowance for doubtful
accounts $ 21,873 $ 4,603 $ (278) $ 13,468(1) $ 12,730
Assets from price risk
management activities $102,520 $13,367 $ 19,400 $ 5,362 $129,925
Reserve for regulatory issues
Current $ 21,730 $14,555 $ 5,472 $ 36,017(2) $ 5,740
Noncurrent $ 21,418 $ 892 $ - $ 22,310 $ -
Reserve for insurance claims
and losses - noncurrent $ 28,410 $ 1,893 $ - $ 5,017 $ 25,286
1993
Reserves deducted from
assets to which they apply
Allowance for doubtful
accounts $ 14,555 $ 6,558 $ 2,955 $ 2,195 $ 21,873
Assets from price risk
management activities $ 74,108 $60,207 $ - $ 31,795 $102,520
Reserve for regulatory issues
Current $ 8,799 $29,282 $(24,345) $ (7,994) $ 21,730
Noncurrent $ 3,677 $ 8,069 $ 9,672 $ - $ 21,418
Reserve for insurance claims
and losses - noncurrent $ 22,779 $10,355 $ - $ 4,724 $ 28,410
<FN>
(1) Includes $10.8 million resulting from the sale of a majority interest
in Enron's crude oil trading and transportation assets.
(2) Includes amounts credited to income in connection with the resolution
of regulatory issues.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of
the Securities Exchange Act of 1934, the Registrant has duly
caused this Report to be signed on its behalf by the
undersigned, thereunto duly authorized, on this 29th day of
March, 1996.
ENRON CORP.
(Registrant)
By: JACK I. TOMPKINS
(Jack I. Tompkins)
Senior Vice President
and Chief Information,
Administrative and
Accounting Officer
Pursuant to the requirements of the Securities Exchange
Act of 1934, this Report has been signed below on March 29th,
1996 by the following persons on behalf of the Registrant and
in the capacities indicated.
Signature Title
KENNETH L. LAY Chairman of the Board, Chief Executive
(Kenneth L. Lay) Officer and Director (Principal
Executive Officer)
JACK I. TOMPKINS Senior Vice President and Chief
(Jack I. Tompkins) Information, Administrative and
Accounting Officer (Principal
Accounting Officer)
KURT S. HUNEKE Vice President, Finance and Treasurer
(Kurt S. Huneke) (Principal Financial Officer)
ROBERT A. BELFER* Director
(Robert A. Belfer)
NORMAN P. BLAKE, JR.* Director
(Norman P. Blake, Jr.)
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)
RICHARD D. KINDER* Director and President and Chief
(Richard D. Kinder) Operating Officer
CHARLES A. LEMAISTRE* Director
(Charles A. LeMaistre)
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)
EXHIBIT INDEX
Exhibit
Number Description
*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.
*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. 3364057 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 10.49
*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.
*10.03 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to
Registration Statement No. 33-27893).
*10.04 - Executive Incentive Plan (Exhibit 10.13 to Enron Form
10-K for 1987, File No. 1-3423).
*10.05 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to
Enron Form 10-K for 1987, File No. 1-3423).
10.06 - First Amendment to Enron Corp. 1988 Deferral Plan.
10.07 - Second Amendment to Enron Corp. 1988 Deferral Plan.
*10.08 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron
Form 10-K for 1991, File No. 1-3423).
*10.09 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to
Enron Form 10-K for 1991, File No. 1-3423).
10.10 - First Amendment to Enron Corp. 1992 Deferral Plan.
10.11 - Second Amendment to Enron Corp. 1992 Deferral Plan.
*10.12 - Enron Corp. Directors' Deferred Income Plan (Exhibit
10.09 to Enron Form 10-K for 1992, File No. 1-3423).
*10.13 - 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).
*10.14 - 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).
*10.15 - 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).
*10.16 - 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).
*10.17 - 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).
*10.18 - 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).
*10.19 - 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).
*10.20 - 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).
*10.21 - 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).
*10.22 - 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).
*10.23 - 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).
*10.24 - 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).
*10.25 - 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).
*10.26 - 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).
*10.27 - 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).
*10.28 - 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).
*10.29 - 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).
*10.30 - 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).
10.31 - Second Amendment to Employment Agreement between
Enron International Inc. and Rodney L. Gray, dated as
of January 1, 1995.
*10.32 - 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).
*10.33 - 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).
*10.34 - 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.
13423).
10.35 - Fourth Amendment to Consulting Services Agreement
between Enron and John A. Urquhart dated as of May 9,
1994.
10.36 - Fifth Amendment to Consulting Services Agreement
between Enron and John A. Urquhart.
10.37 - Sixth Amendment to Consulting Services Agreement
between Enron and John A. Urquhart.
*10.38 - 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).
*10.39 - 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.
13423).
*10.40 - 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).
*10.41 - 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).
*10.42 - 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).
*10.43 - Enron Corp. Performance Unit Plan (Exhibit A to Enron
Proxy Statement filed pursuant to Section 14(a) on
March 25, 1994).
*10.44 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron
Proxy Statement filed pursuant to Section 14(a) on
March 25, 1994).
*10.45 - 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).
10.46 - First Amendment to Enron Corp. Performance Unit Plan.
*10.47 - Form of Enron Corp. 1994 Deferral Plan (Exhibit 10.59
to Enron Form 10-K for 1994).
10.48 - First Amendment to Enron Corp. 1994 Deferral Plan.
10.49 - Second Amendment to Enron Corp. 1994 Deferral Plan.
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 22, 1996.
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; all other exhibits are filed herewith.
(b) Reports on Form 8-K
No reports on Form 8-K were filed by Enron during
the last quarter of1995.
Dates Referenced Herein and Documents Incorporated by Reference
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