Document/Exhibit Description Pages Size
1: 10-K Enron Corp. 1994 Form 10-K 128± 530K
2: EX-3.01 Restated Certificate of Incorporation 66± 239K
3: EX-10.16 Sixth Amendment to Lay Employment Agreement 2± 11K
4: EX-10.17 Split Dollar Life Insurance Agreement - Kll & Lpl 8± 36K
5: EX-10.25 Seventh Amendment to Employment Agmt - Kinder 2± 12K
6: EX-10.27 First Amendment to Employment Agmt. - Gray 1 10K
7: EX-10.31 Third Amendment to Employment Agmt. - Burns 1 10K
8: EX-10.33 First Amendment to Employment Agmt. - Tompkins 1 10K
9: EX-10.39 Second Amendment to Employment Agmt. - Segner 1 10K
10: EX-10.51 Second Amendment to Employment Agmt. - White 2± 12K
11: EX-10.53 First Amendment to Employment Agmt. - Derrick 1 10K
12: EX-10.59 Enron Corp. 1994 Deferral Plan 15± 65K
13: EX-11 Statement Re Computation of Per Share Earnings 2± 10K
14: EX-12 Statement Re Computation of Per Share Earnings 1 9K
15: EX-21 Enron Corp. and Subsidiary Companies 7± 29K
16: EX-23.01 Consents of Experts and Counsel 1 9K
17: EX-23.02 Consent of Degolyer & Macnaughton 1 11K
18: EX-23.03 Letter Report of Degolyer and Macnaughton 3± 14K
19: EX-24 Powers of Attorney 13 36K
20: EX-27 Article 5 FDS for 10-K 1 8K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
F O R M 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, 1994 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 and
$1 Par Value Chicago Stock Exchange
Notes
10-3/4% due June 1, 1998 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90
days. Yes X No
Indicate by check mark if disclosure of delinquent
filers pursuant to Item 405 of Regulation S-K is not
contained herein, and will not be contained, to the best of
registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. _____
Aggregate market value of the voting stock held by non-
affiliates of the registrant, based on closing prices in the
daily composite list for transactions on the New York Stock
Exchange on January 31, 1995, was approximately
$7,582,366,000. As of March 1, 1995, there were 251,685,536
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 2, 1995 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 . . . . . . . . . . . . . . . . . . . . . . . . . .16
Operating Statistics . . . . . . . . . . . . . . . . . . . . .21
Current Executive Officers
of the Registrant . . . . . . . . . . . . . . . . . . . .23
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . .24
Gas Transmission and Liquid Fuels. . . . . . . . . . . . . . .24
Oil and Gas Exploration and Production
Properties and Reserves. . . . . . . . . . . . . . . . . .25
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . .27
Item 4. Submission of Matters to a Vote of Security
Holders. . . . . . . . . . . . . . . . . . . . . . . . . . .29
PART II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters. . . . . . . . . . . . . . .30
Item 6. Selected Financial Data (Unaudited) . . . . . . . . . . . . . . .31
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations . . . . . . . . . . . . . . . . . . . . . . . . .32
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . .40
Item 9. Disagreements on Accounting and Financial
Disclosure . . . . . . . . . . . . . . . . . . . . . . . . .40
PART III
Item 10. Directors and Executive Officers of the
Registrant . . . . . . . . . . . . . . . . . . . . . . . . .41
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . .41
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . .41
Item 13. Certain Relationships and Related
Transactions . . . . . . . . . . . . . . . . . . . . . . . .41
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . .42
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 44,000 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,
1994, Enron employed approximately 6,955 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
and electric power; price risk management in connection with
natural gas, natural gas liquids 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; and international marketing of
natural gas liquids.
4) Exploration and Production: Natural gas and crude
oil exploration and production and sale of reserves and
related assets primarily in the United States, Canada,
Trinidad and India.
For financial information by business segment for the
fiscal years ended December 31, 1992 through December 31,
1994, please see Note 17 to the Consolidated Financial
Statements on page F-20.
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. 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
23,500-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 gathers and
transports gas at various points outside its traditional
market area in the production areas of Colorado, Kansas,
Montana, New Mexico, Oklahoma, Texas and Wyoming for
utilities, end-users and other pipeline and marketing
companies.
In Northern's market area, natural gas is an energy
source available for traditional residential, commercial and
industrial uses. Northern's throughput totaled 1,996
trillion British thermal units ("Tbtu") in 1994, compared to
1,943 Tbtu in 1993. In its traditional market area,
Northern's throughput increased to 819 Tbtu in 1994 from 788
Tbtu in 1993. Northern's jurisdictional sales decreased
from 61 Tbtu in 1993 to 33 Tbtu in 1994, evidencing a
continuing shift from sales to transportation volumes due to
the implementation of open access transportation service.
Transportation of volumes in the traditional market area
rose from 788 Tbtu in 1993 to 819 Tbtu in 1994. The volume
of gas delivered by Northern in its non-traditional market
area increased to 1,177 Tbtu in 1994 from 1,115 Tbtu in
1993.
Order Nos. 636, 636-A and 636-B were promulgated by the
FERC in 1992. The primary intent of the orders was to
create equality of service between the traditional pipeline
merchant sales service and open-market transportation
service, and the primary effect of which has been to
substantially eliminate merchant sales by pipelines like
Northern. The orders also 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. (See "Regulation - Natural Gas
Rates and Regulations"). Northern implemented the service
restructuring required by Order Nos. 636, 636-A and 636-B on
November 1, 1993, by unbundling its 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 its rates. The FERC has indicated that Northern 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.
As a result of Northern's restructuring under Order 636,
and as part of the unbundling of its services, Northern has
ceased its function as a merchant of gas. Gas gathering is
no longer an activity that is needed to support the 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 under
Section 7(b) of the Natural Gas Act. On November 15, 1994,
Enron executed an agreement with a third party pursuant to
which Enron has agreed to sell its interests in Northern's
Anadarko gas gathering assets.
On December 22, 1994, Northern filed an application with
the FERC for authority to construct and operate five
compressor stations and three town border stations in Iowa,
Illinois and Wisconsin to expand capacity on Northern's
system in those areas. These facilities will 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. Northern's application proposes to 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 markets 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.
Northern competes with other interstate pipelines in the
transportation and storage of gas. Northern competes with
other pipelines, producers, gatherers and gas aggregators
for gathering volumes. As noted above, FERC orders have
been designed to introduce more competition into the natural
gas industry, and have had the effect of increasing
transportation volumes and decreasing or eliminating sales
of natural gas by pipelines.
Transwestern Pipeline Company. Transwestern is an open-
access interstate pipeline engaged in the transportation of
natural gas. Through its approximately 4,500-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, in
addition to transportation off the east end of its system.
Substantially all of Transwestern's total of 1.06 billion
cubic feet ("Bcf") per day of delivery capacity to
California is currently held by shippers on a firm basis.
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.
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 706 million cubic feet ("MMcf") per
day in 1994, compared to 757 MMcf per day in 1993.
During 1993, Transwestern developed its firm
transportation service on the east end of its system to
transport Permian and San Juan Basin supplies into Texas,
Oklahoma and the midwestern United States. Transwestern
transported an average of 388 MMcf per day off the east end
of its system in 1994, as compared 312 MMcf per day in 1993
and 156 MMcf per day in 1992.
Transwestern filed its Order No. 636 compliance filing in
July 1992, and received FERC approval on February 1, 1993.
Under its Order 636 program, Transwestern now has, among
other things, a capacity release program and a straight
fixed variable rate design. This rate design collects all
fixed costs, including income taxes and return on equity, in
monthly demand or reservation fees.
In 1994, Transwestern filed an application with the FERC
to spin-down its production and gathering facilities to
Transwestern Gathering Company ("TGC"), a wholly-owned
subsidiary of Transwestern. TGC intends to sell these
production and gathering facilities to third parties. In
November 1994, TGC entered into a sale agreement covering
certain of these facilities subject to FERC approval of
Transwestern's spin-down proceeding.
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
increases FGT's firm average delivery capacity into Florida
by 532 BBtu per day to 1,457 BBtu per day. The Phase III
expansion includes approximately 800 miles of new FGT
pipeline facilities, seven additional delivery points and
approximately 106,000 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 purchased 100 Bbtu per day of capacity on another
interstate pipeline system to provide its customers with
additional sources of supply.
Historically, FGT primarily sold natural gas to customers
who resold such natural gas ("sales for resale") and sold
natural gas directly to industrial and utility end users
("direct sales"). To a lesser extent, FGT also transported
natural gas for others ("transportation services"),
primarily under long-term contracts to firm customers.
As an open access pipeline and with the implementation of
Order No. 636, commencing November 1, 1993, FGT began
providing transportation services to any shipper of natural
gas on a nondiscriminatory basis to the extent it has
capacity available, subject to the terms of its FERC-
approved tariff. These services are provided under long-
term contracts to firm customers and under interruptible
contracts with customers who purchase interruptible
capacity. Interruptible capacity is scheduled according to
the rate charged by FGT in the event that nominations exceed
available capacity. As part of the transition to open
access in 1990, all of FGT's sales for resale and direct
sales customers were given the opportunity over time to
convert their contractual sales entitlements to firm
transportation service. Most major customers chose to do
so, converting at least a part of their requirements to firm
transportation. All remaining sales customers became
transportation customers, effective on November 1, 1993 with
the Order No. 636 restructuring. FGT's customers have
reserved over 99% of the existing capacity on the FGT system
pursuant to firm 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 will 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 proposed
pipelines, if they are built, will affect usage of its
existing capacity or the Phase III facilities in the near
term. The 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 is that FGT will recover substantially
all of its fixed costs regardless of levels of usage by its
customers.
While FGT has no definitive plans for a Phase IV
expansion, it continues to measure the demand for increased
service to Florida to determine if demand warrants further
expansions.
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
and the Great Plains Coal Gasification Project in the United
States. 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 for the referenced Canadian and U.S.
natural gas reserves. 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 does not own
the gas that it transports and therefore it does not assume
any gas commodity price risk.
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, 1994, Northern Border had
firm transportation service agreements, other than those
under temporary release, with four interstate pipeline
companies, 18 domestic and Canadian producers and marketers,
including Enron Capital & Trade Resources Corp., and 11
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 1997, and 93% of such capacity 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 a marketing affiliate of a
general partner in Northern Border, holds 8% of the
contracted capacity. Northern Border competes with two
other pipeline systems that transport gas from Canada to the
Midwest.
Northern Border is currently evaluating 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. The proposed project also includes seven new
compressor stations. The proposed expansion would add
approximately 213 MMcf per day of Canadian gas, and the
extension would deliver approximately 263 MMcf per day into
new markets. Both the expansion and extension, if approved
as proposed, are expected to be in service by November 1997
at a cost of approximately $370 million.
Enron Liquids Pipeline, L.P. Enron owns approximately
15% of Enron Liquids Pipeline, L.P., a Delaware limited
partnership formed in August 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 Facilities
Enron's subsidiary companies are involved in the
independent power industry, 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 has
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.
(See "International Gas and Power Services" for a general
description of Enron's international power businesses).
In North America, Enron subsidiary companies manage the
physical operation of a 330-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. Enron subsidiaries also manage the physical
operations of several international power plants which are
described herein under the caption "International Gas and
Power Services."
Crude Oil Transportation Services
EOTT Energy Partners, L.P., a Delaware limited
partnership formed in March 1994, owns and operates the
business and assets of EOTT Energy Corp. ("EOTT"), an
independent gatherer and marketer of crude oil. Enron owns
an approximately 40% interest in EOTT Energy Partners, L.P.
EOTT is engaged in the purchasing, gathering, transporting,
processing, 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 23,000 leases in 18 states, principally in the
Gulf Coast, Southwest, Rocky Mountain and Mid-Continent
regions of the United 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 300 owned or
leased trucks, and by pipeline, including more than 1,000
miles of intrastate and interstate pipeline and gathering
systems owned by EOTT and common carrier pipeline systems
owned by third parties. In addition, to a limited degree,
EOTT provides transportation and trading services for third
party purchasers of crude oil. These pipeline systems and
trucking operations cover 16 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 256,000 barrels per day of lease
crude oil during 1994.
Through its West Coast operations, EOTT gathers crude oil
from leases in the Los Angeles Basin and San Joaquin Valley
in Southern California, acquires Alaskan crude oil delivered
into onshore facilities in Los Angeles Harbor and acquires
additional crude oil volumes from marketers and others.
EOTT then blends and upgrades the crude oil, remarkets it to
refiners and other parties, and/or delivers it to a refinery
owned by a third party, where it may be processed for EOTT's
account under a long-term processing agreement. Such
processing arrangement allows EOTT to provide asphalts to
the roofing and paving industries in the Southern California
market. The profitability of EOTT's processing agreement is
significantly influenced by the crack spread, which is the
difference between the sales price of refined petroleum
products and the cost of feedstocks (principally crude oil)
delivered to the refinery for processing.
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 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 portfolio.
ECT's cash and physical business is augmented by its
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 1994 averaged 24
trillion British thermal units ("Tbtu") of natural gas
equivalents per day. Included in this amount are physical
volumes of approximately 7.5 Tbtu per day.
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." In April
1993, Enron acquired Louisiana Resources Company, which
includes rights to a 540-mile intrastate pipeline which
spans the state of Louisiana and serves the industrial
complex along the Mississippi River from Baton Rouge to New
Orleans. The pipeline interconnects with the Henry Hub and
has numerous interconnections with both interstate and
intrastate pipelines.
ECT's Napoleonville natural gas storage facility located
in Louisiana, which accesses the Louisiana Resources Company
pipeline, provides approximately 4 Bcf of working capacity.
This facility enhances the benefits of Louisiana Resources
Company by improving ECT's ability to meet the firm
requirements of industrial markets in Louisiana, and
secondly, to provide 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 330-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 new 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 6.6 Tbtu in
1994. 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 group 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 1994, ECT provided $503 million in funding.
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 $316 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. 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 42 Bcf of natural gas during 1994.
At December 31, 1994, Enron's gas processing businesses
had an interest in 17 hydrocarbon extraction and
fractionation facilities, 13 of which are operated by Enron,
which generally are located along Enron's natural gas
pipeline systems. During 1994, Enron's plants extracted 1.2
billion gallons of NGLs. A total of .4 billion gallons of
product were fractionated for affiliates and others. These
businesses' margins are sensitive to the relationship
between NGL prices and the price of natural gas. In 1995,
Enron will attempt to mitigate some of this market risk
through hedging techniques.
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. In addition, Enron 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 and the
Philippines; 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 worldwide.
Enron Development Corp. ("EDC") is involved in power and
pipeline projects in varying stages of development in India,
China, the Dominican Republic, Colombia, Turkey, Bolivia and
Brazil, Indonesia and elsewhere.
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 own and
manage Enron's operating power plant and natural gas
pipeline business conducted outside the United States,
Canada and Western Europe, and to expand such business
through acquisitions. EPP's initial 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. Enron
presently does not intend to reduce its ownership of EPP
below 52%.
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 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 built in Louisiana 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 4,069-mile pipeline system has a capacity of
approximately 1.7 Bcf per day and serves four distribution
companies under long-term firm transportation contracts.
TGS expanded its pipeline in 1994 by 240 MMcf per day
through the addition of four compressor stations. TGS has
signed transportation contracts for 210 MMcf per day of
additional capacity for ten years.
India. In December 1993, an Enron affiliate signed a 20-
year power purchase agreement with Maharashtra State
Electricity Board, the largest generator and distributor of
power in the State of Maharashtra. The contract supports
the first and second phases of an approximately 2,015
megawatt gas-fired power plant and related facilities, which
will ultimately include a liquefied natural gas (LNG)
terminal and harbor development near Dabhol, which is
approximately 100 miles south of Bombay. Enron's partners
in the two-phase project are affiliates of General Electric
Company, which is supplying equipment and holds a 10% equity
interest, and affiliates of Bechtel Enterprises, Inc., which
is the contractor and also holds a 10% equity interest.
Enron plans to reduce its current 80% equity interest to a
50% interest at or before the completion of the project.
Construction of the 695-megawatt first phase is underway and
includes harbor development, fuel facilities, housing and
related activities necessary to complete this project. The
first phase of the project is expected to begin commercial
operations in 1997. The construction of the 1,320-megawatt
second phase addition is subject to, among other things,
financing and obtaining acceptable LNG supply contracts.
Enron expects to offer its ownership interest in the project
to EPP when it reaches commercial operation.
Teesside. At December 31, 1994, Enron had a 50%
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. The first phase of the liquids plant is in place
and producing in excess of 300,000 gallons of natural gas
liquids per day, which is being sold in the European
markets. A second phase of construction began in 1994 in
order to be operating by 1996 when additional natural gas
volumes which Enron has purchased from the J-Block in the
North Sea become available.
Enron has long-term contractual rights to 300 MMcf per
day capacity on the Central Area Transmission System, a
1,400 MMcf per day capacity pipeline from the North Sea.
Enron's capacity will be used to transport J-Block gas to
Teesside when that gas becomes available in 1996. These new
supplies will support Enron's future marketing programs.
Germany. During 1993, Enron acquired an approximately
125 megawatt gas-fired plant in Bitterfeld, Germany. Enron
is a 50/50 joint venture partner with the second largest
regional utility company in Germany. The Bitterfeld project
provides Enron with a presence in Germany as well as access
to a site for possible expansion.
Other International Development Stage Projects. The
following is a brief description of power and natural gas
pipeline projects which, upon commencement of commercial
operations and completion of financing arrangements, will 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, 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 and the
availability of project financing on acceptable terms.
There can be no assurance that these projects will commence
commercial operations.
China. Enron is developing a $135 million, 150-
megawatt diesel or gas-fired combined cycle power plant on
Hainan Island, an economic free trade zone off the southern
coast of China. The independent power project is the first
such project developed by a U.S. company in China. Enron
will be operator, fuel manager and construction contractor.
Full combined cycle operations are expected to begin in mid-
1996.
Dominican Republic. A limited partnership in which
Enron affiliated companies have a 50% ownership interest has
signed a 20-year power purchase agreement with the Dominican
Republic government utility in connection with the
development of an estimated $200 million, 185-megawatt
barge-mounted combined cycle power plant on the north coast
of the Dominican Republic. The partnership will serve as
operator, fuel manager and construction manager of the
plant. The project is expected to be in commercial
operation by mid-1995.
Colombia. Construction is underway on Enron's
approximately $215 million, 357-mile natural gas pipeline
and related facilities project, which pipeline will run 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 15
years. Commercial operations are expected to commence in
1996.
Turkey. Enron holds a 50% interest in a $545
million, 478-megawatt gas-fired power plant to be located in
Marmara, Turkey. Enron will be operator and 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 mid-1995, with
commercial operation expected by the fourth quarter of 1997.
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 $1.5 billion, 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 at an
estimated cost of $1.5 billion. 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.
Indonesia. Enron has negotiated a 20-year power
purchase agreement with the Indonesia state utility to build
a $520 million, 500-megawatt gas-fired power project in East
Java, subject to terms of a gas contract under negotiation.
Enron will be the contractor, plant operator and will hold a
50% interest in the project. In East Kalimantan, Indonesia,
Enron is developing a $138 million, 136-megawatt gas-fired
power plant. A 20-year power purchase agreement has been
negotiated with the state utility, also subject to terms of
a gas contract. Enron will be the contractor and plant
operator and hold a 50% interest. Enron expects the first
project to be in commercial operation by mid-1997 and the
second project in early 1998.
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 declined from 646
million gallons in 1993 to 464 million gallons in 1994,
reflecting a reduction in spot market transactions in 1994
to focus on higher value transactions.
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 80% 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, 1994,
EOG had estimated net proved natural gas reserves of 1,910
Bcf and estimated net proved crude oil, condensate and
natural gas liquids reserves of 37 million barrels, and at
such date, approximately 70% of EOG's reserves (on a natural
gas equivalent basis) was located in the United States, 16%
in Canada, 11% in Trinidad and 3% in India.
EOG's main producing areas are the Big Piney area in
Wyoming, South Texas primarily centered in the Lobo Trend
area, the Matagorda Trend area located in federal waters
offshore Texas, the Canyon Trend area located in West Texas,
the Pitchfork Ranch area in southwestern New Mexico and the
Kiskadee area offshore Trinidad. EOG's other domestic
natural gas and crude oil producing properties are located
primarily in other areas of Texas, Utah, New Mexico and
Oklahoma. At December 31, 1994, 93% of EOG's proved
domestic reserves (on a natural gas equivalent basis) was
natural gas and 7% was crude oil, condensate and natural gas
liquids.
EOG's six principal U.S. producing areas are the Big
Piney area, the South Texas area, Matagorda Trend area, the
Canyon Trend area, the Pitchfork Ranch area and the Vernal
area. Properties in these areas comprised approximately 76%
of EOG's domestic reserves (on a natural gas equivalent
basis) and 76% of EOG's maximum domestic net natural gas
deliverability as of December 31, 1994 and are substantially
all operated by EOG. EOG also has operations in Canada and
in Trinidad and is conducting exploration in selected other
international areas.
EOG is engaged in the exploration for and the development
and production 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. Maximum Canadian natural gas
deliverability net to EOG at December 31, 1994 was
approximately 85 MMcf per day, and EOG held approximately
354,000 net undeveloped acres in Canada.
EOG has operations in offshore Trinidad and India and is
conducting exploration in selected other international
areas. Properties in offshore Trinidad and India comprised
100% of EOG's reserves and production outside of North
America.
In November 1992, EOG was awarded a 95% working interest
concession in the South East Coast Consortium Block offshore
Trinidad, encompassing three undeveloped fields, previously
held by three government-owned energy companies. The
Kiskadee field is currently being developed while the
remaining two undeveloped fields are anticipated to be
developed over the next three to five years. Natural gas is
being sold into the local market under a take-or-pay
agreement with the National Gas Company of Trinidad and
Tobago. At December 31, 1994, maximum natural gas
deliverability net to EOG was approximately 150 MMcf per day
and EOG held approximately 71,000 net undeveloped acres in
Trinidad.
In December 1994, EOG signed agreements covering profit
sharing, joint operations and product sales and representing
a 30% working interest in and was designated operator of the
Tapti, Panna and Mukta Blocks located offshore Bombay,
India. The blocks were previously operated by the Indian
national oil company, Oil & Natural Gas Corporation Limited,
which retains a 40% working interest. The 363,000 acre
Tapti Block contains two major proved gas accumulations
delineated by 22 expendable exploration wells that have been
plugged. EOG intends to commence development of the Tapti
Block accumulations in 1995. The 106,000 acre Panna Block
and the 192,000 acre Mukta Block are partially developed
with five producing platforms located in the Panna and Mukta
fields. The fields were producing approximately 3,000
barrels per day of crude oil net to EOG as of December 31,
1994; 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 continues to pursue other selected conventional
natural gas and crude oil opportunities outside North
America. During 1995, EOG will pursue other opportunities
in countries where indigenous natural gas 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 non-binding letter of intent concerning the
possible development of a liquefied natural gas project for
natural gas to be produced from the North Dome Field.
In 1994, EOG continued 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
Queensland, Australia and in two basins in China. A similar
project in Russia continues under evaluation.
EOG actively competes for reserve acquisitions and
exploration leases, licenses and concessions, frequently
against companies with substantially larger financial and
other resources. To the extent EOG's exploration budget is
lower than that of certain of its competitors, EOG may be
disadvantaged in effectively competing for certain reserves,
leases, licenses and concessions. Competitive factors
include price, contract terms and quality of service,
including pipeline connection times and distribution
efficiencies. In addition, EOG faces competition from other
producers and suppliers, including 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, 1994:
[Download Table]
Year Ended December 31,
1994 1993 1992
Volumes (per day)
Natural Gas (MMcf)
United States(1) 614 649 534
Canada 72 58 30
Trinidad 63 2 -
Total(1) 749 709 564
Crude Oil and Condensate (MBbl)
United States 8.0 6.6 6.3
Canada 2.0 2.2 2.2
Trinidad 2.5 .1 -
India .1 - -
Total 12.6 8.9 8.5
Natural Gas Liquids (MBbl)
United States .3 .2 .3
Canada .4 .4 .4
Total .7 .6 .7
Average Prices
Natural Gas ($/Mcf)
United States(2) $ 1.71 $ 1.97 $ 1.61
Canada 1.42 1.34 1.18
Trinidad .93 .89 -
Composite(2) 1.62 1.92 1.58
Crude Oil and Condensate ($/Bbl)
United States $16.06 $ 16.96 $ 18.29
Canada 14.05 14.63 16.80
Trinidad 15.50 14.36 -
India 15.70 - -
Composite 15.62 16.37 17.90
Natural Gas Liquids ($/Bbl)
United States $12.45 $ 13.85 $ 11.56
Canada 8.45 9.46 10.05
Composite 9.90 11.12 10.69
Lease and Well Expenses ($/Mcfe)
United States $ .19 $ .18 $ .20
Canada .34 .48 .50
Trinidad .17 1.46 -
India .13 - -
Composite .20 .21 .22
___________________
<FN>
(1) Includes 48 MMcf per day in 1994, 81 MMcf per day in 1993
and 28 MMcf per day in 1992 delivered under the terms of
a volumetric production payment agreement effective
October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of $1.27
per Mcf in 1994, $1.57 per Mcf in 1993 and $1.70 per Mcf
in 1992 for the volumes described in note (1), net of
transportation costs.
The following table sets forth certain information
regarding EOG's volumes of natural gas delivered under other
marketing and volumetric production payment arrangements,
and the resulting average per unit gross revenue and per
unit amortization of deferred revenues along with associated
costs during each of the three years in the period ended
December 31, 1994.
[Download Table]
Year Ended December 31,
1994 1993 1992
Volumes (MMcf per day)(1) . . . . 324 293 255
Average Gross Revenue ($/Mcf)(2) $ 2.38 $ 2.57 $ 2.62
Associated Costs ($/Mcf)(3)(4) . 2.06 2.32 1.99
Margin ($/Mcf) . . . . . . . . . $ 0.32 $ 0.25 $ 0.63
<FN>
___________________
(1) Includes 48 MMcf per day in 1994, 81 MMcf per day in 1993
and 28 MMcf per day in 1992 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
1994, $2.50 per Mcf ($2.40 per million British thermal
units) in 1993 and $2.51 per Mcf ($2.40 per million
British thermal units) in 1992.
(3) Includes an average value of $1.92 per Mcf in 1994, $2.20
per Mcf in 1993 and $2.37 per Mcf in 1992, including
average equivalent wellhead value, any applicable
transportation costs and exchange differentials, for the
volumes detailed in note (1).
(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 sales 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 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, Florida Gas and Northern
Border are "natural gas companies" under the NGA and, as
such, are subject to the jurisdiction of the FERC. The FERC
has jurisdiction over, among other things, the construction
and operation of pipeline and related facilities used in the
transportation, storage and sale of natural gas in
interstate commerce, including the extension, expansion or
abandonment of such facilities. The FERC also has
jurisdiction over the rates and charges for the
transportation of natural gas in interstate commerce and the
sale by a natural gas company of natural gas in interstate
commerce for resale. Northern, Transwestern, Florida Gas
and Northern Border hold the required certificates of public
convenience and necessity issued by the FERC authorizing
them to construct and operate all of their pipelines,
facilities and properties for which certificates are
required in order to transport and sell natural gas for
resale in interstate commerce.
As necessary, Northern, Transwestern, Florida Gas and
Northern Border file applications with the FERC for changes
in their rates and charges designed to allow them to recover
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, subject to refund under
applicable law, until such time as the FERC rules 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 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,
mandates a fundamental restructuring of interstate pipeline
sales and transportation services. Order No. 636 requires
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. Under Order No. 636,
unbundled pipeline sales can be made only in the production
areas. Order No. 636 also requires 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. 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 have filed petitions
for court review of Order Nos. 636, 636-A and 636-B, as well
as orders in individual pipeline restructuring proceedings.
Upon such 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
effects.
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 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, 1994 are approximately $305 million,
which include transition costs incurred related to FERC
Order 636 of approximately $158 million. Such regulatory
assets are scheduled to be recovered from customers over
varying time periods, generally up to five years.
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. 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 implemented.
In certain recent cases, the FERC has asserted ancillary NGA
jurisdiction over gathering activities of interstate
pipelines and their affiliates. 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 condition 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 and transportation
and operation business segments as well as revenue data for all
of Enron's businesses. Revenue amounts are in thousands of
dollars.
[Download Table]
Year Ended December 31,
1994 1993 1992
ECT Physical and Notional Quantities
(BBtue/d)
ECT Physical Sales Volumes* 6,934 5,138 3,525
Financial Settlements 16,459 5,027 1,536
Intrastate Transport Volumes* 538 571 536
23,931 10,736 5,597
Interstate Pipeline Net Throughput
(Tbtu/d) 6.34 6.15 5.62
Liquids Marketing Volumes (Mmgal)
Domestic NGLs Marketed 2,032 2,506 3,388
International NGLs Marketed 464 646 1,180
2,496 3,152 4,568
Total NGL Production Volumes 1,205 1,334 1,296
<FN>
*Includes intercompany amounts
Revenues by Business Segment
[Download Table]
Year Ended December 31,
1994 1993 1992
Transportation and Operation
Natural Gas and Other Products
Unaffiliated $ 87,670 $ 453,621 $ 504,720
Intersegment 9,455 22,779 4,068
97,125 476,400 508,788
Transportation Services
Unaffiliated 740,606 751,896 671,520
Intersegment 25,395 35,841 44,443
766,001 787,737 715,963
Other Revenues
Unaffiliated 109,248 180,408 242,521
Intersegment 3,906 21,461 34,002
113,154 201,869 276,523
TOTAL 976,280 1,466,006 1,501,274
Domestic Gas and Power Services
Natural Gas and Other Products
Unaffiliated 6,633,039 5,214,870 3,871,271
Intersegment 59,684 95,934 85,414
6,692,723 5,310,804 3,956,685
Transportation Services
Unaffiliated 13,511 16,015 16,778
Intersegment 1,041 506 507
14,552 16,521 17,285
Other Revenues
Unaffiliated 519,032 219,061 (15,980)
Intersegment (47,333) 37,718 4,295
471,699 256,779 (11,685)
TOTAL 7,178,974 5,584,104 3,962,285
International Gas and Power Services
Natural Gas and Other Products
Unaffiliated 337,917 598,472 496,377
Intersegment 983 12,697 7,436
338,900 611,169 503,813
Other Revenues
Unaffiliated 54,002 152,903 368,318
Intersegment 6,001 6,516 3,093
60,003 159,419 371,411
TOTAL 398,903 770,588 875,224
Exploration and Production
Natural Gas and Other Products
Unaffiliated 431,907 364,643 229,338
Intersegment 242,008 280,363 257,680
673,915 645,006 487,018
Other Revenues
Unaffiliated 56,791 33,911 30,448
Intersegment 48,082 28,208 42,695
104,873 62,119 73,143
TOTAL 778,788 707,125 560,161
Intersegment Eliminations (349,222) (542,023) (483,634)
Total Revenues $8,983,723 $7,985,800 $6,415,310
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
Name and Age Present Principal Position and Other
Material Positions Held During Last
Five Years
Kenneth L. Lay (52) Chairman of the Board and Chief
Executive Officer since February 1986.
President from February 1989 to October
1990.
Richard D. Kinder (50) President and Chief Operating Officer
since October 1990. Vice Chairman of
the Board from December 1988 to October
1990, and Chairman and Chief Executive
Officer of Enron Gas Pipeline Group from
January 1989 to October 1990. Executive
Vice President and Chief of Staff from
August 1987 to December 1988.
Ronald J. Burns (41) Managing Director, North American
Operations, Enron Capital & Trade
Resources Corp., since December 1994.
Chairman and Chief Executive Officer
(Marketing and Supply), Enron Gas
Services Corp., from June 1993 to
December 1994. Chairman and Chief
Executive Officer, Enron Pipeline and
Liquids Group from October 1992 to June
1993. Chairman and Chief Executive
Officer, Enron Corp. Gas Pipeline Group
from October 1990 to October 1992.
President, Enron Corp. Interstate
Pipeline Group from 1988 to October
1990.
Rodney L. Gray (42) President and Chief Executive Officer of
Enron Global Power & Pipelines L.L.C.
since October 1994. Managing Director,
International Operations, Enron Capital
& Trade Resources Corp., since December
1994. Chairman and Chief Executive
Officer, Enron International Inc. since
June 1993. Senior Vice President,
Finance and Treasurer from October 1992
to June 1993. Vice President, Finance
and Treasurer from 1988 to October 1992.
Jeffrey K. Skilling (41) Managing Director, Development, Enron
Capital & Trade Resources Corp., since
December 1994. 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 (51) Chairman and Chief Executive Officer of
Enron Operations Corp. since June 1993.
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 (41) Executive Vice President and Chief of
Staff since October 1992. Senior Vice
President, Investor, Public & Government
Relations from October 1990 to October
1992. Vice President, Public and
Investor Relations from February 1988
until October 1990.
James V. Derrick, Jr.(50) Senior Vice President and General
Counsel since June 1991. Partner,
Vinson & Elkins from January 1977 until
June 1991.
Jack I. Tompkins (49) 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 (41) 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
44,000 miles of transmission and gathering lines, 111
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 17 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, 1992, 1993 and 1994 were based on studies
performed by EOG's engineering staff for reserves in both
the United States, Canada, Trinidad and India. Opinions by
DeGolyer and MacNaughton, independent petroleum consultants,
for the years ended December 31, 1992, 1993 and 1994
covering producing areas containing 69%, 65% and 59%,
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 summary reflects EOG's ownership at
December 31, 1994 in gas wells in 390 fields and oil wells
in 87 fields located in Texas, offshore Texas and Louisiana
in 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 188 with multiple completions.
[Download Table]
Productive Productive Total
Gas Wells Oil Wells Productive Wells
Gross Net Gross Net Gross Net
4,501 3,246 993 564 5,434 3,810
Acreage
The following table summarizes EOG's developed and
undeveloped acreage at December 31, 1994. 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 1,142 935 683,350 633,424 684,492 634,359
Texas 345,558 265,039 234,057 218,862 579,615 483,901
Federal Offshore 195,009 94,960 424,823 388,236 619,832 483,196
Wyoming 160,364 113,540 312,323 234,423 472,687 347,963
Oklahoma 104,844 59,502 69,664 62,434 174,508 121,936
Utah 59,620 48,085 36,525 31,187 96,145 79,272
New Mexico 81,416 36,852 67,460 35,563 148,876 72,415
Kansas 12,215 11,482 35,892 33,729 48,107 45,211
Michigan 11 10 34,810 34,810 34,821 34,820
Colorado 10,111 1,490 34,037 16,674 44,148 18,164
Mississippi 1,942 1,853 10,100 9,262 12,042 11,115
Montana 1,301 1,169 6,689 4,961 7,990 6,130
Other 4,894 2,953 2,926 2,151 7,820 5,104
Total 978,427 637,870 1,952,656 1,705,716 2,931,083 2,343,586
Canada
Alberta 330,932 152,360 228,043 148,731 558,975 301,091
Saskatchewan 158,870 145,891 207,660 202,999 366,530 348,890
Manitoba 11,531 9,581 1,820 1,820 13,351 11,401
British Columbia 656 164 - - 656 164
Total Canada 501,989 307,996 437,523 353,550 939,512 661,546
Other International
Australia - - 9,600,000 9,600,000 9,600,000 9,600,000
China - - 1,700,000 850,000 1,700,000 850,000
Russia - - 1,425,000 712,500 1,425,000 712,500
France - - 1,015,000 507,500 1,015,000 507,500
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 21,990 14,590,658 12,008,570 14,654,858 12,030,560
Total 1,544,616 967,856 16,980,837 14,067,836 18,525,453 15,035,692
Drilling and Acquisition Activities
During each of the years ended December 31, 1994, 1993 and 1992,
EOG spent approximately $493.9 million, $430.1 million, and $395.7
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,
1994 1993 1992
Gross Net Gross Net Gross Net
Development Wells Completed
Gas 558 434.53 579 469.10 486 401.06
Oil 45 34.67 49 22.51 32 22.50
Dry 54 43.65 70 54.43 69 60.17
Exploratory Wells Completed
Gas 22 17.70 28 21.43 18 14.47
Oil 4 3.07 5 3.40 5 4.09
Dry 37 30.67 42 29.43 20 16.27
Total 720 564.29 773 600.30 630 518.56
Wells in Progress at End of
Period 45 28.79 82 61.09 82 60.75
Total 765 593.08 855 661.39 712 579.31
Wells Acquired
Gas 41 40.90* 44 26.44* 641 597.29*
Oil 60 38.99* - 12.80* 28 25.80*
Total 101 79.89 44 39.24 669 623.09
<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,
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
TransAmerican Natural Gas Corporation
(TransAmerican) has 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 seeks actual damages of $100
million and exemplary damages of $300 million. EOG has
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. As to EOG, the trial date, which was
most recently set for September 12, 1994, has been continued
and there is no current setting. Although no assurances can
be given, Enron believes that TransAmerican's claims are
without merit and that the ultimate resolution of this
matter will not have a materially adverse effect on its
financial position or results of operations.
A pipeline company in which an Enron affiliate has
a minority interest and for which an Enron affiliate has
served as operator has filed a petition against Enron and
certain affiliates alleging an unspecified amount of damages
relating to the operation of such pipeline company. Based
upon information currently available, Enron believes that
the outcome of such litigation will not have a materially
adverse effect on Enron's financial position or results of
operations.
During 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. Enron is
currently investigating the explosion to determine the full
extent of any damages; however, based upon business
interruption and casualty insurance coverages, Enron
currently anticipates that the explosion will not have a
material adverse effect on its financial position or results
of operations.
Environmental Matters
Enron is subject to extensive Federal, state and
local environmental laws and regulations. These laws and
regulations require expenditures in connection with the
construction of new facilities, the operation of existing
facilities and for remediation at various operating sites.
The implementation of the Clean Air Act Amendments is
expected to result in increased operating 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 impact 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 the second quarter of 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. Three of such
installments have been paid and the fourth installment is
due and payable in June 1995.
In addition, Enron has received requests for
information from the EPA and state environmental agencies
inquiring whether Enron has disposed of materials at other
waste disposal sites. Enron has also received requests for
contribution from other parties with respect to the cleanup
of other sites. Enron may be required to share in the costs
of the cleanup of some of these sites. However, based upon
the amounts claimed and the nature and volume of materials
sent to sites at which Enron has an interest, management
does not believe that any potential costs incurred in
connection with these notices and third party claims, either
taken individually or in the aggregate, will have a material
impact on Enron's financial position or results of
operations.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security
holders during the fourth quarter of 1994.
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 Midwest Stock Exchange and the Pacific Stock
Exchange, as well as The London Stock Exchange and Frankfurt
Stock Exchange.
[Download Table]
1994 1993
High Low Dividends High Low Dividends
First Quarter $34 1/8 $28 1/4 $.1875 $31 3/4 $22 1/8 $.175
Second Quarter 34 5/8 28 7/8 .1875 31 1/4 26 7/8 .175
Third Quarter 33 1/4 29 1/8 .1875 36 3/4 32 1/8 .175
Fourth Quarter 32 7/8 27 .20 37 27 .1875
</TABLE
Cumulative Second Preferred Convertible Stock
The following table indicates the high and low sales prices
for the Cumulative Second Preferred Convertible Stock ("Second
Preferred Stock") of Enron as reported on the New York Stock
Exchange (consolidated transactions reporting system), the
principal market in which the securities are traded, and
dividends paid per share for the calendar quarters indicated.
The Second Preferred Stock is also listed for trading on the
Midwest Stock Exchange.
[Download Table]
1994 1993
High Low Dividends High Low Dividends
First Quarter $450 $376 3/4 $2.625 $413 $306 1/2 $2.625
Second Quarter 455 450 2.625 419 7/8 388 1/4 2.625
Third Quarter 450 427 2.625 500 3/4 445 2.625
Fourth Quarter 410 410 2.7304 480 375 3/8 2.625
At December 31, 1994, there were approximately 26,775
record holders of common stock, and 272 record holders of
Second Preferred Stock.
Other information required by this item is set forth on
page 31 under Item 6 -- "Selected Financial Data (Unaudited)
- Common Stock Statistics" for the years 1989-1994.
Item 6. SELECTED FINANCIAL DATA (UNAUDITED)
[Enlarge/Download Table]
1994 1993 1992 1991 1990 1989
Operating Revenues (millions) $ 8,984 $ 7,986 $ 6,415 $ 5,698 $5,460 $4,631
Total Assets (millions) $11,966 $11,504 $10,312 $10,070 $9,849 $9,105
Common Stock Statistics
Income from continuing
operations(a)
Total (millions) $453.4 $386.5 $328.8 $232.1 $202.2 $226.1
Per share - primary $1.80 $1.55 $1.39 $1.03 $0.88 $1.01
Per share - fully diluted $1.70 $1.46 $1.30 $0.98 $0.86 $0.97
Earnings on common stock(a)
Total (millions) $438.4 $369.6 $284.1 $207.4 $177.2 $201.0
Per share - primary $1.80 $1.55 $1.29 $1.03 $0.88 $1.01
Per share - fully diluted $1.70 $1.46 $1.21 $0.98 $0.86 $0.97
Dividends
Total (millions) $191.8 $170.5 $148.2 $127.0 $125.0 $124.7
Per share $0.76 $0.71 $0.66 $0.63 $0.62 $0.62
Shares outstanding (millions)
Actual at year-end 244.2 241.6 237.2 202.4 201.8 201.4
Average for the year 243.4 239.0 220.0 202.1 201.6 199.4
Capitalization (millions)
Long-term debt $2,805 $2,661 $2,459 $3,109 $2,983 $3,184
Preferred stock of subsidiary 377 214 - - - -
Minority interest 290 196 179 101 97 93
Shareholders' equity 2,880 2,623 2,518 1,901 1,838 1,767
Total capitalization $6,352 $5,694 $5,156 $5,111 $4,918 $5,044
<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%.
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 1994 was $453 million compared to
$387 million in 1993 (exclusive of a primarily non-cash
charge of $54 million to adjust the deferred tax liability
for the increase in the corporate Federal statutory income
tax rate from 34% to 35%) and $306 million in 1992. Net
income for all three years reflects improved income before
interest, minority interest and income taxes as compared to
the applicable preceding year. Primary earnings per share
of common stock was $1.80 in 1994 as compared to $1.32 in
1993, after a $0.23 per share charge applicable to the $54
million tax rate change adjustment, and $1.29 in 1992.
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) 1994 1993 1992
Transportation and Operation $403 $382 $378
Capital & Trade Resources 225 169 147
Domestic Gas Processing (23) 28 56
International Gas and Power Services 148 132 33
Exploration and Production 198 129 102
Corporate and Other (7) (42) 51
Total $944 $798 $767
Transportation and Operation
The transportation and operation segment includes Enron's
regulated natural gas pipelines, construction, management
and operation of pipelines, liquids and clean fuels plants
and power facilities, Enron's investment in crude oil
marketing and transportation operations conducted by EOTT
Energy Corp. (EOTT) and Enron's investment in liquids
pipeline operations. The segment realized a $21 million
increase in IBIT in 1994 as compared to 1993 primarily due
to increased IBIT from the regulated natural gas pipelines
and the construction, management and operation of assets
partially offset by lower earnings from EOTT due to reduced
ownership interest as discussed below. In the first quarter
of 1994, EOTT exchanged its crude oil trading and
transportation operations for common and subordinated units
and a 2% general partner interest in EOTT Energy Partners,
L.P. (the EOTT Partnership). Enron continues to own
approximately 40% of the EOTT Partnership. The
transportation and operation segment realized a $4 million
increase in IBIT in 1993 as compared to 1992. The increase
was due primarily to increases in IBIT realized by the
regulated natural gas pipelines and EOTT, offset by declines
in earnings from the liquids pipeline operations due to the
sale of a significant portion of these operations in August
1992 and reduced revenues on completed construction
projects. The following discussion analyzes the significant
changes in the various components of income before interest,
minority interest and income taxes for the transportation
and operation segment.
Revenues
Regulated Natural Gas Pipelines. Revenues of the
regulated natural gas pipelines declined approximately $398
million (30%) during 1994 after increasing $60 million (5%)
in 1993 as compared to the applicable preceding year. The
revenue decline reflects lower sales revenues of Northern
Natural Gas Company (Northern) as Northern is now primarily
a transporter of natural gas. Transport revenues declined
slightly as higher volumes were offset by lower average
transport rates. The increased revenues during 1993 reflect
increased transportation revenues recognized by Northern
primarily as a result of higher commodity volumes and
increased capacity utilization, combined with management
fees earned in connection with the operation of the
Argentina pipeline. These increases were offset by reduced
sales revenues for both Northern and Transwestern Pipeline
Company (Transwestern) as those companies are now primarily
transporters of natural gas. Sales and transportation
volumes were as follows:
[Download Table]
Billion British Thermal Sales*
Units per Day - (BBtu/d) 1994 1993 1992
Northern 90 342 495
Transwestern 16 20 33
<FN>
*Includes intercompany amounts.
[Download Table]
Billion British Thermal Transportation*
Units per Day - (BBtu/d) 1994 1993 1992
Northern 4,452 4,030 3,740
Transwestern 1,078 1,049 867
<FN>
*Includes intercompany amounts.
Construction, Management and Operation Revenues.
Revenues earned in connection with the construction,
management and operation of power and pipeline projects
totaled $39 million in 1994 as compared to $27 million and
$52 million during 1993 and 1992, respectively. The increase
in 1994 reflects fees earned in connection with the
operation of additional facilities offset by lower
construction revenues as a result of project completions.
The decline during 1993 reflects reduced construction
revenues in connection with the Teesside power project in
the United Kingdom as a result of the completion of that
project in March 1993, offset by revenues earned, beginning
in 1993, in connection with the sales of fuel to a joint
venture power project in Guatemala and fees earned in
connection with the management and construction of the
Milford power project in the United States.
EOTT and Liquids Pipeline. During 1994, net revenues
from EOTT decreased $95 million as a result of the reduced
ownership interest. Net revenues from EOTT increased
approximately 39% during 1993 as a result of higher product
margins. Revenues earned in connection with the liquids
pipeline operations declined in 1993 primarily as a result
of the sale of those assets to Enron Liquids Pipeline, L.P.,
a master limited partnership formed in August 1992.
Cost of Gas and Other Products Sold
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. During 1993, the cost of gas and other
products sold decreased by less than 1% as compared to 1992
primarily as a result of higher average per unit gas
purchase costs being offset by lower purchase volumes.
Operating Expenses
Operating expenses of the transportation and operation
segment declined 24% primarily as a result of the decreased
ownership interest in EOTT combined with lower operating
expenses of the regulated natural gas pipelines reflecting
system modernization and reduced expenses resulting from
lower sales volumes transported on other pipelines.
Operating expenses in the transportation and operation
segment declined 10% during 1993 as compared to 1992. The
decline reflects lower expenses of the regulated natural gas
pipelines as a result of efficiencies gained in connection
with system modernization projects, combined with a decline
in operating expenses due to the previously discussed sale
of the liquids pipeline operations.
Amortization of deferred contract reformation costs
increased 2% during 1994 after declining by 12% during 1993
as compared to the applicable preceding year. The increase
during 1994 reflects additional transition costs being
amortized by Transwestern while the decline in 1993 resulted
primarily from Transwestern's completion of the recovery of
certain transition costs in early 1992.
Depreciation expense for the transportation and operation
segment decreased $28 million (24%) during 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.
Depreciation expense increased $5 million (4%) during 1993
as compared to 1992 primarily as a result of the previously
mentioned adjustment of accumulated depreciation partially
offset by a decline in depreciation recorded for the liquids
pipeline operations.
Other Income and Deductions
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) and $5 million of equity
earnings from the EOTT Partnership. 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 Florida Gas
Transmission's Phase III pipeline expansion. These
increases were offset by reduced earnings resulting from the
decreased ownership interest in Northern Border Pipeline
Company (Northern Border) as a result of Enron's
contribution of its investment in Northern Border to
Northern Border Partners, L.P., a master limited partnership
(the Northern Border Partnership) and Enron's subsequent
sale of a portion of its interest in the Northern Border
Partnership in an underwritten public offering in the fourth
quarter of 1993. Other income increased 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.
Equity in earnings of unconsolidated subsidiaries declined
by $14 million (39%) during 1993 as compared to 1992
primarily reflecting reduced earnings from Northern Border.
Additionally, during 1993, equity in earnings from Mojave
Pipeline Company (Mojave) decreased as a result of the sale
of Enron's investment in Mojave.
Outlook
The transportation and operation segment should continue
to provide stable earnings and cash flows during 1995. Full
implementation of FERC Order 636 and the successful
settlement of all significant regulatory issues by the
regulated natural gas pipelines should allow for a reliable
stream of cash flow. Additionally, the segment will
actively promote engineering and construction services to
provide incremental earnings and will seek to selectively
monetize assets and reduce its overall cost structure.
During 1995, 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.
Domestic Gas and Power Services
The domestic gas and power services segment includes Enron
Capital & Trade Resources (ECT) and the domestic gas
processing operations. ECT includes the marketing,
purchasing and financing of natural gas, natural gas liquids
and power and the management of the portfolio of commitments
arising from these activities. The domestic gas processing
operations consist of the earnings associated with
extraction of natural gas liquids (NGL). The following
reflects income (loss) before interest, minority interest
and income taxes for these businesses:
[Download Table]
(In Millions) 1994 1993 1992
ECT $225 $169 $147
Gas Processing (23) 28 56
Total $202 $197 $203
Enron Capital & Trade Resources
ECT's strategy is to provide predictable pricing, reliable
delivery and low cost capital to its customers. ECT provides
these services through a variety of products including
forward contracts, swap agreements, options, futures and
other contractual commitments. In providing these services,
ECT manages a variety of risks, such as market risk, credit
risk, legal risk and operational risk. ECT identifies,
measures and monitors these risks through a comprehensive
system of internal controls. ECT's Risk Control Group is a
centralized, integrated and independent control function
under the direction of ECT's Chief Control Officer. It
evaluates the risk exposures of ECT's business activities
and develops policies and methodologies to improve ECT's
ability to assess risks and protect against significant
losses in existing businesses. This group is independent,
but works in conjunction with ECT's business units, which
are primarily accountable for managing the risks taken at
the transactional and business unit levels. The Risk
Control Group monitors and assesses the risk management
activities of the business units, independently reviews
significant risk positions, and develops and enhances
policies, procedures and tools that facilitate the
identification, measurement and effective mitigation of
ECT's risks.
ECT had a $56 million (33%) increase in income before
interest, minority interest and income taxes in 1994 as
compared to 1993. This increase was primarily due to
significant risk management originations and increased
earnings from ECT's cash and physical businesses. This
increase in earnings was partially offset by a decrease in
earnings from finance operations and an increase in ECT's
unallocated overhead expenses. ECT's income before
interest, minority interest and income taxes increased $22
million (15%) in 1993 as compared to 1992. The increase was
due primarily to increased earnings from risk management
origination and finance, while the results from the cash and
physical operations were virtually unchanged.
ECT can be categorized into three business lines: cash and
physical, risk management and finance. The combined
earnings for these business lines before unallocated
expenses were $350 million in 1994, $250 million in 1993 and
$215 million in 1992. The following discussion analyzes the
contributions to income before interest, minority interest
and income taxes and the future 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 physical natural
gas, liquids 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.
This business line accounted for 53% of ECT's earnings
before unallocated expenses in 1994 and 51% and 60% in 1993
and 1992, respectively.
Statistics for ECT's cash and physical operations are as
follows:
[Download Table]
1994 1993 1992
Physical and Notional Sales (Bbtue/d)*
Firm 4,895 4,310 2,632
Interruptible 2,039 828 893
Financial Settlements (notional) 16,459 5,027 1,536
Total 23,393 10,165 5,061
Transportation Volumes (Bbtu/d)* 538 571 536
Liquids Marketing Volumes (MMgal)
Domestic NGL Marketed* 2,032 2,506 3,388
International NGL Marketed 464 646 1,180
MTBE Marketing Volumes (MMgal) 390 254 28
Electricity Volumes**
(Gigawatt hours) 4,357 2,951 2,903
(Megawatts/hour) 803 337 331
<FN>
*Includes intercompany amounts.
**Includes sales from facilities in which ECT has an
ownership interest and, effective October 1994, volumes from
electricity marketing activities. Megawatts per hour
reflect the average hourly amounts produced as well as
average hourly amounts marketed since October 1994.
The earnings from cash and physical activities increased
44% in 1994 as compared to 1993. This increase resulted
primarily from ECT's successful management in 1994 of its
portfolio of contracts and the ability to benefit from the
relationship between the financial and physical prices for
natural gas (through exchange for physical transactions, as
well as providing daily and hourly physical options or swing
service to customers). Earnings from short-term marketing
in the purely physical gas market decreased slightly due to
lower margins reflecting the more competitive marketplace.
The liquids marketing activities continued to experience
lower product prices, however this did not have a
significant impact on the overall cash and physical
business. Earnings from ECT's physical assets declined
slightly due to increased fees paid for operational asset
management.
Earnings from the cash and physical business decreased 1%
in 1993 compared to the prior year. For 1993, earnings from
short-term gas marketing and the management of ECT's
contract portfolio increased 16%. This increase was offset
by a decline in NGL marketing earnings due to lower volumes
and margins and decreased earnings from power related assets
due primarily to the inclusion in 1992 of earnings
associated with certain power projects.
During 1995, ECT expects continued growth in its cash and
physical business as it continues to capitalize on its
position as a significant marketer of natural gas on both a
financial and physical basis. The existence of its
substantial portfolio of contracts, as well as the
capability to benefit from the relationship between the
financial and physical marketplace provides substantial
opportunity for earnings. Additionally, opportunities for
growth in new markets, including electricity, should enhance
1995 results.
Risk Management. The risk management operations consist
of market origination activity on new long-term contracts
(transactions greater than one year) and restructuring of
existing long-term contracts. In 1994, the earnings from
risk management originations were 41% of ECT's earnings
before unallocated expenses, while this segment contributed
38% and 32% in 1993 and 1992, respectively. Fixed price
contract originations were 6,615 trillion British thermal
unit equivalents (TBtue), 3,781 TBtue and 2,165 TBtue for
1994, 1993 and 1992, respectively.
The earnings from these activities increased 52% in 1994.
This increase resulted from the execution of various new
long-term gas contracts and the restructuring of existing
long-term contracts with utilities, local distribution
companies and independent power producers. Additionally,
the origination of liquids contracts associated with new
product offerings contributed to this increase.
Earnings from risk management originations increased 41%
in 1993 primarily as a result of an increase in sales
volumes particularly to independent power producers.
ECT expects continued growth from its risk management
activities in 1995 as it continues to provide attractive
pricing structures and solutions to its customers.
Additionally, significant earnings are anticipated from the
growth of the market for electricity during 1995 and beyond.
The infrastructure for electricity marketing is in place at
ECT and ECT's growth opportunities are based on its ability
to capitalize on its existing customer base, 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 activities
contributed 6% of ECT's earnings before unallocated expenses
in 1994 and 11% and 8% in 1993 and 1992, respectively.
Production payments and financings arranged were $503
million, $470 million and $516 million in 1994, 1993 and
1992, respectively. The 1992 amount included $327 million
of volumetric production payments arranged for Enron Oil &
Gas Company (EOG), an 80% owned subsidiary of Enron.
Although total production payments and financings
arranged were greater in 1994 than 1993, the earnings from
these operations decreased 23% in 1994 due to a difference
in the types of transactions originated in each of these
periods. During 1994, ECT's finance activities transitioned
from purely "senior debt-like structures," such as
production payments, to more "equity-like transactions"
including subordinated loans and actual equity issuances.
Earnings and returns associated with these equity-like
transactions are expected to be equal to or greater than
returns on debt-like instruments over the life of the
transactions.
Earnings associated with the finance operations increased
56% in 1993 due primarily to increased non-affiliated
production payments and financings arranged.
In 1995, ECT will be expanding its products and services
in its finance operations to become 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 36% of
ECT's earnings before unallocated expenses in 1994 and 32%
in both 1993 and 1992. The costs increased in 1994 as
compared to 1993 due to continued expansion into new
markets. Expenses also increased in 1993 from 1992 due to
increased activity. ECT expects its overall expenses to
increase during 1995 as it continues to expand into new
markets, such as electricity. However, certain process and
information system enhancements will somewhat offset this
increase.
Gas Processing
The gas processing operations had a loss before interest
and taxes of $23 million as compared to income of $28
million in 1993 and $56 million in 1992. The decline in
1994 reflects lower processing margins due to lower product
prices. During 1994, Enron entered into hedges to minimize
additional volatility in product and feedstock (natural gas)
prices. The decline in 1993 as compared to 1992 was
attributable primarily to lower processing margins
reflecting higher natural gas feedstock prices and lower
product prices. Earnings for 1993 also included gains
realized on the sales of certain coal handling and NGL
assets.
Volume and price statistics for the gas processing
operations (including intercompany amounts) are detailed
below:
[Download Table]
1994 1993 1992
Total Production Volumes
(MMgal) 1,205 1,334 1,296
Gross Margin (per gal.) $0.058 $0.089 $0.112
In 1995, Enron will continue to mitigate the market risk
inherent in the gas processing business through hedging
transactions. Additionally, cost cutting and streamlining
actions have recently been completed, positioning the
business to maximize earnings opportunities.
International Gas and Power Services
Enron's international gas and power services segment
includes international development activities and its
international power and pipeline operations. International
development activities include the development and promotion
of power and natural gas projects worldwide. Income before
interest and taxes for the international gas and power
services group totaled $148 million during 1994, $132
million in 1993 and $33 million in 1992. The increase in
IBIT during 1994 primarily reflects increased promotion and
development activities and increased earnings from power and
pipeline projects. The increase in IBIT during 1993
primarily reflects promotion and development activities of
the power operations and earnings from the Argentina
pipeline operations acquired in the fourth quarter of 1992.
Revenues
Revenues of the international gas and power services
segment decreased 48% during 1994 primarily due to the
transfer of certain gas liquids marketing operations to ECT
during the second quarter of 1994. This decline was
partially offset by $65 million of revenues earned in
connection with the formation of Enron Global Power &
Pipelines L.L.C. (EPP), $28 million of revenues earned on
the promotion of liquids processing facilities at Teesside
in northeast England and higher revenues earned in
connection with liquids processing activities at Teesside.
Revenues of the international gas and power services
segment declined 12% during 1993 as compared to 1992
primarily as a result of decreased revenues earned by the
international gas liquids marketing operations. These
declines were caused by a 45% decline in marketing volumes
as compared to the prior year, reflecting reduced spot
market activity. The decline in liquids marketing revenues
was partially offset by a $102 million increase in revenues
in the power operations. The increase reflects revenues
earned in connection with the promotion and development of
liquids and power projects of which approximately $55
million is related to revenues in connection with the
liquids processing facilities at Teesside.
Costs and Expenses
The cost of gas and other products sold by the
international gas and power services segment declined 63%
primarily as a result of the transfer of the liquids
marketing activities to ECT offset in part by product costs
incurred in connection with liquids processing activities at
Teesside.
The cost of gas and other products sold by the
international gas and power services segment declined by 24%
in 1993 as compared to 1992 and reflected a decline in
international liquids marketing volumes.
Operating expenses increased $7 million (10%) during 1994
and $20 million (40%) during 1993 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 the
international gas and power services segment increased $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 $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 project. These increases were
offset by lower earnings from certain Venezuelan operations.
Equity in earnings of unconsolidated subsidiaries of the
international gas and power services segment increased $36
million during 1993 as compared to 1992 primarily as a
result of $23 million in earnings from the Argentina
pipeline project and $12 million in earnings from the
Teesside power project which was placed in commercial
operation during the first quarter of 1993. Other income,
net, increased during 1994 primarily as a result of foreign
currency gains. Other income, net, declined $7 million
during 1993 primarily as a result of lower interest income
earned by the power operations in 1993 as compared with 1992
combined with gains on asset sales during 1992.
Outlook
The objective of the international gas and power services
segment is to deliver energy solutions worldwide through the
utilization of Enron's extensive product line. Growth
opportunities in the international market should 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.
During 1994, 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. Enron
retains a 52% ownership interest in EPP and does not intend
to reduce its ownership below such level.
Exploration and Production
Income before interest, minority interest and income taxes
of the exploration and production segment totaled $198
million during 1994 as compared to $129 million during 1993
and $102 million during 1992. Enron+s exploration and
production activities are conducted by EOG. Additionally,
the exploration and production segment's 1994 and 1993
income before interest, minority interest and income taxes
includes approximately $35 million and $7 million,
respectively, of income related to hedges placed on open
positions by Enron independent of EOG. The increase in IBIT
realized by EOG during 1994 primarily reflects increased
gains on sales of reserves and related assets combined with
a reduction in per unit operating costs. The 1993 increase
was due primarily to higher natural gas prices and volumes,
lower per unit operating costs and increased gains on sales
of reserves and related assets. Volume and price statistics
are as follows (including intercompany amounts):
[Download Table]
1994 1993 1992
Wellhead Delivered Volumes
Natural Gas (MMcf/d)(a) 749 709 564
Crude Oil and Condensate (MBbl/d) 12.6 8.9 8.5
Natural Gas Liquids (MBbl/d) 0.7 0.6 0.7
Wellhead Average Prices
Natural Gas ($/Mcf)(b) $ 1.62 $ 1.92 $ 1.58
Crude Oil and Condensate ($/Bbl) $15.62 $16.37 $17.90
Natural Gas Liquids ($/Bbl) $ 9.90 $11.12 $10.69
Other Natural Gas Marketing
Volumes (MMcf/d)(a) 324 293 255
Average Gross Revenue ($/Mcf) $ 2.38 $ 2.57 $ 2.62
Associated Costs ($/Mcf)
(including transportation and
exchange differentials $ 2.06 $ 2.32 $ 1.99
<FN>
(a) Includes an annual average of 48 MMcf per day in
1994, 81 MMcf per day in 1993 and 28 MMcf per day in 1992
delivered under the terms of a volumetric production payment
agreement effective October 1, 1992, as amended.
(b) Includes an average equivalent wellhead value of
$1.27 per Mcf in 1994, $1.57 per Mcf in 1993 and $1.70 per
Mcf in 1992 for the volumes detailed in Note (a) 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
increased $72 million (10%) during 1994 after increasing by
$147 million (26%) in 1993. The increases primarily reflect
gains on sales of reserves and related assets which totaled
$54 million in 1994 as compared to $13 million in 1993. In
continuing its strategy of fully utilizing its assets to
optimize profitability, cash flow and return on investment,
EOG expects to continue to periodically sell selected oil
and gas reserves and related assets. The 1994 and 1993
revenues include hedges placed by Enron on open commodity
positions not hedged by EOG.
During 1994, the effects of volume increases of 6% in
wellhead natural gas volumes and 42% in crude oil and
condensate volumes were largely offset by declines of 16%
and 5% in wellhead natural gas prices and crude oil and
condensate prices, respectively. The increase in wellhead
natural gas volumes was achieved despite voluntary U.S.
curtailments of up to 25% during portions of 1994. Such
curtailments occurred in response to significantly lower
U.S. natural gas prices during the second half of 1994. The
increase in both wellhead natural gas volumes and crude oil
and condensate volumes reflects increased production from
operations in Trinidad and to a lesser extent, Canada. The
increased revenues in 1993 are attributable to a 22%
increase in average wellhead natural gas prices combined
with a 26% increase in average wellhead natural gas volumes.
The increased natural gas volumes primarily reflect the
effects of exploration and development activities relating
to tight gas sand formations.
Costs and Expenses
The cost of natural gas sold by the exploration and
production segment in connection with other natural gas
marketing activities declined less than 2% in 1994 as
compared to 1993 after increasing 18% in 1993 as compared to
1992. The decrease in 1994 as compared to 1993 reflects 11%
lower average costs partially offset by 11% higher other
natural gas marketing volumes. The increase in 1993 as
compared to 1992 was due to 17% higher average associated
costs combined with a 15% increase in natural gas marketing
volumes.
Operating expenses for the exploration and production
segment increased $15 million (9%) in 1994 compared to 1993
and $35 million (24%) in 1993 compared to 1992. The increase
in 1994 reflects higher exploration expenses due primarily
to an increased level of exploration activities, higher
impairments associated with certain offshore Gulf of Mexico
leases and increased general and administrative expenses
associated with expanded operations. The increase in 1993
relates to higher lease and well expenses and exploration
expenses primarily due to expanded domestic and
international operations.
Depreciation, depletion and amortization (DD&A) expense
declined 3% in 1994 after increasing 39% in 1993 as compared
to the applicable prior year. The decline during 1994
reflects increased production from offshore Trinidad at an
average DD&A rate significantly less than the North American
operations rate and a $0.03 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) decrease in the North
American DD&A rate. The increases in 1993 primarily reflect
increased production volumes. On a per unit natural gas
equivalent volumes delivered basis, DD&A expense declined
$0.09 per Mcfe in 1994 to $0.80 per Mcfe as compared to
$0.89 per Mcfe in 1993 and $0.79 per Mcfe in 1992. The 1993
increase primarily reflects higher costs associated with
tight gas sand drilling activities.
Taxes, other than income taxes, declined $7 million (20%)
during 1994 primarily due to lower taxable United States
wellhead volumes and prices and reductions related to
revisions of production and franchise taxes applied in 1994.
Taxes, other than income taxes, increased $7 million (25%)
from 1992 to 1993 due to increased production volumes and
revenues, partially offset by continuing benefits associated
with certain state severance tax exemptions allowed on high
cost natural gas sales and a refund received in 1993 of
franchise taxes paid in prior years.
Total per unit operating costs for lease and well expense,
DD&A, general and administrative expense, interest expense
and taxes other than income decreased $0.14 per Mcfe,
averaging $1.29 per Mcfe during 1994 compared to $1.43 per
Mcfe for 1993.
Outlook
There continues to exist a good deal of uncertainty as to
the direction of future North American natural gas price
trends and a rather wide divergence in the opinions held by
some in the industry. EOG's 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.
Being primarily a natural gas producer, EOG is more
significantly impacted by changes in natural gas prices than
by changes in crude oil and condensate prices. However, the
use of various commodity price hedging mechanisms will tend
to mitigate this level of sensitivity. Enron has hedged a
substantial portion of its anticipated 1995 natural gas
production at prices above those currently available.
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 American
natural gas prices and the current weakness in that market
and, as a result of the recent success realized in Trinidad
and opportunities available to EOG in connection with the
recent signing of agreements in India, 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 China,
France, Australia and certain other countries.
Corporate and Other
The corporate and other segment's income before interest,
minority interest and income taxes was an expense of $7
million in 1994 as compared to an expense of $42 million in
1993 and income of $51 million in 1992. The improvement
during 1994 primarily reflects a $15 million pretax gain
realized on the formation of EOTT Energy Partners, L.P.
Included in 1992 are gains from the sale of stock by EOG and
sales of Mobil Corporation common stock partially offset by
charges related to the establishment of reserves for
litigation and other contingencies.
Interest and Related Charges, net
Interest and related charges, net, is shown on the
Consolidated Income Statement net of interest capitalized.
The net expense decreased $27 million during 1994 and $30
million during 1993 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 Subsidiary Companies
Dividends on preferred stock of subsidiary companies
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 and the issuance by
Enron Capital Resources, L.P. of 3 million shares of 9%
Cumulative Preferred Securities, Series A in August 1994.
Additionally, during December 1994, Enron Equity Corp.
issued 880 shares of 8.57% Preferred Stock, $0.001 par
value, in a private transaction (see Note 9 to the
Consolidated Financial Statements).
Income Tax Expense
Income tax expense increased during 1994 compared to 1993
due to increased pretax income and a decrease in tight gas
sand Federal tax credits. Exclusive of the adjustment for
the increase in the U.S. corporate Federal statutory income
tax rate from 34% to 35%, income tax expense declined
slightly during 1993 as compared to 1992 as increased pretax
income was offset by increased tight gas sand Federal tax
credits.
Extraordinary Items
The extraordinary loss recognized during 1992 results
primarily from the early retirement of $599 million
principal amount of 10.625% senior subordinated debentures
in September 1992.
Financial Condition
Cash From Operating Activities
Net cash provided by operating activities totaled $504
million during 1994 as compared to $468 million during 1993.
The increase primarily reflects higher net income and
reduced deferred contract reformation costs partially offset
by increased working capital requirements.
Cash From Investing Activities
Cash used in investing activities totaled $604 million
during 1994 as compared to $639 million during 1993.
Proceeds from asset sales totaled $440 million during 1994
as compared to $454 million during 1993. The 1994 amount
primarily reflects proceeds realized on the formation of
Enron Global Power & Pipelines L.L.C. and the sale of
Enron's crude oil trading and transportation operations to
EOTT Energy Partners, L.P. The 1993 amount includes
proceeds received in connection with the sale of Enron's
interest in Northern Border Partners, L.P. and the sale of
information technology assets. As more fully discussed
below, capital expenditures (property additions and other
capital expenditures) declined to $669 million in 1994 as
compared to $695 million in 1993. Equity investments
totaled $273 million in 1994 as compared to $267 million in
1993. The 1994 amount primarily reflects investments in
connection with Florida Gas Transmission's Phase III
pipeline expansion and investments in Joint Energy
Development Investments Limited Partnership and in various
international projects. Equity investments during 1993
primarily reflect investments in Teesside Power Ltd. and the
Argentina pipeline project.
Cash From Financing Activities
Net cash provided by financing activities totaled $92
million during 1994 as compared to $170 million in 1993.
During 1994, Enron issued $190 million of long-term debt
while retiring $162 million principal amount of long-term
borrowings. Other cash outflows during 1994 included $231
million of cash dividend payments on common and preferred
stock and $50 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 inflows during 1994 included $161 million from the
issuance of preferred stock by wholly-owned subsidiaries of
Enron (see Note 9 to the Consolidated Financial Statements),
a $115 million increase in short-term borrowings and
$66 million in proceeds from common stock issuances.
Working Capital
At December 31, 1994, Enron had a working capital deficit
of $388 million. Enron is able to fund its deficit in
working capital through the utilization of credit facilities
which, at December 31, 1994, provided for up to $2.05
billion of committed and uncommitted credit of which $53
million was 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 up to $600 million of 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]
1995
(In Millions) Estimate 1994 1993 1992
Transportation and Operation $128 $125 $152 $140
Domestic Gas & Power Services* 94 83 102 79
International Gas & Power Services 43 14 53 41
Exploration and Production** 400 442 383 362
Corporate and Other 7 5 5 12
Total $672 $669 $695 $634
<FN>
* Includes domestic gas processing operations.
** Excludes exploration expenses of $50 million (estimate),
$59 million, $55 million, and $44 million for 1995, 1994,
1993 and 1992, respectively.
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
expenditure 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.
The increase in capital expenditures during 1993 as
compared to 1992 reflects increased expenditures by ECT as a
result of the acquisition of gas storage assets and system
improvement costs combined with increased capital
expenditures in the exploration and production segment. The
exploration and production segment's capital expenditures
increased as a result of increased domestic drilling
activity and the implementation of Enron's first development
program outside of North America.
Capital expenditures during 1995 are expected to total
approximately $672 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 $213
million. 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, 1994 was $6.4
billion. Debt as a percentage of total capitalization
decreased to 44.2% at December 31, 1994 as compared to 46.7%
at December 31, 1993. The improvement primarily reflects
increased retained earnings and the issuance of $163 million
of preferred securities, partially offset by a net increase
of $144 million in long-term debt.
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 2, 1995, 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 1994; Aggregated Stock Option/SAR Exercises During
1994 and Stock Option/SAR Values as of December 31, 1994;
Long-Term Incentive Plan - Awards in 1994; Retirement and
Severance Plans; Enron's 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,
1995", 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.
*3.02 - Bylaws of Enron Corp. as currently in effect (Exhibit
3.02 to Enron Form 10-K for 1990, File No. 1-3423).
*4.01 - Indenture dated as of November 1, 1985, between Enron
and Harris Trust and Savings Bank (Form T-3 Application
for Qualification of Indentures under the Trust
Indenture Act of 1939, File No. 22-14390, filed
October 24, 1985). 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
10.59
*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 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to
Registration Statement No. 33-27893).
*10.04 - Enron Corp. 1986 Stock Option Plan with Stock
Appreciation Rights (Exhibit 4.3 to Registration
Statement No. 33-13498).
*10.05 - Executive Incentive Plan (Exhibit 10.13 to Enron Form
10-K for 1987, File No. 1-3423).
*10.06 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to Enron
Form 10-K for 1987, File No. 1-3423).
*10.07 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron
Form 10-K for 1991, File No. 1-3423).
*10.08 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to Enron
Form 10-K for 1991, File No. 1-3423).
*10.09 - Enron Corp. Directors' Deferred Income Plan (Exhibit
10.09 to Enron Form 10-K for 1992, File No. 1-3423).
*10.10 - 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).
*10.11 - 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).
*10.12 - 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).
*10.13 - 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).
*10.14 - 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).
*10.15 - 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).
10.16 - Sixth Amendment to Employment Agreement between Enron
and Kenneth L. Lay, dated April 27, 1994.
10.17 - Split Dollar Life Insurance Agreement between Enron and
the KLL and LPL Family Partnership, Ltd., dated April
22, 1994.
*10.18 - 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).
*10.19 - 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).
*10.20 - 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).
*10.21 - 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).
*10.22 - 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).
*10.23 - 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).
*10.24 - 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).
10.25 - Seventh Amendment to Employment Agreement between Enron
and Richard D. Kinder, dated November 30, 1994.
*10.26 - 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).
10.27 - First Amendment to Employment Agreement between Enron
International Inc. and Rodney L. Gray, dated May 2,
1994.
*10.28 - Employment Agreement between Enron and Ronald J. Burns
dated as of July 1, 1989 (Exhibit 10.15 to Enron Form
10-K for 1989, File No. 1-3423).
*10.29 - First Amendment to Employment Agreement between Enron
and Ronald J. Burns dated June 21, 1990 (Exhibit 10.20
to Enron Form 10-K for 1991, File No. 1-3423).
*10.30 - Second Amendment to Employment Agreement between Enron
and Ronald J. Burns dated August 19, 1991 (Exhibit
10.21 to Enron Form 10-K for 1991, File No. 1-3423).
10.31 - Third Amendment to Employment Agreement between Enron
and Ronald J. Burns, dated May 2, 1994.
*10.32 - Employment Agreement between Enron and Jack I. Tompkins
dated October 1, 1991 (Exhibit 10.22 to Enron Form 10-K
for 1991, File No. 1-3423).
10.33 - First Amendment to Employment Agreement between Enron
and Jack I. Tompkins, dated May 2, 1994.
*10.34 - 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).
*10.35 - 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).
*10.36 - 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).
*10.37 - 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).
*10.38 - 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).
10.39 - Second Amendment to Employment Agreement between Enron
and Edmund P. Segner, III, dated May 2, 1994.
*10.40 - Employment Agreement between Enron and Jeffrey K.
Skilling, effective August 1, 1990 (Exhibit 10.18 to
Enron Form 10-K for 1990, File No. 1-3423).
*10.41 - First Amendment to Employment Agreement between Enron
and Jeffrey K. Skilling, dated August 1, 1990 (Exhibit
10.30 to Enron Form 10-K for 1992, File No. 1-3423).
*10.42 - Second Amendment to Employment Agreement between Enron
and Jeffrey K. Skilling, dated June 1, 1991 (Exhibit
10.31 to Enron Form 10-K for 1992, File No. 1-3423).
*10.43 - Third Amendment to Employment Agreement between Enron
and Jeffrey K. Skilling, dated February 10, 1992
(Exhibit 10.32 to Enron Form 10-K for 1992, File No. 1-
3423).
*10.44 - Loan Commitment Agreement between Enron and Jeffrey K.
Skilling, dated April 13, 1992 (Exhibit 10.33 to Enron
Form 10-K for 1992, File No. 1-3423).
*10.45 - Fourth Amendment to Employment Agreement between Enron
and Jeffrey K. Skilling, dated June 23, 1992 (Exhibit
10.34 to Enron Form 10-K for 1992, File No. 1-3423).
*10.46 - Fifth Amendment to Employment Agreement between Enron
and Jeffrey K. Skilling, dated December 18, 1992
(Exhibit 10.35 to Enron Form 10-K for 1992, File No. 1-
3423).
*10.47 - Buyout Agreement between Enron and Jeffrey K. Skilling,
dated December 18, 1992 (Exhibit 10.36 to Enron Form
10-K for 1992, File No. 1-3423).
*10.48 - First Amendment to Buyout Agreement between Enron and
Jeffrey K. Skilling, dated December 23, 1992 (Exhibit
10.37 to Enron Form 10-K for 1992, File No. 1-3423).
*10.49 - Loan Agreement between Enron and Jeffrey K. Skilling,
dated January 1, 1993 (Exhibit 10.38 to Enron Form 10-K
for 1992, File No. 1-3423).
*10.50 - Employment Agreement among Enron Corp., Enron Power
Corp., and Thomas E. White, dated December 9, 1992
(Exhibit 10.39 to Enron Form 10-K for 1992, File No. 1-
3423).
10.51 - Second Amendment to Employment Agreement between Enron
Corp., Enron Power Corp., and Tom White, dated May 2,
1994.
*10.52 - 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).
10.53 - First Amendment to Employment Agreement between Enron
and James V. Derrick, Jr., dated May 2, 1994.
*10.54 - Enron Gas Services Group Phantom Equity Plan (Exhibit
10.26 to Enron Form 10-K for 1991, File No. 1-3423).
*10.55 - Enron Power Corp. Executive Compensation Plan (Exhibit
10.42 to Enron Form 10-K for 1992, File No. 1-3423).
*10.56 - Enron Corp. Performance Unit Plan (Exhibit A to Enron
Proxy Statement filed pursuant to Section 14(a) on
March 25, 1994).
*10.57 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron
Proxy Statement filed pursuant to Section 14(a) on
March 25, 1994).
*10.58 - 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, 1994).
10.59 - Form of 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
13, 1995.
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
Current Report on Form 8-K filed on August 3, 1994 containing
certain documentation in connection with the sale by Enron
Capital Resources, L.P. of its 9% Cumulative Preferred
Securities, Series A.
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, 1994, 1993 and 1992 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, 1994, 1993 and 1992 F-6
Consolidated Statement of Changes in
Shareholders' Equity Accounts for the
years ended December 31, 1994, 1993 and 1992 F-7
Notes to the Consolidated Financial Statements F-8
Supplemental Financial Information (Unaudited) F-27
Financial Statements Schedules
Report of Independent Public Accountants on
Financial Statements Schedules 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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, 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, 1994, in conformity with generally accepted
accounting principles.
Arthur Andersen LLP
Houston, Texas
February 17, 1995
[Enlarge/Download Table]
Enron Corp. and Subsidiaries
Consolidated Income Statement
Year Ended December 31,
(In Thousands, Except Per Share Amounts) 1994 1993 1992
Revenues
Natural gas and other products $7,490,533 $6,652,333 $5,124,230
Transportation 754,117 767,911 688,297
Other 739,073 565,556 602,783
8,983,723 7,985,800 6,415,310
Costs and Expenses
Cost of gas and other products 6,517,109 5,566,026 4,222,395
Operating expenses 1,032,831 1,057,415 936,040
Amortization of deferred contract
reformation costs 90,617 89,240 101,253
Oil and gas exploration expenses 83,944 75,743 59,178
Depreciation, depletion and amortization 441,329 458,188 376,019
Taxes, other than income taxes 102,121 108,386 100,616
8,267,951 7,354,998 5,795,501
Operating Income 715,772 630,802 619,809
Other Income and Deductions
Equity in earnings of unconsolidated
subsidiaries 112,409 73,293 56,545
Interest income 39,162 31,457 53,623
Other, net 77,049 62,115 37,205
Income Before Interest, Minority Interest
and Income Taxes 944,392 797,667 767,182
Interest and Related Charges, net 273,482 300,149 330,282
Dividends on Preferred Stock of Subsidiary 19,875 2,137 -
Minority Interest 31,041 27,605 17,632
Income Taxes 166,584 89,077 90,468
Income Tax Rate Adjustment - 46,177 -
Income Before Extraordinary Items 453,410 332,522 328,800
Extraordinary Items - - (22,615)
Net Income 453,410 332,522 306,185
Preferred Stock Dividends 15,038 16,919 22,109
Earnings on Common Stock $ 438,372 $ 315,603 $ 284,076
Earnings Per Share of Common Stock
Primary
Income before extraordinary items $ 1.80 $ 1.32 $ 1.39
Extraordinary items - - (.10)
$ 1.80 $ 1.32 $ 1.29
Fully Diluted
Income before extraordinary items $ 1.70 $ 1.25 $ 1.30
Extraordinary items - - (.09)
$ 1.70 $ 1.25 $ 1.21
Average Number of Common Shares Used in
Primary Computation 243,395 239,019 219,965
<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) 1994 1993
Assets
Current Assets
Cash and cash equivalents $ 132,336 $ 140,240
Trade receivables (net of allowance
for doubtful accounts of $12,729 and
$21,873, respectively) 604,985 783,603
Other receivables 233,213 205,956
Transportation and exchange gas receivable 98,787 102,887
Inventories 138,405 197,737
Assets from price risk management activities 449,588 279,715
Other 251,679 308,472
Total Current Assets 1,908,993 2,018,610
Investments and Other Assets
Investments in and advances to
unconsolidated subsidiaries 1,065,189 697,084
Assets from price risk management activities 1,027,945 887,342
Other 1,225,224 1,178,507
Total Investments and Other Assets 3,318,358 2,762,933
Property, Plant and Equipment, at cost
Transportation and operation 3,906,952 4,070,325
Domestic gas and power services 3,811,037 3,809,773
Exploration and production, successful
efforts accounting 3,015,435 2,772,220
International gas and power services 119,740 135,918
Corporate and other 111,237 98,622
10,964,401 10,886,858
Less accumulated depreciation, depletion
and amortization 4,225,741 4,164,086
Net Property, Plant and Equipment 6,738,660 6,722,772
Total Assets $11,966,011 $11,504,315
<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
[Download Table]
Enron Corp. and Subsidiaries
Consolidated Balance Sheet
December 31,
1994 1993
Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable $ 924,446 $ 1,477,290
Transportation and exchange gas payable 114,124 98,569
Accrued taxes 90,906 88,837
Accrued interest 58,569 53,292
Liabilities from price risk management
activities 522,070 609,403
Other 587,271 348,198
Total Current Liabilities 2,297,386 2,675,589
Long-Term Debt 2,805,142 2,661,240
Deferred Credits and Other Liabilities
Deferred income taxes 1,893,450 1,860,237
Deferred revenue 256,298 327,802
Liabilities from price risk management
activities 575,377 330,209
Other 591,134 615,839
Total Deferred Credits and Other
Liabilities 3,316,259 3,134,087
Commitments and Contingencies (Notes 2, 8,
13, 14 and 15)
Minority Interests 290,146 196,275
Preferred Stock of Subsidiary Companies 376,750 213,750
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,
1,404,983 shares and 1,496,677 shares of
Cumulative Second Preferred Convertible
Stock issued, respectively 140,498 149,668
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, 253,069,668 shares and
249,095,312 shares issued, respectively 25,308 24,910
Additional paid-in capital 1,788,044 1,707,938
Retained earnings 1,351,297 1,104,986
Cumulative foreign currency translation
adjustment (158,881) (138,704)
Common stock held in treasury (1,394,833
shares at December 31, 1994) (41,090) -
Other (including Flexible Equity Trust,
Note 10) (224,848) (225,424)
Total Shareholders' Equity 2,880,328 2,623,374
Total Liabilities and Shareholders' Equity $11,966,011 $11,504,315
<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
[Enlarge/Download Table]
Enron Corp. and Subsidiaries
Consolidated Statement of Cash Flows
Year Ended December 31,
(In Thousands) 1994 1993 1992
Cash Flows From Operating Activities
Reconciliation of net income to net cash
provided by operating activities
Income before extraordinary items $ 453,410 $ 332,522 $ 328,800
Depreciation, depletion and amortization 441,329 458,188 376,019
Oil and gas exploration expenses 83,944 75,743 59,178
Amortization of deferred contract
reformation costs 90,617 89,240 101,253
Deferred income taxes 92,959 51,200 (14,647)
Gains on sales of stock by subsidiary
and other assets (91,284) (115,586) (136,249)
Regulatory, litigation and other
contingency adjustments (25,212) 58,944 42,549
Changes in components of working capital (141,372) (76,513) (157,234)
Deferred contract reformation costs (54,182) (136,383) (129,694)
Deferred revenues (5,466) 12,669 32,679
Prepaid information technology services - - (150,000)
Net assets from price risk management
activities (152,642) (115,415) (15,892)
Other, net (188,101) (166,320) (6,898)
Net Cash Provided by Operating Activities 504,000 468,289 329,864
Cash Flows From Investing Activities
Proceeds from sales of investments and
other assets 439,627 453,977 387,788
Production payment transactions, net (43,345) (73,867) 301,395
Additions to property, plant and equipment (660,915) (688,032) (596,885)
Equity investments (272,517) (267,097) (53,283)
Other, net (66,561) (64,224) (82,334)
Net Cash Used in Investing Activities (603,711) (639,243) (43,319)
Cash Flows From Financing Activities
Net increase (decrease) in short-term
borrowings 115,326 42,767 (142,651)
Issuance of long-term debt 190,115 613,938 700,000
Decrease in long-term debt (161,786) (450,161) (1,116,911)
Decrease in other long-term obligations - (22,757) (72,140)
Issuance of preferred stock of subsidiary 163,000 213,750 -
Issuance of common stock 66,372 22,882 399,355
Issuance of common stock by subsidiary - - 111,861
Dividends paid (231,079) (189,769) (174,880)
Net acquisition of treasury stock (41,090) (71,145) (37,524)
Other, net (9,051) 10,000 (5,818)
Net Cash Provided by (Used in) Financing
Activities 91,807 169,505 (338,708)
Decrease in Cash and Cash Equivalents (7,904) (1,449) (52,163)
Cash and Cash Equivalents, Beginning of Year 140,240 141,689 193,852
Cash and Cash Equivalents, End of Year $ 132,336 $ 140,240 $ 141,689
<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, 1991 $222,735 $1,032,688 $ - $ 823,683 $ (77,110) $(67,398) $ (33,667)
Net income 306,185
Cash dividends
Common stock (148,237)
Preferred stock (22,109)
Treasury stock reissued (12,083) 49,737 (351)
Purchase of treasury stock (62,933)
Exchange of common stock for
convertible preferred stock (39,771) 27,147 12,624
Exchange of common stock for
convertible debentures 12,346 5,117 73,043
Common stock issued 115,480 319,794
Translation adjustments (41,050)
Other (508) (549) 23,504
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)
Treasury stock reissued (7,607) 42,665 (5,601)
Purchase of treasury stock (89,105)
Exchange of common stock for
convertible preferred stock (33,296) 3,573 (25,289) 55,012
Common stock issued 4,645 245,227 (219,563)
Common stock split and
reduction of par value to $0.10 (1,170,969) 1,170,969
Translation adjustments (20,544)
Other (306) 318 (472) 10,254
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)
Treasury stock reissued 975 14,821
Purchase of treasury stock (55,911)
Exchange of common stock for
convertible preferred stock (9,170) 125 9,045
Common stock issued 273 80,221
Translation adjustments (20,177)
Other (10,135) (222) 576
Balance at December 31, 1994 $140,498 $ 25,308 $1,788,044 $1,351,297 $(158,881) $(41,090) $(224,848)
<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
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.
"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 $79.1 million and $77.3 million, crude oil and
refined products of $.5 million and $75.5 million and
liquid petroleum products of $54.3 million and $37.3
million at December 31, 1994 and 1993, 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.
E. Income Taxes
Enron accounts for income taxes under the provisions
of Statement of Financial Accounting Standards (SFAS) No.
109. SFAS No. 109 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 (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. These market prices 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 for any impairment quarterly and on a property-
by-property basis and any impairment in value is
recognized. Amortization of the costs of individually
significant leases begins twenty-four to thirty-six
months prior to expiration for five year and ten year
leases, respectively, if no drilling has been initiated
on the property. Unproved properties with acquisition
costs that are not individually significant are
aggregated, and the portion of such costs estimated to be
unproductive based on historical experience and future
expected abandonments 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.
Based on Enron's strategy of maximizing the economic
value of its oil and gas assets through a combination of
both developing and producing, over time, crude oil and
natural gas reserves and the sale of such reserves in
place with related assets; gains and losses associated
with such sales in place 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 it becomes
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 based on the percentage relationship of incurred
costs to total estimated costs. 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, 1994, 1993 and 1992, exclusive
of amounts discussed below, were $28 million, $65 million
and $8 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 while deferring $48 million pending the
expected 1995 expiration of certain contingent
obligations. Pursuant to a Purchase Right Agreement,
Enron has agreed to offer to sell to EPP Enron's
ownership interests in any 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. Accounting for Sales of Stock by Subsidiary Companies
Enron recognizes gains or losses on sales of stock by
its subsidiary companies when such sales are not made as
part of a larger plan of corporate reorganization. Such
gains or losses are based upon the difference between the
book value of Enron's investment in the subsidiary
immediately after the sale and the historical book value
of Enron's investment immediately prior to the sale.
During August 1992, Enron Oil & Gas Company (EOG)
completed a public offering, reducing Enron's ownership
interest from 84% to 80%. Enron recognized a gain of
$59.6 million on net proceeds totaling $111.9 million.
No income tax expense was recorded related to this
transaction, consistent with U.S. tax law.
K. Foreign Currency Translation
For subsidiaries whose functional currency is deemed
to be other than the U.S. dollar, 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. Translation adjustments
are included as a separate component of shareholders'
equity.
L. Reclassifications
Certain reclassifications have been made to the
consolidated financial statements for prior years to
conform with the current presentation.
2 Price Risk Management
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
commodities specified by the options, futures 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, futures, certain
equity investments 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 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, 1994
are set forth below (volumes in trillions of British
thermal units (TBtus), U.S. dollars in millions):
[Download Table]
Fixed Price Fixed Price Maximum
Product Payor Receiver Terms in years
Energy Commodities
Gas 3,786 3,590 20
Crude and Liquids 2,443 2,457 10
Financial Products
Interest rate(a) $4,288 $1,995 20
Foreign currency 761 694 20
<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 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 3,850
TBtus, 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 instruments may be traded in the markets
at any time in response to the company's risk management
needs.
The midpoint of ECT's entire portfolio of price risk
management activities as of December 31, 1994 and 1993
was approximately 6.7 years and 4.5 years, respectively
(based on the weighted average life of each transaction).
Fair Value. The fair value of the financial instruments
as of December 31, 1994 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
12/31/94 12/31/94(a)
Product Assets Liabilities Assets Liabilities
Energy Commodities
Gas $1,184 $428 $978 $320
Crude and Liquids 274 637 359 578
Financial Products
Interest rate 104 10 100 4
Foreign currency 46 22 28 2
<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, 1994, primarily attributable to financial
instruments fixing energy commodity pricing, was $153
million and is included in other revenues. All of ECT's
operations relate to providing price risk management
services to the energy sector. Accordingly, earnings
before unallocated expenses for this operating segment of
$350 million appropriately reflects the net gain arising
from trading activities for the year ended December 31, 1994.
Market Risk. ECT's price risk management activities
involve offering fixed or known price commitments into
the future. These transactions give rise to market risk,
which represents the potential loss that can be caused by
a change in the market value of a particular commitment.
Market risks are actively monitored by an independent
risk control group to ensure compliance with Enron's
stated risk management policies at both the corporate and
subsidiary levels. These policies, including related
risk limits, are regularly assessed to ensure their
appropriateness given the corporation's objectives,
strategies and current market conditions. It is Enron's
policy to prohibit speculation on market fluctuations.
Although ECT's objective is to maintain a balanced
portfolio, net open positions often result from the
timing of the origination of new transactions.
Accordingly, ECT closely monitors and manages its
exposure to market risk through a variety of risk
management techniques. Policies are in place which limit
the amount of total net exposure and net exposure during
any twelve month period for each commodity traded and all
traded commodities combined. Procedures exist which
allow for real time monitoring of all commitments and
positions with daily reporting of positions to senior
Enron management. Additionally, sensitivities to changes
in market prices of each commodity and exposure to
interest rate shifts are examined on a daily basis.
The market risks of ECT's financial asset and
liability positions are also assessed using value-at-risk
analysis methods. Value-at-risk represents the potential
loss exposure from adverse changes in market factors over
a specified time period, with a given confidence level.
Based on application of this risk measurement technique
utilizing a probability of 95%, ECT's value-at-risk on a
one day basis as of December 31, 1994 for its price risk
management activities was less than 2% (unaudited) of
Enron's total income before interest, minority interest
and income taxes. 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, 1994 and 1993 are summarized as follows
(amounts in millions):
[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
Other 178 58 236
Total $1,422 $186 1,608
Credit and Other Reserves (130)
Assets from Price Risk
Management Activities(b) $1,478
[Download Table]
December 31, 1993
Assets from Price Risk Management Activities
Investment Below
Grade(a) Investment Grade Total
Independent Power Producers $ 348 $ 17 $ 365
Gas and Electric Utilities 162 22 184
Oil and Gas Producers 380 39 419
Industrials 17 21 38
Financial Institutions 96 - 96
Other 128 40 168
Total $1,131 $139 1,270
Credit and Other Reserves (103)
Assets from Price Risk
Management Activities(b) $1,167
<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, 1994
and 1993 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
minimizes overall credit risk. These policies include a
thorough review 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 current exposures and the credit reserve,
Enron does not anticipate a materially adverse effect on
the financial position or results of operations as a
result of counterparty nonperformance.
Non-Trading Activities
Enron's other businesses also enter into forwards,
futures 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, 1994, Enron and
EOG had entered into interest rate swap agreements
primarily to hedge floating rate exposure with a notional
principal amount of $1.275 billion. Swap agreements
relating to notional amounts of $875 million, $325
million and $75 million are scheduled to terminate in
1995, 1996 and thereafter, respectively. Subsequent to
December 31, 1994, Enron entered into additional interest
rate swap agreements with a notional principal amount of
$1.150 billion. Such swap agreements with notional
amounts of $650 million, $350 million and $150 million
are scheduled to terminate in 1995, 1996 and 2000,
respectively.
Energy Commodity Price Swaps. At December 31, 1994,
Enron was a party to energy commodity price swaps
covering approximately 128 Bcf, 87 Bcf and 241 Bcf of
natural gas for the years 1995, 1996 and the period 1997
through 2004, respectively, and 2 million, 6 million and
3 million barrels of crude oil for the years 1995, 1996
and the period 1997 through 1999, respectively.
Foreign Currency Contracts. At December 31, 1994,
foreign currency contracts with a notional principal
amount of $32.8 million were outstanding. Such contracts
will substantially expire in 1995.
The following table summarizes the carrying amount and
estimated fair value of financial instruments held for
non-trading activities as of December 31, 1994.
[Download Table]
1994
Carrying Estimated
(In Millions) Amount Fair Value(a)
Interest rate swaps - $ 5
Energy commodity price swaps - 80
Foreign currency contracts - (1)
<FN>
(a) 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.
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.
3 Income Taxes
The principal components of Enron's net deferred
income tax liability at December 31, 1994 and 1993 are as
follows:
[Download Table]
(In Millions) 1994 1993
Deferred income tax assets -
Alternative minimum tax credit carryforward $ 236 $ 219
Other 51 18
287 237
Deferred income tax liabilities -
Depreciation, depletion and amortization 1,583 1,565
Price risk management activities 256 146
Other 406 391
2,245 2,102
Net deferred income tax liabilities* $1,958 $1,865
<FN>
*Includes $65 million and $5 million in other current
liabilities for 1994 and 1993, respectively.
The components of income before income taxes and
extraordinary items are as follows:
[Download Table]
(In Thousands) 1994 1993 1992
U.S. $415,011 $336,445 $337,618
Foreign 204,983 131,331 81,650
$619,994 $467,776 $419,268
Total income tax expense is summarized as follows:
[Download Table]
(In Thousands) 1994 1993 1992
Payable currently -
Federal $ 49,021 $ 57,093 $ 78,109
State 13,494 14,692 13,284
Foreign 11,110 12,269 13,722
73,625 84,054 105,115
Payment deferred -
Federal 77,595 (26,070) (40,361)
State (5,948) 15,724 13,375
Foreign 21,312 15,369 12,339
92,959 5,023 (14,647)
166,584 89,077 90,468
Effect of tax rate
increase on deferred
tax liability(a) - 46,177 -
Total Income Tax Expense $166,584 $135,254 $ 90,468
<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 rate are
as follows:
[Download Table]
1994 1993 1992
Statutory Federal income tax
rate provision 35.0% 35.0% 34.0%
Net state income taxes 0.8% 4.1% 4.2%
Revision of prior years' tax estimates (0.8)% (5.3)% (2.7)%
Tax rate increase - 9.9% -
Tight gas sands tax credit (5.9)% (13.9)% (10.1)%
Earnings in foreign jurisdictions taxed
at rates different from the statutory
U.S. Federal rate (0.2)% 1.0% 1.9%
Equity earnings (3.7)% (2.6)% (0.2)%
Minority interest 1.7% 2.1% 1.4%
Asset and stock sale differences - - (5.1)%
Other - (1.4)% (1.8)%
Effective Federal income tax rate 26.9% 28.9% 21.6%
Enron has an alternative minimum tax (AMT) credit
carryforward of approximately $236 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 subsidiary companies that are expected to be remitted
to the parent company. Foreign subsidiaries' cumulative
undistributed earnings of approximately $188 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) 1994 1993 1992
Income taxes $ 56,595 $ 39,307 $111,125
Interest (net of amounts
capitalized) 268,205 299,568 355,370
Non-cash investing and financing activities during
1994 and 1993 included the exchange of common stock for
convertible preferred stock in transactions valued at
$9.2 million and $33.3 million, respectively.
Non-cash investing and financing activities during
1992 included the exchange of common stock for
convertible subordinated debentures and convertible
preferred stock in transactions valued at $90.5 million
and $39.8 million, respectively, and the acquisition of
retail gas marketing operations in exchange for common
stock valued at $18.3 million.
Changes in components of working capital are as
follows:
[Download Table]
(In Thousands) 1994 1993 1992
Receivables $(250,295) $(360,206) $ 118,854
Inventories (25,117) 92,228 (22,741)
Payables (91,329) 144,518 (55,188)
Accrued taxes 12,178 (11,941) (24,690)
Accrued interest 5,277 2,913 (25,088)
Other 207,914 55,975 (148,381)
Total $(141,372) $ (76,513) $(157,234)
5 Credit Facilities, Short-Term Borrowings and Long-Term Debt
Enron and EOG have credit facilities with domestic and
foreign banks which provided for an aggregate of $1.0
billion in long-term committed credit. Expiration dates
of the committed facilities range from May 1995 to
January 1998. 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 1994, no amounts were
borrowed under these facilities.
Enron and EOG have also entered into agreements which
provide for uncommitted lines of credit totaling $1.05
billion at December 31, 1994. 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,
1994, Enron had outstanding $53.0 million under certain
of the uncommitted lines at average interest rates of
5.2%. 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, 1994, 1993 and
1992, short-term borrowings of $259.1 million, $143.8
million and $101.0 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, 1994, 1993 and 1992, $171.1 million,
$132.4 million and $292.3 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]
(Dollars In Millions) 1994 1993 1992
As of end of year
Borrowings from -
Commercial paper $ 206.1 $ - $ 75.0
Banks and other 53.0 143.8 26.0
Amount reclassified as long-term debt (259.1) (143.8) (101.0)
Total short-term borrowings $ - $ - $ -
Weighted average interest rate
at end of year(a) 6.2% 3.6% 3.7%
For the year ended
Maximum borrowings
at any month end(a) $1,156.0 $1,087.1 $ 885.5
Average borrowings(a)(b) 768.1 590.9 588.0
Weighted average interest rate
during the year(a)(c) 4.6% 3.3% 3.9%
<FN>
(a) Before reclassification as long-term debt.
(b) Computed using the ending balance at each month end.
(c) Computed using the weighted average interest rates of debt outstanding
at each month end.
Detailed information on long-term debt is as follows:
[Download Table]
December 31,
(In Thousands) 1994 1993
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 250,000 200,000
9.50% to 10.75% due from 1998 to 2001 342,777 342,777
7.625% to 9.875% due from 2003 to 2006 692,200 692,200
7% due 2023 100,000 100,000
Other 56,508 57,512
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 100,000 100,000
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 50,000
9.10% due from 1996 to 1998 70,000 100,000
Other 67,421 33,000
Amount reclassified from short-term debt 259,099 143,774
Unamortized debt discount and premium (7,863) (8,023)
Total Long-Term Debt $2,805,142 $2,661,240
The aggregate annual maturities of long-term debt
outstanding at December 31, 1994 are $171.1 million,
$283.1 million, $22.9 million, $126.2 million and $255.2
million for 1995 through 1999, respectively. In
addition, based upon available committed credit
facilities, $259.1 million of short-term debt which has
been reclassified as long-term debt would be due in 1995.
During 1992, Enron retired, pursuant to call
provisions, $836 million principal amount of long-term
debt with interest rates ranging from 8.7% to 11.5%. The
early retirement of debt resulted in extraordinary items
of $22.6 million, net of tax.
The estimated fair value of the long-term debt at
December 31, 1994 and 1993 was approximately $2.8 billion
and $2.9 billion, respectively, which is the estimated
cost to acquire the debt, including a premium or discount
for the differential between the issue rate and the year-
end market rate. The fair value of long-term debt is
based upon quoted market prices and, where such prices
are not available, upon interest rates available to
Enron.
6 Accounts Receivable
In September 1994, Enron entered into an agreement
which provides for the sale of up to $600.0 million of
trade accounts receivable with limited recourse
provisions and the rights to certain recoverable pipeline
transition surcharges expiring January 31, 1999. At
December 31, 1994, $327.7 million of receivables were
sold under this agreement. At December 31, 1993, $700.1
million of receivables were sold under similar agreements
which were replaced by the current agreement.
The fees incurred on the sales of accounts receivable
totaled $20.8 million, $20.6 million and $23.5 million
for 1994, 1993 and 1992, 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). The
natural gas and other hydrocarbons are scheduled to be
produced and delivered through March 31, 1999. 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
term of the amended agreement. Annual amortization of
remaining deferred revenue, based on scheduled deliveries
under the production payment agreement, as amended, is
approximately $43.3 million per year through 1998 and
$10.7 million for 1999. Reserves dedicated to the
transaction are included in the estimate of proved oil
and gas reserves (see Note 18).
8 Unconsolidated Subsidiaries
Enron has investments in and advances to
unconsolidated subsidiaries as follows:
[Download Table]
Ownership
Investee Interest December 31,
(In Thousands) 1994 1993
Citrus Corp. 50% $ 356,538 $169,984
Teesside Power Limited 50% 173,461 173,915
Transportadora de Gas del Sur S.A. 18% 96,451 97,450
Northern Border Partners, L.P. 13% 55,050 55,731
EOTT Energy Partners, L.P. 40% 63,044 -
Joint Energy Development
Investments L.P. 50% 77,024 4,703
Other 243,621 195,301
$1,065,189 $697,084
Enrons equity in earnings (losses) of unconsolidated
subsidiaries is as follows:
[Download Table]
Investee Year Ended December 31,
(In Thousands) 1994 1993 1992
Citrus Corp. $ 27,554 $(8,066) $(11,059)
Teesside Power Limited 12,669 12,444 -
Transportadora de Gas del Sur S.A. 22,965 20,721 -
Northern Border Pipeline Company - 22,934 34,004
Northern Border Partners, L.P. 6,970 1,368 -
EOTT Energy Partners, L.P. 4,815 - -
Joint Energy Development
Investments L.P. 7,321 - -
Other 30,115 23,892 33,600
$112,409 $73,293 $56,545
Summarized combined financial information of Enron's
unconsolidated subsidiaries is presented below:
[Download Table]
December 31,
(In Thousands) 1994 1993
Balance Sheet
Current assets $1,805,050 $ 921,850
Property, plant and equipment, net 6,072,820 5,028,673
Other noncurrent assets 1,287,790 1,356,494
Current liabilities 1,189,478 982,874
Noncurrent liabilities 5,866,276 4,584,922
Owners' equity 2,109,906 1,739,221
[Download Table]
Year Ended December 31,
(In Thousands) 1994 1993 1992
Income Statement
Operating revenues $7,102,886 $2,351,177 $1,825,158
Operating expenses 6,421,637 2,016,977 1,528,770
Net income 290,089 204,262 122,346
Distributions Paid to Enron 81,100 59,585 42,490
Citrus Corp. Enron has a 50% indirect ownership
interest in and operates 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). Enron has a 50%
ownership interest 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 Footnote 15. Transportadora de Gas del Sur
S.A. In December 1992, Enron acquired 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.
Northern Border Partners, L.P. During October 1993,
Northern Plains Natural Gas Company (Northern Plains), a
wholly-owned subsidiary of Enron, along with two of the
other three general partners in Northern Border Pipeline
Company contributed all of their combined 70% interest in
Northern Border 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 for net proceeds of approximately $217
million resulting in a pretax gain of approximately $64
million. Northern Plains retains 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. (the EOTT
Partnership) 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 40% ownership of the EOTT Partnership
through its seven million subordinated units and general
partnership interest.
Joint Energy Development Investments (JEDI). An Enron
subsidiary and the California Public Employee Retirement
System (CalPERS) each own a 50% interest in JEDI, a
limited partnership which acquires and owns energy
investments. The Enron subsidiary, as general partner,
and CalPERS as limited partner, have each committed to
invest $250 million of capital in JEDI through 1996, $70
million of which has already been contributed by Enron as
of December 31, 1994. Enron intends to meet its required
capital commitments by contributing Enron common stock.
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 1994 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 1994, 1993 and 1992, 91,694 shares,
332,964 shares and 397,710 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).
Preferred Stock of Subsidiary Company. 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 Preferred Stock is redeemable at
Enron's option after December 1999 at a price of $100,000
per share plus accumulated and unpaid dividends.
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
On July 28, 1993, Enron increased the number of
authorized shares of common stock from 300,000,000 to
600,000,000 shares and decreased the par value of such
common stock from $10.00 to $0.10 per share. The reduced
par value of $9.90 for each share outstanding, or $1.18
billion, was transferred to additional paid-in capital.
On August 16, 1993, Enron effected, in the form of a
stock dividend, a two-for-one common stock split on all
issued common stock. The par value of $11.9 million for
119,486,623 additional shares was transferred from
additional paid-in capital to common stock. Appropriate
references in the financial statements and supplemental
financial information to number of shares and related
prices, per share amounts and stock option information
reflect the stock split.
Enron paid quarterly cash dividends on common stock of
$.1625 per share ($.65 per share annually) until the
final quarter of 1992. The dividend was increased to
$.175 per share ($.70 per share annually) for the final
quarter of 1992 and was increased to $.1875 per share
($.75 per share annually) for the final quarter of 1993.
The dividend was further increased to $.20 per share
($.80 per share annually) for the final quarter of 1994.
Enron's debt agreements do not limit the payment of cash
dividends on common stock. Common stock information is as
follows:
[Download Table]
(In Thousands) 1994 1993(a) 1992
Common Stock, beginning of year 249,095 237,532 103,269
Issued to Employee Benefit Plans 1,239 1,394 11,149
Conversions 1,252 2,447 3,949
Dividend reinvestment 64 66 -
Flexible Equity Trust - 7,500 -
Other 1,420 156 399
Common Stock, end of year 253,070 249,095 118,766
<FN>
(a) Presented as if the 1993 stock split was January 1, 1993.
Treasury stock information is as follows:
[Download Table]
1994 1993(d) 1992
Treasury Stock, beginning of year - 349,400 2,050,644
Employee Benefit Plans
Issued (47,790) (1,435,687) (1,314,196)
Returned - 98,381 15,021
Open Market Purchases(a) 1,897,923 3,005,200 1,610,100
Conversions(b) - (2,043,090) (2,205,393)
Dividend Reinvestment Plan - (43,608) -
Other(c) (455,300) 69,404 18,524
Treasury Stock, end of year 1,394,833 - 174,700
<FN>
(a) Purchased in connection with a stock repurchase program authorized
by the Board of Directors.
(b) Conversions of convertible subordinated debentures in 1992 and
convertible preferred stock in 1993.
(c) The 1994 amount represents shares sold to Joint Energy Developments
Investments. The 1993 and 1992 amounts were purchased pursuant to
compensation agreements.
(d) Presented as if the 1993 stock split was January 1, 1993.
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. Expiration dates of the options outstanding at
December 31, 1994 range from July 8, 1995 to December 30,
2004. 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]
1994 1993 1992
Shares under option,
beginning of year 9,679,719 7,314,332 8,996,560
Granted(a) 15,805,680 4,253,233 1,409,480
Exercised (1,019,090) (1,621,680) (2,807,984)
Cancelled or expired (220,862) (266,166) (283,724)
Shares under option, end of year 24,245,447 9,679,719 7,314,332
Shares available for grant at
end of year(b) 4,006,833 1,500,301 5,582,480
Shares exercisable at end of year 7,183,664 3,104,722 2,199,224
Average price of options exercised
during the year $13.50 $13.30 $11.82
Average price of options outstanding
at end of year $27.38 $19.64 $13.47
<FN>
(a) Includes options granted on December 30, 1994 for 9,717,750 shares
under employee stock option grants for the years 1995 through 2000.
(b) Excludes up to 5,245,100 shares, 2,528,560 shares and 2,730,780
shares as of December 31, 1994, 1993 and 1992, respectively, which
may be issued as either Restricted Stock or as 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]
1994 1993 1992
Outstanding at beginning of year 221,658 35,588 365,088
Granted 30,190 203,700 19,220
Cancelled or expired (2,040) (3,632) -
Issued (56,303) (13,998) (348,720)
Outstanding at end of year 193,505 221,658 35,588
Available for grant at end of year 5,245,100 2,528,560 2,730,780
Average price per share
on date of grant $32.89 $27.50 $11.18
Flexible Equity Trust (the Trust). In December 1993,
Enron established the Trust to fund a portion of its
obligations arising from its various employee
compensation and benefit plans. Enron issued 7.5 million
shares of common stock to the Trust in exchange for cash
and an interest bearing promissory note. The note held
by Enron is reflected as a reduction of shareholders'
equity. Common shares held by the Trust are not included
in the computation of earnings per share until such
shares are released to fund employee benefits. No such
shares were released at December 31, 1994.
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 are entitled to retirement benefits
based on a formula that uses a percentage of final
average pay and years of service.
In connection with a contemplated change to the
retirement benefit formula, Enron amended the Enron Plan
providing, among other things, that all employees become
fully vested in retirement benefits earned through
December 31, 1994. The contemplated change to the benefit
formula is not expected to have a material effect on
Enron's projected benefit obligation.
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. To the extent
allocations to the individual employees retirement
account within the ESOP exceed accrued benefits under
the Enron Plan at the date of retirement, the individual
employees receive the additional shares.
The components of pension expense are as follows:
[Download Table]
(In Thousands) 1994 1993 1992
Service cost - benefits earned
during the year $ 16,192 $ 11,709 $ 10,224
Interest cost on projected
benefit obligation 25,996 25,230 22,699
Actual return on plan assets (22,235) (37,507) (52,141)
Amortization and deferrals (12,225) 11,184 28,897
Early retirement termination benefits - - 166
Pension expense $ 7,728 $ 10,616 $ 9,845
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. Assets of the ESOP offset
retirement benefits accrued under the Enron Plan only to
the extent allocated to individual employee retirement
accounts.
[Download Table]
(In Thousands) 1994 1993
Actuarial present value of accumulated
benefit obligation
Vested $(253,881) $(284,559)
Nonvested (25,546) (27,862)
Additional amounts related
to projected wage increases (54,260) (66,641)
Projected benefit obligation (333,687) (379,062)
Plan assets at fair value(a) 352,608 404,397
Plan assets in excess of projected
benefit obligation 18,921 25,335
Unrecognized net loss 35,563 29,690
Unrecognized prior service cost 12,416 14,113
Unrecognized net asset at transition (42,238) (48,272)
Contributions 548 815
Prepaid pension cost at December 31 $ 25,210 $ 21,681
Discount rate 8.00% 7.00%
Long-term rate of return on assets 10.50 10.50
Rate of increase in wages 4.00 4.00
<FN>
(a) Includes plan assets of the ESOP of $235,540 and $286,041 for the
years 1994 and 1993, 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 minimum amount required by
Federal tax regulations.
12 Benefits Other Than Pensions
Enron provides certain medical, life insurance and
dental benefits to eligible employees who retire under
the Enron Retirement Plan and their eligible surviving
spouses. Benefits are provided under the provisions of a
contributory defined dollar benefit plan. 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) 1994 1993
Actuarial present value of accumulated
postretirement benefit obligation (APBO)
Retirees $ (88,838) $ (93,101)
Fully eligible active plan participants (2,164) (2,748)
Other employees (15,712) (21,611)
Total APBO (106,714) (117,460)
Plan assets at fair value 3,073 1,938
APBO in excess of plan assets (103,641) (115,522)
Unrecognized transition obligation 74,803 79,547
Unrecognized prior service costs 18,148 19,297
Unrecognized net loss 5,148 14,249
Accrued postretirement benefit obligation $ (5,542) $ (2,429)
The components of net periodic postretirement benefit
expenses are as follows:
[Download Table]
(In Thousands) 1994 1993
Service costs $ 1,527 $ 850
Interest costs 7,964 7,374
Return on plan assets (106) (39)
Amortization of transition obligation 6,003 4,744
Postretirement benefit expense $15,388 $12,929
The measurement of the APBO assumes an 8% discount
rate and a health care cost trend rate of 12.3% in 1994
decreasing to 5% by the year 2006 and beyond. 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 $7.9 million and $0.8 million,
respectively.
Effective January 1, 1994, Enron adopted the
provisions of SFAS 112 - "Employers' Accounting for
Postemployment Benefits." The effects of adopting SFAS
112 were not material.
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, 1994 are
approximately $305 million, which include transition
costs incurred related to FERC Order 636 of approximately
$158 million. Such regulatory assets are scheduled to be
recovered from customers over varying time periods,
generally up to five years.
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. 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
TransAmerican Natural Gas Corporation (TransAmerican)
has filed a suit 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 seeks actual damages of $100
million and exemplary damages of $300 million. EOG has
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. As to EOG, the
trial date, which was most recently set for September 12,
1994, has been continued and there is no current setting.
Although no assurances can be given, Enron believes that
TransAmerican's claims are without merit. Enron believes
that the ultimate resolution of this matter will not have
a materially adverse effect on its financial position or
results of operations.
A pipeline company in which an Enron affiliate has a
minority interest and for which an Enron affiliate has
served as operator, has filed a petition against Enron
and certain affiliates alleging an unspecified amount of
damages relating to the operation of such pipeline
company. Based upon information currently available, it
is not possible to predict the outcome of such
litigation; however, Enron believes that the results will
not have a materially adverse effect on Enron's 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
During October 1994, an explosion occurred at Enron's
methanol plant in Pasadena, Texas. The plant produces
approximately 420,000 gallons of methanol per day,
approximately half of which is used at Enron's MTBE
plant. Enron is currently investigating the explosion to
determine the full extent of any damages; however, based
upon business interruption and casualty insurance
coverages, Enron currently anticipates that the explosion
will not have a material adverse effect on its financial
position or results of operations.
15 Commitments
Firm Transportation Obligations
Enron has firm transportation agreements with various
joint venture pipelines. Under these agreements, Enron
must make specified minimum payments each month. The
estimated aggregate amounts of such required future
payments at December 31, 1994, were:
[Download Table]
(In Millions)
1995 $ 32.0
1996 109.3
1997 114.4
1998 113.7
1999 107.1
Later years 1,094.9
Total $1,571.4
The costs incurred under these agreements, including
commodity charges on actual quantities shipped, totaled
$20.8 million, $42.4 million and $45.1 million in 1994,
1993 and 1992, 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 $43.6 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 $1.03
billion at December 31, 1994.
During November 1994, Enron modified its prior
agreement for a substantial amount of data processing
facilities management services. The modification reduces
the aggregate and required annual minimum services to be
purchased by Enron. Enron prepaid $150 million in 1992
and $40 million in early 1995 for certain services to be
performed under the terms of the agreement.
Future commitments related to these items at December
31, 1994 are as follows:
[Download Table]
(In Millions)
1995 $159.6
1996 138.5
1997 60.3
1998 53.4
1999 39.4
Later years 423.4
Total minimum payments $874.6
Total rent expense incurred during 1994, 1993 and 1992
was $125.6 million, $103.7 million and $64.7 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, 1994, a
total of $118.6 million of such guarantees were
outstanding. In addition, Enron is a guarantor on
certain debt of unconsolidated joint ventures and
unconsolidated subsidiaries and other companies totaling
approximately $267.9 million. The fair value of
guarantees at December 31, 1994 and 1993, based upon
Enron's estimation of the cost of securing third party
letters of credit equal to Enron's obligations under such
guarantees, was $2.4 million and $2.7 million,
respectively. Management does not consider it likely
that they would be required to perform or otherwise incur
any losses associated with these guarantees. In addition,
certain commitments have been made related to 1995
planned capital expenditures.
16 Other Income, Net
The components of Other Income, Net are as follows:
[Download Table]
Year Ended December 31,
(In Thousands) 1994 1993 1992
Gains on sales of Mobil stock $ - $ - $ 52,048
Gains on sales of stock by
subsidiary company - - 59,615
Gains on sales of other
assets and investments 37,270 102,268 18,549
Regulatory, contingency
and other adjustments 17,700 (55,689) (40,927)
Foreign currency gains 8,188 - -
Litigation adjustments and
settlements, net (1,110) 4,282 (41,870)
Other 15,001 11,254 (10,210)
$77,049 $62,115 $ 37,205
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 and power. Price risk management in connection
with natural gas, natural gas liquids 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
natural gas fired power plants, natural gas liquids
facilities and pipelines outside of North America.
International marketing of natural gas liquids.
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, 1994, follows.
Geographic Segments
[Download Table]
Year Ended December 31,
(In Thousands) 1994 1993 1992
Operating Revenues from
Unaffiliated Customers
United States $ 7,604,127 $ 7,071,406 $5,521,637
Foreign 1,379,596 914,394 893,673
$ 8,983,723 $ 7,985,800 $6,415,310
Intersegment Sales
United States $ 48,369 $ 20,785 $ 54,498
Foreign 116,257 66,574 24,108
$ 164,626 $ 87,359 $ 78,606
Operating Income
United States $ 609,008 $ 567,274 $ 634,579
Foreign 106,764 63,528 (14,770)
$ 715,772 $ 630,802 $ 619,809
Income Before Interest, Minority
Interest and Income Taxes
United States $ 755,686 $ 663,276 $ 743,623
Foreign 188,706 134,391 23,559
$ 944,392 $ 797,667 $ 767,182
Identifiable Assets
United States $10,662,282 $ 9,939,618 $8,982,307
Foreign 1,303,729 867,613 693,234
$11,966,011 $10,807,231 $9,675,541
Operations In Business and Geographic Segments
Business Segments
[Enlarge/Download Table]
International
Transportation Domestic Gas Gas and Exploration Corporate
and and Power Power and and
(In Thousands) Operation Services Services Production Other(c)(d) Total
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
1992
Unaffiliated Revenues(a) $1,418,761 $3,872,068 $864,695 $ 259,786 $ - $ 6,415,310
Intersegment Revenues(b) 82,513 90,217 10,529 300,375 (483,634) -
Total Revenues 1,501,274 3,962,285 875,224 560,161 (483,634) 6,415,310
Depreciation, Depletion and
Amortization 111,141 76,721 6,897 179,839 1,421 376,019
Operating Income (Loss) 314,412 214,299 (4,502) 105,609 (10,009) 619,809
Equity in Earnings of
Unconsolidated Subsidiaries 36,628 14,317 5,505 - 95 56,545
Other Income, net 27,267 (26,223) 32,074 (3,476) 61,186 90,828
Income Before Interest, Minority
Interest and Income Taxes 378,307 202,393 33,077 102,133 51,272 767,182
Additions to Property, Plant
and Equipment 144,468 67,795 10,236 362,403 11,983 596,885
Identifiable Assets 2,420,053 4,308,588 388,248 1,563,136 995,516 9,675,541
Investments in and Advances to
Unconsolidated Subsidiaries 479,246 75,483 79,991 - 1,342 636,062
Total Assets $2,899,299 $4,384,071 $468,239 $1,563,136 $ 996,858 $10,311,603
<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.
Capitalized Costs Relating to Oil and Gas Producing Activities
[Download Table]
December 31,
(In Thousands) 1994 1993
Proved properties $ 2,889,242 $ 2,675,419
Unproved properties 126,193 96,801
Total 3,015,435 2,772,220
Accumulated depreciation,
depletion and amortization (1,330,624) (1,226,175)
Net capitalized costs $ 1,684,811 $ 1,546,045
Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities(a)
[Enlarge/Download Table]
Foreign
(In Thousands) United States Canada Trinidad India Other Total
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
1992
Acquisition of properties
Unproved $ 21,844 $ 1,173 $ - $ - $ 3 $ 23,020
Proved 25,958 39,281 - - - 65,239
Total 47,802 40,454 - - 3 88,259
Exploration 38,547 5,787 151 - 10,990 55,475
Development 256,814 5,162 735 - - 262,711
Total $343,163 $51,403 $ 886 $ - $10,993 $406,445
<FN>
(a) Costs have been categorized on the basis of Financial Accounting
Standards Board definitions which include costs of oil and gas
producing activities whether capitalized or charged to expense as
incurred.
Results of Operations for Oil and Gas Producing Activities(a)
The following tables set forth results of operations for oil
and gas producing activities for the three years in the
period ended December 31, 1994:
[Enlarge/Download Table]
Foreign
(In Thousands) United States Canada Trinidad India Other Total
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
1992
Operating revenues
Associated companies $251,649 $10,074 $ - $ - $ - $261,723
Trade 106,633 19,313 - - - 125,946
Gains on sales of reserves
and related assets 6,037 - - - - 6,037
Total 364,319 29,387 - - - 393,706
Exploration expenses,
including dry hole costs 29,705 3,829 151 - 10,357 44,042
Production costs 63,571 9,271 - - - 72,842
Impairment of unproved
oil and gas properties 12,001 1,034 - - 2,101 15,136
Depreciation, depletion
and amortization 167,767 11,719 - - 327 179,813
Income (loss) before
income taxes 91,275 3,534 (151) - (12,785) 81,873
Income tax expense (benefit) (13,977) 1,202 (75) - (4,323) (17,173)
Results of Operations $105,252 $ 2,332 $ (76) $ - $ (8,462) $ 99,046
<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, 1994. 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, 1994, 1993 and 1992 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, 1994, 1993
and 1992 covering producing areas, in the United States
and Canada, containing 59%, 65% and 69%, 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.
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves(a)
[Enlarge/Download Table]
(In Thousands) United States Canada Trinidad India Total
1994
Future revenues(b) $2,411,087(d) $487,050 $317,758 $ 168,370 $3,384,265(d)
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 1,668,387 281,179 228,498 58,030 2,236,094
Discount to present value at
10% annual rate (617,960) (106,353) (54,380) (29,460) (808,153)
Present value of future net
cash flows before income taxes 1,050,427 174,826 174,118 28,570 1,427,941
Future income taxes discounted
at 10% annual rate(c) (27,353) (17,885) (70,688) (7,752) (123,678)
Standardized measure of
discounted future net cash
flows relating to proved oil
and gas reserves(b) $1,023,074(e) $156,941 $103,430 $ 20,818 $1,304,263
1993
Future revenues(b) $3,343,900(d) $592,845 $147,542 $ - $4,084,287(d)
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 2,538,667 341,614 94,575 - 2,974,856
Discount to present value at
10% annual rate (951,748) (143,992) (20,097) - (1,115,837)
Present value of future net
cash flows before income taxes 1,586,919 197,622 74,478 - 1,859,019
Future income taxes discounted
at 10% annual rate(c) (219,228) (37,851) (24,899) - (281,978)
Standardized measure of
discounted future net cash
flows relating to proved oil
and gas reserves(b) $1,367,691(e) $159,771 $ 49,579 $ - $1,577,041(e)
1992
Future revenues(b) $3,017,188(d) $363,284 $ - $ - $3,380,472(d)
Future production costs (573,763) (105,802) - - (679,565)
Future development costs (194,246) (12,881) - - (207,127)
Future net cash flows before
income taxes 2,249,179 244,601 - - 2,493,780
Discount to present value at
10% annual rate (790,027) (91,126) - - (881,153)
Present value of future net
cash flows before income taxes 1,459,152 153,475 - - 1,612,627
Future income taxes discounted
at 10% annual rate(c) (147,736) (28,056) - - (175,792)
Standardized measure of
discounted future net cash
flows relating to proved oil
and gas reserves(b) $1,311,416(e) $125,419 $ - $ - $1,436,835(e)
<FN>
(a) Includes amounts attributable to a 20% minority interest at December 31,
1994, 1993 and 1992.
(b) Based on year-end market prices determined at the point of delivery
from the producing unit.
(c) Future income taxes before discount were $230.0 million U.S., $55.8
million Canada, $102.1 million Trinidad and $22.5 million India, $540.3
million U.S., $91.7 million Canada and $35.5 million Trinidad, $394.1
million U.S. and $63.0 million Canada for the years ended December 31,
1994, 1993 and 1992, respectively.
(d) "Future revenues" includes approximately $95.9 million ($77.9 million
discounted at 10% annual rate for 1994), $189.1 million ($146.9 million
discounted at 10% annual rate for 1993) and $203.5 million ($174.5
million discounted at 10% annual rate for 1992) related to volumes
associated with a volumetric production payment sold effective October 1,
1992, as amended, to be delivered over a seventy-eight month period
which period commenced October 1, 1992 (see Note 7).
(e) Includes approximately $49.3 million in 1994, $92.6 million in 1993
and $111.2 million in 1992 representing the discounted present value
at a discount rate of 10% of the "future revenues" detailed in
Note (d) after deducting future income taxes.
Changes in Standardized Measure of Discounted Future Net
Cash Flows
[Enlarge/Download Table]
(In Thousands) United States Canada Trinidad India Total
December 31, 1991 $1,061,821 $ 94,256 $ - $ - $1,156,077
Sales and transfers of oil
and gas produced, net of
production costs (294,711) (20,116) - - (314,827)
Net changes in prices and
production costs 257,572 8,190 - - 265,762
Extensions, discoveries,
additions and improved
recovery, net of related
costs 275,231 8,999 - - 284,230
Development costs incurred 49,668 177 - - 49,845
Revisions of estimated
development costs (19,540) 1,406 - - (18,134)
Revisions of previous
quantity estimates (45,863) (7,539) - - (53,402)
Accretion of discount 118,901 12,224 - - 131,125
Net change in income taxes (20,548) (77) - - (20,625)
Purchases of reserves in place 28,884 32,533 - - 61,417
Sales of reserves in place (34,984) (15) - - (34,999)
Changes in timing and other (65,015) (4,619) - - (69,634)
December 31, 1992 $1,311,416 $125,419 $ - $ - $1,436,835
Sales and transfers of oil
and gas produced, net of
production costs (434,609) (28,802) 287 - (463,124)
Net changes in prices and
production costs 180,240 28,400 - - 208,640
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 145,915 15,348 - - 161,263
Net change in income taxes (71,492) (9,795) (24,899) - (106,186)
Purchases of reserves in place 9,462 2,707 - - 12,169
Sales of reserves in place (38,498) (1,140) - - (39,638)
Changes in timing and other (75,043) (18,374) - - (93,417)
December 31, 1993 $1,367,691 $159,771 $ 49,579 $ - $1,577,041
Sales and transfers of oil
and gas produced, net of
production costs (362,243) (37,693) (30,825) (483) (431,244)
Net changes in prices and
production costs (566,358) (65,287) 11,002 - (620,643)
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 158,692 19,762 7,448 - 185,902
Net change in income taxes 191,875 19,966 (45,789) (7,752) 158,300
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 $1,023,074 $156,941 $103,430 $20,818 $1,304,263
Reserve Quantity Information
Enrons 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:
[Download Table]
United States Canada Trinidad India Total
Proved developed reserves
Natural gas (Bcf)
December 31, 1991 1,138.5 113.0 - - 1,251.5
December 31, 1992 1,168.4(b) 194.4 - - 1,362.8
December 31, 1993 1,167.3(b) 250.6 71.4 - 1,489.3
December 31, 1994 1,199.1(b) 288.3 206.2 - 1,693.6
Liquids (MBbl)(c)
December 31, 1991 13,002 6,484 - - 19,486
December 31, 1992 12,762(b) 5,329 - - 18,091
December 31, 1993 11,165(b) 5,409 1,591 - 18,165
December 31, 1994 16,770(b) 7,073 4,429 7,585 35,857
[Enlarge/Download Table]
United States Canada Trinidad India Total
Natural gas (Bcf)
Proved reserves at
December 31, 1991(a) 1,455.9 128.9 - - 1,584.8
Revisions of previous estimates (46.3) (4.1) - - (50.4)
Purchases in place 30.5 112.6 - - 143.1
Extensions, discoveries and
other additions 228.0 6.3 - - 234.3
Sales in place (27.7) - - - (27.7)
Production (200.0) (11.2) - - (211.2)
Proved reserves at
December 31, 1992(a) 1,440.4(b) 232.5 - - 1,672.9
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 (12.5) (1.5) - - (14.0)
Production (240.0) (21.3) (0.8) - (262.1)
Proved reserves at
December 31, 1993(a) 1,400.7(b) 271.0 100.5 - 1,772.2
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 (228.6) (26.3) (23.2) - (278.1)
Proved reserves at
December 31, 1994(a) 1,378.3 296.6 206.2 29.3 1,910.4
Liquids (MBbl)(c)
Proved reserves at
December 31, 1991(a) 13,822 6,512 - - 20,334
Revisions of previous estimates 365 (885) - - (520)
Purchases in place 65 - - - 65
Extensions, discoveries and
other additions 2,320 698 - - 3,018
Sales in place (296) (4) - - (300)
Production (2,411) (963) - - (3,374)
Proved reserves at
December 31, 1992(a) 13,865(b) 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)
Proved reserves at
December 31, 1993(a) 13,172(b) 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)
Proved reserves at
December 31, 1994(a) 17,787 7,237 4,429 7,585 37,038
<FN>
(a) Includes reserves attributable to a 20% minority interest at
December 31, 1994, 1993 and 1992 and a 16% minority interest
at December 31, 1991.
(b) Includes approximately 71 billion cubic feet equivalent (78 trillion
British thermal units) in 1994, 87 billion cubic feet equivalent
(96 trillion British thermal units) in 1993 and 114 billion cubic feet
equivalent (126 trillion British thermal units) in 1992 associated with
a volumetric production payment sold effective October 1, 1992, as
amended, to be delivered over a seventy-eight month period which period
commenced October 1, 1992 (see Note 7).
(c) Includes crude oil, condensate and natural gas liquids.
Enron Corp. and Subsidiaries
Supplemental Financial Information (UNAUDITED)
Quarterly Results
[Enlarge/Download Table]
Fully
Income Before Primary Earnings Diluted Earnings
Interest, Minority Per Share(a) Per Share(a)
(In Thousands, Operating Gross Interest and Net Net
Except Per Share Amounts) Revenues(b) Profit Income Taxes Net Income Income Income
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
1993
First Quarter $1,857,469 $601,008 $268,249 $146,228 $.60 $.55
Second Quarter 1,907,108 530,381 151,673 61,245 .24 .23
Third Quarter 1,945,215 661,212 168,834 20,995 .07 .07
Fourth Quarter 2,276,008 627,173 208,911 104,054 .42 .39
<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.
(b) Reclassified, see Note 1.
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
included in this Form 10-K, and have issued our report
thereon dated February 17, 1995. Our audits were made for
the purpose of forming an opinion on the basic financial
statements taken as a whole. The schedule listed in Item
14(a)2 is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part
of the basic financial statements. This schedule has been
subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly
states in all material respects the financial data required
to be set forth therein in relation to the basic financial
statements taken as a whole.
ARTHUR ANDERSEN LLP
Houston, Texas
February 17, 1995
[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
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 $ -
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
1992
Reserves deducted from
assets to which they apply
Allowance for doubtful
accounts $ 15,386 $ 4,577 $ 9,228 $14,636 $ 14,555
Assets from price risk
management activities $ 32,224 $49,270 $ - $ 7,386 $ 74,108
Reserve for regulatory issues
Current $ 6,105 $ 6,939 $ 8,161 $12,406 $ 8,799
Noncurrent $ 12,568 $ - $ - $ 8,891 $ 3,677
<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, 1995.
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 29,
1995 by the following persons on behalf of the Registrant
and in the capacities indicated.
Signature Title
KENNETH L. LAY Chairman of the Board, Chief
(Kenneth L. Lay) Executive Officer and
Director (Principal
Executive Officer)
JACK I. TOMPKINS Senior Vice President and
(Jack I. Tompkins) Chief Information,
Administrative and
Accounting Officer
(Principal Accounting
Officer)
KURT S. HUNEKE Vice President, Finance and
(Kurt S. Huneke) Treasurer (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
(Richard D. Kinder) Chief 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.
*3.02 - Bylaws of Enron Corp. as currently in effect
(Exhibit 3.02 to Enron Form 10-K for 1990, File
No. 1-3423).
*4.01 - Indenture dated as of November 1, 1985, between
Enron and Harris Trust and Savings Bank (Form T-3
Application for Qualification of Indentures under
the Trust Indenture Act of 1939, File No. 22-
14390, filed October 24, 1985). 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 10.59
*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 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to
Registration Statement No. 33-27893).
*10.04 - Enron Corp. 1986 Stock Option Plan with Stock
Appreciation Rights (Exhibit 4.3 to Registration
Statement No. 33-13498).
*10.05 - Executive Incentive Plan (Exhibit 10.13 to Enron
Form 10-K for 1987, File No. 1-3423).
*10.06 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to
Enron Form 10-K for 1987, File No. 1-3423).
*10.07 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to
Enron Form 10-K for 1991, File No. 1-3423).
*10.08 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to
Enron Form 10-K for 1991, File No. 1-3423).
*10.09 - Enron Corp. Directors' Deferred Income Plan
(Exhibit 10.09 to Enron Form 10-K for 1992, File
No. 1-3423).
*10.10 - 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).
*10.11 - 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).
*10.12 - 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).
*10.13 - 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).
*10.14 - 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).
*10.15 - 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).
10.16 - Sixth Amendment to Employment Agreement between
Enron and Kenneth L. Lay, dated April 27, 1994.
10.17 - Split Dollar Life Insurance Agreement between
Enron and the KLL and LPL Family Partnership,
Ltd., dated April 22, 1994.
*10.18 - 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).
*10.19 - 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).
*10.20 - 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).
*10.21 - 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).
*10.22 - 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).
*10.23 - 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).
*10.24 - 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).
10.25 - Seventh Amendment to Employment Agreement between
Enron and Richard D. Kinder, dated November 30,
1994.
*10.26 - 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).
10.27 - First Amendment to Employment Agreement between
Enron International Inc. and Rodney L. Gray, dated
May 2, 1994.
*10.28 - Employment Agreement between Enron and Ronald J.
Burns dated as of July 1, 1989 (Exhibit 10.15 to
Enron Form 10-K for 1989, File No. 1-3423).
*10.29 - First Amendment to Employment Agreement between
Enron and Ronald J. Burns dated June 21, 1990
(Exhibit 10.20 to Enron Form 10-K for 1991, File
No. 1-3423).
*10.30 - Second Amendment to Employment Agreement between
Enron and Ronald J. Burns dated August 19, 1991
(Exhibit 10.21 to Enron Form 10-K for 1991, File
No. 1-3423).
10.31 - Third Amendment to Employment Agreement between
Enron and Ronald J. Burns, dated May 2, 1994.
*10.32 - Employment Agreement between Enron and Jack I.
Tompkins dated October 1, 1991 (Exhibit 10.22 to
Enron Form 10-K for 1991, File No. 1-3423).
10.33 - First Amendment to Employment Agreement between
Enron and Jack I. Tompkins, dated May 2, 1994.
*10.34 - 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).
*10.35 - 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).
*10.36 - 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).
*10.37 - 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).
*10.38 - 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).
10.39 - Second Amendment to Employment Agreement between
Enron and Edmund P. Segner, III, dated May 2,
1994.
*10.40 - Employment Agreement between Enron and Jeffrey K.
Skilling, effective August 1, 1990 (Exhibit 10.18
to Enron Form 10-K for 1990, File No. 1-3423).
*10.41 - First Amendment to Employment Agreement between
Enron and Jeffrey K. Skilling, dated August 1,
1990 (Exhibit 10.30 to Enron Form 10-K for 1992,
File No. 1-3423).
*10.42 - Second Amendment to Employment Agreement between
Enron and Jeffrey K. Skilling, dated June 1, 1991
(Exhibit 10.31 to Enron Form 10-K for 1992, File
No. 1-3423).
*10.43 - Third Amendment to Employment Agreement between
Enron and Jeffrey K. Skilling, dated February 10,
1992 (Exhibit 10.32 to Enron Form 10-K for 1992,
File No. 1-3423).
*10.44 - Loan Commitment Agreement between Enron and
Jeffrey K. Skilling, dated April 13, 1992 (Exhibit
10.33 to Enron Form 10-K for 1992, File No. 1-
3423).
*10.45 - Fourth Amendment to Employment Agreement between
Enron and Jeffrey K. Skilling, dated June 23, 1992
(Exhibit 10.34 to Enron Form 10-K for 1992, File
No. 1-3423).
*10.46 - Fifth Amendment to Employment Agreement between
Enron and Jeffrey K. Skilling, dated December 18,
1992 (Exhibit 10.35 to Enron Form 10-K for 1992,
File No. 1-3423).
*10.47 - Buyout Agreement between Enron and Jeffrey K.
Skilling, dated December 18, 1992 (Exhibit 10.36
to Enron Form 10-K for 1992, File No. 1-3423).
*10.48 - First Amendment to Buyout Agreement between Enron
and Jeffrey K. Skilling, dated December 23, 1992
(Exhibit 10.37 to Enron Form 10-K for 1992, File
No. 1-3423).
*10.49 - Loan Agreement between Enron and Jeffrey K.
Skilling, dated January 1, 1993 (Exhibit 10.38 to
Enron Form 10-K for 1992, File No. 1-3423).
*10.50 - Employment Agreement among Enron Corp., Enron
Power Corp., and Thomas E. White, dated December
9, 1992 (Exhibit 10.39 to Enron Form 10-K for
1992, File No. 1-3423).
10.51 - Second Amendment to Employment Agreement between
Enron Corp., Enron Power Corp., and Tom White,
dated May 2, 1994.
*10.52 - 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).
10.53 - First Amendment to Employment Agreement between
Enron and James V. Derrick, Jr., dated May 2,
1994.
*10.54 - Enron Gas Services Group Phantom Equity Plan
(Exhibit 10.26 to Enron Form 10-K for 1991, File
No. 1-3423).
*10.55 - Enron Power Corp. Executive Compensation Plan
(Exhibit 10.42 to Enron Form 10-K for 1992, File
No. 1-3423).
*10.56 - Enron Corp. Performance Unit Plan (Exhibit A to
Enron Proxy Statement filed pursuant to Section
14(a) on March 25, 1994).
*10.57 - Enron Corp. Annual Incentive Plan (Exhibit B to
Enron Proxy Statement filed pursuant to Section
14(a) on March 25, 1994).
*10.58 - 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).
10.59 - Form of 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 13, 1995.
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.
Dates Referenced Herein and Documents Incorporated by Reference
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