UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report: March 1, 1994
Commission File Number 1-3423
ENRON CORP.
(Exact name of registrant as specified in its charter)
Delaware 47-0255140
(State or other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) Number)
Enron Building
1400 Smith Street
Houston, Texas 77002
(Address of principal executive (Zip Code)
Offices)
(713) 853-6161
(Registrant's telephone number, including area code)
<PAGE>
ENRON CORP. AND SUBSIDIARIES
Item 7. Financial Statements and Exhibits.
(a) Financial Statements of Enron Corp.
Financial Statements of Enron Corp. and its
Consolidated Subsidiaries for the fiscal year ended
December 31, 1993, including Report of Arthur
Andersen & Co., Independent Public Accountants.
(b) Exhibits.
11 Calculation of Earnings Per Share
23 Consent of Arthur Andersen & Co.
SIGNATURES
Pursuant to the requirements of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to
be signed on its behalf by the undersigned hereunto duly
authorized.
ENRON CORP.
Date: March 1, 1994 By: Jack I. Tompkins
Jack I. Tompkins
Senior Vice President and Chief
Information, Administrative and
Accounting Officer
<PAGE>
ENRON CORP. AND SUBSIDIARIES
TABLE OF CONTENTS
Page No.
Management's Discussion and Analysis 4
Report of Independent Public Accountants 13
Consolidated Statement of Income for the years ended
December 31, 1993, 1992 and 1991 14
Consolidated Balance Sheet, December 31, 1993 and 1992 15
Consolidated Statement of Cash Flows for the years
ended December 31, 1993, 1992 and 1991 17
Consolidated Statement of Changes in Shareholders'
Equity Accounts for the years ended December 31,
1993, 1992 and 1991 18
Notes to Consolidated Financial Statements 19
Supplemental Financial Information 36
Exhibits
Exhibit 11 - Calculation of Earnings Per Share 37
Exhibit 23 - Consent of Arthur Andersen & Co. 38
<PAGE>
Enron Corp. and Subsidiaries
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 subsidiaries (Enron)
should be read in conjunction with the Consolidated
Financial Statements.
Results of Operations
Consolidated Net Income
Enron's net income for 1993 was $387 million, 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%, compared
to $306 million and $232 million for 1992 and 1991,
respectively. Net income for all three years reflects
improved income before interest, minority interest and
income taxes as compared to the applicable preceding year.
Net income for 1993 includes a $64 million pretax gain from
the sale of limited partnership units in Northern Border
Partners, L.P., substantially offset by the establishment of
reserves for litigation and other contingencies. The net
income for 1993 also includes $13 million in pretax gains
from the sales of oil and gas properties and a $10 million
net share of a deferred tax reduction at Enron Oil & Gas
Company (EOG).
Net income for 1992 includes a $60 million nontaxable gain
from the sale of stock by EOG, a $52 million pretax gain
from the sale of Enron's remaining investment in Mobil
Corporation common stock (Mobil stock), $6 million in pretax
gains from the sales of oil and gas properties and an $11
million gain on the sale of investments. These amounts were
partially offset by a $57 million pretax charge reflecting
the establishment of reserves for litigation and other
contingencies and a $23 million extraordinary charge
relating to the early retirement of high coupon debt.
Net income for 1991 includes a $28 million pretax gain from
the sale of a portion of Enron's investment in Mobil stock,
a $24 million pretax gain from two favorable litigation
settlements, $15 million in pretax gains from the sales of
oil and gas properties and a $14 million pretax gain from
the sale of certain gas processing assets.
Primary earnings per share of common stock was $1.32 in
1993, after a $0.23 per share charge applicable to the $54
million tax rate change adjustment, as compared to $1.29 and
$1.03 in 1992 and 1991, respectively.
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:
<TABLE>
<CAPTION>
(In Millions) 1993 1992 1991
<S> <C> <C> <C>
Transportation and Operation $382 $378 $343
Gas Services 169 147 71
Gas Processing 28 56 94
International Gas and Power Services 132 33 69
Exploration and Production 122 102 75
Corporate and Other (35) 51 63
Total $798 $767 $715
</TABLE>
Transportation and Operation
The transportation and operation segment includes Enron's
regulated natural gas pipelines, construction, management
and operation of pipelines, liquids plants and power
facilities, Enron's crude oil marketing and transportation
operations conducted by EOTT Energy Corp. (EOTT) and Enron's
investment in liquids pipeline operations. The 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 the crude oil marketing and transportation operations,
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. During 1992, the transportation and
operations segment's IBIT increased 10% as compared to 1991
reflecting higher regulated natural gas pipeline earnings
and increased revenues recognized in connection with the
construction of various power projects. These increases
were offset by lower earnings from EOTT and from liquids
pipeline operations. 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 increased
approximately $60 million (5%) during 1993 after declining
$120 million (9%) in 1992 as compared to the applicable
preceding year. The increase in revenues reflects increased
transportation revenues recognized by Northern Natural Gas
Company (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 in which Enron owns a 17.5% interest.
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.
During 1992, revenues of the regulated natural gas pipeline
companies declined primarily as a result of lower sales
revenues realized by Northern reflecting a 27% decline in
sales volumes due to the shifting of customers from sales
service to transport service and lower revenues earned by
Transwestern. The decline in Transwestern's revenues
reflects lower transport rates as a result of the completion
by Transwestern of the recovery of certain transition costs
in early 1992. These declines were partially offset by
higher transportation volumes resulting from Transwestern's
mainline expansion and San Juan extension which became
operational at the end of the first quarter of 1992. In
addition, Northern's transportation revenues increased 17%
during 1992 as a result of higher volumes.
Sales and transportation volumes were as follows:
<TABLE>
<CAPTION>
Billion British Thermal Sales*
Units per Day - (Bbtu/d) 1993 1992 1991
<S> <C> <C> <C>
Northern 342 495 682
Transwestern 20 33 80
<FN>
*Includes intercompany amounts.
</TABLE>
<TABLE>
<CAPTION>
Billion British Thermal Transportation*
Units per Day - (Bbtu/d) 1993 1992 1991
<S> <C> <C> <C>
Northern 4,030 3,740 3,691
Transwestern 1,049 867 785
<FN>
*Includes intercompany amounts.
</TABLE>
Construction and Management Revenues
Revenues earned in connection with the construction and
operation of power projects totaled $27 million in 1993 as
compared to $52 million and $23 million during 1992 and
1991, respectively. 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 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.
Liquids Pipeline and EOTT
Revenues earned in connection with the liquids pipeline
operations declined in 1993 and 1992 primarily as a result
of the sale of those assets to Enron Liquids Pipeline, L.P.,
a master limited partnership formed in August 1992. Net
revenues from EOTT increased approximately 39% during 1993
as a result of higher product margins.
Cost of Gas and Other Products Sold
The cost of gas and other products sold by the
transportation and operation segment decreased by less than
1% during 1993 as compared to 1992 primarily as a result of
higher average per unit gas purchase costs being offset by
lower purchase volumes. During 1992, the cost of gas and
other products sold by the transportation and operations
segment declined 19% as compared to 1991 due primarily to a
27% decline in Northern's sales volumes combined with a 59%
reduction in Transwestern's sales volumes. These declines
were offset in part by higher average per unit gas purchase
costs.
Operating Expenses
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. During 1992, operating
expenses of the transportation and operation segment
declined by 10% as compared to 1991 primarily as a result of
lower operating expenses of the regulated pipeline group as
a result of lower transmission and compression expenses
reflecting lower sales volumes and the sale of the liquids
pipeline operations.
Amortization of deferred contract reformation costs declined
by 12% during 1993 and 19% during 1992 as compared to the
applicable preceding year primarily as a result of
Transwestern's completion of the recovery of certain
transition costs in early 1992.
Depreciation expense for the transportation and operation
segment increased $5 million (4%) during 1993 as compared to
1992 primarily as a result of a 10% increase in depreciation
expense recognized by the regulated natural gas pipeline
group reflecting Northern's adjustment in 1993 of
accumulated depreciation in accordance with a Federal Energy
Regulatory Commission (FERC) ruling. The increase in
depreciation by Northern was partially offset by a decline
in depreciation recorded for the liquids pipeline
operations.
Other Income and Deductions
Equity in earnings of unconsolidated subsidiaries declined
by $14 million (39%) during 1993 as compared to 1992
reflecting reduced earnings from 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 Partnership) and Enron's subsequent sale of a portion
of its interest in the Partnership in an underwritten public
offering (see Note 9 to the Consolidated Financial Statements).
Additionally, during 1993 equity in earnings from Mojave Pipeline
Company (Mojave) decreased as a result of the sale of Enron's
investment in Mojave during 1993. Equity in earnings of
unconsolidated subsidiaries of the transportation and operation
segment remained virtually unchanged in 1992 as compared to 1991
as increased earnings from Northern Border were offset by lower
earnings from Citrus Corp. and Mojave.
Outlook
Transportation and Operation
The transportation and operation segment should continue to
provide stable earnings and cash flows during 1994. Full
implementation of FERC Order 636 and the successful
settlement of all significant regulatory issues by the
regulated natural gas pipelines during 1993 should allow for
a constant and 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 reinvest
proceeds in system modernization projects and reduce its
overall cost structure. Expansion of the Florida Gas
pipeline system should also provide growth
opportunities for the transportation and operations segment.
In January 1994, Enron filed a registration statement with
the Securities and Exchange Commission to sell units in a
master limited partnership which will contain substantially
all of the operations and assets of EOTT. EOTT will serve
as general partner and own a substantial interest in the new
limited partnership (see Note 3 to the Consolidated
Financial Statements).
Gas Services
Enron's Gas Services segment (EGS) had a $22 million (15%)
increase in income before interest, minority interest and
income taxes in 1993 as compared to 1992. The increase was
due primarily to increased production payments arranged,
successful long-term contracting efforts and the continued
growth of the physical and financial risk management
services provided to the natural gas business. Offsetting
these increases were declines in earnings associated with
EGS's North American power ventures and natural gas liquids
(NGL) marketing activities. Each year's results also
include earnings from the Sithe Energies contract (Sithe).
The Sithe contract, which was signed in 1992, provides for
Enron Power Services Inc. to deliver approximately 1.5
trillion cubic feet of gas over the next 20 years (five
years on a fixed-price basis) to fuel Sithe's independent
power project in upstate New York. Income before interest,
minority interest and income taxes increased $76 million
(107%) in 1992 as compared to 1991 due primarily to long-
term contracting and production payment activities.
Statistics for the gas services segment are as follows:
<TABLE>
<CAPTION>
1993 1992 1991
Physical and Notional Sales (Bbtu/d)*
<S> <C> <C> <C>
Firm 4,310 2,632 1,593
Interruptible 828 893 1,597
Financial Settlements (notional) 5,027 1,536 424
Total 10,165 5,061 3,614
Transportation Volumes (Bbtu/d)* 571 536 498
Liquids Marketing Volumes
NGL Marketed (MMgal) 2,506 3,388 2,512
Gross Margin ($/Gal) $0.008 $0.009 $0.010
MTBE
Marketing Volumes (MMgal) 254 28 -
Owned Production (MMgal) 128 15 -
Gross Margin ($/Gal) $0.197 $0.175 $ -
Production Payments and Financings Arranged
(in millions) $ 413 $ 516** $ 121
Fixed Price Contract Originations (TBtue) 3,781 2,165 964
<FN>
*Includes intercompany amounts.
**Includes $327 million of production payments promoted for EOG.
</TABLE>
EGS's strategy is to provide predictable pricing, reliable
delivery and low cost capital to its customers. EGS
provides these services through a variety of financial
instruments including forward contracts, swap agreements,
options, futures and other contractual commitments.
These services can be categorized into four business lines:
Gas, Power, Finance and Liquids. The following discussion
analyzes the contributions to income before interest,
minority interest and income taxes and the future outlook
for each of the businesses.
Gas. The Gas operations include price risk management and
origination activities as well as the physical natural gas
trading and transportation activities of Enron Gas
Marketing, Houston Pipe Line Company, Enron Access, the
Louisiana Resources companies and the Canadian gas supply
and marketing operations. The earnings from these
activities increased 30% in 1993 primarily as a result of
increases in sales volumes. The volume increase is
primarily attributable to continued growth in the
derivatives business, the September 1992 acquisition of
Enron Access, the April 1993 acquisition of Louisiana
Resources and expansion into the Canadian market. The 1993
results also include earnings from significant fixed and
index-priced contract originations and management of the
existing contract portfolio. Earnings during 1992 included
fixed price originations and earnings from the marketing and
trading activities and was virtually unchanged as compared
to 1991.
During 1994, EGS anticipates continued strong performance
from its gas business. Growth in the physical and financial
trading activities is expected despite continued competition
from financial and industry companies, particularly in the
derivatives area. Additionally, contract originations
should increase as the impact of FERC Order 636 becomes more
evident.
Power. EGS's Power business includes activities in North
America such as providing natural gas contract services to
the power industry; managing, acquiring and developing power-
related assets and joint ventures; and marketing and
supplying electricity. Power's earnings declined 15% during
1993 due primarily to the inclusion in 1992 of earnings
associated with the Richmond and Milford power projects.
The 1993 and 1992 results also included earnings related to
the gas forward sales contract with Sithe. Earnings in 1993
and 1992 also included significant contract originations
involving sales of gas to other power generation facilities.
The 1992 results were significantly higher than 1991
reflecting the initiation of contract origination
activities.
The Power operations will benefit in 1994 from the
opportunities being created in the power marketing area as a
result of the continuing regulatory and economic changes in
the electric industry. During 1994, EGS expects to compete
as an independent marketer of electricity.
Additionally, EGS will aggressively continue marketing of
natural gas to independent power projects as well as
electric utilities converting to natural gas in response to
the Clean Air Act of 1990.
Finance. Enron Finance Corp. (EFC) secures natural gas
supplies from independent producers through a variety of
financial transactions, primarily volumetric production
payments. EFC arranges these transactions through financial
entities and provides related price risk management
services. Additionally, EGS purchases the natural gas and
crude oil associated with these transactions. EFC's
earnings increased 50% in 1993 due primarily to increased
non-affiliated production payments and financings arranged.
EFC's earnings increased during 1992 as compared to 1991 due
to increased production payment activities. From inception
through December 31, 1993, production payments and
financings arranged total over $1 billion.
In 1994, EFC expects continued growth in its business
resulting primarily from offerings of innovative alternative
financing to producers. This activity will include
production payments, debt and equity financings, as well as
other products. During 1993, Joint Energy Development
Investments, a limited partnership, was formed
comprised of an EGS subsidiary as general partner and the
California Public Employees Retirement System (CalPERS) as
limited partner. The partnership will provide significant
capital for energy investments.
Liquids. The Liquids business of EGS includes the North
American natural gas liquids (NGL) marketing activities and
the Clean Fuels business which consists of the methanol and
methyl tertiary butyl ether (MTBE) businesses. Liquids
earnings were virtually unchanged from 1992 to 1993.
Earnings from the Clean Fuels business increased as a result
of higher MTBE volumes and the impact of reflecting
contractual commitments at market value. The Clean Fuels
increase was partially offset by a decrease in the NGL
marketing results due to lower volumes and margins. Liquids
earnings declined 40% from 1991 to 1992 due
primarily to expenses associated with the start-up of the
Clean Fuels business and the impact of lower NGL prices.
During 1994, EGS's Liquids business expects to improve its
NGL marketing results by expanding to provide derivative
products in that area. Additionally, in the MTBE business,
EGS plans to continue development of its merchant business
by actively marketing MTBE, including long-term and fixed
margin-based pricing terms. Although current MTBE prices
continue to be weak, market conditions are expected to
improve as the Clean Air Act of 1990 mandates the increased
use of reformulated gasoline (a primary market for MTBE).
Other. EGS's net unallocated expenses such as rent, systems
expenses and other support group costs increased 27% in 1993
as compared to 1992 due primarily to continued
expansion into new markets, system upgrades and the
generally increased level of activity. Expenses increased
45% from 1991 to 1992 due also to increased activity
and establishment of certain contingency reserves.
Gas Processing
The income before interest and taxes of the gas processing
segment totaled $28 million in 1993 as compared to $56
million in 1992 and $94 million in 1991. The declines in
both 1992 and 1993 as compared to the applicable preceding
years were attributable primarily to lower processing
margins reflecting higher natural gas feedstock prices and
lower product prices. Volume and price statistics for the
gas processing segment (including intercompany amounts) are
detailed below:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Total Production Volumes (MMgal) 1,334 1,296 1,153
Gross Margin (per gal.) $0.089 $0.112 $0.163
Product Prices
Average at Mt. Belvieu (cents/gallon)
Ethane 21.09 23.64 22.32
Propane 31.24 32.06 33.95
Normal Butane 36.52 39.17 42.44
Isobutane 40.09 46.39 47.21
Natural Gasoline 40.97 45.51 49.60
</TABLE>
Revenues
Revenues of the gas processing segment increased 4% during
1993 after an increase of 8% during 1992 as compared to the
applicable preceding year. In both 1993 and 1992, the
increase in revenues was primarily caused by increased
production volumes partially offset by reduced product
prices.
Costs and Expenses
The cost of products sold by the gas processing segment
increased 22% in 1993 as compared to 1992 and 20% in 1992 as
compared to 1991. The increases in both years were
attributable to higher natural gas feedstock prices combined
with higher production volumes. The increases in cost of
products sold coupled with reduced product prices resulted
in declines in gross margin of the domestic gas processing
segment of 48% in 1993 and 18% in 1992.
Other Income and Deductions
Other income increased $23 million during 1993 as compared
to 1992 primarily as a result of gains realized on the sales
of certain coal handling and NGL assets.
Outlook
In 1994, Enron plans to mitigate the market risk inherent in
the gas processing business through hedging techniques.
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 its international power, pipeline and natural gas liquids
marketing operations. International power operations
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 $132 million during 1993, $33 million in 1992 and
$69 million in 1991. The increase in IBIT between 1992 and
1993 and the decline between 1991 and 1992 primarily
reflects the promotion and development activities of its
power operations. The 1993 increase also reflects earnings
from the Argentina pipeline operations acquired in the fourth
quarter of 1992.
Revenues
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
earned in connection with the promotion and sale of liquids
processing facilities at Teesside.
During 1992, revenues of the international gas and power
services segment declined 15% as compared to 1991 primarily
as a result of lower liquids marketing and power revenues.
Liquids marketing revenues declined by 13% reflecting a 14%
decline in marketing volumes. Power revenues declined $46
million (87%) primarily as a result of promotion and
development revenues earned in connection with the Teesside
power project in 1991.
Costs and Expenses
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 the previously mentioned
decline in international liquids marketing volumes.
Operating expenses increased $20 million (40%) during 1993
as compared to 1992 primarily as a result of higher
operating expenses incurred in connection with increased
activities in the power operations area. Operating income
for the segment increased $69 million during 1993 as
compared to 1992 as a result of the previously mentioned
successful power development and promotion activities and
improved margins earned by the international liquids marketing
operations reflecting a reduction in spot market transactions which
negatively impact margin. Operating income declined by $45
million during 1992 as compared to 1991 primarily as a
result of the recognition in 1991 of promotion and
development revenues earned in connection with the Teesside
power project.
Other Income and Deductions
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, 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 realized by Enron's operations in South
America (Enron Americas) during 1992. Other income
increased $8 million during 1992 as compared to 1991
primarily as a result of the gain on asset sales realized by
Enron Americas.
Outlook
The objective of the international gas and power services
segment is to deliver Enron's extensive product line to the
international marketplace including Enron's product concepts
in the areas of marketing and risk management of natural gas
based products. Growth opportunities in that market should
result from the current and projected high demand for
electrical power generation, the under utilization of
natural gas reserves throughout the world and increased
environmental awareness.
Exploration and Production
Income before interest, minority interest and income taxes
for EOG increased $20 million (20%) during 1993 and $27
million (36%) during 1992 as compared to the applicable
preceding year due primarily to higher natural gas prices
and volumes, and lower per unit operating costs.
Volume and price statistics are as follows (including
intercompany amounts):
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Wellhead Delivered Volumes
Natural Gas (MMcf/d) 709(a) 564(a) 491
Crude Oil and Condensate (MBbl/d) 8.9 8.5 8.2
Natural Gas Liquids (MBbl/d) 0.6 0.7 0.6
Wellhead Average Prices
Natural Gas ($/Mcf) $ 1.92(b) $ 1.58(b) $ 1.37
Crude Oil and Condensate ($/Bbl) $16.37 $17.90 $18.78
Natural Gas Liquids ($/Bbl) $11.12 $10.69 $11.64
Other Natural Gas Marketing
Volumes (MMcf/d) 293(a) 255(a) 237
Average Gross Revenue ($/Mcf) $ 2.57 $ 2.62 $ 2.63
Associated Costs ($/Mcf)
(including transportation and exchange
differentials) $ 2.32 $ 1.99 $1.75
<FN>
(a) Includes an annual average of 81.0 MMcf per day in
1993 and 27.6 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
$1.57 per Mcf in 1993 and $1.70 per Mcf in 1992 for the
volumes detailed in Note (a) above, net of transportation
costs.
</TABLE>
The following discussion further analyzes the significant
changes in EOG's results.
Revenues
EOG's gross revenues increased $133 million (24%) during
1993 and $84 million (18%) in 1992 as compared to the
applicable preceding year. 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. The increased revenues in 1992 are attributable
to a 15% increase in average wellhead natural gas delivered
volumes combined with a 15% increase in average wellhead
natural gas prices. Although exploration and development
efforts resulted in deliverability increases in certain core
areas, the earnings in 1992 and 1991 were mitigated by
voluntary curtailments initiated due to lower than
acceptable prices during certain periods.
Costs and Expenses
The cost of gas sold by the exploration and production
segment in connection with other natural gas marketing
activities increased 18% in 1993 as compared to 1992 and 23%
in 1992 as compared to 1991. The increase in 1993 as
compared to 1992 was due to 17% higher average associated
costs per Mcf combined with a 15% increase in natural gas
marketing volumes. The increase in 1992 was due to 14%
higher average associated costs per Mcf combined with 8%
higher other natural gas marketing volumes.
Operating expenses for the exploration and production
segment increased $35 million (24%) in 1993 compared to 1992
and remained stable in 1992 as compared to 1991. 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 expense increased 39% in 1993 and 12% in 1992
as compared to prior years. The increases in both years
primarily reflect increased production volumes. On a per
unit natural gas equivalent volumes delivered basis,
depreciation, depletion and amortization expense increased
to $0.89 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,
condensate or natural gas liquids) in 1993 from $0.79 per
Mcfe in 1992 and $0.81 per Mcfe in 1991 primarily due to
higher costs associated with tight gas sand drilling
activities.
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. Taxes, other than
income taxes, increased $10 million (56%) from 1991 to 1992
due to increased production volumes and revenues, increases
in certain ad valorem and state franchise taxes in 1992, and
earnings benefits realized in 1991 associated with the
refund of certain state natural gas severance taxes
resulting from overpayments in prior years. These increases
were mitigated by Texas severance tax exemptions for high
cost gas production that were in effect for the full year.
Total per unit operating costs for lease and well expense,
DD&A, general and administrative expense, interest expense,
and taxes other than income increased $0.03 Mcfe, averaging
$1.43 per Mcfe during 1993 compared to $1.40 per Mcfe for 1992.
Other Income and Deductions
The exploration and production segment's other income was
$20 million in 1993 as compared to $3 million in 1992 and
$12 million in 1991. Gains on property sales were the
primary components of other income during each of the three
years and totaled $13 million in 1993, $6 million in 1992
and $15 million in 1991.
Outlook
While there still exists a good deal of uncertainty as to
the direction of future natural gas price trends, some
recent experiences may suggest a converging of the overall
supply/demand relationship reflecting, at least partially,
the significantly reduced level of drilling activity during
recent years. EOG's management remains confident 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 further 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 by the exploration and production segment from time to
time of various commodity price hedging mechanisms will tend
to mitigate this level of sensitivity. Enron has hedged the
vast majority of its anticipated 1994 natural gas production
by selling forward at recent prices.
EOG will continue to focus development and certain
exploration expenditures in its core and other major
producing areas, and include limited exploratory exposure in
areas outside of North America. Expenditure plans for 1994
will continue to be focused toward certain areas that were
not addressed as actively in the recent past due to the
increased emphasis on tight gas sand drilling opportunities
during 1991 and 1992. EOG will continue expenditures in new
areas outside of North America, primarily for additional
development operations in Trinidad, new development
operations in other countries and the continued evaluation
of coalbed methane recovery potential in France, Australia,
China 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 $35
million in 1993 as compared to income of $51 million in 1992
and $63 million in 1991. During 1993, the segment
recognized higher administrative and general expenses.
Included in 1992 are the previously discussed gains from
the sale of stock by EOG and sales of Mobil stock partially offset
by charges related to the establishment of reserves for
litigation and other contingencies. Included in 1991 are the previously
discussed gains related to sales of Mobil stock, two
favorable litigation settlements and the sale of certain gas
processing assets.
Interest Expense and Income Taxes
Interest and related charges, net, is shown on the
Consolidated Income Statement net of interest capitalized.
The net expense for 1993 decreased $30 million (9%) from
1992. The decrease is primarily due to lower interest
rates. The net expense for 1992 decreased $43 million (12%)
from 1991. The decrease is primarily due to a decrease in
short-term interest rates and lower total obligations. Short-
term borrowings averaged $591 million during 1993 as
compared to $588 million during 1992 and $500 million during
1991 while the average interest rate on short-term debt fell
to 3.3% in 1993 from 3.9% in 1992 and 6.3% in 1991.
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 utilization
of increased tight gas sand tax credits. Although income
before income taxes increased, income taxes decreased in
1992 as compared to 1991 primarily due to the inclusion of a
nontaxable gain from the sale of stock by EOG and
utilization of increased tight gas sand tax credits.
Extraordinary Items
The extraordinary loss 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 $468
million during 1993 as compared to $330 million in 1992.
The increase primarily reflects higher income levels in 1993
and the prepayment of $150 million made in 1992 for
information technology services.
Cash From Investing Activities
Cash used in investing activities totaled $639 million
during 1993 as compared to $43 million during 1992. The
change primarily reflects increased expenditures in
connection with Enron's investment in Argentina pipeline
operations, Teesside and other power projects.
Additionally, during 1992, EOG recorded proceeds of $327
million under the terms of a volumetric production payment
transaction (see Note 8 to the Consolidated Financial
Statements). Proceeds from the sales of assets totaled $454
million during 1993 as compared to $388 million during 1992.
The 1993 amounts include approximately $217 million in
connection with the sale of Enron's interest in Northern
Border Partners, L.P., $100 million from the sale of
information technology assets and $42 million realized
from the sale of exploration and production properties.
Proceeds from the sale of assets during 1992 included
$62 million from the sale of Mobil stock, $138 million,
net, realized on the sale of certain liquids pipeline
assets to Enron Liquids Pipeline, L.P., $121 million from
the sale of certain pipeline assets by Enron Gas Services
and $33 million realized from the sale of exploration and
production properties.
Cash From Financing Activities
Net cash provided by financing activities totaled $170
million during 1993 as compared to the use of $339 million
in 1992. The difference in cash flow from financing
activities between 1993 and 1992 was the retirement in 1992
of $1.1 billion of long-term debt primarily through the
utilization of call provisions available on higher coupon
debt issues. The repayments of long-term debt were
partially funded by proceeds from the sales of common stock
by Enron and EOG. During 1993, Enron issued $614 million of
long-term debt while retiring $450 million principal amount
of long-term borrowings. Other cash outflows during 1993
included $190 million of cash dividend payments on common
and preferred stock and $23 million in repayments of other
long-term obligations. In addition to the debt issuances
discussed above, financing cash inflows during 1993 included
$214 million from the issuance of preferred stock by a
wholly-owned subsidiary of Enron (see Note 10 to the
Consolidated Financial Statements).
Working Capital
At December 31, 1993, Enron had a working capital deficit of
$657 million. Enron is able to fund its deficit in working
capital through the utilization of credit facilities which,
at December 31, 1993, provided for up to $2.2 billion of
committed and uncommitted credit. 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. At December 31,
1993, Enron had $144 million outstanding under the
uncommitted agreements. In addition, Enron sells commercial
paper and has agreements to sell up to $800 million of
accounts receivable, thus providing short-term 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:
<TABLE>
<CAPTION>
1994
(In Millions) Estimate 1993 1992 1991
<S> <C> <C> <C> <C>
Transportation and Operation $123 $152 $140 $396
Gas Services 45 78 45 47
Gas Processing 8 24 34 110
International Gas and Power Services 16 53 41 28
Exploration and Production* 394 383 362 212
Corporate and Other 8 5 12 35
Total $594 $695 $634 $828
<FN>
*Excludes exploration expenses of $56 million (estimate), $55 million,
$44 million, and $46 million for 1994, 1993, 1992 and 1991, respectively.
</TABLE>
Capital expenditures by the transportation and operation
segment increased $12 million during 1993 as compared to
1992. The decline during 1992 as compared to 1991 reflects
the completion in early 1992 of Transwestern's pipeline
expansion project and its San Juan lateral project which
began during 1991.
Capital expenditures of the gas services segment increased
$33 million during 1993 as compared to 1992 primarily as a
result of the acquisition of gas storage assets and systems
improvement costs.
The exploration and production segment's capital
expenditures increased from $362 million in 1992 to $383
million in 1993. The increase was primarily attributable to
increased domestic drilling activity with reduced emphasis
on development drilling expenditures associated with tight
gas sand formations. Enron also implemented its first
development program outside of North America. The increase
in capital spending by the exploration and production
segment in 1992 compared to 1991 reflects development
drilling expenditures associated with tight gas sand
drilling activities and the acquisition in December 1992 of
$40 million of producing properties in Canada.
Capital expenditures during 1994 are expected to total
approximately $594 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 $387
million of which approximately $150 million for the Florida
Gas Transmission Company expansion and approximately $160
million for various international power projects.
Management believes that the capital expenditure program
will be funded by a combination of internally generated
funds and proceeds from dispositions of selected assets.
Capitalization
Total capitalization at December 31, 1993 of $5.7 billion
was comprised of total long-term debt of $2.7 billion,
shareholders' equity of $2.6 billion, preferred stock of
subsidiary company of $.2 billion and minority interests of
$.2 billion. Debt as a percentage of total capitalization
decreased to 46.7% at December 31, 1993 as compared to 47.7%
at December 31, 1992. The improvement primarily reflects
higher net income and the issuance of preferred stock by
Enron Capital L.L.C., the proceeds of which were used to
reduce debt and other corporate purposes. Additionally, the
average cost of long-term debt declined to 8.2% at December
31, 1993 from 8.9% at December 31, 1992. The decline was
accomplished primarily through the retirement of additional
higher coupon long-term debt which was subject to call
provisions during 1993.
<PAGE>
Report of Independent Public Accountants
To the Shareholders and Board of Directors of Enron Corp.:
We have audited the accompanying consolidated balance sheet
of Enron Corp. (a Delaware corporation) and subsidiaries as
of December 31, 1993 and 1992, 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, 1993. 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,
1993 and 1992, 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, 1993, in
conformity with generally accepted accounting principles.
Arthur Andersen & Co.
Houston, Texas
February 18, 1994
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Income Statement
(In Thousands, Except Per Share Amounts)
<CAPTION>
Year Ended December 31,
1993 1992 1991
(Restated) (Restated)
<S> <C> <C> <C>
Revenues
Natural gas and gas liquids $6,125,638 $4,712,422 $4,270,720
Transportation 767,911 688,297 637,082
Other 1,078,933 1,008,554 775,139
7,972,482 6,409,273 5,682,941
Costs and Expenses
Cost of gas sold 3,856,499 2,502,253 2,029,232
Cost of other products sold 1,709,527 1,720,142 1,616,611
Operating expenses 1,057,415 936,040 914,538
Amortization of deferred
contract reformation costs 89,240 101,253 124,947
Oil and gas exploration expenses 75,743 59,178 58,959
Depreciation, depletion and
amortization 458,188 376,019 365,957
Taxes, other than income taxes 108,386 100,616 74,760
7,354,998 5,795,501 5,185,004
Operating Income 617,484 613,772 497,937
Other Income and Deductions
Equity in earnings of
unconsolidated subsidiaries 73,293 56,545 55,228
Interest income 31,457 53,623 56,051
Gain on sale of stock by
subsidiary company - 59,615 -
Other, net 75,433 (16,373) 106,086
Income Before Interest, Minority
Interest and Income Taxes 797,667 767,182 715,302
Interest and Related Charges, net 300,149 330,282 373,492
Dividends on Preferred Stock of
Subsidiary 2,137 - -
Minority Interest 27,605 17,632 7,210
Income Taxes 89,077 90,468 102,454
Income Tax Rate Adjustment 46,177 - -
Income Before Extraordinary Items 332,522 328,800 232,146
Extraordinary Items - (22,615) -
Net Income 332,522 306,185 232,146
Preferred Stock Dividends 16,919 22,109 24,740
Earnings on Common Stock $ 315,603 $ 284,076 $ 207,406
Earnings Per Share of Common Stock
Primary
Income before extraordinary
items $ 1.32 $ 1.39 $ 1.03
Extraordinary items - (.10) -
$ 1.32 $ 1.29 $ 1.03
Fully Diluted
Income before extraordinary
items $ 1.25 $ 1.30 $ .98
Extraordinary items - (.09) -
$ 1.25 $ 1.21 $ .98
Average Number of Common Shares
Used in Primary Computation 239,019 219,965 202,080
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Balance Sheet
<CAPTION>
December 31,
(In Thousands) 1993 1992
(Restated)
<S> <C> <C>
Assets
Current Assets
Cash and cash equivalents $ 140,240 $ 141,689
Trade receivables (net of allowance for
doubtful accounts of $21,873 and $14,555,
respectively) 783,603 514,505
Other receivables 205,956 96,227
Transportation and exchange gas receivable 102,887 123,572
Inventories 197,737 293,809
Deferred contract reformation costs 103,520 103,520
Assets from price risk management activities 279,715 170,279
Other 204,952 208,255
Total Current Assets 2,018,610 1,651,856
Investments and Other Assets
Investments in and advances to unconsolidated
subsidiaries 697,084 636,062
Deferred contract reformation costs 168,479 266,466
Assets from price risk management activities 887,342 360,861
Other 1,010,028 850,595
Total Investments and Other Assets 2,762,933 2,113,984
Property, Plant and Equipment, at cost
Transportation and operations 4,070,325 3,862,076
Gas services 3,543,991 3,483,504
Exploration and production, successful
efforts accounting 2,772,220 2,475,371
International gas and power services 135,918 54,672
Gas processing 265,782 326,505
Corporate and other 98,622 213,148
10,886,858 10,415,276
Less accumulated depreciation, depletion
and amortization 4,164,086 3,869,513
Net Property, Plant and Equipment 6,722,772 6,545,763
Total Assets $11,504,315 $10,311,603
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Balance Sheet
<CAPTION>
December 31,
(In Thousands) 1993 1992
(Restated)
<S> <C> <C>
Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable $ 1,477,290 $ 1,323,782
Transportation and exchange gas payable 98,569 107,559
Accrued taxes 88,837 105,692
Accrued interest 53,292 52,712
Billings in excess of costs on uncompleted
contracts 45,380 55,487
Liabilities from price risk management activities 609,403 283,877
Deferred revenue 48,804 87,599
Other 254,014 201,220
Total Current Liabilities 2,675,589 2,217,928
Long-Term Debt 2,661,240 2,458,924
Deferred Credits and Other Liabilities
Deferred income taxes 1,860,237 1,879,027
Deferred revenue 327,802 439,847
Liabilities from price risk management activities 330,209 135,233
Other (including Flexible Equity Trust, Note 11) 615,839 482,930
Total Deferred Credits and Other Liabilities 3,134,087 2,937,037
Commitments and Contingencies (Notes 9, 14, 15,
16 and 18)
Minority Interests 196,275 179,397
Preferred Stock of Subsidiary Company 213,750 -
Shareholders' Equity
Preferred stock, cumulative, $100 par value,
1,500,000 shares authorized, no shares issued - -
Preference stock, cumulative, $1 par value,
10,000,000 shares authorized, no shares issued - -
Second preferred stock, cumulative, $1 par value,
5,000,000 shares authorized, 1,496,677 shares
and 1,829,641 shares of $10.50 Cumulative Second
Preferred Convertible Stock issued, respectively 149,668 182,964
Common stock, 600,000,000 shares authorized,
249,095,312 shares $0.10 par value, and
118,766,088 shares $10.00 par value, issued,
respectively 24,910 1,187,661
Additional paid-in capital 1,707,938 324,944
Retained earnings 1,104,986 959,522
Cumulative foreign currency translation
adjustment (138,704) (118,160)
Common stock held in treasury (174,700 shares
at December 31, 1992) - (8,100)
Other (225,424) (10,514)
Total Shareholders' Equity 2,623,374 2,518,317
Total Liabilities and Shareholders' Equity $11,504,315 $10,311,603
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Statement of Cash Flows
<CAPTION>
Year Ended December 31,
(In Thousands) 1993 1992 1991
(Restated) (Restated)
<S> <C> <C> <C>
Cash Flows From Operating Activities
Reconciliation of net income to net cash
provided by operating activities
Income before extraordinary items $ 332,522 $ 328,800 $ 232,146
Depreciation, depletion and amortization 458,188 376,019 365,957
Oil and gas exploration expenses 75,743 59,178 58,959
Amortization of deferred contract
reformation costs 89,240 101,253 124,947
Deferred income taxes 51,200 (14,647) (42,942)
Gains on sales of stock by subsidiary
company and other assets (115,586) (136,249) (58,353)
Regulatory, litigation and other
contingency adjustments 58,944 42,549 (11,036)
Changes in components of working capital (76,513) (157,234) 349,264
Deferred contract reformation costs (136,383) (129,694) (84,512)
Deferred revenues 12,669 32,679 20,851
Prepaid information technology services - (150,000) -
Net assets from price risk management
activities (115,415) (15,892) (96,138)
Other, net (166,320) (6,898) (45,463)
Net Cash Provided by Operating Activities 468,289 329,864 813,680
Cash Flows From Investing Activities
Proceeds from sales of investments and
other assets 453,977 387,788 277,086
Production payment transactions, net (73,867) 301,395 -
Additions to property, plant and
equipment (688,032) (596,885) (707,083)
Other capital expenditures (7,405) (37,656) (120,837)
Other, net (323,916) (97,961) (71,231)
Net Cash Used in Investing Activities (639,243) (43,319) (622,065)
Cash Flows From Financing Activities
Net increase (decrease) in short-term
borrowings 42,767 (142,651) (261,179)
Issuance of long-term debt 613,938 700,000 412,783
Decrease in long-term debt (450,161) (1,116,911) (59,120)
Decrease in other long-term obligations (22,757) (72,140) (73,972)
Issuance of preferred stock of
subsidiary 213,750 - -
Issuance of common stock 22,882 399,355 -
Issuance of common stock by subsidiary - 111,861 -
Dividends paid (189,769) (174,880) (154,274)
Net acquisition of treasury stock (71,145) (37,524) (65,755)
Other, net 10,000 (5,818) 18,000
Net Cash Provided by (Used in) Financing
Activities 169,505 (338,708) (183,517)
Increase (Decrease) in Cash and Cash
Equivalents (1,449) (52,163) 8,098
Cash and Cash Equivalents, Beginning of Year 141,689 193,852 185,754
Cash and Cash Equivalents, End of Year $ 140,240 $ 141,689 $ 193,852
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Statement of Changes in
Shareholders' Equity Accounts
<CAPTION>
Cumulative
Foreign Other
Convertible Additional Retained Currency (Including
Preferred Common Paid-in Earnings Translation Treasury Flexible
(In Thousands) Stock Stock Capital (Restated) Adjustment Stock Equity Trust)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1990 $237,585 $ 506,244 $ 260,792 $ 966,096 $ (76,982) $ (6,555) $ (49,633)
Net income 232,146
Cash dividends
Common stock (126,957)
Preferred stock (24,740)
Treasury stock reissued (620) 16,837 (3,483)
Purchase of treasury stock (76,696)
Exchange of common stock for
convertible preferred stock (14,850) 5,068 9,782
Exchange of common stock for
convertible debentures 2,000 8,524
Common stock issued 3,032 13,909
Translation adjustments (128)
Common stock split 516,344 (293,482) (222,862)
Other 1,095 (984) 19,449
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 re-
duction 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)
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
Enron Corp. and Subsidiaries
Notes to the Consolidated Financial Statements
1. Summary of Significant Accounting Policies
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.
Financial statements for prior periods have been restated to
reflect the adoption of Statement of Financial Accounting
Standards (SFAS) No. 109 (see E below) and the
reclassification of EOTT Energy Corp.'s net assets and
results of operations to continuing operations (see Note 3).
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 $77.3 million and $116.2 million, crude oil and refined
products of $75.5 million and $97.4 million and liquid
petroleum products of $37.3 million and $71.7 million at
December 31, 1993 and 1992, 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 adopted the provisions of SFAS No. 109 - "Accounting
for Income Taxes" effective January 1, 1993 and applied the
provisions of the statement retroactively. Enron previously
accounted for income taxes under the provisions of SFAS No.
96 which was superceded by SFAS No. 109. SFAS No. 109
retains the 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. The adoption of SFAS No. 109
did not have a material impact on Enron's results of
operations or financial position.
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 11). 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 Activities
Enron, through its Gas Services Group (EGS), provides price
risk management services in the energy sector (these
services are further described in Note 2). Enron accounts
for these activities using the mark-to-market method of
accounting. Under mark-to-market accounting, forwards,
swaps, options, futures contracts 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 revenues in the Consolidated Income
Statement.
The market prices used to value these transactions reflect
management's best estimate of market prices 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.
Periodically, Enron's other businesses also enter into
forwards, futures and other contracts to hedge the impact of
market fluctuations on inventories, 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 inventory or commitment.
Disclosures regarding the fair value of these financial
instruments are included in Note 18.
H. Accounting for Oil and Gas Producing Activities
Enron accounts for oil and gas exploration and production
activities under the successful efforts method of
accounting. Under such method, oil and gas lease
acquisition costs are capitalized when incurred. Unproved
properties with significant acquisition costs are assessed
quarterly on a property-by-property basis, and any
impairment in value is recognized. 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.
I. 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 and sale of 4.1 million shares of its
common stock, reducing Enron's ownership interest from 84%
to 80%. The shares were priced to the public at $28.50 per
share and net proceeds from the transaction after
underwriting commissions and expenses totaled $111.9
million. A gain in the amount of $59.6 million was
recognized by Enron on the transaction. No income tax
expense was recorded related to this transaction, consistent
with U.S. tax law.
J. 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.
2. Price Risk Management Activities
EGS provides price risk intermediation services to its
customers. These services primarily relate to commodities
associated with the energy sector (natural gas, crude oil,
natural gas liquids), but in some instances also include
financial products (interest rates and Canadian dollars).
EGS 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
contract, options, futures and other contractual
arrangements.
Market Risk
EGS'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. As discussed in Note 1,
Enron accounts for these activities at market value. As a
result, the impact of changes in market prices are reflected
currently in the consolidated financial statements. It is
Enron's policy to prohibit speculation on market
fluctuations and EGS's objective to maintain a balanced
portfolio. However, net open positions often result from
the timing of the origination of new transactions.
Accordingly, EGS closely monitors and manages its exposure
to market risk. 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 are examined on a daily basis. Accordingly,
Enron does not anticipate a materially adverse effect on
financial position or results of operations as a result of
market fluctuations.
SFAS No. 105, - "Disclosures of Information about Financial
Instruments with Off-Balance-Sheet Risk and Financial
Instruments with Concentrations of Credit Risk," requires
the disclosure, as set forth below, of the notional amounts
of financial instruments that give rise to off-balance-sheet
risk. The notional amounts and terms of these agreements,
as well as volumetric information regarding EGS's future
fixed price commitments, at December 31, 1993 are set forth
below (volumes in billions of British thermal units
(Bbtus), U.S. dollars in millions):
<TABLE>
<CAPTION>
Fixed Price Fixed Price Maximum
Product Payor Receiver Terms in
years
<S> <C> <C> <C>
Energy Commodities (Bbtus)
Swaps 1,715,355 1,480,787 10
Options 269,984 382,098 14
Forwards 795,626 1,195,368 20
Futures 240,971 115,424 3
Financial Products (millions $)
Interest rate swaps,
forwards and futures $ 610 $ 1,028 30
Canadian Dollar
swaps and futures 289 313 20
</TABLE>
EGS also has sales and purchase commitments associated with
contracts based on market prices totaling 4,900,000 Bbtus,
with terms extending up to 21 years. The midpoint of EGS's
entire portfolio of price risk management activities as of
December 31, 1993 was approximately 4.5 years (based on the
weighted average value of each transaction).
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 EGS's price risk management
services as of December 31, 1993 are summarized as follows
(amounts in millions):
<TABLE>
<CAPTION>
Assets from Price Risk Management Activities
Investment Below
Grade(a) Investment Grade Total
<S> <C> <C> <C>
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) After consideration of collateral, which encompass
standby letters of credit,parent company guarantees and
property interests, including oil and gas reserves.
(b) Three customers' exposures each comprise greater than
5% of assets from price risk management activities.
</TABLE>
This concentration of counterparties may impact EGS'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.
EGS 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.
EGS 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 EGS'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.
3. Discontinued Operations Subsequently Retained
During October 1992, the Board of Directors approved a plan
to divest all of the crude oil trading and transportation
operations of Enron's wholly-owned subsidiary, EOTT Energy
Corp. (EOTT), through a spin-off transaction to holders of
Enron common stock . As a result, Enron classified these
activities as discontinued operations for financial
reporting purposes. During the fourth quarter of 1993,
Enron's Board of Directors approved a revised plan to divest
a majority, but not all, of EOTT through a public offering
of limited partnership interests in a master limited
partnership.
In January 1994, EOTT Energy Partners, L.P. filed a
registration statement with the Securities and Exchange
Commission (SEC) to offer common units. Under terms of this
offering, Enron will sell substantially all of the business
and assets of EOTT to EOTT Energy Partners, L.P., a newly
formed limited partnership. Enron will be the general
partner and own a substantial interest in EOTT Energy
Partners, L.P. after completion of the transaction.
Enron reclassified the net assets and results of operations
of EOTT, from discontinued operations, for all periods
presented. EOTT's total assets and total liabilities as of
December 31, 1992, the year it was reported as discontinued
operations, were $695.7 million and $598.4 million,
respectively. The components of EOTT's net revenues are as
follows:
<TABLE>
<CAPTION>
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Revenues $6,358,820 $7,696,734 $8,235,529
Cost of sales 6,231,583 7,605,273 8,102,917
Net revenues $ 127,237 $ 91,461 $ 132,612
</TABLE>
4. Income Taxes
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 principal components of Enron's net deferred
income tax liability at December 31, 1993 and 1992 are as
follows:
<TABLE>
<CAPTION>
(In Millions) 1993 1992
<S> <C> <C>
Deferred income tax assets -
Alternative minimum tax credit carryforward $ 219 $ 189
Other 18 28
237 217
Deferred income tax liabilities -
Depreciation, depletion and amortization 1,565 1,552
Deferred contract reformation costs 73 107
Other 464 377
2,102 2,036
Net deferred income tax liabilities* $1,865 $1,819
<FN>
*Includes $5 million in other current liabilities for 1993
and $60 million in other current assets for 1992.
</TABLE>
The components of income before income taxes and
extraordinary items are as follows:
<TABLE>
<CAPTION>
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
U.S. $336,445 $337,618 $269,970
Foreign 131,331 81,650 64,630
$467,776 $419,268 $334,600
</TABLE>
Total income tax expense is summarized as follows:
<TABLE>
<CAPTION>
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Payable currently -
Federal $ 57,093 $ 78,109 $117,402
State 14,692 13,284 6,074
Foreign 12,269 13,722 21,920
84,054 105,115 145,396
Payment deferred -
Federal (26,070) (40,361) (72,214)
State 15,724 13,375 26,909
Foreign 15,369 12,339 2,363
5,023 (14,647) (42,942)
89,077 90,468 102,454
Effect of tax rate increase on
deferred tax liability 46,177 - -
Total Income Tax Expense $135,254 $ 90,468 $102,454
</TABLE>
The differences between taxes computed at the U.S. Federal
statutory rate and Enron's effective rate are as follows:
<TABLE>
<CAPTION>
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Statutory Federal income tax
provision $163,722 $142,551 $113,764
Net state income taxes 18,980 17,595 21,769
ESOP dividends (5,356) (6,859) (7,115)
Revision of prior years' tax estimates (25,000) (11,200) (6,351)
Tax rate increase 46,177 - -
Net operating loss utilization - - (6,656)
Tight gas sands tax credit (65,172) (42,500) (16,926)
Asset and stock sale differences (21) (21,324) -
Other 1,924 12,205 3,969
$135,254 $ 90,468 $102,454
</TABLE>
Enron has an alternative minimum tax (AMT) credit
carryforward of approximately $219 million which can be used
to offset regular income taxes payable in future years. The
AMT credit has an indefinite carryforward period.
Foreign subsidiaries' cumulative undistributed earnings of
approximately $185 million are considered to be indefinitely
reinvested outside the U.S. and, accordingly, no U.S.
Federal or state 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. Determination of any potential amount
of unrecognized deferred income tax liability is not
practicable.
5. Supplemental Cash Flow Information
Cash paid for income taxes and interest expense is as
follows:
<TABLE>
<CAPTION>
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Income taxes $ 39,307 $111,125 $ 74,416
Interest (net of amounts
capitalized) 228,034 299,469 284,285
</TABLE>
Non-cash investing and financing activities during 1993
included the exchange of common stock for convertible
preferred stock of $33.3 million.
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. During 1991, non-cash investing and financing
activities included the exchange of common stock for
convertible subordinated debentures and convertible
preferred stock in transactions valued at $10.5 million and
$14.9 million, respectively.
Changes in components of working capital are as follows:
<TABLE>
<CAPTION>
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Receivables $(360,206) $ 118,854 $ 403,840
Inventories 92,228 (22,741) (15,597)
Payables 144,518 (55,188) (248,307)
Accrued taxes (11,941) (24,690) 50,307
Accrued interest 2,913 (25,088) 13,804
Other 55,975 (148,381) 145,217
Total $ (76,513) $(157,234) $ 349,264
</TABLE>
6. Credit Facilities, Short-Term Borrowings and Long-Term
Debt
Enron and EOG have credit facilities with domestic and
foreign banks which at December 31, 1993 provided for an
aggregate of $1.1 billion in long-term committed credit.
Expiration dates of the committed facilities range from
December 1994 to January 1997. 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 for Enron 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 1993, no amounts were
borrowed under these facilities.
Enron and EOG have also entered into agreements which
provide for uncommitted lines of credit totaling $1.06
billion at December 31, 1993. 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, 1993, Enron had
outstanding $144 million under certain of the uncommitted
lines at average interest rates of 3.6%. In addition to
borrowing from banks on a short-term basis, Enron and
certain of its subsidiaries sell commercial paper to provide
short-term financing for various corporate purposes. As of
December 31, 1993, 1992 and 1991, short-term borrowings of
$143.8 million, $101.0 million, and $243.7 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, 1993, 1992 and 1991, $132.4 million, $292.3 million, and
$289.8 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:
<TABLE>
<CAPTION>
(Dollars In Millions) 1993 1992 1991
<S> <C> <C> <C>
As of end of year
Borrowings from -
Commercial paper $ - $ 75.0 $ 189.2
Banks and other 143.8 26.0 54.5
Amount reclassified
as long-term debt (143.8) (101.0) (243.7)
Total short-term borrowings $ - $ - $ -
Weighted average interest rate
at end of year(a) 3.6% 3.7% 5.5%
For the year ended
Maximum borrowings
at any month end(a) $1,087.1 $885.5 $ 743.2
Average borrowings(a)(b) 590.9 588.0 500.3
Weighted average interest rate
during the year(a)(c) 3.3% 3.9% 6.3%
<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.
</TABLE>
Detailed information on long-term debt is as follows:
<TABLE>
<CAPTION>
December 31,
(In Thousands) 1993 1992
<S> <C> <C>
Enron Corp.
Debentures
6.75% due 2005 - senior subordinated $ 200,000 $ -
8.25% due 2012 - senior subordinated 150,000 150,000
Notes Payable
Variable rates - 10,000
8.15% to 9.25% due from 1994 to 1996 200,000 393,702
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 -
Other 57,512 10,484
Northern Natural Gas Company
Notes Payable
11.00% due 1995 - 88,573
8.00% due 1999 250,000 250,000
6.875% due 2005 100,000 -
Houston Pipe Line Company
Notes Payable
12.125% due 1995 100,000 100,000
Other - 24,062
Transwestern Pipeline Company
Notes Payable
7.55% to 9.10% due 2000 123,000 123,000
9.20% due 1998 to 2004 27,000 27,000
Enron Oil & Gas Company
Notes Payable
8.92% to 8.98% due 1995 50,000 50,000
9.10% due 1994 to 1998 100,000 100,000
Other 33,000 -
Amount reclassified from short-term debt 143,774 101,007
Unamortized debt discount and premium (8,023) (3,881)
Total Long-Term Debt $2,661,240 $2,458,924
</TABLE>
The aggregate annual maturity requirements applicable to
long-term debt outstanding at December 31, 1993 are $132.4
million, $153.4 million, $133.1 million, $22.9 million and
$169.0 million for 1994 through 1998, respectively. In
addition, based upon available committed credit facilities,
$143.8 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.
7. Accounts Receivable
Enron has entered into agreements which provide for the sale
of up to $800.0 million of trade accounts receivable with
limited recourse provisions. Included in this amount is a
$300.0 million agreement which will expire in April 1994 with
the remainder expiring in February 1995. At December 31,
1993 and 1992, $700.1 million and $700.0 million,
respectively, of receivables were sold under these
agreements.
The fees incurred on the sales of accounts receivables
totaled $20.6 million, $23.5 million and $37.8 million for
1993, 1992 and 1991, respectively. Additionally, fees
incurred in connection with other long-term obligations and
the sales of rights to certain recoverable take-or-pay
buyout and contract reformation costs totaled $5.1 million,
$12.5 million and $30.7 million, respectively, for 1993,
1992 and 1991 and are included in "Interest and Related
Charges, net", in the Consolidated Income Statement.
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. Credit
losses incurred on receivables in these industries compare
favorably to losses experienced on Enron's receivables
portfolio as a whole. Receivables are generally not
collateralized.
8. 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 in the Big Piney area of Wyoming for
consideration of $326.8 million (the production payment
agreement). The natural gas and other hydrocarbons were
originally scheduled to be produced and delivered over a
period of forty-five months, which period commenced October
1, 1992. Effective October 1, 1993, the agreement was
amended providing for the extension of the original term of
the volumetric production payment through March 31, 1999
based on a revised schedule of daily quantities of
hydrocarbons to be delivered which is approximately one-half
of the original schedule. EOG retains responsibility for
its working interest share of the cost of operations.
Proceeds from the sale were used to repay long-term debt and
for other corporate purposes. 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 remaining
amortization of deferred revenue, based on scheduled
deliveries under the amended production payment agreement at
December 31, 1993, 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 20).
9. Unconsolidated Subsidiaries
Enron has investments in and advances to unconsolidated
subsidiaries as follows:
<TABLE>
<CAPTION>
Ownership
Investee Interest December 31,
(In Thousands) 1993 1992
<S> <C> <C> <C>
Citrus Corp. 50% $169,984 $178,050
Northern Border Pipeline Company 35% - 207,459
Northern Border Partners, L.P. 13% 55,731 -
Teesside Power Limited 50% 173,915 20,475
Enron/Dominion Cogen Corp. 50% 46,243 49,911
Mojave Pipeline Company 50% - 42,464
Trailblazer Pipeline Company 33% 25,717 25,538
Oasis Pipe Line Company 25% 7,884 10,140
Madosa 42% 12,894 12,151
Argentina Southern Gas
Pipeline System 18% 97,450 23,689
Enron Liquids Pipeline, L.P. 15% 24,036 22,368
Other 83,230 43,817
$697,084 $636,062
</TABLE>
Enron's equity in earnings (losses) of unconsolidated
subsidiaries is as follows:
<TABLE>
<CAPTION>
Investee Year Ended December 31,
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Citrus Corp. $(8,066) $(11,059) $(4,601)
Northern Border Pipeline Company 22,934 34,004 24,181
Northern Border Partners, L.P. 1,368 - -
Teesside Power Limited 12,444 - -
Enron/Dominion Cogen Corp. 5,703 7,485 6,776
Mojave Pipeline Company 2,435 6,749 11,982
Trailblazer Pipeline Company 3,514 6,687 3,623
Oasis Pipe Line Company 1,299 2,879 5,830
Madosa 5,522 5,873 2,747
Argentina Southern Gas Pipeline
System 22,904 - -
Other 3,236 3,927 4,690
$73,293 $ 56,545 $55,228
</TABLE>
Summarized combined financial information of Enron's
unconsolidated subsidiaries is presented below:
<TABLE>
<CAPTION>
December 31,
(In Thousands) 1993 1992
<S> <C> <C>
Balance Sheet
Current assets $ 921,850 $1,476,459
Property, plant and equipment, net 4,054,780 4,853,117
Other noncurrent assets 2,330,387 600,060
Current liabilities 982,874 645,981
Noncurrent liabilities 4,584,922 5,174,091
Owners' equity 1,739,221 1,109,564
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Income Statement
Operating revenues $2,351,177 $1,825,158 $1,352,232
Operating expenses 2,016,977 1,528,770 1,064,360
Net income 204,262 122,346 163,886
Distributions Paid to Enron 59,585 42,490 45,973
</TABLE>
Northern Border Partners, L.P. During October 1993,
Northern Plains Natural Gas Company, 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 Partnership), in exchange for general
partner interests, subordinated units and common units in
the Partnership. Northern Plains sold its common units in
the Partnership in an underwritten public offering and
received net proceeds of approximately $217 million
resulting in a pretax gain of approximately $64 million.
Northern Plains retained a 13% interest in the Partnership.
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. The remaining 50% ownership
interest is held by four of the twelve regional electric
companies operating in England.
Under the terms of the Shareholder Agreement relating to
Teesside, Enron made a capital investment of $151 million on
April 1, 1993. An affiliate of Enron operates the facility
which was placed in commercial operation on March 27, 1993.
Construction revenue and profit have been recognized on the
portion of the joint venture not owned by Enron using the
percentage of completion method of accounting. Revenue and
profit on that portion of the joint venture owned by Enron
have been deferred and are being amortized.
Enron has guaranteed the payment of Teesside's obligation in
connection with certain grid connection charges which could
become due should the power plant terminate operations.
Further, Enron has guaranteed the payment of its
proportionate share of amounts which could become due in the
event of default by Teesside under the terms of the power
sales agreements (see Note 16).
Under the terms of certain gas supply agreements extending
through 2008, Teesside is obligated to take-or-pay for an
average of up to 240 billion British Thermal Units of
natural gas per day at indexed prices. Enron has guaranteed
70% of Teesside's payment obligation under the gas supply
agreements. However, Enron believes there are alternative
markets for such gas should the gas not be taken by
Teesside.
Joint Energy Development Investments. In 1993, Joint
Energy Development Investments (JEDI), a limited partnership,
was formed, comprised of an Enron Subsidiary as general
partner and the California Public Employees Retirement System
(CalPERS) as limited partner, to acquire energy investments.
Enron and CalPERS each own a 50% interest and have each
committed to invest $250 million of capital over the next
three years in JEDI, $5 million of which has already been
contributed as of December 31, 1993. Enron intends to meet
its required capital commitments by contributing Enron common stock.
10. Preferred Stock
Convertible Preferred Stock. Each share of the $10.50
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 call at Enron's option at a price of $100 per
share plus accrued dividends. Upon involuntary liquidation,
holders would be entitled to $100 per share. During 1993,
1992 and 1991, 332,964 shares, 397,710 shares and 148,497
shares, respectively, of the Convertible Preferred Stock
were converted into common stock.
Preferred Stock of Subsidiary Company. 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. Net proceeds of approximately $207 million were used
by Enron to reduce indebtedness and for other corporate
purposes. The MIPS are redeemable at the option of Enron in
whole or in part beginning November 1998 at a redemption
price of $25 per share plus accumulated and unpaid
dividends. Upon liquidation of Enron Capital LLC, the
holders of the MIPS are entitled to $25 per share.
11. 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.
The dividend history during each of the three years in the
period ended December 31, 1993 is as follows: Enron paid
quarterly cash dividends on common stock of $.155 per share
($.62 per share annually) until the final quarter of 1991 at
which time the dividend was increased to $.1625 per share
($.65 per share annually). The dividend was increased to
$.175 per share ($.70 per share annually) for the final
quarter of 1992 and was further increased to $.1875 per
share ($.75 per share annually) for the final quarter of
1993. Enron's debt agreements do not limit the payment of
cash dividends on common stock. Common stock information is
as follows:
<TABLE>
<CAPTION>
(In Thousands) 1993(a) 1992 1991
<S> <C> <C> <C>
Common Stock, beginning of year 237,532 103,269 50,625
Issued to Employee Benefit Plans 1,394 11,149 303
Conversions 2,447 3,949 707
Other 156 399 -
Dividend reinvestment 66 - -
Flexible Equity Trust 7,500 - -
Stock Split - - 51,634
Common Stock, end of year 249,095 118,766 103,269
<FN>
(a) Presented as if the 1993 stock split was January 1, 1993.
</TABLE>
Treasury stock information is as follows:
<TABLE>
<CAPTION>
1993(d) 1992 1991
<S> <C> <C> <C>
Treasury Stock, beginning of year 349,400 2,050,644 177,755
Employee Benefit Plans
Issued (1,435,687) (1,314,196) (343,249)
Returned 98,381 15,021 7,754
Open Market Purchases(a) 3,005,200 1,610,100 1,173,800
Conversions(b) (2,043,090) (2,205,393) -
Other(c) 69,404 18,524 9,262
Dividend Reinvestment Plan (43,608) - -
Stock Split - - 1,025,322
Treasury Stock, end of year - 174,700 2,050,644
<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) Purchased pursuant to compensation agreements.
(d) Presented as if the 1993 stock split was January 1, 1993.
</TABLE>
During 1993, Enron issued 130,329,224 shares of its common
stock in connection with certain transactions including the
two-for-one stock split, the conversion of preferred stock
and employee benefit plans.
Enron has various stock option plans (the Plans) under which
options for shares of Enron's common stock have been or may
be granted to officers, key 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,
1993 range from July 9, 1994 to September 23, 2003. 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:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Shares under option,
beginning of year 7,314,332 8,996,560 9,406,204
Granted 4,253,233 1,409,480 2,992,000
Exercised (1,621,680) (2,807,984) (2,868,092)
Cancelled or expired (266,166) (283,724) (533,552)
Shares under option, end of year 9,679,719 7,314,332 8,996,560
Shares available for grant at
end of year 1,500,301* 5,582,480* 6,954,400*
Shares exercisable at end of year 3,104,722 2,199,224 2,983,784
Average price of options exercised
during the year $13.30 $11.82 $11.05
Average price of options outstanding
at end of year $19.64 $13.47 $12.60
<FN>
*Excludes up to 2,528,560 shares, 2,730,780 shares
and 2,750,000 shares as of December 31, 1993, 1992 and 1991,
respectively, which may be issued as either Restricted Stock
or as stock options.
</TABLE>
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:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Outstanding at beginning of year 35,588 365,088 223,624
Granted 203,700 19,220 270,080
Cancelled or expired (3,632) - (9,840)
Issued (13,998) (348,720) (118,776)
Outstanding at end of year 221,658 35,588 365,088
Available for grant at end of year 2,528,560 2,730,780 2,750,000
Average price per share
on date of grant $27.50 $11.18 $11.08
</TABLE>
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 "Other" shareholders' equity.
Common shares held by the Trust are not included in the computation
of earnings per share.
12. 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. 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.
Enron 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:
<TABLE>
<CAPTION>
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Service cost - benefits earned
during the year $ 11,709 $ 10,224 $ 7,960
Interest cost on projected
benefit obligation 25,230 22,699 20,008
Actual return on plan assets (37,507) (52,141) (43,092)
Amortization and deferrals 11,184 28,897 21,775
Early retirement termination benefits - 166 -
Pension expense $ 10,616 $ 9,845 $ 6,651
</TABLE>
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 at December 31, 1993 and 1992.
Assets of the ESOP offset retirement benefits accrued under
the Enron Plan only to the extent allocated to individual
employee retirement accounts.
<TABLE>
<CAPTION>
(In Thousands) 1993 1992
<S> <C> <C>
Actuarial present value of accumulated
benefit obligation at September 30
Vested $(284,559) $(204,176)
Nonvested (27,862) (15,696)
Additional amounts related to
projected wage increases (66,641) (65,796)
Projected benefit obligation (379,062) (285,668)
Plan assets at fair value(a) 404,397 300,755
Projected benefit obligation less than
Plan assets 25,335 15,087
Unrecognized net loss 29,690 51,762
Unrecognized prior service cost 14,113 15,810
Unrecognized net asset at transition (48,272) (56,634)
Contributions 815 2,004
Prepaid pension cost at December 31 $ 21,681 $ 28,029
Discount rate 7.00% 9.00%
Long-term rate of return on assets 10.50 10.50
Rate of increase in wages 4.00 5.00
<FN>
(a) Includes plan assets of the ESOP of $286,041 and
$193,144 for the years 1993 and 1992, respectively.
</TABLE>
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.
13. Postretirement 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.
Effective January 1, 1993, Enron adopted the provisions of
SFAS No. 106 - "Employers Accounting for Postretirement
Benefits Other Than Pensions". SFAS No. 106 requires that
employers providing postretirement benefits accrue those
costs over the service lives of the employees expected to be
eligible to receive such benefits. Enron has elected the
prospective transition approach and 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.
<TABLE>
<CAPTION>
(In Thousands) 1993
<S> <C>
Actuarial present value of accumulated
postretirement benefit obligation (APBO)
Retirees $ (93,101)
Fully eligible active plan participants (2,748)
Other employees (21,611)
Total APBO (117,460)
Plan assets at fair value 1,938
Accumulated postretirement benefit
obligation in excess of plan assets (115,522)
Unrecognized transition obligation 79,547
Unrecognized prior service costs 19,297
Unrecognized net loss 14,249
Accrued postretirement benefit obligation $ (2,429)
</TABLE>
The components of net periodic postretirement benefit
expenses are as follows:
<TABLE>
<CAPTION>
(In Thousands) 1993
<S> <C>
Service costs $ 850
Interest costs 7,374
Return on plan assets (39)
Amortization of transition obligation 4,744
Postretirement benefit expense $12,929
</TABLE>
The measurement of the APBO assumes a 7% discount rate and a
health care cost trend rate of 13% in 1993 decreasing to 5%
by the year 2005 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 $9.7
million and $0.6 million, respectively.
14. Natural Gas Rates and Regulatory Issues
Regulatory issues on Enron's regulated pipelines are subject
to final determination by the FERC. Enron has provided a
reserve related to pending regulatory issues and believes
that the ultimate resolution of such issues will not have a
materially adverse impact on Enron's financial position or
results of operations.
The regulated pipelines have all successfully completed
their transitions under FERC Order 636 (currently under
appeal before the U.S. Court of Appeals for the 11th
Circuit), and have completely unbundled their sales services
from their transportation services. As required by Order 636,
each of the regulated pipelines has implemented a straight
fixed variable rate design which provides that all fixed costs
to firm customers including return on equity, are to be
received through fixed monthly demand or capacity reservation
charges which are not a function of volumes transported.
Under their respective restructuring orders, the regulated
pipelines are entitled to recover FERC Order 636 transition
costs from customers. Transition costs incurred of $168
million have been deferred pending recovery from customers
over varying time periods, generally of up to five years. Future
transition costs are subject to ongoing negotiations and
market factors. Enron believes that the ultimate resolution
of FERC Order 636 transition costs will not have a material
impact on Enron's financial position or results of
operations.
15. 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 petition 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
fraud, land fraud, negligent misrepresentation and breach of
state antitrust laws. Trial is set for May 2, 1994.
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, 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.
Like other companies in the natural gas industry, Enron has
certain gas purchase contracts which provide for take-or-pay
obligations and fixed prices. Certain suppliers have made
claims, either formally or informally, for payment under
take-or-pay provisions. At December 31, 1993, amounts of
pending take-or-pay claims and litigation are not material.
Peruvian Operations
During 1985, the Peruvian government unilaterally cancelled
certain exploration and production agreements between the
government-owned oil company and Belco Petroleum Corporation
of Peru (BPCP), a wholly-owned subsidiary of Enron, and
subsequently nationalized the operations of BPCP. Enron
filed claims with its insurers in connection with the
nationalization and in February 1989, the insurers paid
Enron approximately $162 million. On September 21, 1993,
the Peruvian government signed a settlement agreement with
American International Group, Inc. and BPCP which will allow
Enron to recover its remaining investment of approximately
$33 million.
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.
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, management does not believe that
any potential assessments in connection with these PRP
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.
16. Commitments
Firm Transportation Obligations
Enron has firm transportation agreements with various joint
ventures. Under these agreements, Enron must make
specified minimum payments each month. The estimated
aggregate amounts of such required future payments at
December 31, 1993, were:
<TABLE>
<CAPTION>
(In Millions)
<C> <C>
1994 $ 40.2
1995 40.1
1996 108.2
1997 117.2
1998 118.9
Later years 1,240.0
Total $1,664.6
</TABLE>
The costs incurred under these agreements, including
commodity charges on actual quantities shipped, totaled
$38.2 million, $42.7 million and $53.8 million in 1993, 1992
and 1991, respectively. Enron has assigned a firm
transportation contract with one of its joint venture pipelines
to a third party and guaranteed minimum payments under the
contract averaging approximately $43 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 $955 million at December
31, 1993.
During July 1992, Enron modified and extended an agreement
entered into in 1988 for a substantial amount of data
processing facilities management services. The modification
extends the original 10 year agreement for a period of three
years through 2001. As part of the agreement, Enron prepaid
$150 million for certain services to be performed over the
life of the agreement.
Future commitments related to these items at December 31,
1993 are as follows:
<TABLE>
<CAPTION>
(In Millions)
<C> <C>
1994 $ 194.1
1995 243.4
1996 334.9
1997 114.3
1998 105.3
Later years 650.3
Total minimum payments $1,642.3
</TABLE>
Total rent expense incurred during 1993, 1992 and 1991 was
$104.1 million, $64.7 million and $85.9 million, respectively.
Enron guarantees certain long-term contracts for the sale of
electrical power and steam from the Texas City 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
subsidiaries in connection with letters of credit issued on
behalf of those subsidiaries. At December 31, 1993, a total
of $124 million of such guarantees were outstanding.
Management does not expect to incur any material liabilities
as a result of these obligations. In addition, Enron is a
guarantor on certain debt of unconsolidated joint ventures
and unconsolidated subsidiaries and other companies totaling
approximately $305 million. Management does not consider it
likely that there would be any losses associated with these
guarantees. In addition, certain commitments have been made
related to 1994 planned capital expenditures.
17. Other Income, Net
The components of Other Income, Net are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Gains on sales of Mobil stock $ - $ 52,048 $27,944
Gains on sales of oil and
gas properties 13,318 6,037 14,983
Gains on sales of other
assets and investments 102,268 18,549 15,426
Regulatory, contingency
and other adjustments (55,689) (40,927) 11,036
Litigation adjustments and
settlements, net 4,282 (41,870) 27,086
Other 11,254 (10,210) 9,611
$75,433 $(16,373) $106,086
</TABLE>
18. Financial Instruments
The following disclosures on the estimated fair value of
financial instruments are presented in accordance with the
requirements of SFAS No. 107 - "Disclosures About Fair Value
of Financial Instruments." Fair value as used in SFAS No.
107 represents the amount at which the instrument could be
exchanged in a current transaction between willing parties.
The estimated fair value amounts have been determined by
Enron 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. The amounts disclosed below
exclude Enron's price risk management activities discussed
in Notes 1 and 2.
<TABLE>
<CAPTION>
December 31, 1993 December 31, 1992
Carrying Estimated Carrying Estimated
(In Millions) Amount Fair Value Amount Fair Value
<S> <C> <C> <C> <C>
Balance Sheet Financial
Instruments
Long-term debt $2,661.2 $2,903.4 $2,458.9 $2,603.0
Other Financial Instruments
Interest rate swap agreements - (2.3) - (4.8)
Foreign currency contracts - (0.1) - 0.3
Guarantees - (2.7) - (9.3)
</TABLE>
Long-Term Debt. The fair market value of long-term debt 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.
Interest Rate Swap Agreements. Enron and EOG have entered
into various interest rate swap transactions to hedge
certain floating interest rate exposure in 1993 and 1994.
This floating interest rate exposure arises primarily from
short-term interest bearing debt as well as certain
operating lease obligations and accounts receivable sales
for which payments are subject to floating interest rates
(see Notes 6, 7 and 16).
At December 31, 1993, Enron and EOG had outstanding interest
rate swap agreements with a notional principal amount of
$3.6 billion. During January 1994, Enron executed
additional swap agreements with notional principal amounts
totaling $700 million. Included in the $4.3 billion total
swap agreements is $2.1 billion notional principal amount of
interest rate swap agreements which expired subsequent to
December 31, 1993 and which were executed to hedge
anticipated floating rate exposure in 1993. Also included
are approximately $2.1 billion notional principal amount of
interest rate swap agreements executed to hedge anticipated
floating rate exposure in 1994. The remaining notional
principal amounts include swap agreements extending beyond
1994. The fair value of interest rate swap agreements is
based upon termination values obtained from third parties.
Credit Risk. While notional contract amounts are used to
express the volume of interest rate swap agreements, the
amounts potentially subject to credit risk, in the event of
nonperformance by the third parties, are substantially
smaller. Enron does not anticipate any material impact to
its financial position or results of operations as a
result of nonperformance by the third parties.
Price Risk Management. Enron entered into certain price
swap agreements to, in effect, hedge the market risk caused
by fluctuations in the price of natural gas. The agreements
call for Enron to make payments to (or receive payments
from) the other party based upon the differential between a
fixed and a variable price for natural gas as specified by
the contract. The current swap agreements run for periods
of ten years and have a notional contract amount of
approximately $299 million at December 31, 1993.
Foreign Currency Contracts. Foreign currency contracts are
entered into to hedge currency exposure from commercial
transactions. At December 31, 1993, foreign currency
contracts with a principal amount of $38.3 million were
outstanding. Fair value of such contracts are based upon
year-end fair market values.
Guarantees. As more fully discussed in Notes 9 and 16,
Enron is a guarantor on certain debt and lease obligations.
The fair value of such guarantees is based upon Enron's
estimation of the cost of securing third party letters of
credit equal to Enron's obligations under such guarantees.
19. Business and Geographic Segment Information
Enron's operations are classified into five business
segments:
Transportation and Operation - Transmission of natural gas.
Construction, management and operation of pipelines, liquids
plants and power facilities. Crude oil transportation
activities and investment in liquids pipeline operations.
Gas Services - Purchasing, marketing and financing of natural
gas, natural gas liquids and power. Price risk management
in connection with natural gas and natural gas liquids transactions.
Intrastate natural gas pipelines. Development, acquisition
and promotion of natural gas fired power plants in North
America.
Gas Processing - Extraction of natural gas liquids in North America.
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 and Trinidad.
Enron's business segment information has been reclassified
from prior years to reflect the realignment of Enron's
operations. Financial information by business and
geographic segment for each of the three years in the period
ended December 31, 1993, is presented below.
Operations In Business and Geographic Segments
Business Segments
<TABLE>
<CAPTION>
International
Transportation Gas and Exploration Corporate
and Gas Gas Power and and
(In Thousands) Operation Services Processing Services Production Other(c)(d) Total
<S> <C> <C> <C> <C> <C> <C> <C>
1993
Unaffiliated Revenues(a) $1,385,925 $5,392,121 $ 57,825 $ 751,375 $ 385,236 $ - $ 7,972,482
Intersegment Revenues(b) 80,081 243,646 386,976 19,213 301,691 (1,031,607) -
Total Revenues 1,466,006 5,635,767 444,801 770,588 686,927 (1,031,607) 7,972,482
Depreciation, Depletion
and Amortization 115,922 74,677 6,283 9,081 249,704 2,521 458,188
Operating Income (Loss) 341,272 149,886 5,687 64,582 102,241 (46,184) 617,484
Equity in Earnings of
Unconsolidated Subsidiaries 22,427 8,821 - 41,962 - 83 73,293
Other Income, net 18,437 10,115 22,351 24,835 19,953 11,199 106,890
Income Before Interest,
Minority Interest
and Income Taxes 382,136 168,822 28,038 131,379 122,194 (34,902) 797,667
Additions to Property,
Plant and Equipment 144,835 78,453 24,065 52,545 383,064 5,070 688,032
Identifiable Assets 2,808,816 5,165,809 186,354 492,297 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 $5,249,169 $186,354 $ 807,758 $1,668,395 $ 504,911 $11,504,315
1992
Unaffiliated Revenues(a) $1,418,761 $3,806,088 $65,980 $ 864,695 $ 253,749 $ - $ 6,409,273
Intersegment Revenues(b) 82,513 152,371 361,043 10,529 300,375 (906,831) -
Total Revenues 1,501,274 958,459 427,023 875,224 554,124 (906,831) 409,273
Depreciation, Depletion
and Amortization 111,141 70,438 6,283 6,897 179,839 1,421 376,019
Operating Income (Loss) 314,412 160,167 54,132 (4,502) 99,572 (10,009) 613,772
Equity in Earnings of
Unconsolidated Subsidiaries 36,628 12,391 1,926 5,505 - 95 56,545
Other Income, net 27,267 (26,012) (211) 32,074 2,561 61,186 96,865
Income Before Interest,
Minority Interest
and Income Taxes 378,307 146,546 55,847 33,077 102,133 51,272 767,182
Additions to Property,
Plant and Equipment 144,468 33,584 34,211 10,236 362,403 11,983 596,885
Identifiable Assets 2,420,053 4,085,861 222,727 388,248 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 $4,161,344 $222,727 $ 468,239 $1,563,136 $ 996,858 $10,311,603
1991
Unaffiliated Revenues(a) $1,519,147 $2,901,382 $ 67,250 $1,022,998 $ 172,164 $ - $ 5,682,941
Intersegment Revenues(b) 109,930 81,311 329,230 7,778 297,878 (826,127) -
Total Revenues 1,629,077 2,982,693 396,480 1,030,776 470,042 (826,127) 5,682,941
Depreciation, Depletion
and Amortization 108,922 85,342 5,377 4,648 160,885 783 365,957
Operating Income (Loss) 275,013 56,994 91,534 40,117 63,401 (29,122) 497,937
Equity in Earnings of
Unconsolidated Subsidiaries 37,000 13,355 - 4,643 - 230 55,228
Other Income, net 31,393 765 2,636 24,075 11,768 91,500 162,137
Income Before Interest,
Minority Interest
and Income Taxes 343,406 71,114 94,170 68,835 75,169 62,608 715,302
Additions to Property,
Plant and Equipment 368,756 40,849 43,216 7,934 211,673 34,655 707,083
Identifiable Assets 2,682,546 3,763,396 265,636 346,494 1,410,244 1,043,327 9,511,643
Investments in and Advances
to Unconsolidated Subsidiaries 502,737 33,625 - 20,280 - 1,385 558,027
Total Assets $3,185,283 $3,797,021 $265,636 $ 366,774 $1,410,244 $1,044,712 $10,069,670
<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.
</TABLE>
Geographic Segments
<TABLE>
<CAPTION>
Year Ended December 31,
(In Thousands) 1993 1992 1991
<S> <C> <C> <C>
Operating Revenues from
Unaffiliated Customers
United States $ 7,058,088 $5,515,600 $4,644,267
Foreign 914,394 893,673 1,038,674
$ 7,972,482 $6,409,273 $5,682,941
Intersegment Sales
United States $ 20,785 $ 54,498 $ 267,119
Foreign 66,574 24,108 23,545
$ 87,359 $ 78,606 $ 290,664
Operating Income
United States $ 553,956 $ 628,542 $ 471,091
Foreign 63,528 (14,770) 26,846
$ 617,484 $ 613,772 $ 497,937
Income Before Interest,
Minority Interest and Taxes
United States $ 663,276 $ 743,623 $ 656,169
Foreign 134,391 23,559 59,133
$ 797,667 $ 767,182 $ 715,302
Identifiable Assets
United States $ 9,939,618 $8,982,307 $8,855,302
Foreign 867,613 693,234 656,341
$10,807,231 $9,675,541 $9,511,643
</TABLE>
20. 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
<TABLE>
<CAPTION>
December 31,
(In Thousands) 1993 1992
<S> <C> <C>
Proved properties $2,675,419 $2,396,601
Unproved properties 96,801 78,770
2,772,220 2,475,371
Accumulated depreciation,
depletion and amortization (1,226,175) (1,007,360)
Net capitalized costs $1,546,045 $1,468,011
</TABLE>
Costs Incurred in Oil and Gas Property Acquisition, Exploration
and Development Activities(a)
<TABLE>
<CAPTION>
Foreign
(In Thousands) United States Canada Other Total
<S> <C> <C> <C> <C>
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 19,439 82,453
Development 247,705 28,045 41,785 317,535
Total $331,934 $44,295 $62,111 $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 11,141 55,475
Development 256,814 5,162 735 262,711
Total $343,163 $51,403 $11,879 $406,445
1991
Acquisition of properties
Unproved $12,156 $ 223 $ 176 $ 12,555
Proved 40,039 2,362 - 42,401
Total 52,195 2,585 176 54,956
Exploration 39,916 5,369 15,062 60,347
Development 132,200 10,338 - 142,538
Total $224,311 $18,292 $15,238 $257,841
<FN>
(a) Costs have been categorized on the basis of Financial
Accounting Standards Board definitions which include costs of oil
and gas producing activities whether capitalized or charged to
expense as incurred.
</TABLE>
Results of Operations for Oil and Gas Producing Activities(a)
The following tables set forth results of operations for oil and
gas producing activities for the three years in the period ended
December 31, 1993:
<TABLE>
<CAPTION>
Foreign
(In Thousands) United States Canada Other Total
<S> <C> <C> <C> <C>
1993
Operating Revenues
Associated Companies $369,824 $ 9,637 $ - $379,461
Trade 140,552 33,228 1,209 174,989
Total 510,376 42,865 1,209 554,450
Exploration expenses,
including dry hole costs 35,029 6,657 13,590 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 14,630 541 249,463
Income (loss) before
income taxes 145,789 6,547 (14,418) 137,918
Income tax expense (benefit) (20,329) 2,447 (2,762) (20,644)
Results of Operations $166,118 $ 4,100 $(11,656) $158,562
1992
Operating Revenues
Associated Companies $251,649 $10,074 $ - $261,723
Trade 106,633 19,313 - 125,946
Total 358,282 29,387 - 387,669
Exploration expenses,
including dry hole costs 29,705 3,829 10,508 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 85,238 3,534 (12,936) 75,836
Income tax expense (benefit) (16,030) 1,202 (4,398) (19,226)
Results of Operations $101,268 $ 2,332 $(8,538) $ 95,062
1991 (Restated)
Operating Revenues
Associated Companies $197,841 $10,244 $ - $208,085
Trade 78,964 19,004 - 97,968
Total 276,805 29,248 - 306,053
Exploration expenses,
including dry hole costs 28,107 3,659 14,402 46,168
Production costs 56,167 9,418 - 65,585
Impairment of unproved
oil and gas properties 10,342 2,449 - 12,791
Depreciation, depletion
and amortization 148,401 12,385 99 160,885
Income (loss) before
income taxes 33,788 1,337 (14,501) 20,624
Income tax expense (benefit) (5,076) 455 (4,930) (9,551)
Results of Operations $38,864 $ 882 $ (9,571) $ 30,175
<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, 1993. 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.
</TABLE>
Oil and Gas Reserve Information (Unaudited)
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, 1993, 1992 and 1991 were based on studies
performed by Enron's engineering staff for reserves in the
United States, Canada and Trinidad. Opinions by DeGolyer
and MacNaughton, independent petroleum consultants, for the
years ended December 31, 1993, 1992 and 1991 covering
producing areas containing 65%, 69% and 73%, 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)
<TABLE>
<CAPTION>
(In Thousands) United States Canada Trinidad Total
<S> <C> <C> <C> <C>
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)
1991
Future revenues(b) $2,501,439 $269,917 $ - $2,771,356
Future production costs (504,420) (79,413) - (583,833)
Future development costs (189,091) (6,132) - (195,223)
Future net cash flows before
income taxes 1,807,928 184,372 - 1,992,300
Discount to present value
at 10% annual rate (618,919) (62,137) - (681,056)
Present value of future net
cash flows before income taxes 1,189,009 122,235 - 1,311,244
Future income taxes discounted
at 10% annual rate(c) (127,188) (27,979) - (155,167)
Standardized measure of
discounted future net
cash flows relating to proved
oil and gas reserves(b) $1,061,821 $ 94,256 $ - $1,156,077
<FN>
(a) Includes amounts attributable to a 20% minority
interest at December 31, 1993 and 1992 and a 16% minority
interest at December 31, 1991.
(b) Based on year-end market prices determined at the
point of delivery from the producing unit.
(c) Future income taxes before discount were $540.3
million U.S., $91.7 million Canada and $35.5 million
Trinidad, $394.1 million U.S. and $63.0 million Canada
and $279.4 million U.S. and $53.0 million Canada for the
years ended December 31, 1993, 1992 and 1991, respectively.
(d) "Future revenues" includes approximately $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 8).
(e) Includes approximately $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.
</TABLE>
Changes in Standardized Measure of
Discounted Future Net Cash Flows
<TABLE>
<CAPTION>
(In Thousands) United States Canada Trinidad Total
<S> <C> <C> <C> <C>
December 31, 1990 $ 928,584 $130,742 $ - $1,059,326
Sales and transfers of
oil and gas produced, net
of production costs (220,638) (19,830) - (240,468)
Net changes in prices
and production costs (150,061) (51,609) - (201,670)
Extensions, discoveries,
additions and improved
recovery, net of related
costs 212,097 4,802 - 216,899
Development costs incurred 36,719 11 - 36,730
Revisions of estimated
development costs 1,640 2,833 - 4,473
Revisions of previous
quantity estimates 37,535 1,178 - 38,713
Accretion of discount 116,559 17,823 - 134,382
Net change in income taxes 109,821 19,512 - 129,333
Purchases of reserves in place 38,350 (558) - 37,792
Sales of reserves in place (17,321) (2,328) - (19,649)
Changes in timing and other (31,464) (8,320) - (39,784)
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
</TABLE>
Reserve Quantity Information
Enron's estimates of net proved and proved developed
reserves of crude oil, condensate, natural gas liquids and
natural gas and of changes in net proved reserves were as
follows:
<TABLE>
<CAPTION>
United States Foreign(d) Total
<S> <C> <C> <C>
Natural gas (MMcf)
Proved reserves at
December 31, 1990(a) 1,343,467 131,508 1,474,975
Revisions of previous estimates 48,371 35 48,406
Purchases in place 45,030 2,885 47,915
Extensions, discoveries and
other additions 199,410 6,193 205,603
Sales in place (6,933) (2,477) (9,410)
Production (173,460) (9,237) (182,697)
Proved reserves at
December 31, 1991(a) 1,455,885 128,907 1,584,792
Revisions of previous estimates (46,325) (4,082) (50,407)
Purchases in place 30,537 112,592 143,129
Extensions, discoveries and
other additions 228,044 6,336 234,380
Sales in place (27,707) (2) (27,709)
Production (200,054) (11,249) (211,303)
Proved reserves at
December 31, 1992(a) 1,440,380(b) 232,502 1,672,882
Revisions of previous estimates (31,282) 11,058 (20,224)
Purchases in place 9,183 2,627 11,810
Extensions, discoveries and
other additions 234,858 148,970 383,828
Sales in place (12,453) (1,501) (13,954)
Production (240,014) (22,137) (262,151)
Proved reserves at
December 31, 1993(a) 1,400,672(b) 371,519 1,772,191
United States Foreign(d) Total
Liquids (MBbl)(c)
Proved reserves at
December 31, 1990(a) 16,272 6,856 23,128
Revisions of previous estimates (86) 256 170
Purchases in place 173 42 215
Extensions, discoveries and
other additions 983 310 1,293
Sales in place (1,248) (25) (1,273)
Production (2,272) (927) (3,199)
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 3,366 6,918
Sales in place (3,230) (23) (3,253)
Production (2,520) (965) (3,485)
Proved reserves at
December 31, 1993(a) 13,172(b) 7,689 20,861
Proved developed reserves
Natural gas (MMcf)
December 31, 1990 1,023,711 114,045 1,137,756
December 31, 1991 1,138,530 112,975 1,251,505
December 31, 1992 1,168,386(b) 194,366 1,362,752
December 31, 1993 1,167,313(b) 321,965 1,489,278
Liquids (MBbl)(c)
December 31, 1990 15,269 6,804 22,073
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) 7,000 18,165
<FN>
(a) Includes reserves attributable to a 20% minority
interest at December 31, 1993 and 1992 and a 16% minority
interest at December 31, 1991 and 1990.
(b) Includes approximately 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 8).
(c) Includes crude oil, condensate and natural gas liquids.
(d) Includes Canada and Trinidad.
</TABLE>
Enron Corp. and Subsidiaries
Supplemental Financial Information (unaudited)
Quarterly Results(b)
<TABLE>
<CAPTION>
Income Fully
Before Primary Diluted
Interest Earnings Earnings
(In Thousands, Minority Per Share(a) Per Share(a)
Except Per Share Operating Gross Interest and Net Net Net
Amounts) Revnues Profit Income Taxes Income Income Income
<S> <C> <C> <C> <C> <C> <C>
1993
First Quarter $1,857,455 $600,994 $268,249 $146,228 $.60 $.55
Second Quarter 1,907,115 530,388 151,673 61,245 .24 .23
Third Quarter 1,933,666 649,663 168,834 20,995 .07 .07
Fourth Quarter 2,274,246 625,411 208,911 104,054 .42 .39
1992
First Quarter $1,519,092 $565,268 $237,249 $115,764 $.54 $.49
Second Quarter 1,335,424 481,332 155,032 50,565 .21 .21
Third Quarter 1,521,794 513,766 150,179 40,887 .15 .15
Fourth Quarter 2,032,963 626,512 224,722 98,969 .40 .37
<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.
</TABLE>
<TABLE>
Exhibit 11
ENRON CORP. AND SUBSIDIARIES
Calculation of Earnings Per Share
(Unaudited)
<CAPTION>
Year Ended December 31,
1993 1992 1991
(in thousands except
per share amounts)
<S> <C> <C> <C>
Primary Earnings Per Share
Earnings on common stock
Income before extraordinary items $332,522 $328,800 $232,146
Preferred stock dividends (16,919) (22,109) (24,740)
315,603 306,691 207,406
Extraordinary items - (22,615) -
$315,603 $284,076 $207,406
Average number of common shares outstanding 239,019 219,965 202,080
Primary earnings per share of common stock
Income before extraordinary items $ 1.32 $ 1.39 $ 1.03
Extraordinary items - (.10) -
$ 1.32 $ 1.29 $ 1.03
Fully Diluted Earnings Per Share
Adjusted earnings on common stock
Income before extraordinary items $332,522 $328,800 $232,146
Preferred stock dividends (16,919) (22,109) (24,740)
Add back:
Dividends on convertible preferred stock 16,919 22,109 24,740
Interest paid on convertible debentures - 1,463 6,309
332,522 330,263 238,455
Extraordinary items - (22,615) -
$332,522 $307,648 $238,455
Average number of common shares outstanding
on a fully diluted basis
Average number of common shares
outstanding 239,019 219,965 202,080
Additional shares issuable upon:
Conversion of preferred stock 22,379 29,248 32,192
Conversion of convertible debentures - 1,966 7,618
Exercise of stock options reduced
by the number of shares which could
have been purchased with the proceeds
from exercise of such options 3,930 3,064 972
265,328 254,243 242,862
Fully diluted earnings per share of
common stock
Income before extraordinary items $ 1.25 $ 1.30 $ .98
Extraordinary items - (.09) -
$ 1.25 $ 1.21 $ .98
</TABLE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report dated February 18, 1994 included
in this Form 8-K, into Enron Corp.'s previously filed
Registration Statement Nos. 2-90992 (1984 Stock Option
Plan), 2-86917 (Dividend Reinvestment Plan), 33-13397
(Savings Plan), 33-34796 (Savings Plan), 33-52261 (Savings
Plan), 33-13498 (1986 Stock Option Plan), 33-35065 (Employee
Stock Ownership Plan), 33-43324 ($300 million Debt
Securities), 33-50641 (Enron Corp. Debt Securities and
Second Preferred Stock and Enron Capital LLC Preferred
Shares), 33-27893 (1988 Stock Option Plan), 33-46459 ($700
million Senior Subordinated Debt Securities), 33-55580
(569,354 Shares of Common Stock), 33-54132 (395,935 Shares
of Common Stock), 33-52768 (Enron Corp. 1991 Stock Plan), 33-
49839 (1,253,768 Shares of Common Stock), and 33-52143
(955,640 Shares of Common Stock). It should be noted that
we have not audited any financial statements of Enron Corp.
subsequent to December 31, 1993 or performed any audit
procedures subsequent to the date of our report.
ARTHUR ANDERSEN & CO.
Houston, Texas
March 1, 1994
