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 8, 1996
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)
1 of 41
<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, 1995, 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 8, 1996 By: Jack I. Tompkins
Jack I. Tompkins
Senior Vice President and Chief
Information, Administrative and
Accounting Officer
2
<PAGE>
ENRON CORP. AND SUBSIDIARIES
TABLE OF CONTENTS
Page No.
Management's Discussion and Analysis 4
Reports of Independent Public Accountants 12
Consolidated Income Statement for the years ended
December 31, 1995, 1994 and 1993 14
Consolidated Balance Sheet, December 31, 1995 and 1994 15
Consolidated Statement of Cash Flows for the years
ended December 31, 1995, 1994 and 1993 17
Consolidated Statement of Changes in Shareholders'
Equity Accounts for the years ended December 31,
1995, 1994 and 1993 18
Notes to Consolidated Financial Statements 19
Supplemental Financial Information 39
Exhibits
Exhibit 11 - Calculation of Earnings Per Share 40
Exhibit 23 - Consent of Arthur Andersen & Co. 41
3
<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 its subsidiaries and
affiliates (Enron) should be read in conjunction with the
Consolidated Financial Statements.
Results of Operations
Consolidated Net Income
Enron's net income for 1995 was $520 million compared to
$453 million in 1994 and $387 million in 1993 (exclusive of
a primarily non-cash charge of $54 million in 1993 to adjust
the deferred tax liability for the increase in the corporate
Federal statutory income tax rate from 34% to 35%). Net
income for all three years reflects improved income before
interest, minority interest and income taxes as compared to
the applicable preceding year, partially offset by higher
dividends on preferred stock of subsidiaries and income tax
expense.
Primary earnings per share of common stock was $2.07 in 1995
as compared to $1.80 in 1994 and $1.32 in 1993, after a
$0.23 per share charge applicable to the $54 million tax
rate change adjustment.
Income Before Interest, Minority
Interest and Income Taxes
The following table presents income before interest,
minority interest and income taxes (IBIT) for each of
Enron's operating segments:
<TABLE>
<CAPTION>
(In Millions) 1995 1994 1993
<S> <C> <C> <C>
Transportation and Operation $ 359 $403 $382
Domestic Gas and Power Services 157 202 197
International Gas and Power Services 142 148 132
Exploration and Production 241 198 129
Corporate and Other 266 (7) (42)
Total $1,165 $944 $798
</TABLE>
Transportation and Operation
The transportation and operation segment includes Enron's
interstate natural gas pipelines, including results of
Northern Natural Gas Company (Northern), Transwestern
Pipeline Company (Transwestern) and Florida Gas Transmission
(Florida Gas), and construction, management and operation of
pipelines, clean fuels plants and power facilities,
including results of Enron Engineering & Construction.
Enron's investment in crude oil marketing and transportation
operations conducted by EOTT Energy Partners, L.P. (EOTT)
and Enron's investment in liquids pipeline operations are
also in this segment.
The following reflects revenues and IBIT for each of these
groups:
<TABLE>
<CAPTION>
(In Millions) 1995 1994 1993
<S> <C> <C> <C>
Revenues
Interstate Natural Gas Pipelines $787 $901 $1,306
Construction, Management and Operation 44 47 37
EOTT - 28 123
Total 831 976 1,466
Cost of gas and other products 39 72 409
Operating expenses 322 442 551
Depreciation and amortization 83 88 116
Taxes, other than income taxes 47 47 49
Equity in earnings of unconsolidated
subsidiaries 23 49 23
Other income, net 79 27 18
Total before fourth quarter charges 442 403 382
Fourth quarter regulatory and
contingency adjustments (83) - -
Income before interest, minority
interest and income taxes $359 $403 $ 382
</TABLE>
The segment's IBIT decreased $44 million in 1995 as compared
to 1994 primarily due to lower earnings from the interstate
natural gas pipelines and EOTT and a $19 million charge to
reflect the discontinuance of EOTT's West Coast processing
and asphalt marketing operations, partially offset by gains
of $67 million from the sale of non-strategic gathering and
processing assets. The decrease in earnings from the
interstate natural gas pipelines was primarily due to fourth
quarter charges of $83 million related to regulatory
reserves and other contingencies. The segment realized a $21
million increase in IBIT in 1994 as compared to 1993
primarily due to increased IBIT from the interstate natural
gas pipelines and the construction, management and operation
of assets, partially offset by lower earnings from EOTT
primarily due to the reduced ownership interest in the first
quarter of 1994 resulting from the exchange by EOTT Energy
Corp. of its crude oil trading and transportation operations
for common and subordinated units and a 2% general partner
interest in EOTT. See Note 8 to the Consolidated Financial
Statements. The following discussion analyzes the
significant changes in the various components of IBIT for
the transportation and operation segment, prior to fourth
quarter regulatory and contingency adjustments.
Revenues
Interstate Natural Gas Pipelines. Revenues of the
interstate natural gas pipelines declined $114 million (13%)
during 1995 and $405 million (31%) during 1994 as compared
to the applicable preceding year. The decrease in revenues
from 1994 to 1995 primarily reflects completion of the
recovery of certain transition costs for Northern. The 1994
decline reflects the effect of unbundling services which
reduced sales revenues of Northern as Northern is now
primarily a transporter of natural gas. Transport revenues
declined 9% in 1995 and 2% in 1994 as compared to the prior
year. Transport volumes for Northern and Transwestern
totaled 5.6 trillion British thermal units per day (TBtu/d)
in 1995, 5.5 TBtu/d in 1994 and 5.1 TBtu/d in 1993. The
increases in volumes were more than offset by lower average
transport rates.
Construction, Management and Operation Revenues. Revenues
earned in connection with the construction, management and
operation of power and pipeline projects totaled $44 million
in 1995 as compared to $47 million and $37 million during
1994 and 1993, respectively. The 1994 increase reflects fees
earned in connection with the operation of additional
facilities offset by lower construction revenues as a result
of project completions.
EOTT. Net revenues from EOTT decreased $28 million in 1995
and $95 million in 1994 as a result of the reduced ownership
interest effective in March 1994.
Cost of Gas and Other Products Sold
The cost of gas and other products sold by the
transportation and operation segment decreased by $33
million (46%) during 1995 as compared to 1994 primarily as a
result of decreased gas purchases following the termination
of the merchant function by Northern. The cost of gas and
other products sold by the transportation and operation
segment decreased 82% during 1994 as compared to 1993 as a
result of lower sales volumes as discussed above combined
with lower average cost per unit of natural gas sold.
Operating Expenses
Operating expenses of the transportation and operation
segment declined $120 million (27%) during 1995 and $109
million (20%) during 1994. The 1995 decline primarily
reflects a decrease of $64 million in amortization of
deferred contract reformation costs due to the completion by
Northern of the recovery of certain transition costs in
early 1995, combined with lower transmission, compression
and storage transition costs. Additionally, operating
expenses decreased as a result of the decreased ownership
interest in EOTT. The 1994 decline is primarily a result of
the decreased ownership interest in EOTT combined with lower
operating expenses of the interstate natural gas pipelines
reflecting system modernization and reduced expenses
resulting from lower sales volumes transported on other
pipelines.
Depreciation expense for the transportation and operation
segment decreased $5 million (6%) during 1995 as compared to
1994 primarily as a result of the decreased ownership
interest in EOTT. Depreciation expense decreased $28 million
(24%) in 1994 as compared to 1993 primarily as a result of
the decreased ownership interest in EOTT and the interstate
pipelines' adjustment in 1993 of accumulated depreciation in
accordance with a Federal Energy Regulatory Commission
(FERC) ruling.
Other Income and Deductions
Equity in earnings of unconsolidated subsidiaries decreased
by $26 million (53%) during 1995 as compared to 1994
primarily reflecting decreased earnings from EOTT and a $19
million charge to reflect the discontinuance of EOTT's West
Coast processing and asphalt marketing operations. Equity in
earnings of unconsolidated subsidiaries increased by $26
million during 1994 compared to 1993 reflecting a $36
million increase in earnings from the 50% owned Citrus Corp.
(Citrus), which owns Florida Gas, and $5 million of equity
earnings from EOTT. The increased earnings of Citrus reflect
improved sales margins as a result of the renegotiation of
the pricing terms of Citrus' gas sales contract with its
largest customer and allowance for funds used during
construction related to the Florida Gas Phase III pipeline
expansion. These increases were offset by reduced earnings
resulting from the decreased ownership interest in Northern
Border Pipeline Company.
Other income, net, increased $52 million (193%) in 1995 as
compared to 1994 primarily due to gains related to the
disposition of non-strategic natural gas processing and
gathering facilities. Other income increased $9 million
(50%) in 1994 as compared to 1993 primarily as a result of
the continued resolution of regulatory and contractual
matters relating to the interstate natural gas pipelines.
Outlook
The transportation and operation segment should continue to
provide stable earnings and cash flows during 1996. The
successful settlement of significant regulatory issues and
various expansion projects underway or proposed by the
interstate natural gas pipelines should provide a reliable
stream of cash flow. During 1996, the transportation and
operation segment expects to complete sales of certain
natural gas gathering facilities as a result of the
cessation of its gas merchant function following the
implementation of FERC Order 636. Additionally, the segment
will actively promote engineering and construction services
to provide incremental earnings and will continue to
concentrate on reducing its overall cost structure.
Domestic Gas and Power Services
The domestic gas and power activities are conducted
primarily by Enron Capital & Trade Resources (ECT) and
include the marketing, purchasing and financing of natural
gas, natural gas liquids, crude oil, power and other energy
commodities and the management of the portfolio of
commitments arising from these activities. The domestic gas
processing operations are also included in this segment.
ECT's stated objective is to provide solutions to energy
problems worldwide. To meet this objective, ECT serves a
diverse customer group that includes independent power
producers, gas and electric utilities, industrials, oil and
gas producers, financial institutions and other energy
marketers. This broad customer mix generates a need for a
variety of financial structures, products and terms. This
diversity requires ECT to manage, on a portfolio basis, the
resulting market risks inherent in these transactions. To
provide a framework to manage such risks, ECT has defined a
set of fundamental portfolio management principles,
including formal definition of portfolio management
responsibilities; continual evaluation of ECT's market risk,
communicated and managed through risk limits and controls
approved by Enron's Board of Directors; measurement of risk
in accordance with value-at-risk methodologies and
evaluation of business performance, including risk/return
relationships. ECT has established portfolio management
functions for both market and credit risk. Operating
separately from the units that create or actively manage
these risk exposures, ECT's Risk Control Group reports to an
ECT Managing Director who reports extensively to the Audit
Committee of the Enron Board of Directors. This group is
responsible for the establishment of policies, measurement
of the risks within ECT's portfolio and the communication of
these risks to senior management and the Enron Board of
Directors. This group is committed to the continuous review
of the portfolio, policies and procedures to ensure that
ECT's portfolio remains aligned with ECT's policies.
ECT's services can be categorized into three business lines:
Cash and Physical, Risk Management and Finance. The
following table reflects IBIT for each business line:
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Cash and Physical $146 $170 $171
Risk Management 193 151 93
Finance 31 13 26
Unallocated expenses (138) (132) (93)
Total before Non-Recurring Charge 232 202 197
Charge for Clean Fuels Plant Operations (75) - -
Total $157 $202 $197
</TABLE>
The following discussion analyzes the contributions to IBIT
and the outlook for each of the business lines.
Cash and Physical. The cash and physical operations
include earnings from physical contracts of one year or less
involving marketing and transportation of natural gas,
liquids, electricity and other commodities, earnings from
the management of ECT's contract portfolio and earnings
related to the physical assets of ECT. Also included in this
line of business are the effects of actual settlements of
ECT's long-term physical and notional quantity based
contracts. The cash and physical operations earnings before
overhead expenses and a $75 million charge in the fourth
quarter of 1995 related to the clean fuels plant operations
were $146 million in 1995, $170 million in 1994 and $171
million in 1993.
ECT markets a substantial quantity of energy commodities on
a daily basis as reflected in the following table (including
intercompany amounts):
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Natural Gas and Crude Oil
Physical/Notional Quantities (BBtue/d)(a)
Firm(b) 5,392 4,895 4,558
Interruptible 2,255 2,039 828
Transport Volumes 580 538 571
Subtotal 8,227 7,472 5,957
Financial Settlements (notional) 32,938 16,459 5,027
Total 41,165 23,931 10,984
Electricity (Thousand megawatt hours)
Owned Production 3,441 3,481 2,883
Transaction Volumes Marketed 7,767 1,221 -
<FN>
(a) Billion British thermal units equivalent per day.
(b) Commitments to deliver a specified volume of gas at
a fixed or market responsive price.
</TABLE>
Exclusive of the $75 million charge related to the clean
fuels plant operations, the earnings from cash and physical
operations decreased 14% in 1995 as compared to 1994 as a
result of lower margins in liquids marketing and an increase
in clean fuels operating expenses. Earnings from the
marketing of physical natural gas also declined in 1995 as
compared to 1994 due to lower margins in all but the fourth
quarter. Partially offsetting these declines in earnings
were increased earnings from electricity marketing, the sale
of certain physical assets and the management of ECT's
contract portfolio. During the fourth quarter of 1995, ECT
provided for expected losses of $75 million on its clean
fuels plant operations resulting from higher natural gas
prices and low MTBE prices because of soft demand for MTBE.
Earnings for the cash and physical sector in 1994 were
virtually unchanged compared to 1993. Earnings from ECT's
management of its portfolio of contracts increased in 1994,
but were offset by lower gas processing margins. Margins
from short-term marketing in the purely physical natural gas
market also decreased slightly reflecting the more
competitive marketplace.
During 1996, ECT anticipates improvement in the cash and
physical business over the 1995 results. The existence of
its substantial portfolio of contracts as well as the
ability to benefit from the relationships between the
financial and physical markets and the natural gas and
electricity markets provide substantial opportunities for
earnings. Additionally, opportunities for the growth in
earnings from new markets, including electricity, should
enhance future results.
Risk Management. ECT's risk management operations consist
of market activity on long-term contracts (transactions
greater than one year). ECT originates new contracts for the
energy sector and evaluates and restructures its existing
contracts on an on-going basis to develop additional
products and services to meet its customers' changing needs.
Fixed price contract market activity totaled 5,952 trillion
British thermal units equivalent (TBtue), 6,615 TBtue and
3,781 TBtue for 1995, 1994 and 1993, respectively. In 1995,
the earnings before unallocated expenses from the risk
management operations were $193 million compared to $151
million in 1994 and $93 million in 1993.
Earnings from risk management increased 28% in 1995 as
compared to 1994 due primarily to earnings related to the
restructuring of existing long-term contracts with
independent power producers and local distribution
companies. Growth in originations from the Canadian
operations also contributed to the earnings increase. For
1995, originations with utilities were lower than in 1994.
Earnings from risk management increased 62% in 1994,
primarily as a result of the execution of various
electricity and new long-term gas contracts and the
restructuring of existing long-term contracts with
utilities, local distribution companies and independent
power producers.
ECT expects a strong performance from its risk management
business in 1996 as it expands further into electricity and
other new markets and pursues opportunities in the
international marketplace. The infrastructure for this
business has been established and ECT will be capitalizing
on its existing customer base, its skills and the emerging
competitive marketplace.
Finance. ECT's finance operations provide capital to
customers through various product offerings including
volumetric production payments. The finance sector
contributed $31 million of ECT's earnings in 1995 and $13
million and $26 million in 1994 and 1993, respectively.
Production payments and financings arranged were $382
million, $503 million and $470 million in 1995, 1994 and
1993, respectively.
Earnings from the finance sector increased 138% in 1995
compared with 1994 due primarily to the partial sale of
ECT's interests in certain equity investments and earnings
associated with the restructuring of long-term gas supply
contracts with an independent power plant. This was
partially offset by lower earnings from production payments
arranged.
Although total production payments and financings arranged
were greater in 1994 than 1993, the earnings in this
business decreased 50% in 1994 due to the difference in the
types of transactions originated in each of these periods
and the timing of income recognition from these
transactions.
In 1996, ECT will continue to expand its products and
services in its role as a full-service provider of various
types of capital. Additionally, opportunities will be
pursued in the international marketplace.
Other. ECT's net unallocated expenses such as rent,
systems expenses and other support group costs were $138
million, $132 million and $93 million in 1995, 1994 and
1993, respectively. These costs increased in both years due
to continued expansion into new markets and system upgrades.
ECT expects its unallocated expenses to increase during 1996
as it continues to expand into new markets.
International Gas and Power Services
Enron's international gas and power services segment
includes international power and pipeline development
activities and operations. IBIT for this group totaled $142
million during 1995, $148 million in 1994 and $132 million
in 1993. The decrease in 1995 was a result of decreased
earnings related to the formation of Enron Global Power &
Pipelines L.L.C. (EPP) and lower earnings from Enron
Americas, partially offset by increased earnings from Enron
Europe and increased promotion and development activities,
while the 1994 increase primarily reflects earnings from the
formation of EPP and increased earnings from power and
pipeline projects.
Net Revenues
Revenues net of cost of sales for the international segment
increased by $32 million (19%) in 1995 as compared to 1994
and $22 million (15%) during 1994. Included in 1995 were net
revenues of $24 million from the promotion of a portion of
Enron's interest in its power assets at Teesside in
Northeast England. In addition, revenues of $48 million were
recognized as a result of the satisfaction of Enron's
support obligations related to the formation of EPP. The
1994 results included $65 million of revenues earned in
connection with the formation of EPP and $28 million of net
revenues earned on the promotion of a portion of Enron's
interest in its liquids processing facilities at Teesside.
Costs and Expenses
Operating expenses for this segment increased $16 million
(21%) during 1995 and $7 million (10%) during 1994 as
compared to the preceding years primarily as a result of
higher operating expenses incurred in connection with
increased activities in the power operations area.
Depreciation expense of this segment increased $11 million
(75%) during 1995 as compared to 1994 as a result of
increased international project activities and $6 million
(68%) during 1994 as compared to 1993 primarily as a result
of increased investment in international natural gas liquids
assets.
Other Income and Deductions
Equity in earnings of unconsolidated subsidiaries of the
international gas and power services segment increased $12
million (27%) during 1995 as compared to 1994 primarily as a
result of increased earnings from Teesside and improved
results from Enron Americas' Venezuelan manufacturing
operations. Equity in earnings of unconsolidated
subsidiaries of this segment increased $3 million (8%)
during 1994 primarily as a result of earnings from two
Philippine power projects which began operations in mid-1993
and early 1994, combined with increased earnings from the
Argentina pipeline. These increases were partially offset by
lower earnings from Enron Americas' manufacturing operations
in Venezuela.
Other income, net, decreased $21 million in 1995 after
increasing $5 million during 1994, primarily as a result of
foreign currency gains realized by Enron Americas in 1994.
Outlook
The objective of the international gas and power services
segment is to deliver energy solutions worldwide through the
utilization of Enron's extensive portfolio of products and
services. Growth opportunities in the international market
are expected to result from the current and projected demand
for electrical power generation, the under-utilization of
natural gas reserves throughout the world and increased
environmental awareness.
Exploration and Production
IBIT of the exploration and production segment totaled $241
million during 1995 as compared to $198 million during 1994
and $129 million during 1993. Enron's exploration and
production activities are conducted by Enron Oil & Gas
Company (EOG). The exploration and production segment's
1995, 1994 and 1993 IBIT includes approximately $45 million,
$35 million and $7 million, respectively, of income related
to hedges placed by Enron on commodity positions not hedged
by EOG. The increase in IBIT realized by EOG primarily
reflects increased crude oil production and prices, strong
other marketing results and increased gains on sales of
reserves and related assets, combined with a reduction in
total per unit operating costs.
Wellhead volume and price statistics (including intercompany
amounts) are as follows:
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Natural Gas Volumes (MMcf/d)(a)
North America(b) 636 686 707
Trinidad 107 63 2
Total 743 749 709
Average Natural Gas Prices ($/Mcf)
North America(c) $1.34 $1.68 $1.92
Trinidad 0.97 0.93 0.89
Composite $1.29 $1.62 $1.92
Crude/Condensate Volumes (MBbl/d)(a)
North America 11.5 10.0 8.8
Trinidad 5.1 2.5 0.1
India 2.5 0.1 -
Total 19.1 12.6 8.9
Average Crude/Condensate Prices ($/Bbl)
North America $17.09 $15.65 $16.39
Trinidad 16.07 15.50 14.36
India 16.81 15.70 -
Composite $16.78 $15.62 $16.37
<FN>
(a) Million cubic feet per day or thousand barrels per
day, as applicable.
(b) Includes an annual average of 48 MMcf per day in 1995
and 1994 and 81 MMcf per day in 1993 delivered under
the terms of a volumetric production payment agreement
effective October 1, 1992, as amended.
(c) Includes an average equivalent wellhead value of
$0.80 per Mcf in 1995, $1.27 per Mcf in 1994 and
$1.57 per Mcf in 1993 for the volumes detailed in Note (b)
above, net of transportation costs.
</TABLE>
The following discussion analyzes the significant changes in
the various components of IBIT for the exploration and
production segment.
Revenues
Gross revenues of the exploration and production segment
decreased $19 million (2%) during 1995 after increasing by
$72 million (10%) in 1994. The impact of reduced wellhead
natural gas sales volumes and prices was partially offset by
the positive effects of EOG's hedging strategies which
resulted in a gain of $65 million from natural gas commodity
price hedging activities during 1995 compared to a gain of
$11 million during 1994 and a loss of $18 million in 1993.
Gains related to hedges placed by Enron on commodity
positions not hedged by EOG increased to $45 million in 1995
from $35 million in 1994 and $7 million in 1993.
Because of significantly lower average wellhead natural gas
prices beginning in the second half of 1994, U.S. wellhead
natural gas volumes were voluntarily curtailed by an average
of 105 MMcf/d during 1995 compared to an average of 70
MMcf/d during 1994. In addition, the impact of reduced
drilling for U.S. natural gas deliverability and sales of
oil and gas reserves and related assets net of purchases
resulted in a reduction of 20 MMcf/d in U.S. delivered
volumes during 1995 as compared to 1994.
Increased production of natural gas, crude oil and
condensate from Trinidad contributed to increased revenues
in both years, as did new crude oil and condensate volumes
associated with the initiation of operations in India and
increased crude oil and condensate prices during 1995.
Also included in revenues are gains on sales of oil and gas
reserves and related assets of $63 million in 1995 compared
with $54 million in 1994 and $13 million in 1993.
Costs and Expenses
The cost of natural gas sold by the exploration and
production segment in connection with other natural gas
marketing activities declined 44% in 1995 as compared to
1994 and 2% in 1994 as compared to 1993. The 1995 decline
was primarily due to lower other natural gas marketing
volumes and lower average associated costs per Mcf. The
decrease in 1994 as compared to 1993 reflects lower average
costs partially offset by higher other natural gas marketing
volumes.
Operating expenses for the exploration and production
segment increased $14 million (13%) in 1995 compared to 1994
and $7 million (7%) in 1994 compared to 1993. The increase
in 1995 is due primarily to increased lease and well and
general and administrative expenses due to expanded
international operations, including the initiation of
operations in India in late December 1994. The increase in
1994 reflects increased general and administrative expenses
associated with expanded operations.
Oil and gas exploration expenses decreased $5 million (6%)
in 1995 as compared to 1994 after increasing $8 million in
1994. The 1995 decline was a result of lower dry hole and
impairment costs, while the increase in 1994 reflects an
increased level of exploration activities and higher
impairments associated with certain offshore Gulf of Mexico
leases.
Depreciation, depletion and amortization (DD&A) expense
declined 11% in 1995 and 3% in 1994 as compared to the
applicable prior year. The 1995 decline reflects a decrease
in the average DD&A rate primarily reflecting an overall
decrease of $0.09 per thousand cubic feet equivalent (Mcfe -
natural gas equivalents are determined using the ratio of 6
Mcf of natural gas to 1 barrel of crude oil, condensate or
natural gas liquids) in certain North America DD&A rates and
an increase in the proportion of production from
international operations which have lower average DD&A rates
than incurred in North America operations. The decline
during 1994 reflects increased production from offshore
Trinidad at an average DD&A rate significantly less than the
North America operations rate including a $0.03 per Mcfe
decrease in the North America DD&A rate. On a per unit
natural gas equivalent volumes delivered basis, DD&A expense
declined 15% in 1995 to $0.68 per Mcfe as compared to $0.80
per Mcfe in 1994 and $0.89 per Mcfe in 1993.
Taxes, other than income taxes, increased $4 million (15%)
in 1995 and declined $7 million (20%) during 1994. The
increase in 1995 was primarily due to higher production
related taxes associated with new production in India. The
decline in 1994 was primarily due to lower taxable United
States wellhead volumes and prices and reductions in 1994
related to revisions of certain prior year production taxes.
Total per unit operating costs for lease and well expense,
DD&A, general and administrative expense, interest expense
and taxes other than income decreased $0.07 per Mcfe,
averaging $1.22 per Mcfe during 1995 compared to $1.29 per
Mcfe for 1994 and $1.43 per Mcfe for 1993.
Outlook
Management remains optimistic that continually increasing
recognition of natural gas as a more environmentally
friendly source of energy along with the availability of
significant domestically sourced supplies will result in
increases in demand and a strengthening of the overall
natural gas market over time.
EOG plans to continue to focus a substantial portion of its
development and certain exploration expenditures in its
major producing areas in North America. However, based on
the continuing uncertainty associated with North America
natural gas prices and as a result of the recent success
realized in Trinidad, opportunities available to EOG in
connection with the signing of agreements in India in
December 1994 and EOG's selection as the winning bidder on a
block offshore Venezuela in January 1996, EOG anticipates
spending an increasing part of its available funds in the
further development of those opportunities. In addition, EOG
will continue limited exploratory expenditures in new areas
outside of North America, including the continued evaluation
of coalbed methane recovery potential in the United Kingdom,
China, France, Australia and certain other countries.
Corporate and Other
The corporate and other segment's IBIT was $266 million in
1995 as compared to expense of $7 million in 1994 and $42
million in 1993. Results from this segment in 1995 reflect a
gain of $367 million on the public offering of 31 million
outstanding shares of EOG stock held by Enron, which reduced
Enron's interest in EOG from 80% to 61% (see Note 16 to the
Consolidated Financial Statements), and amounts recognized
following the resolution of certain litigation. These
increases were partially offset by $74 million of charges
primarily related to the conversion of a compensation plan
to more closely align employees' interests to Enron common
stock. The improvement during 1994 primarily reflects a $15
million pretax gain realized on the formation of EOTT.
Interest and Related Charges, net
Interest and related charges, net, is shown on the
Consolidated Income Statement net of interest capitalized.
The net expense increased $11 million in 1995 primarily due
to higher debt levels and increased interest rates. The net
expense decreased $27 million during 1994 primarily because
of lower overall interest costs on Enron's floating rate
obligations as a result of lower rates achieved through
hedging activities. Enron periodically enters into certain
interest rate swaps to manage its overall interest costs.
Dividends on Preferred Stock of Subsidiaries
Dividends on preferred stock of subsidiaries relate to the
issuance of 8.55 million shares of 8% Cumulative Guaranteed
Monthly Income Preferred Shares by Enron Capital L.L.C. in
November 1993, the issuance by Enron Capital Resources, L.P.
of 3 million shares of 9% Cumulative Preferred Securities,
Series A in August 1994 and the issuance in December 1994 by
Enron Equity Corp. of 880 shares of 8.57% Preferred Stock,
$0.001 par value, in a private transaction. See Note 9 to
the Consolidated Financial Statements.
Minority Interests
Minority interests increased during 1995 as compared to 1994
primarily as a result of the sale in the fourth quarter of
1994 of approximately 48% of Enron's interest in EPP.
Income Tax Expense
Income tax expense increased during 1995 and 1994 compared
to the applicable prior year due to increased pretax income,
a decrease in tight gas sand Federal tax credits and the
higher effective tax rate on the sale of EOG shares by Enron
in 1995.
Financial Condition
Cash From Operating Activities
Net cash used in operating activities totaled $15 million
during 1995 as compared to $461 million provided by
operating activities during 1994. The decline primarily
reflects increased working capital requirements, due in part
to reduced sales of accounts receivable, partially offset by
increased cash from monetization of price risk management
assets.
Cash From Investing Activities
Net cash provided by investing activities totaled $13
million during 1995 compared to $560 million used in
investing activities during 1994. Proceeds from asset sales
totaled $997 million during 1995 compared to $440 million
during 1994. The 1995 amounts reflect proceeds from the sale
of 31 million outstanding shares of EOG common stock held by
Enron, as well as sales of oil and gas properties and non-
strategic processing and gathering facilities. The 1994
amount primarily reflects proceeds realized on the formation
of EPP and the previously discussed sale of Enron's crude
oil trading and transportation operations to EOTT. As more
fully discussed below, capital expenditures (property
additions and other capital expenditures) totaled $777
million in 1995 compared to $669 million in 1994. Equity
investments totaled $170 million in 1995 compared to $273
million in 1994. Equity investments during 1995 primarily
reflect investments in international power projects. The
1994 amount primarily reflects investments in connection
with the Florida Gas Phase III pipeline expansion and
investments in Joint Energy Development Investments Limited
Partnership and in various international projects.
Cash From Financing Activities
Net cash used in financing activities totaled $16 million
during 1995 compared to cash provided of $92 million during
1994. During 1995, Enron issued $967 million of long-term
debt while retiring $448 million principal amount of long-
term borrowings. Other cash outflows during 1995 included
$254 million of cash dividend payments on common and
preferred stock and $65 million for net repurchases of Enron
Corp. common stock under Enron's stock repurchase
authorization. In addition to the debt issuances discussed
above, financing cash outflows during 1995 included a $250
million decrease in short-term borrowings.
Working Capital
At December 31, 1995, Enron had working capital of $295
million. Should a working capital deficit occur, Enron would
be able to fund such a deficit through the utilization of
credit facilities which, at December 31, 1995, provided for
up to $2.1 billion of committed and uncommitted credit of
which no amounts were outstanding. Certain of the credit
agreements contain prefunding covenants. However, such
covenants are not expected to materially restrict Enron's
access to funds under these agreements. In addition, Enron
sells commercial paper and has agreements to sell trade
accounts receivable, thus providing financing to meet
seasonal working capital needs. Management believes that the
sources of funding described above are sufficient to meet
short- and long-term liquidity needs not met by cash flows
from operations.
Capital Expenditures
Capital expenditures by operating segment are detailed as
follows:
<TABLE>
<CAPTION>
1996
(In Millions) Estimate 1995 1994 1993
<S> <C> <C> <C> <C>
Transportation and Operation $190 $129 $125 $152
Domestic Gas and Power Services 120 118 83 102
International Gas and Power Services 10 58 14 53
Exploration and Production* 470 464 442 383
Corporate and Other 10 8 5 5
Total $800 $777 $669 $695
<FN>
* Excludes exploration expenses of $60 million
(estimate), $55 million, $59 million, and $55 million
for 1996, 1995, 1994 and 1993, respectively.
</TABLE>
Capital expenditures increased $108 million during 1995 as
compared to 1994 primarily as a result of increased
expenditures by ECT primarily related to upgrade of existing
facilities and systems costs, combined with higher capital
expenditures in the international operations. The increase
in international capital expenditures primarily reflects
property additions by Enron Europe and Enron Americas.
Capital expenditures during 1994 declined slightly as
compared to 1993. Reduced capital expenditures by the
transportation and operation, domestic gas and power
services and international gas and power services segments
were partially offset by higher capital spending by the
exploration and production segment. The increase in capital
expenditures by the exploration and production segment
reflects the acquisition of selected properties to
complement existing North American producing areas and the
addition of new international activities in India.
Capital expenditures during 1996 are expected to total
approximately $800 million. However, the overall level of
capital spending as well as spending by individual business
segments will vary depending upon conditions in the energy
market and other related economic conditions. In addition,
equity investments are expected to be approximately $200
million, primarily relating to international projects.
Management believes that the capital spending program will
be funded by a combination of internally generated funds,
proceeds from dispositions of selected assets and long- and
short-term borrowings.
Capitalization
Total capitalization at December 31, 1995 was $7.2 billion.
Debt as a percentage of total capitalization decreased to
42.8% at December 31, 1995 as compared to 44.2% at December
31, 1994. The improvement primarily reflects increased
retained earnings and the utilization of proceeds from the
previously discussed sale of EOG shares to reduce long-term
debt. Assuming the mandatory conversion in late 1998 of 10.5
million Exchangeable Notes into EOG shares held by Enron,
the pro-forma debt to capitalization percentage would be
approximately 40.5% at December 31, 1995.
INFORMATION REGARDING
FORWARD LOOKING STATEMENTS
This Annual Report includes forward looking statements
within the meaning of Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934.
Although Enron believes that its expectations are based on
reasonable assumptions, it can give no assurance that its
goals will be achieved. Important factors that could cause
actual results to differ materially from those in the
forward looking statements herein include political
developments in foreign countries, the pace of deregulation
of retail natural gas and electricity markets in the United
States, the timing and extent of changes in commodity prices
for crude oil, natural gas, electricity and interest rates,
the extent of EOG's success in acquiring oil and gas
properties and in discovering, developing and producing
reserves, the timing and success of Enron's efforts to
develop international power, pipeline and other
infrastructure projects and conditions of the capital
markets and equity markets during the periods covered by the
forward looking statements.
<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, 1995 and 1994, and the related consolidated
statements of income, cash flows and changes in
shareholders' equity accounts for each of the three years in
the period ended December 31, 1995. These financial
statements are the responsibility of Enron Corp.'s
management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial
position of Enron Corp. and subsidiaries as of December 31,
1995 and 1994, and the results of their operations, cash
flows and changes in shareholders' equity accounts for each
of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles.
Arthur Andersen LLP
Houston, Texas
February 16, 1996
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Income Statement
<CAPTION>
Year Ended December 31,
(In Thousands, Except Per Share Amounts) 1995 1994 1993
<S> <C> <C> <C>
Revenues
Natural gas and other products $7,529,357 $7,490,533 $6,652,333
Transportation 691,702 754,117 767,911
Other 967,938 739,073 565,556
9,188,997 8,983,723 7,985,800
Costs and Expenses
Cost of gas and other products 6,733,486 6,517,109 5,566,026
Operating expenses 1,218,341 1,123,448 1,146,655
Oil and gas exploration expenses 78,670 83,944 75,743
Depreciation, depletion and
amortization 431,706 441,329 458,188
Taxes, other than income taxes 108,792 102,121 108,386
8,570,995 8,267,951 7,354,998
Operating Income 618,002 715,772 630,802
Other Income and Deductions
Equity in earnings of unconsolidated
subsidiaries 86,018 112,409 73,293
Interest income 26,821 39,162 31,457
Other, net 434,241 77,049 62,115
Income Before Interest, Minority
Interest and Income Taxes 1,165,082 944,392 797,667
Interest and Related Charges, net 284,029 273,482 300,149
Dividends on Preferred Stock of
Subsidiaries 31,859 19,875 2,137
Minority Interests 44,056 31,041 27,605
Income Taxes 285,444 166,584 89,077
Income Tax Rate Adjustment - - 46,177
Net Income 519,694 453,410 332,522
Preferred Stock Dividends 15,414 15,038 16,919
Earnings on Common Stock $ 504,280 $ 438,372 $ 315,603
Earnings Per Share of Common Stock
Primary $ 2.07 $ 1.80 $ 1.32
Fully Diluted $ 1.94 $ 1.70 $ 1.25
Average Number of Common Shares Used
in Primary Computation 243,669 243,395 239,019
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Balance Sheet
<CAPTION>
December 31,
(In Thousands) 1995 1994
<S> <C> <C>
Assets
Current Assets
Cash and cash equivalents $ 114,917 $ 132,336
Trade receivables (net of allowance
for doubtful accounts of $11,642 and
$12,729, respectively) 1,115,709 604,985
Other receivables 310,790 233,213
Transportation and exchange gas
receivable 149,659 98,787
Inventories 111,463 138,405
Assets from price risk management
activities 579,749 449,588
Other 344,620 251,679
Total Current Assets 2,726,907 1,908,993
Investments and Other Assets
Investments in and advances to
unconsolidated subsidiaries 1,216,474 1,065,189
Assets from price risk management
activities 1,197,029 1,027,945
Other 1,230,090 1,225,224
Total Investments and Other Assets 3,643,593 3,318,358
Property, Plant and Equipment, at cost
Transportation and operation 3,639,734 3,906,952
Domestic gas and power services 3,797,530 3,811,037
Exploration and production, successful
efforts accounting 3,380,924 3,015,435
International gas and power services 181,981 119,740
Corporate and other 107,012 111,237
11,107,181 10,964,401
Less accumulated depreciation,
depletion and amortization 4,238,746 4,225,741
Net Property, Plant and Equipment 6,868,435 6,738,660
Total Assets $13,238,935 $11,966,011
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Balance Sheet
<CAPTION>
December 31,
1995 1994
<S> <C> <C>
Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable $ 1,020,599 $ 924,446
Transportation and exchange gas
payable 144,141 114,124
Accrued taxes 121,192 90,906
Accrued interest 51,692 58,569
Liabilities from price risk
management activities 708,353 522,070
Other 386,015 587,271
Total Current Liabilities 2,431,992 2,297,386
Long-Term Debt 3,064,839 2,805,142
Deferred Credits and Other Liabilities
Deferred income taxes 2,185,748 1,893,450
Deferred revenue 311,478 256,298
Liabilities from price risk
management activities 590,302 575,377
Other 563,962 591,134
Total Deferred Credits and
Other Liabilities 3,651,490 3,316,259
Commitments and Contingencies
(Notes 2, 8, 13, 14 and 15)
Minority Interests 548,648 290,146
Company-Obligated Preferred Stock
of Subsidiaries 376,750 376,750
Shareholders' Equity
Preferred stock, cumulative, $100
par value, 1,500,000 shares authorized,
no shares issued - -
Second preferred stock, cumulative,
$1 par value, 5,000,000 shares authorized,
1,375,494 shares and 1,404,983 shares of
Cumulative Second Preferred Convertible
Stock issued, respectively 137,550 140,498
Preference stock, cumulative, $1 par
value, 10,000,000 shares authorized,
no shares issued - -
Common stock, $0.10 par value,
600,000,000 shares authorized,
253,860,360 shares and 253,069,668
shares issued, respectively 25,386 25,308
Additional paid-in capital 1,791,151 1,788,044
Retained earnings 1,650,949 1,351,297
Cumulative foreign currency translation
adjustment (153,563) (158,881)
Common stock held in treasury (2,618,034
and 1,394,833 shares, respectively) (92,642) (41,090)
Other (including Flexible Equity Trust,
Note 10) (193,615) (224,848)
Total Shareholders' Equity 3,165,216 2,880,328
Total Liabilities and Shareholders' Equity $13,238,935 $11,966,011
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Statement Of Cash Flows
<CAPTION>
Year Ended December 31,
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Cash Flows From Operating Activities
Reconciliation of net income to net
cash provided by (used in) operating
activities
Net income $ 519,694 $ 453,410 $ 332,522
Depreciation, depletion and amortization 431,706 441,329 458,188
Oil and gas exploration expenses 78,670 83,944 75,743
Amortization of deferred contract
reformation costs 25,858 90,617 89,240
Deferred income taxes 216,090 92,959 51,200
Gains on sales of stock by subsidiary
and other assets (529,990) (91,284) (115,586)
Regulatory, litigation and other
contingency adjustments 111,666 (25,212) 58,944
Changes in components of working
capital (833,647) (141,372) (76,513)
Deferred contract reformation costs (18,089) (54,182) (136,383)
Net assets from price risk management
activities (98,037) (152,642) (115,415)
Production payment transaction, net (43,345) (43,345) (73,867)
Other, net 124,401 (193,567) (153,651)
Net Cash Provided by (Used in) Operating
Activities (15,023) 460,655 394,422
Cash Flows From Investing Activities
Proceeds from sales of investments and
other assets 996,537 439,627 453,977
Additions to property, plant and
equipment (730,502) (660,915) (688,032)
Equity investments (170,262) (272,517) (267,097)
Other, net (82,397) (66,561) (64,224)
Net Cash Provided by (Used in)
Investing Activities 13,376 (560,366) (565,376)
Cash Flows From Financing Activities
Net increase (decrease) in
short-term borrowings (250,305) 115,326 42,767
Issuance of long-term debt 967,126 190,115 613,938
Repayment of long-term debt (447,734) (161,786) (450,161)
Decrease in other long-term obligations - - (22,757)
Issuance of company-obligated preferred
stock of subsidiaries - 163,000 213,750
Issuance of common stock 19,806 66,372 22,882
Dividends paid (254,262) (231,079) (189,769)
Net acquisition of treasury stock (64,654) (41,090) (71,145)
Other, net 14,251 (9,051) 10,000
Net Cash Provided by (Used in)
Financing Activities (15,772) 91,807 169,505
Decrease in Cash and Cash Equivalents (17,419) (7,904) (1,449)
Cash and Cash Equivalents, Beginning
of Year 132,336 140,240 141,689
Cash and Cash Equivalents, End of Year $ 114,917 $ 132,336 $ 140,240
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
Enron Corp. and Subsidiaries
Consolidated Statement Of Changes In Shareholders' Equity Accounts
<CAPTION>
Cumulative
Foreign
Convertible Additional Currency
(In Thousands, Except Preferred Common Paid-in Retained Translation Treasury
Per Share Amounts) Stock Stock Capital Earnings Adjustment Stock Other
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1992 $182,964 $1,187,661 $ 324,944 $ 959,522 $(118,160) $ (8,100) $ (10,514)
Net income 332,522
Cash dividends
Common stock (170,457)
Preferred stock (16,919)
Purchase of treasury stock (86,301)
Exchange of common stock for
convertible preferred stock (33,296) 3,573 (25,289) 55,012
Benefit and dividend reinvestment
plans 3,881 25,426 39,788 (5,347)
Sales of stock 14 4,986
Issuance to Flexible Equity Trust 750 219,563 (219,563)
Common stock split and reduction
of par value to $0.10 (1,170,969) 1,170,969
Translation adjustments (20,544)
Other (12,661) 318 (399) 10,000
Balance at December 31, 1993 149,668 24,910 1,707,938 1,104,986 (138,704) - (225,424)
Net income 453,410
Cash dividends
Common stock (191,839)
Preferred stock (15,038)
Purchase of treasury stock (55,911)
Exchange of common stock for
convertible preferred stock (9,170) 125 9,045
Benefit and dividend reinvestment
plans 131 29,625 1,392 576
Sales of stock 142 51,594 13,366
Translation adjustments (20,177)
Other (10,158) (222) 63
Balance at December 31, 1994 140,498 25,308 1,788,044 1,351,297 (158,881) (41,090) (224,848)
Net income 519,694
Cash dividends
Common stock (204,628)
Preferred stock (15,414)
Purchase of treasury stock (118,368)
Exchange of common stock for
convertible preferred stock (2,948) 22 (2,536) 5,462
Benefit and dividend reinvestment
plans 19 (5,189) 61,381 29,569
Sales of stock 37 15,468
Translation adjustments 5,318
Other (4,636) (27) 1,664
Balance at December 31, 1995 $137,550 $ 25,386 $1,791,151 $1,650,949 $(153,563) $(92,642) $(193,615)
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
Enron Corp. and Subsidiaries
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
1 Summary of Significant Accounting Policies
A. Consolidation Policy and Use of Estimates
The consolidated financial statements include the accounts
of all majority-owned subsidiaries of Enron Corp. after the
elimination of significant intercompany accounts and
transactions. Investments in unconsolidated subsidiaries are
accounted for by the equity method.
The preparation of financial statements in conformity with
generally accepted accounting principles requires management
to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results
could differ from those estimates.
"Enron" is used from time to time herein as a collective
reference to Enron Corp. and its subsidiaries and
affiliates. In material respects, the businesses of Enron
are conducted by Enron Corp.'s subsidiaries and affiliates
whose operations are managed by their respective officers.
B. Cash Equivalents
Enron records as cash equivalents all highly liquid short-
term investments with original maturities of three months or
less.
C. Inventories
Inventories consisting primarily of natural gas in storage
of $55.9 million and $79.1 million and crude oil and liquid
petroleum products of $50.0 million and $54.8 million at
December 31, 1995 and 1994, respectively, are priced at the
lower of cost or market.
D. Depreciation, Depletion and Amortization
The provision for depreciation and amortization with respect
to operations other than oil and gas producing activities
(see below) is computed using the straight-line or Federal
Energy Regulatory Commission (FERC) mandated method based on
estimated economic lives. Composite depreciation rates are
applied to functional groups of property having similar
economic characteristics.
Provisions for depreciation, depletion and amortization of
proved oil and gas properties are calculated using the units-
of-production method. Estimated future dismantlement,
restoration and abandonment costs, net of salvage credits,
are taken into account in determining depreciation,
depletion and amortization.
In March 1995, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards (SFAS)
No. 121 - "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of," which
requires, among other things, that long-lived assets and
certain identifiable intangibles to be held and used by an
entity be reviewed for impairment whenever events or changes
in circumstances indicate that the carrying amount of an
asset may not be recoverable. Enron will adopt SFAS No. 121
in the first quarter of 1996. Enron believes that the
adoption of SFAS No. 121 will not have a material impact on
its financial position or results of operations.
E. Income Taxes
Enron accounts for income taxes under the provisions of SFAS
No. 109 - "Accounting for Income Taxes," which provides for
an asset and liability approach for accounting for income
taxes. Under this approach, deferred tax assets and
liabilities are recognized based on anticipated future tax
consequences attributable to differences between financial
statement carrying amounts of assets and liabilities and
their respective tax bases (see Note 3).
F. Earnings Per Share
Primary earnings per share is computed on the basis of the
average number of common shares outstanding during the
periods. Common shares held by the Enron Corp. Flexible
Equity Trust are not included in the computation of earnings
per share until such shares are released to fund employee
benefits (see Note 10). Dilutive common stock equivalents
are not material and are not included in the computation of
primary earnings per share. Fully diluted earnings per share
is computed based upon the average number of common stock
and common stock equivalent shares outstanding plus the
average number of common shares issuable upon the assumed
conversion of convertible securities.
G. Accounting for Price Risk Management
Enron engages in price risk management activities for both
trading and non-trading purposes. Activities for trading
purposes, generally consisting of services provided to the
energy sector through Enron Capital & Trade Resources (ECT),
are accounted for using the mark-to-market method. Under
such method, changes in the market value of outstanding
financial instruments are recognized as gain or loss in the
period of change. The market prices used to value these
transactions reflect management's best estimate considering
various factors including closing exchange and over-the-
counter quotations, time value and volatility factors
underlying the commitments. The values are adjusted to
reflect the potential impact of liquidating Enron's position
in an orderly manner over a reasonable period of time under
present market conditions.
Activities for non-trading purposes consist of transactions
entered into by Enron's other business units to hedge the
impact of market fluctuations on assets, liabilities,
production or other contractual commitments. Changes in the
market value of these transactions are deferred until the
gain or loss on the hedged item is recognized. See Note 2
for further discussion of Enron's price risk management
activities.
H. Accounting for Oil and Gas Producing Activities
Enron accounts for oil and gas exploration and production
activities under the successful efforts method of
accounting. Under such method, oil and gas lease acquisition
costs are capitalized when incurred. Unproved properties
with significant acquisition costs are assessed quarterly on
a property-by-property basis and any impairment in value is
recognized. Amortization of any remaining costs of such
leases begins at a point prior to the end of the lease term
depending upon the length of such term. Unproved properties
with acquisition costs that are not individually significant
are aggregated, and the portion of such costs estimated to
be nonproductive, based on historical experience, is
amortized over the average holding period. If the unproved
properties are determined to be productive, the appropriate
related costs are transferred to proved oil and gas
properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of
drilling exploratory wells, are charged to expense as
incurred. The costs of drilling exploratory wells are
capitalized pending determination of whether the wells have
discovered proved commercial reserves. If proved commercial
reserves are not discovered, such drilling costs are
expensed. The costs of all development wells and related
equipment used in the production of crude oil and natural
gas are capitalized.
Gains and losses associated with the sale of crude oil and
natural gas reserves in place with related assets are
classified as "Other Revenues" in the Consolidated Income
Statement.
I. Accounting for Development Activity
Enron's project development costs consist of fees, licenses
and permits, site testing, bid costs and other charges,
including salaries and employee expenses, incurred in
developing domestic and international projects. These costs
may be recovered through development cost reimbursements
from joint venture partners or other third parties, written
off against development fees received, or may be included as
part of an investment in those ventures where Enron
continues to participate. Accumulated costs of project
development are otherwise expensed in the period that
management determines it is probable that the costs will not
be recovered.
Development revenue results from Enron's participation in
the development, construction, operation and ownership of
various projects. Revenue from development fees is
recognized when realizable under the development agreement.
Revenue from long-term construction contracts is recognized
using the percentage-of-completion method and is primarily
based on project costs incurred compared with total
estimated costs. Estimated contract earnings are reviewed
and revised periodically as the work progresses. Development
and construction revenues earned from joint ventures in
which Enron holds an equity interest are deferred to the
extent of Enron's ownership interest and recognized over the
life of the facility owned by the joint venture on a
straight-line basis. Proceeds from the sale of all or part
of Enron's investment in development projects are recognized
as revenues at the time of sale to the extent that such
sales proceeds exceed the proportionate carrying amount of
the investment. Total revenues recognized from the sale of
development projects for the years ended December 31, 1995,
1994 and 1993, exclusive of amounts discussed below, were
$11 million, $28 million and $65 million, respectively.
During November 1994, Enron sold an approximately 48%
interest in Enron Global Power & Pipelines L.L.C. (EPP) for
net proceeds totaling approximately $225 million. In
connection with the sale, Enron recognized revenues of $65
million in 1994 and $48 million in 1995 following the
satisfaction of Enron's support obligations. Pursuant to a
Purchase Right Agreement, Enron has agreed to offer to sell
to EPP Enron's ownership interests in power plant and
natural gas pipeline projects developed or acquired outside
the United States, Canada and Western Europe, prior to 2005,
subject to certain exceptions.
J. Foreign Currency Translation
For international subsidiaries, asset and liability accounts
are translated at year-end rates of exchange and revenue and
expenses are translated at average exchange rates prevailing
during the year. For subsidiaries whose functional currency
is deemed to be other than the U.S. dollar, translation
adjustments are included as a separate component of
shareholders' equity. Currency transaction gains and losses
are recorded in income.
K. Reclassifications
Certain reclassifications have been made to the consolidated
financial statements for prior years to conform with the
current presentation.
2 Price Risk Management and Financial Instruments
Trading Activities
Enron, through ECT, offers price risk management services to
the energy sector. These services primarily relate to
commodities associated with the energy sector (natural gas,
crude oil, natural gas liquids and electricity), but in some
instances also include financial products (interest rate
swaps and foreign currency contracts). ECT provides these
services through a variety of financial instruments
including forward contracts involving physical delivery of
an energy commodity, swap agreements, which require payments
to (or receipt of payments from) counterparties based on the
differential between a fixed and variable price for the
commodity, options and other contractual arrangements.
ECT accounts for these activities using the mark-to-market
method of accounting. Under mark-to-market accounting,
forwards, swaps, options and other financial instruments
with third parties are reflected at market value, net of
future servicing costs, with resulting unrealized gains and
losses recorded as "Assets and Liabilities From Price Risk
Management Activities" in the Consolidated Balance Sheet.
Terms regarding cash settlements of these contracts vary
with respect to the actual timing of cash receipts and
payments. The amounts shown in the Consolidated Balance
Sheet related to price risk management activities also
include assets or liabilities which arise as a result of the
actual timing of settlements related to these contracts.
Current period changes in the assets and liabilities from
price risk management activities (resulting primarily from
newly originated transactions, restructurings and the impact
of price movements) are recognized as net gains or losses in
"Other Revenues."
Notional Amounts and Terms. The notional amounts and terms
of these financial instruments at December 31, 1995 are set
forth below (volumes in trillions of British thermal units
equivalent (TBtue), dollars in millions):
<TABLE>
<CAPTION>
Fixed Price Fixed Price Maximum
Product Payor Receiver Terms in years
<S> <C> <C> <C>
Energy Commodities
Gas 3,741 4,933 19
Crude and liquids 606 743 10
Electricity 33 165 5
Financial Products
Interest rate (a) $14,364 $1,465 19
Foreign currency 1,040 1,045 19
<FN>
(a) The interest rate fixed price receiver represents
the net notional dollar value of the interest rate sensitive
component of the combined commodity portfolio. The interest
rate fixed price payor represents the notional contract
amount of a portfolio of various financial instruments used
to hedge the net present value of the commodity portfolio.
The effectiveness of a hedge on the net present value of the
combined commodity portfolio is not a function of notional
hedge value but, rather, of cash flows resulting from the
notional hedge value. Accordingly, the notional dollar
values will not be equal. However, the portfolio is
substantially balanced from a cash flow perspective and is
not sensitive to movement in interest rates.
</TABLE>
ECT also has sales and purchase commitments associated with
contracts based on market prices totaling 4,432 TBtue, with
terms extending up to 20 years.
Notional amounts reflect the volume of transactions but do
not represent the amounts exchanged by the parties to the
financial instruments. Accordingly, notional amounts do not
accurately measure ECT's exposure to market or credit risks.
The maximum terms in years detailed above are not indicative
of likely future cash flows as these positions may be offset
in the markets at any time in response to the company's risk
management needs.
The volumetric weighted average maturity
of ECT's entire portfolio of price risk management
activities as of December 31, 1995 was approximately 2.3
years.
Fair Value. The fair value of the financial instruments as
of December 31, 1995 and the average fair value of those
instruments held during the year are set forth below
(amounts in millions):
<TABLE>
<CAPTION>
Fair Value Average Fair Value
as of for the Year Ended
12/31/95 12/31/95(a)
Product Assets Liabilities Assets Liabilities
<S> <C> <C> <C> <C>
Energy Commodities
Gas $1,217 $744 $1,190 $477
Crude and liquids 249 363 293 495
Electricity 97 62 29 14
Financial Products
Interest rate 357 92 225 60
Foreign currency 64 38 58 35
<FN>
(a) Computed using the ending balance at each month end.
</TABLE>
The net change in the value of ECT's portfolio of price risk
management activities for the year ended December 31, 1995,
primarily attributable to financial instruments fixing
energy commodity pricing, was $98 million and is included in
"Other Revenues". All of ECT's operations relate to
providing price risk management services. Accordingly,
earnings for this operating segment appropriately reflect
the net gain arising from trading activities for the year
ended December 31, 1995.
Market Risk. To provide solutions to energy problems
worldwide, ECT serves a diverse customer group that includes
independent power producers, industrials, gas and electric
utilities, oil and gas producers, financial institutions and
other energy marketers. This broad customer mix generates a
need for a variety of financial structures, products and
terms. This diversity requires ECT to manage, on a portfolio
basis, the resulting market risks inherent in these
transactions subject to parameters established by Enron's
Board of Directors. Market risks are monitored by a risk
control group operating separately from the units that
create or actively manage these risk exposures to ensure
compliance with Enron's stated risk management policies at
both the corporate and subsidiary levels. Risk measurement
is also supplemented with stress testing and scenario
analysis. ECT's fixed price contract portfolio is typically
balanced to within approximately 1% of the gross position at
the end of each day.
ECT measures the risk in its portfolio on a daily basis in
accordance with value-at-risk methodologies, which simulate
forward price curves in the energy markets to estimate the
size and probability of future potential losses. The
quantification of market risk using value-at-risk provides a
consistent measure of risk across diverse energy markets and
products. The use of this methodology requires a number of
key assumptions including the selection of a confidence
level for losses, the holding period chosen for the value-at-
risk calculation and the treatment of risks outside the
value-at-risk methodologies, including liquidity risk and
event risk.
ECT expresses value-at-risk as a percentage of Enron's
earnings based on a 95% confidence level using one day
holding periods. On a one day basis as of December 31, 1995,
ECT's value-at-risk for its price risk management activities
was less than 2% (unaudited) of Enron's total income before
interest, minority interest and income taxes. Since this is
not an absolute measure of risk under all conditions for all
products, ECT performs alternative scenario analyses to
estimate the economic impact of a sudden market movement on
the value of the trading portfolio (stress testing). The
results of the stress testing, along with the professional
judgments of experienced business and risk managers, are
used to supplement the value-at-risk methodology and capture
additional market-related risks, including liquidity, event,
concentration and correlation reliance risk.
Based upon the ongoing policies and controls discussed
above, Enron does not anticipate a materially adverse effect
on financial position or results of operations as a result
of market fluctuations.
Credit Risk. Credit risk relates to the risk of loss that
Enron would incur as a result of nonperformance by
counterparties pursuant to the terms of their contractual
obligations. The counterparties associated with ECT's assets
from price risk management activities as of December 31,
1995 and 1994 are summarized as follows (amounts in
millions):
<TABLE>
<CAPTION>
December 31, 1995
Assets from Price Risk Management Activities
Investment Below
Grade(a) Investment Grade Total
<S> <C> <C> <C>
Independent Power Producers $ 573 $105 $ 678
Gas and Electric Utilities 234 45 279
Oil and Gas Producers 318 109 427
Industrials 35 43 78
Financial Institutions 38 5 43
Energy Marketers 132 103 235
Other 202 42 244
Total $1,532 $452 1,984
Credit and Other Reserves (207)
Assets from Price Risk
Management Activities(b) $1,777
</TABLE>
<TABLE>
<CAPTION>
December 31, 1994
Assets from Price Risk Management Activities
Investment Below
Grade(a) Investment Grade Total
<S> <C> <C> <C>
Independent Power Producers $ 447 $ 44 $ 491
Gas and Electric Utilities 287 37 324
Oil and Gas Producers 310 26 336
Industrials 24 21 45
Financial Institutions 176 - 176
Energy Marketers 20 25 45
Other 158 33 191
Total $1,422 $186 1,608
Credit and Other Reserves (130)
Assets from Price Risk
Management Activities(b) $1,478
<FN>
(a) "Investment Grade" is primarily determined using
publicly available credit ratings along with consideration
of collateral, which encompass standby letters of credit,
parent company guarantees and property interests, including
oil and gas reserves. Included in "Investment Grade" are
counterparties with a minimum Standard & Poor's or Moody's
rating of BBB- or Baa3, respectively.
(b) Three customers' exposures at December 31, 1995 and
1994 each comprise greater than 5% of Assets From Price Risk
Management Activities.
</TABLE>
This concentration of counterparties may impact ECT's
overall exposure to credit risk, either positively or
negatively, in that the counterparties may be similarly
affected by changes in economic, regulatory or other
conditions.
ECT maintains credit policies with regard to its
counterparties that management believes significantly
minimize overall credit risk. These policies include an
evaluation of potential counterparties' financial condition
(including credit rating), collateral requirements under
certain circumstances and the use of standardized agreements
which allow for the netting of positive and negative
exposures associated with a single counterparty.
ECT maintains a credit reserve which is based on
management's evaluation of the credit risk of the overall
portfolio. This reserve is objectively determined using an
implied risk profile based on the difference between risk-
free rates of return and each counterparty's cost of
borrowing. This implied risk is then used to evaluate the
exposure (based on current market value) to each
counterparty adjusted for collateral provisions and overall
concentration of exposure. Based on ECT's policies, its
exposures and the credit reserve, Enron does not anticipate
a materially adverse effect on financial position or results
of operations as a result of counterparty nonperformance.
Non-Trading Activities
Enron's other businesses also enter into forwards, swaps and
other contracts to hedge the impact of market fluctuations
on assets, liabilities, production or other contractual
commitments. Changes in the market value of these
transactions are deferred until the gain or loss is
recognized on the hedged item.
Interest Rate Swaps. At December 31, 1995, Enron had
entered into interest rate swap agreements with a notional
principal amount of $4,005 million to manage interest rate
exposure. Swap agreements relating to notional amounts of
$1,315 million, $700 million and $1,990 million are
scheduled to terminate in 1996, 1997 and thereafter,
respectively.
Energy Commodity Price Swaps. At December 31, 1995, Enron
was a party to energy commodity price swaps covering
approximately 233 TBtu, 169 TBtu and 427 TBtu of natural gas
for the years 1996, 1997 and the period 1998 through 2004,
respectively, and 4 million, 4 million and 6 million barrels
of crude oil for the years 1996, 1997 and the period 1998
through 2000, respectively. During the first quarter of
1996, Enron removed substantially all of its natural gas
commodity price swaps for 1996 by entering into offsetting
positions.
Foreign Currency Contracts. At December 31, 1995, foreign
currency contracts with a notional principal amount of $11.9
million were outstanding. Such contracts will substantially
expire in 1996.
Credit Risk. While notional amounts are used to express
the volume of various derivative financial instruments, the
amounts potentially subject to credit risk, in the event of
nonperformance by the third parties, are substantially
smaller. Counterparties to the forwards, futures and other
contracts discussed above are investment grade financial
institutions. Accordingly, Enron does not anticipate any
material impact to its financial position or results of
operations as a result of nonperformance by the third
parties on financial instruments related to non-trading
activities.
Financial Instruments
The carrying amounts and estimated fair values of Enron's
financial instruments, excluding trading activities which
are marked to market, at December 31, 1995 and 1994 were as
follows:
<TABLE>
<CAPTION>
1995 1994
Carrying Estimated Carrying Estimated
(In Millions) Amount Fair Value Amount Fair Value
<S> <C> <C> <C> <C>
Long-term debt (Note 5) $3,065 $3,360 $2,805 $2,752
Company-obligated preferred
stock of subsidiaries (Note 9) 377 386 377 348
Interest rate swaps - (18) - 5
Energy commodity price swaps - 90 - 80
Foreign currency contracts - - - (1)
</TABLE>
Enron used the following methods and assumptions in
estimating fair values: (a) Long-term debt - the carrying
amount of variable-rate debt approximates fair value, the
fair value of marketable debt is based on quoted market
prices, and the fair value of other debt is based on the
discounted present value of cash flows using Enron's current
borrowing rates; (b) Company-obligated preferred stock of
subsidiaries - the fair value is based on quoted market
prices; and (c) Interest rate swaps, Energy commodity price
swaps and Foreign currency contracts - estimated fair values
have been determined by using available market data and
valuation methodologies. Judgement is necessarily required
in interpreting market data and the use of different market
assumptions or estimation methodologies may affect the
estimated fair value amounts (see "Non-Trading Activities"
above).
The fair market value of cash and cash equivalents, accounts
receivable and accounts payable are not materially different
from their carrying amounts.
Guarantees of liabilities of unconsolidated entities and
residual value guarantees have no book value associated with
them and the fair values of these items are not readily
determinable (see Note 15).
3 Income Taxes
The principal components of Enron's net deferred income tax
liability at December 31, 1995 and 1994 are as follows:
<TABLE>
<CAPTION>
(In Millions) 1995 1994
<S> <C> <C>
Deferred income tax assets -
Alternative minimum tax credit carryforward $ 231 $ 236
Other 84 51
315 287
Deferred income tax liabilities -
Depreciation, depletion and amortization 1,617 1,583
Price risk management activities 427 256
Other 470 406
2,514 2,245
Net deferred income tax liabilities* $2,199 $1,958
<FN>
* Includes $13 million and $65 million in other
current liabilities for 1995 and 1994,respectively.
</TABLE>
The components of income before income taxes are as follows:
<TABLE>
<CAPTION>
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
U.S. $621,881 $415,011 $336,445
Foreign 183,257 204,983 131,331
$805,138 $619,994 $467,776
</TABLE>
Total income tax expense is summarized as follows:
<TABLE>
<CAPTION>
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Payable currently -
Federal $ 29,315 $ 49,021 $ 57,093
State 25,955 13,494 14,692
Foreign 14,084 11,110 12,269
69,354 73,625 84,054
Payment deferred -
Federal 157,716 77,595 (26,070)
State 30,327 (5,948) 15,724
Foreign 28,047 21,312 15,369
216,090 92,959 5,023
285,444 166,584 89,077
Effect of tax rate increase on
deferred tax liability(a) - - 46,177
Total Income Tax Expense $285,444 $166,584 $135,254
<FN>
(a) In August 1993, the U.S. corporate Federal income
tax rate increased from 34% to 35% retroactive to January 1,
1993. Under the provisions of SFAS No. 109, the effect of a
change in the tax rate is recognized in income for the
period of enactment.
</TABLE>
The differences between taxes computed at the U.S. Federal
statutory tax rate and Enron's effective income tax rate are
as follows:
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Statutory Federal income tax
rate provision 35.0% 35.0% 35.0%
Net state income taxes 4.5% 0.8% 4.1%
Revision of prior years' tax estimates (1.5)% (0.8)% (5.3)%
Tax rate increase - - 9.9%
Tight gas sands tax credit (2.8)% (5.9)% (13.9)%
Earnings in foreign jurisdictions taxed
at rates different from the statutory
U.S. Federal rate 0.4% (0.2)% 1.0%
Equity earnings (3.8)% (3.7)% (2.6)%
Minority interest 1.9% 1.7% 2.1%
Asset and stock sale differences 2.1% - -
Other (0.3)% - (1.4)%
Effective income tax rate 35.5% 26.9% 28.9%
</TABLE>
Enron has an alternative minimum tax (AMT) credit
carryforward of approximately $231 million which can be used
to offset regular income taxes payable in future years. The
AMT credit has an indefinite carryforward period.
U.S. and foreign taxes have been provided for earnings of
foreign subsidiary companies that are expected to be
remitted to the parent company. Foreign subsidiaries'
cumulative undistributed earnings of approximately $195
million are considered to be indefinitely reinvested outside
the U.S. and, accordingly, no U.S. income taxes have been
provided thereon. In the event of a distribution of those
earnings in the form of dividends, Enron may be subject to
both foreign withholding taxes and U.S. income taxes net of
allowable foreign tax credits.
4 Supplemental Cash Flow Information
Cash paid for income taxes and interest expense, including
fees incurred on sales of accounts receivable, is as
follows:
<TABLE>
<CAPTION>
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Income taxes $ 13,278 $ 56,595 $ 39,307
Interest (net of amounts
capitalized) 296,180 268,205 299,568
</TABLE>
Non-cash investing and financing activities during 1995,
1994 and 1993 included the exchange of common stock for
convertible preferred stock in transactions valued at $2.9
million, $9.2 million and $33.3 million, respectively.
In addition, in March 1995, a subsidiary of EOG issued
redeemable preferred stock with a liquidation/redemption
value of $19 million in exchange for certain oil and gas
properties. These preferred shares were exchanged in
November 1995 for 633,333 shares of Enron's common stock.
Changes in components of working capital are as follows:
<TABLE>
<CAPTION>
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Receivables $(639,173) $(250,295) $(360,206)
Inventories 26,942 (25,117) 92,228
Payables 126,170 (91,329) 144,518
Accrued taxes 30,286 12,178 (11,941)
Accrued interest (6,877) 5,277 2,913
Other (370,995) 207,914 55,975
Total $(833,647) $(141,372) $ (76,513)
</TABLE>
5 Credit Facilities, Short-Term
Borrowings and Long-Term Debt
Enron and EOG have credit facilities with domestic and
foreign banks which provide for an aggregate of $1.1 billion
in long-term committed credit. Expiration dates of the
committed facilities range from February 1998 to March 2000.
Interest rates on borrowings are based upon the London
Interbank Offered Rate, certificate of deposit rates or
other short-term interest rates. Certain credit facilities
contain covenants which must be met to borrow funds. Such
debt covenants are not anticipated to materially restrict
Enron's ability to borrow funds under such facilities.
Compensating balances are not required, but Enron is
required to pay a commitment or facility fee. During 1995,
no amounts were borrowed under these facilities.
Enron and EOG have also entered into agreements which
provide for uncommitted lines of credit totaling $995
million at December 31, 1995. The uncommitted lines have no
stated expiration dates. Neither compensating balances nor
commitment fees are required as borrowings under the
uncommitted credit lines are available subject to agreement
by the participating banks. At December 31, 1995, no amounts
were outstanding under the uncommitted lines.
In addition to borrowing from banks on a short-term basis,
Enron and certain of its subsidiaries sell commercial paper
to provide financing for various corporate purposes. As of
December 31, 1995, 1994 and 1993, short-term borrowings of
$15.3 million, $259.1 million and $143.8 million,
respectively, have been reclassified as long-term debt based
upon the availability of committed credit facilities with
expiration dates exceeding one year and management's intent
to maintain such amounts in excess of one year subject to
overall reductions in debt levels. Similarly, at December
31, 1995, 1994 and 1993, $286.5 million, $171.1 million and
$132.4 million, respectively, of long-term debt due within
one year remained classified as long-term.
Detailed information on short-term borrowings by Enron is as
follows:
<TABLE>
<CAPTION>
(In Millions) 1995 1994 1993
<S> <C> <C> <C>
As of end of year
Borrowings from -
Commercial paper $ - $ 206.1 $ -
Banks and other 15.3 53.0 143.8
Amount reclassified
as long-term debt (15.3) (259.1) (143.8)
Total short-term borrowings $ - $ - $ -
Weighted average interest rate
at end of year (a) 6.3% 6.2% 3.6%
For the year ended
Maximum borrowings
at any month end (a) $782.9 $1,156.0 $1,087.1
Average borrowings (a)(b) 636.2 768.1 590.9
Weighted average interest rate
during the year (a)(c) 6.1% 4.6% 3.3%
<FN>
(a) Before reclassification as long-term debt.
(b) Computed using the average daily balances
during each month.
(c) Computed using the weighted average interest
rates of debt outstanding during each month.
</TABLE>
Detailed information on long-term debt is as follows:
<TABLE>
<CAPTION>
December 31,
(In Thousands) 1995 1994
<C> <C> <C>
Enron Corp.
Debentures
6.75% due 2005 - senior subordinated $ 200,000 $ 200,000
8.25% due 2012 - senior subordinated 150,000 150,000
Notes Payable
8.10% to 9.25% due 1996 250,000 250,000
6.25% due 1998 - mandatorily
exchangeable into EOG stock 228,375 -
8.50% to 10.75% due from 1998 to 2001 450,000 342,777
6.75% to 9.875% due from 2003 to 2007 992,200 692,200
7% due 2023 100,000 100,000
Other 9,678 56,508
Northern Natural Gas Company
Notes Payable
8.00% due 1999 250,000 250,000
6.875% due 2005 100,000 100,000
Houston Pipe Line Company
Notes Payable
12.125% due 1995 - 100,000
Transwestern Pipeline Company
Notes Payable
7.55% to 9.10% due 2000 123,000 123,000
9.20% due from 1998 to 2004 27,000 27,000
Enron Oil & Gas Company
Notes Payable
8.92% due 1995 - 25,000
9.10% due from 1996 to 1998 70,000 70,000
Other 77,559 67,421
Enron Europe Limited
Other 38,933 -
Amount reclassified from short-term debt 15,348 259,099
Unamortized debt discount and premium (17,254) (7,863)
Total Long-Term Debt $3,064,839 $2,805,142
</TABLE>
The aggregate annual maturities of long-term debt
outstanding at December 31, 1995 are $286.5 million, $26.7
million, $388.9 million, $299.8 million and $281.4 million
for 1996 through 2000, respectively.
6 Accounts Receivable
Enron has entered into an agreement which provides for the
sale of trade accounts receivable with limited recourse
provisions and the rights to certain recoverable pipeline
transition surcharges expiring January 31, 1999. Sales of
trade receivables under these agreements totaled $100.0
million and $328.0 million at December 31, 1995 and 1994,
respectively. Rights to certain recoverable pipeline
transition surcharges sold under these agreements totaled
$34.9 million and $64.2 million at December 31, 1995 and
1994, respectively.
The fees incurred on the sales of accounts receivable
totaled $23.7 million, $20.8 million and $20.6 million for
1995, 1994 and 1993, respectively, and are included in
"Interest and Related Charges, net."
Enron affiliates have concentrations of customers in the
electric and gas utility industries. These concentrations of
customers may impact Enron's overall exposure to credit
risk, either positively or negatively, in that the customers
may be similarly affected by changes in economic or other
conditions. However, Enron's management believes that the
portfolio of receivables is well diversified and that such
diversification minimizes any potential credit risk.
Receivables are generally not collateralized.
7 Production Payment Agreement
In September 1992, EOG entered into a transaction with a
limited partnership under which EOG conveyed an interest in
approximately 124 billion cubic feet equivalent (136
trillion British thermal units) of natural gas and other
hydrocarbons for consideration of $326.8 million (the
production payment agreement). EOG retains responsibility
for its working interest share of the cost of operations.
Enron has accounted for the proceeds received in the
transaction as deferred revenue which is being amortized
into revenue as natural gas and other hydrocarbons are
produced and delivered during the terms of the agreement as
amended in October 1993. Annual amortization of remaining
deferred revenue, based on scheduled deliveries under the
production payment agreement, is approximately $43.3 million
per year through 1998 and $10.7 million for 1999. See Note
18 for the estimate of proved oil and gas reserves dedicated
to the transaction.
8 Unconsolidated Subsidiaries
Enron has investments in and advances to unconsolidated
subsidiaries as follows:
<TABLE>
<CAPTION>
Ownership
Investee Interest December 31,
(In Thousands) 1995 1994
<S> <C> <C> <C>
Citrus Corp. 50% $ 383,351 $ 356,538
Teesside Power Limited 50%(a) 182,937 173,461
Transportadora de Gas del Sur S.A. 18%(a) 97,608 96,451
Joint Energy Development
Investments L.P. 50% 83,952 77,024
Northern Border Partners, L.P. 13% 54,143 55,050
Enron/Dominion Cogen Corp. 50% 50,411 43,456
EOTT Energy Partners, L.P. 42% 37,847 63,044
Other(b) 326,225 200,165
$1,216,474 $1,065,189
<FN>
(a) Net of minority interests, the ownership is 42.5%
for Teesside Power Limited and 9.1% for Transportadora de
Gas del Sur S.A.
(b) Includes investments in various international
development projects which have not reached commercial
operation at December 31, 1995.
</TABLE>
Enron's equity in earnings (losses) of unconsolidated
subsidiaries is as follows:
<TABLE>
<CAPTION>
Investee Year Ended December 31,
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Citrus Corp. $26,814 $ 27,554 $(8,066)
Teesside Power Limited 17,530 12,669 12,444
Transportadora de Gas del Sur S.A. 22,252 22,965 20,721
Joint Energy Development
Investments L.P. 4,175 7,321 -
Northern Border Partners, L.P. 6,743 6,970 1,368
Enron Dominion Cogen Corp. 6,993 6,213 6,874
EOTT Energy Partners, L.P. (22,717) 4,815 -
Other 24,228 23,902 39,952
$86,018 $112,409 $73,293
</TABLE>
Summarized combined financial information of Enron's
unconsolidated subsidiaries is presented below:
<TABLE>
<CAPTION>
December 31,
(In Thousands) 1995 1994
<S> <C> <C>
Balance Sheet
Current assets $1,776,646 $1,805,050
Property, plant and equipment, net 7,813,974 6,072,820
Other noncurrent assets 968,464 1,287,790
Current liabilities 2,049,923 1,189,478
Long-term debt 4,981,680 4,623,035
Other noncurrent liabilities 1,141,911 1,243,241
Owners' equity 2,385,570 2,109,906
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Income Statement
Operating revenues $8,258,113 $7,102,886 $2,351,177
Operating expenses 7,334,801 6,421,637 2,016,977
Net income 225,770 290,089 204,262
Distributions Paid to Enron 68,216 81,100 59,585
</TABLE>
Citrus Corp. Enron has a 50% indirect ownership interest
in and provides services to Citrus Corp. (Citrus), a joint
venture to transport and market natural gas to Florida.
Effective March 1, 1995, Citrus' wholly-owned subsidiary,
Florida Gas Transmission (Florida Gas), placed into service
its Phase III pipeline expansion. The Phase III expansion
increased Florida Gas' firm average delivery capacity by 530
MMcf/day to 1.5 Bcf/day.
Teesside Power Limited (Teesside). During the first
quarter of 1995, Enron reduced its effective interest in
Teesside from 50.0% to 42.5% through a sale of an effective
7.5% interest to one of the original joint venture partners
in Teesside, a joint venture cogeneration company which owns
a 1,875 megawatt independent power facility in northeast
England. An affiliate of Enron operates the facility which
was placed in commercial operation on March 27, 1993. Enron
has guaranteed Teesside's obligation for certain grid
charges and other amounts which could become due under
certain power sales agreements. The value of such guarantees
is included in Note 15.
Under the terms of certain gas supply agreements extending
through 2008, Teesside is obligated to take-or-pay for an
average of up to 240 billion British thermal units (BBtu) of
natural gas per day at indexed prices. Enron has guaranteed
70% of Teesside's payment obligation under the gas supply
agreements. However, Enron believes there are alternative
markets for such gas should the gas not be taken by
Teesside.
Transportadora de Gas del Sur S.A. EPP holds a 25%
interest in Compania de Inversiones de Energia S.A., an
Argentine corporation which owns 70% of Transportadora de
Gas del Sur S.A. (TGS). TGS is the owner and operator of a
4,000 mile natural gas pipeline system in Argentina which
connects major gas fields in southern and western Argentina
with distributors of gas in those areas and in the greater
Buenos Aires area, the principal population center of
Argentina. TGS is one of two transmission systems in
Argentina.
Joint Energy Development Investments (JEDI). JEDI, a
limited partnership which acquires and owns energy
investments, was formed in 1993 with an Enron subsidiary and
the California Public Employee Retirement System (CalPERS)
each owning a 50% interest. Enron and CalPERS have committed
to invest a total of $500 million of capital in JEDI through
1996, of which $85 million has been contributed by Enron as
of December 31, 1995. Enron intends to meet its required
capital commitments primarily by contributing Enron common
stock.
Northern Border Partners, L.P. During October 1993,
Northern Plains Natural Gas Company (Northern Plains), a
wholly-owned subsidiary of Enron, contributed its interest
in Northern Border Pipeline Company to Northern Border
Partners, L.P., a Delaware limited partnership (the Northern
Border Partnership), in exchange for general partner
interests,subordinated units and common units in the
Northern Border Partnership. Northern Plains sold its common
units in the Northern Border Partnership in an underwritten
public offering, retaining a 13% interest in the Northern
Border Partnership.
EOTT Energy Partners, L.P. During March 1994, EOTT Energy
Corp., a wholly-owned subsidiary of Enron, exchanged its
crude oil marketing and transportation operations with EOTT
Energy Partners, L.P. (EOTT) for common and subordinated
units and a 2% general partnership interest. The common
units were subsequently sold in an underwritten public
offering resulting in net proceeds to Enron of approximately
$186 million and a pretax gain of approximately $15 million.
Enron retained seven million subordinated units of EOTT and
its general partnership interest.
In September 1995, EOTT discontinued its West Coast
processing and asphalt marketing business (other than
business from its Arizona asphalt terminals). As a result,
EOTT recorded a one-time charge of $45.8 million. Also
during 1995, Enron entered into an agreement to provide
trade credit support on a secured basis to EOTT in the form
of trade guarantees, letters of credit, loans and letters of
indemnity totaling $450 million through March 31, 1996.
Letters of credit and trade guarantees outstanding under
this agreement at December 31, 1995 are included in Note 15.
During 1995, Enron purchased 296,800 additional common units
of EOTT on the open market. In addition, Enron paid $9.1
million to EOTT in support of EOTT's common unit
distributions and in exchange received Additional
Partnership Interests (APIs). Enron is committed to provide
further support, if needed, up to a total of $29 million
through March 1998 through the purchase of additional APIs.
Subsequent to December 31, 1995, Enron increased its total
ownership in EOTT to 50% through the purchase of additional
common units.
9 Preferred Stock
Second Preferred Stock. The Cumulative Second Preferred
Convertible Stock, $1 par value, pays dividends at an amount
equal to the higher of $10.50 per share or the equivalent
dividend that would be paid if shares of the Cumulative
Second Preferred Convertible Stock were converted to Common
Stock. The dividend for the fourth quarter of 1995 was
$2.901 per share. The dividend for the preceding four
quarters was $2.7304 per share. All previous quarterly
dividends had been $2.625 per share. Each share of the
Cumulative Second Preferred Convertible Stock is convertible
at any time at the option of the holder thereof into 13.652
shares of Enron's common stock, subject to certain
adjustments. The Convertible Preferred Stock is currently
subject to redemption at Enron's option at a price of $100
per share plus accrued dividends. During 1995, 1994 and
1993, 29,489 shares, 91,694 shares and 332,964 shares,
respectively, of the Convertible Preferred Stock were
converted into common stock.
During 1994, Enron authorized and issued to a wholly-owned
subsidiary 35.568509 shares of 9.142% Perpetual Second
Preferred Stock (a new series of the Second Preferred
Stock).
Company-Obligated Preferred Stock of Subsidiaries. During
December 1994, Enron's wholly-owned subsidiary, Enron Equity
Corp., issued 880 shares of 8.57% Preferred Stock, par value
$0.001 per share, liquidation preference $100,000 per share,
in a private transaction at a price of $100,000 per share
with net proceeds of approximately $88 million. The 8.57%
Preferred Stock is redeemable at Enron's option after
December 1999 at a price of $100,000 per share plus
accumulated and unpaid dividends. Dividends on the 8.57%
Preferred Stock are guaranteed by Enron.
During August 1994, Enron Capital Resources, L.P., a
Delaware limited partnership in which Enron is the sole
general partner, issued 3 million shares of 9% Cumulative
Preferred Securities, Series A, at a price to the public of
$25 per share with net proceeds of approximately $73
million.
During November 1993, Enron's wholly-owned subsidiary Enron
Capital LLC issued 8.55 million shares of 8% Cumulative
Guaranteed Monthly Income Preferred Shares (MIPS) at a price
of $25 per share with net proceeds of approximately $207
million.
The Series A Preferred Securities and the MIPS are
redeemable at the option of Enron in whole or in part
beginning August 31, 1999 and November 30, 1998,
respectively, at a redemption price of $25 per share plus
accumulated and unpaid dividends. The liquidation preference
of each of the Series A Preferred Securities and the MIPS is
$25 per share.
10 Common Stock and Dividends
Enron paid quarterly cash dividends on common stock of $.175
per share ($.70 per share annually) from the final quarter
of 1992 until the final quarter of 1993, at which time the
dividend was increased to $.1875 per share ($.75 per share
annually). The dividend was further increased to $.20 per
share ($.80 per share annually) for the final quarter of
1994 and was increased to $.2125 per share ($.85 per share
annually) for the final quarter of 1995. Enron's debt
agreements do not limit the payment of cash dividends on
common stock.
Common stock information is as follows:
<TABLE>
<CAPTION>
1995 1994 1993(a)
<S> <C> <C> <C>
Common Stock, beginning of year 253,069,668 249,095,312 237,532,176
Issued to Benefit and Dividend
Reinvestment Plans 197,388 1,303,047 1,476,131
Issued for Conversions (b) 219,138 1,251,793 2,446,632
Issued to Flexible Equity Trust - - 7,500,000
Issued to JEDI 374,166 1,419,516 140,373
Common Stock, end of year 253,860,360 253,069,668 249,095,312
<FN>
(a) Presented as if the 1993 stock split was January 1, 1993.
(b) Conversions of convertible preferred stock.
</TABLE>
Treasury stock information is as follows:
<TABLE>
<CAPTION>
1995 1994 1993(a)
<S> <C> <C> <C>
Treasury Stock, beginning of year 1,394,833 - 349,400
Benefit and Dividend
Reinvestment Plans
Issued (2,418,216) (47,790) (1,482,927)
Returned 328,342 - 102,013
Open Market Purchases (b) 3,496,504 1,897,923 3,005,200
Issued for Conversions (c) (183,429) - (2,043,090)
Issued to JEDI - (455,300) -
Other - - 69,404
Treasury Stock, end of year 2,618,034 1,394,833 -
<FN>
(a) Presented as if the 1993 stock split was January 1, 1993.
(b) Purchased in connection with a stock repurchase
program authorized by the Board of Directors.
(c) Conversions of convertible preferred stock.
</TABLE>
Enron has various stock plans (the Plans) under which
options for shares of Enron's common stock have been or may
be granted to officers, employees and non-employee members
of the Board of Directors. Under the Plans, options granted
may be either incentive stock options or nonqualified stock
options and are granted at not less than the fair market
value of the stock at the time of grant. Enron accounts for
the Plans under APB Opinion No. 25, and accordingly, no
compensation expense has been recognized. Expiration dates
of the options outstanding at December 31, 1995 range from
February 8, 1998 to December 29, 2005. The Plans provide for
options to be granted with stock appreciation rights (SAR);
however, Enron does not presently intend to issue additional
options with an SAR feature. Summarized information for the
Plans is as follows:
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Shares under option,
beginning of year 24,245,447 9,679,719 7,314,332
Granted (a) 2,971,210 15,805,680 4,253,233
Exercised (3,137,433) (1,019,090) (1,621,680)
Cancelled or expired (1,586,541) (220,862) (266,166)
Shares under option, end of year 22,492,683 24,245,447 9,679,719
Shares available for grant at
end of year (b) 7,830,758 4,006,833 1,500,301
Shares exercisable at end of year 9,599,245 7,183,664 3,104,722
Average price of options exercised
during the year $20.91 $13.50 $13.30
Average price of options outstanding
at end of year $29.02 $27.38 $19.64
<FN>
(a) Includes options granted on December 29, 1995 and
December 30, 1994 for 997,095 shares and 9,717,750 shares,
respectively, under all-employee stock option grants for the
years 1995 through 2000.
(b) Excludes up to 5,209,620 shares, 5,245,100 shares
and 2,528,560 shares as of December 31, 1995, 1994 and 1993,
respectively, which may be issued either as Restricted Stock
or pursuant to stock options.
</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>
1995 1994 1993
<S> <C> <C> <C>
Outstanding at beginning of year 193,505 221,658 35,588
Granted 44,900 30,190 203,700
Cancelled or expired (9,420) (2,040) (3,632)
Issued(a) (69,545) (56,303) (13,998)
Outstanding at end of year 159,440 193,505 221,658
Available for grant at end of year 5,209,620 5,245,100 2,528,560
Average price per share
on date of grant $31.36 $32.89 $27.50
<FN>
(a) Subsequent to December 31, 1995, 1,534,275 shares of
restricted stock were issued in connection with the
conversion of certain compensation plans.
</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
areduction of shareholders' equity. Common shares held by
the Trust are not included in the computation of earnings
per share until such shares are released to fund employee
benefits. During 1995, 1,049,403 shares were released to
fund employee benefits.
11 Retirement Benefits Plan and ESOP
Enron maintains a retirement plan (the Enron Plan) which is
a noncontributory defined benefit plan covering
substantially all employees in the United States and certain
employees in foreign countries. Through December 31, 1994,
participants in the Enron Plan with five years or more of
service were entitled to retirement benefits based on a
formula that uses a percentage of final average pay and
years of service. In connection with a change to the
retirement benefit formula, Enron amended the Enron Plan
providing, among other things, that all employees became
fully vested in retirement benefits earned through December
31, 1994. The formula in place prior to January 1, 1995 was
suspended and replaced with a benefit accrual of 5% of
annual base pay beginning January 1, 1996.
Enron also maintains a noncontributory employee stock
ownership plan (ESOP) which covers all eligible employees.
Allocations to individual employees' retirement accounts
within the ESOP offset a portion of benefits earned under
the Enron Plan. At December 31, 1995, all shares included in
the ESOP had been allocated to the employee accounts.
The components of pension expense are as follows:
<TABLE>
<CAPTION>
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Service cost - benefits earned
during the year $ 1,654 $ 16,192 $ 11,709
Interest cost on projected
benefit obligation 21,172 25,996 25,230
Actual return on plan assets (32,299) (22,235) (37,507)
Amortization and deferrals 8,810 (12,225) 11,184
Pension expense (income) $ (663) $ 7,728 $ 10,616
</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.
<TABLE>
<CAPTION>
(In Thousands) 1995 1994
<S> <C> <C>
Actuarial present value of accumulated
benefit obligation
Vested $(275,668) $(253,881)
Nonvested (26,875) (25,546)
Additional amounts related
to projected wage increases (11,536) (54,260)
Projected benefit obligation (314,079) (333,687)
Plan assets at fair value (a) 294,763 352,608
Plan assets in excess of (less than)
projected benefit obligation (19,316) 18,921
Unrecognized net loss 53,524 35,563
Unrecognized prior service cost 44,476 12,416
Unrecognized net asset at transition (36,205) (42,238)
Contributions 553 548
Prepaid pension cost at December 31 $ 43,032 $ 25,210
Discount rate 7.5% 8.0%
Long-term rate of return on assets 10.5% 10.5%
Rate of increase in wages 4.0% 4.0%
<FN>
(a) Includes plan assets of the ESOP of $152,202
and $235,540 for the years 1995 and 1994, respectively.
</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 extent required by Federal tax regulations.
12 Benefits Other Than Pensions
Enron provides certain medical, life insurance and dental
benefits to eligible employees and their eligible
dependents. Benefits are provided under the provisions of
contributory defined dollar benefit plans. Enron is
currently funding that portion of its obligations under its
postretirement benefit plan which is expected to be
recoverable through rates by its regulated pipelines.
Enron accrues these postretirement benefit costs over the
service lives of the employees expected to be eligible to
receive such benefits. Enron is amortizing the transition
obligation which existed at January 1, 1993 over a period of
approximately 19 years.
The following table sets forth the plan's funded status
reconciled with the amounts reported in the Consolidated
Balance Sheet.
<TABLE>
<CAPTION>
(In Thousands) 1995 1994
<S> <C> <C>
Actuarial present value of accumulated
postretirement benefit obligation (APBO)
Retirees $(114,271) $ (88,838)
Fully eligible active plan
participants (2,342) (2,164)
Other employees (14,648) (15,712)
Total APBO (131,261) (106,714)
Plan assets at fair value 10,511 3,073
APBO in excess of plan assets (120,750) (103,641)
Unrecognized transition obligation 70,058 74,803
Unrecognized prior service costs 19,176 18,148
Unrecognized net loss 25,915 5,148
Accrued postretirement benefit obligation $ (5,601) $ (5,542)
Discount rate 7.5% 8.0%
Health care cost trend rate* 11.7% 12.3%
<FN>
* This rate is assumed to decrease to 5.0% over 10 years.
</TABLE>
The components of net periodic postretirement benefit
expenses are as follows:
<TABLE>
<CAPTION>
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Service costs $ 1,220 $ 1,527 $ 850
Interest costs 9,025 7,964 7,374
Return on plan assets (266) (106) (39)
Amortization of transition obligation 6,386 6,003 4,744
Postretirement benefit expense $16,365 $15,388 $12,929
</TABLE>
A 1% increase in the health care cost trend rate would have
the effect of increasing the APBO and the net periodic
expense by approximately $8.8 million and $0.6 million,
respectively.
13 Natural Gas Rates and Regulatory Issues
Regulatory issues and rates on Enron's regulated pipelines
are subject to final determination by the FERC. Enron's
regulated pipelines currently apply accounting standards
that recognize the economic effects of regulation and,
accordingly, have recorded regulatory assets and liabilities
related to their operations. Enron evaluates the
applicability of regulatory accounting and the
recoverability of these assets through rate or other
contractual mechanisms on an ongoing basis. Net regulatory
assets at December 31, 1995 and 1994, respectively, are
approximately $291 million and $305 million, which include
transition costs incurred related to FERC Order 636 of
approximately $125 million and$158 million. The regulatory
assets related to the FERC Order 636 transition costs are
scheduled to be primarily recovered from customers by the
end of 1998, while the remaining assets are expected to be
recovered over varying time periods.
Enron's regulated pipelines have all successfully completed
their transitions under FERC Order 636 although future
transition costs may be incurred subject to ongoing
negotiations and market factors. On March 1, 1995, Northern
filed a general rate case proceeding with the FERC which
fulfilled a commitment made during its FERC Order 636
restructuring proceeding. The rate case included an increase
of $31 million to Northern's cost of service. The FERC
accepted and suspended the filing to be effective September
1, 1995 subject to refund. Northern effectuated the higher
rates January 1, 1996. Enron believes, based upon its
experience to date and after considering appropriate
reserves that have been established, that the ultimate
resolution of pending regulatory matters will not have a
material impact on Enron's financial position or results of
operations.
14 Litigation and Other Contingencies
Enron is party to various claims and litigation, the
significant items of which are discussed below. Although no
assurances can be given, Enron believes, based on its
experience to date and after considering appropriate
reserves that have been established, that the ultimate
resolution of such items, individually or in the aggregate,
will not have a materially adverse impact on Enron's
financial position or results of operations.
Litigation
In 1995, several parties (the Plaintiffs) filed suit in
Harris County District Court in Houston, Texas against
Intratex Gas Company (Intratex), Houston Pipe Line Company
and Panhandle Gas Company (collectively, the Enron
Defendants), each of which is a wholly-owned subsidiary of
Enron. The Plaintiffs also sued certain other unaffiliated
third parties (collectively, the Other Defendants). The
Plaintiffs were either sellers or royalty owners under
numerous gas purchase contracts with Intratex, many of which
have terminated. Early in 1996, the case was severed by the
Court into two matters that will be tried (or otherwise
resolved) separately. In the first matter, the Plaintiffs
sued only the Enron Defendants, alleging that they committed
fraud and negligent misrepresentation in connection with the
"Panhandle program," a special marketing program established
in the early 1980s. In the second matter, the Plaintiffs
allege that Intratex and the Other Defendants violated state
regulatory requirements and certain gas purchase contracts
by failing to take the Plaintiffs' gas ratably with other
producers' gas at certain times between 1978 and 1988. In
both matters, the Plaintiffs seek an unspecified amount of
actual and punitive damages, plus prejudgement interest and
attorneys fees. All Defendants deny the Plaintiffs' claims
and have asserted various affirmative defenses, including
the statute of limitations. The Enron Defendants believe
they have strong legal and factual defenses, and intend to
vigorously contest the claims brought in each matter.
Although no assurances can be given, Enron believes that the
ultimate resolution of these matters will not have a
materially adverse effect on its financial position or
results of operations.
Environmental Matters
Enron is subject to extensive Federal, state and local
environmental laws and regulations. These laws and
regulations require expenditures in connection with the
construction of new facilities, the operation of existing
facilities and for remediation at various operating sites.
The implementation of the Clean Air Act Amendments is
expected to result in increased operating expenses. These
increased operating expenses are not expected to have a
material impact on Enron's financial position or results of
operations.
In addition, Enron received requests for information from
the Environmental Protection Agency (EPA) and state
environmental agencies inquiring whether Enron has disposed
of materials at certain waste disposal sites. Enron has
received notices from EPA and state agencies that it is a
"potentially responsible party" (PRP) under the
Comprehensive Environmental Response, Compensation and
Liability Act and analogous state statutes, and may be
required to share in the costs of the cleanup of other,
similar sites. However, Enron believes that any potential
assessments in connection with these PRP notices and third
party claims, either taken individually or in the aggregate,
will not have a material impact on Enron's financial
position or results of operations.
Other
In October 1994, an explosion occurred at Enron's methanol
plant in Pasadena, Texas. Before the explosion, the plant
was producing approximately 420,000 gallons of methanol per
day, approximately half of which was being used at Enron's
MTBE plant. There were no fatalities or serious injuries as
a result of the explosion. The plant was placed back into
commercial operation in June 1995. Taking into account
business interruption and other insurance coverages, Enron
currently anticipates that the explosion did not and will
not have a materially adverse effect on its financial
position or results of operations.
In connection with a Power Purchase Agreement between Dabhol
Power Company, Enron's 80%-owned subsidiary, and the
Maharashtra State Electricity Board, Dabhol Power Company
has been developing Phase I of an electricity generating
power plant south of Bombay, State of Maharashtra, India
(the Project). On August 3, 1995, after construction had
begun, a new coalition government in the State of
Maharashtra announced the State government's intention to
terminate the Project, and construction ceased on August 8,
1995. Enron believes that such actions were in clear
violation of the contract and in response to these actions,
Dabhol Power Company commenced arbitration proceedings in
London against the State government for the actions it has
taken to terminate the Project. Dabhol Power Company seeks
to recover all of its construction and other expenses, in
addition to lost profits. In addition, Dabhol Power Company
has both orally and in writing communicated to the
Maharashtra State government its desire to go forward with
construction of the Project and its willingness to resolve
any outstanding issues. In January 1996, the Maharashtra
State government notified Dabhol Power Company in writing
that it had approved a restructured transaction (that
includes both Phase I and Phase II and that increases the
planned capacity of the facility by 435 megawatts to 2,450
megawatts) on terms that are acceptable to Enron. While the
parties are working together in good faith and Enron
anticipates construction to resume in the near future,
various approvals remain outstanding from government
agencies and lenders. Although the outcomes of the
arbitration and the renegotiation processes cannot be
predicted with certainty, based on currently available
information, Enron believes that the ultimate outcome of the
Project will not have a materially adverse effect on its
financial position.
In March 1993, Enron entered into long-term gas contracts
with Phillips Petroleum Company United Kingdom Limited,
British Gas Exploration and Production Limited and Agip
(U.K.) Limited to purchase all of the future gas production
from the J-Block field which is located in the North Sea
offshore the United Kingdom (the J-Block Contracts). Such
agreements provide for Enron to take or pay for the gas at a
fixed price (with possible escalations throughout the
contract period). Gas paid for, but not taken, may be
recovered in later contract years. The J-Block Contracts
provide for a first delivery date of not later than October
1, 1996. The contract price for such natural gas is in
excess of current spot market prices in the United Kingdom.
In September 1995, Enron announced that, in accordance with
its contractual rights, it had notified the J-Block sellers
that Enron's nominations for gas from the J-Block fields
were estimated to be zero from the first delivery date
through September 30, 1997. In addition, in accordance with
its contractual rights, Enron has made no estimated
nominations for J-Block gas to date under the J-Block
Contracts for the contract year ending September 30, 1998.
Enron continues its good faith efforts to develop mutually
beneficial solutions regarding pricing terms so that
production from J-Block can begin as soon as possible. Enron
believes that there are many commercial reasons for the
parties to resolve any contract issues, but efforts have not
been successful to date. Enron has advised the J-Block
sellers that it intends to assert all legal rights, exercise
all available commercial flexibility and pursue all
available commercial and legal remedies under the J-Block
Contracts, and stands ready and able to perform all legal
obligations under the J-Block Contracts, including potential
prepayments for gas to be taken in later years. The long-
term market demand for J-Block gas supply remains favorable
and Enron anticipates being able to meet all of its various
short- and long-term market commitments. Although no
assurances can be given, based upon the foregoing and other
information currently available, Enron does not anticipate
that the J-Block Contracts will have a materially adverse
effect on its financial position.
15 Commitments
Firm Transportation Obligations
Enron has firm transportation agreements with various joint
venture pipelines. Under these agreements, Enron must make
specified minimum payments each month. The estimated
aggregate amounts of such required future payments at
December 31, 1995, were:
<TABLE>
<CAPTION>
(In Millions)
<C> <C>
1996 $ 108.5
1997 118.5
1998 122.1
1999 126.9
2000 132.1
Later years 1,194.7
Total $1,802.8
</TABLE>
The costs incurred under these agreements, including
commodity charges on actual quantities shipped, totaled
$18.4 million, $20.8 million and $42.4 million in 1995, 1994
and 1993, respectively. Enron has assigned a firm
transportation contract with one of its joint ventures to a
third party and guaranteed minimum payments under the
contract averaging approximately $45.4 million annually
through 2001.
Other Commitments
Enron leases property, operating facilities and equipment
under various operating leases, certain of which contain
renewal and purchase options and residual value guarantees.
Guarantees under the leases total $1.02 billion at December
31, 1995. Future commitments related to these items at
December 31, 1995 are as follows:
<TABLE>
<CAPTION>
(In Millions)
<C> <C>
1996 $ 164.5
1997 139.2
1998 117.4
1999 92.6
2000 87.4
Later years 434.0
Total minimum payments $1,035.1
</TABLE>
Total rent expense incurred during 1995, 1994 and 1993 was
$147.2 million, $125.6 million and $103.7 million,
respectively.
Enron guarantees certain long-term contracts for the sale of
electrical power and steam from a cogeneration facility
owned by one of Enron's equity investees. Under terms of the
contracts, which initially extend through June 1999, Enron
could be liable for penalties should, under certain
conditions, the contracts be terminated early. Enron also
guarantees the performance of certain of its unconsolidated
subsidiaries in connection with letters of credit issued on
behalf of those unconsolidated subsidiaries. At December 31,
1995, a total of $320.6 million of such guarantees were
outstanding, including $116.2 million on behalf of EOTT. In
addition, Enron is a guarantor on certain liabilities of
unconsolidated subsidiaries and other companies totaling
approximately $665.3 million, including $300.7 million
related to EOTT trade obligations. The EOTT letters of
credit and guarantees of trade obligations are fully secured
by the assets of EOTT. Management does not consider it
likely that Enron would be required to perform or otherwise
incur any losses associated with the above guarantees. In
addition, certain commitments have been made related to 1996
planned capital expenditures.
16 Other Income, Net
The components of Other Income, Net are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Gain on sale of EOG stock $366,695 $ - $ -
Gains on sales of other
assets and investments 100,476 37,270 102,268
Regulatory, contingency
and other adjustments (19,905) 17,700 (55,689)
Foreign currency gains (losses) (735) 8,188 -
Litigation adjustments and
settlements, net (7,605) (1,110) 4,282
Other (4,685) 15,001 11,254
$434,241 $77,049 $ 62,115
</TABLE>
In December 1995, Enron completed a public offering of 31
million outstanding shares of its EOG common stock, reducing
its ownership interest from 80% to 61%. Enron recognized a
pretax gain of $367 million ($161 million after tax) on net
proceeds totaling $650 million.
Concurrently, Enron issued 6 1/4% Exchangeable Notes which
will be mandatorily exchangeable in three years into shares
of EOG common stock owned by Enron at a specified exchange
rate (or at Enron's option, for cash with an equal value).
Proceeds from the issuance of these notes totaled $221
million. At the maturity of the notes, if all of the
Exchangeable Notes are exchanged for the maximum number of
EOG common shares, Enron's interest in EOG will be reduced
to approximately 54%.
17 Geographic and business Segment Information
Enron's operations are classified into four business
segments:
Transportation and Operation - Interstate transmission of
natural gas. Construction, management and operation of
pipelines, liquids, clean fuel plants and power facilities.
Investment in crude oil transportation activities and
liquids pipeline operations.
Domestic Gas and Power Services - Purchasing, marketing and
financing of natural gas, natural gas liquids, crude oil and
power. Price risk management in connection with natural gas,
natural gas liquids, crude oil and power transactions.
Intrastate natural gas pipelines. Development, acquisition
and promotion of natural gas fired power plants in North
America. Extraction of natural gas liquids.
International Gas and Power Services - Independent (non-
utility) development, acquisition and promotion of power
plants, natural gas liquids facilities and pipelines outside
of North America.
Exploration and Production - Natural gas and crude oil
exploration and production primarily in the United States,
Canada, Trinidad and India.
Financial information by geographic and business segment for
each of the three years in the period ended December 31,
1995, follows.
<TABLE>
Geographic Segments
<CAPTION>
Year Ended December 31,
(In Thousands) 1995 1994 1993
<S> <C> <C> <C>
Operating Revenues from
Unaffiliated Customers
United States $ 7,855,215 $ 7,604,127 $ 7,071,406
Foreign 1,333,782 1,379,596 914,394
$ 9,188,997 $ 8,983,723 $ 7,985,800
Intersegment Sales
United States $ 23,735 $ 48,369 $ 20,785
Foreign 158,812 116,257 66,574
$ 182,547 $ 164,626 $ 87,359
Operating Income
United States $ 487,319 $ 609,008 $ 567,274
Foreign 130,683 106,764 63,528
$ 618,002 $ 715,772 $ 630,802
Income Before Interest, Minority
Interest and Income Taxes
United States $ 968,637 $ 755,686 $ 663,276
Foreign 196,445 188,706 134,391
$ 1,165,082 $ 944,392 $ 797,667
Identifiable Assets
United States $10,694,896 $ 9,597,093 $ 9,939,618
Foreign 1,327,565 1,303,729 867,613
$12,022,461 $10,900,822 $10,807,231
</TABLE>
<TABLE>
Operations In Business and Geographic Segments
Business Segments
<CAPTION>
International
Transportation Domestic Gas Gas and Exploration Corporate
and and Power Power and and
(In Thousands) Operation Services Services Production Other(c)(d) Total
<S> <C> <C> <C> <C> <C> <C>
1995
Unaffiliated Revenues(a) $ 804,946 $7,063,750 $ 839,125 $ 481,176 $ - $ 9,188,997
Intersegment Revenues(b) 25,610 (102,975) 43,757 278,191 (244,583) -
Total Revenues 830,556 6,960,775 882,882 759,367 (244,583) 9,188,997
Depreciation, Depletion and
Amortization 82,790 103,582 26,712 216,047 2,575 431,706
Operating Income (Loss) 299,227 114,583 75,192 240,002 (111,002) 618,002
Equity in Earnings of Unconsolidated
Subsidiaries 23,156 6,325 57,245 - (708) 86,018
Other Income, net 36,803 36,590 9,531 669 377,469 461,062
Income Before Interest, Minority
Interest and Income Taxes 359,186 157,498 141,968 240,671 265,759 1,165,082
Additions to Property, Plant
and Equipment 121,208 97,781 58,212 464,045 8,255 749,501
Identifiable Assets 2,360,702 5,991,423 813,868 2,066,952 789,516 12,022,461
Investments in and Advances to
Unconsolidated Subsidiaries 533,531 156,805 467,596 - 58,542 1,216,474
Total Assets $2,894,233 $6,148,228 $1,281,464 $2,066,952 $ 848,058 $13,238,935
1994
Unaffiliated Revenues(a) $ 937,524 $7,165,582 $ 391,919 $ 488,698 $ - $ 8,983,723
Intersegment Revenues(b) 38,756 13,392 6,984 290,090 (349,222) -
Total Revenues 976,280 7,178,974 398,903 778,788 (349,222) 8,983,723
Depreciation, Depletion and
Amortization 87,555 93,795 15,226 242,182 2,571 441,329
Operating Income (Loss) 327,267 164,118 72,206 195,120 (42,939) 715,772
Equity in Earnings of Unconsolidated
Subsidiaries 48,695 18,427 45,227 - 60 112,409
Other Income, net 27,012 19,701 30,312 2,783 36,403 116,211
Income Before Interest, Minority
Interest and Income Taxes 402,974 202,246 147,745 197,903 (6,476) 944,392
Additions to Property, Plant
and Equipment 117,018 83,014 13,887 442,078 4,918 660,915
Identifiable Assets 2,388,517 5,802,989 449,988 1,823,898 435,430 10,900,822
Investments in and Advances to
Unconsolidated Subsidiaries 527,822 161,788 351,354 - 24,225 1,065,189
Total Assets $2,916,339 $5,964,777 $ 801,342 $1,823,898 $ 459,655 $11,966,011
1993
Unaffiliated Revenues(a) $1,385,925 $5,449,946 $ 751,375 $ 398,554 $ - $ 7,985,800
Intersegment Revenues(b) 80,081 134,158 19,213 308,571 (542,023) -
Total Revenues 1,466,006 5,584,104 770,588 707,125 (542,023) 7,985,800
Depreciation, Depletion and
Amortization 115,922 80,960 9,081 249,704 2,521 458,188
Operating Income (Loss) 341,272 155,573 64,582 122,439 (53,064) 630,802
Equity in Earnings of Unconsolidated
Subsidiaries 22,427 8,821 41,962 - 83 73,293
Other Income, net 18,437 32,466 24,835 6,635 11,199 93,572
Income Before Interest, Minority
Interest and Income Taxes 382,136 196,860 131,379 129,074 (41,782) 797,667
Additions to Property, Plant
and Equipment 144,835 102,518 52,545 383,064 5,070 688,032
Identifiable Assets 2,808,816 5,352,163 492,297 1,668,395 485,560 10,807,231
Investments in and Advances to
Unconsolidated Subsidiaries 278,912 83,360 315,461 - 19,351 697,084
Total Assets $3,087,728 $5,435,523 $ 807,758 $1,668,395 $ 504,911 $11,504,315
<FN>
(a) Unaffiliated revenues include sales to unconsolidated subsidiaries.
(b) Intersegment sales are made at prices comparable to those received
from unaffiliated customers and in some instances are affected by
regulatory considerations.
(c) Corporate and Other assets consist of cash and cash equivalents,
investments in marketable securities, receivables transferred from
subsidiaries in connection with the receivables sale program and
miscellaneous other assets.
(d) Includes consolidating eliminations.
</TABLE>
18 Oil and Gas Producing Activities
(Unaudited except for Results of Operations for Oil and Gas
Producing Activities)
The following information regarding Enron's oil and gas
producing activities should be read in conjunction with Note
1. This information includes amounts attributable to a 39%
minority interest at December 31, 1995 and a 20% minority
interest at December 31, 1994, 1993 and 1992.
<TABLE>
Capitalized Costs Relating to Oil and Gas Producing
Activities
<CAPTION>
December 31,
(In Thousands) 1995 1994
<S> <C> <C>
Proved properties $ 3,253,593 $ 2,889,242
Unproved properties 127,331 126,193
Total 3,380,924 3,015,435
Accumulated depreciation,
depletion and amortization (1,499,379) (1,330,624)
Net capitalized costs $ 1,881,545 $ 1,684,811
</TABLE>
<TABLE>
Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities (a)
<CAPTION>
Foreign
(In Thousands) United States Canada Trinidad India Other Total
<S> <C> <C> <C> <C> <C> <C>
1995
Acquisition of properties
Unproved $ 16,196 $ 4,645 $ - $ - $ 1,482 $ 22,323
Proved 122,369 116 - 5,000 - 127,485
Total 138,565 4,761 - 5,000 1,482 149,808
Exploration 47,463 7,197 374 (98) 17,948 72,884
Development 217,674 28,611 32,692 16,756 577 296,310
Total $403,702 $40,569 $33,066 $21,658 $20,007 $519,002
1994
Acquisition of properties
Unproved $ 45,776 $ 6,618 $ - $ - $ (17) $ 52,377
Proved 17,367 4,523 - 12,300 - 34,190
Total 63,143 11,141 - 12,300 (17) 86,567
Exploration 70,669 8,210 850 2,302 11,242 93,273
Development 223,241 35,896 60,778 767 564 321,246
Total $357,053 $55,247 $61,628 $15,369 $11,789 $501,086
1993
Acquisition of properties
Unproved $ 23,686 $ 4,556 $ - $ - $ 887 $ 29,129
Proved 6,625 2,598 - - - 9,223
Total 30,311 7,154 - - 887 38,352
Exploration 53,918 9,096 1,367 - 18,595 82,976
Development 247,705 28,045 41,262 - - 317,012
Total $331,934 $44,295 $42,629 $ - $19,482 $438,340
<FN>
(a) Costs have been categorized on the basis of
Financial Accounting Standards Board definitions which
include costs of oil and gas producing activities whether
capitalized or charged to expense as incurred.
</TABLE>
<TABLE>
Results of Operations for Oil and Gas Producing Activities (a)
The following tables set forth results of operations for oil
and gas producing activities for the three years in the
period ended December 31, 1995:
<CAPTION>
Foreign
(In Thousands) United States Canada Trinidad India Other Total
<S> <C> <C> <C> <C> <C> <C>
1995
Operating revenues
Associated companies $223,652 $ 6,893 $ - $ - $ - $230,545
Trade 122,567 36,815 71,686 15,411 - 246,479
Gains on sales of reserves
and related assets 62,737 84 - - - 62,821
Total 408,956 43,792 71,686 15,411 - 539,845
Exploration expenses, including
dry hole costs 35,298 3,839 374 (98) 15,542 54,955
Production costs 63,734 13,825 8,176 10,553 - 96,288
Impairment of unproved oil and
gas properties 21,981 1,734 - - - 23,715
Depreciation, depletion and
amortization 180,788 19,533 14,633 335 368 215,657
Income (loss) before income taxes 107,155 4,861 48,503 4,621 (15,910) 149,230
Income tax expense (benefit) 1,226 1,133 26,677 2,311 (1,335) 30,012
Results of Operations $105,929 $ 3,728 $21,826 $ 2,310 $(14,575) $119,218
1994
Operating revenues
Associated companies $315,866 $ 8,452 $ - $ - $ - $324,318
Trade 115,375 42,017 35,908 509 - 193,809
Gains on sales of reserves and
related assets 54,026 (12) - - - 54,014
Total 485,267 50,457 35,908 509 - 572,141
Exploration expenses, including
dry hole costs 42,242 4,503 836 2,302 9,125 59,008
Production costs 68,998 12,776 5,083 26 - 86,883
Impairment of unproved oil and
gas properties 23,862 1,074 - - - 24,936
Depreciation, depletion and
amortization 218,433 16,572 6,572 - 281 241,858
Income (loss) before income taxes 131,732 15,532 23,417 (1,819) (9,406) 159,456
Income tax expense (benefit) (8,617) 6,175 12,804 (910) (2,873) 6,579
Results of Operations $140,349 $ 9,357 $10,613 $ (909) $ (6,533) $152,877
1993
Operating revenues
Associated companies $369,824 $ 9,637 $ - $ - $ - $379,461
Trade 140,552 33,228 1,209 - - 174,989
Gains on sales of reserves
and related assets 13,724 (406) - - - 13,318
Total 524,100 42,459 1,209 - - 567,768
Exploration expenses, including
dry hole costs 35,029 6,657 1,367 - 12,223 55,276
Production costs 75,767 14,063 1,496 - - 91,326
Impairment of unproved oil and
gas properties 19,499 968 - - - 20,467
Depreciation, depletion and
amortization 234,292 14,630 387 - 154 249,463
Income (loss) before income taxes 159,513 6,141 (2,041) - (12,377) 151,236
Income tax expense (benefit) (15,525) 2,265 (1,020) - (1,742) (16,022)
Results of Operations $175,038 $ 3,876 $(1,021) $ - $(10,635) $167,258
<FN>
(a) Excludes net revenues associated with other
marketing activities, interest charges, general corporate
expenses and certain gathering and handling fees for each of
the three years in the period ended December 31, 1995. The
gathering and handling fees and other marketing net revenues
are directly associated with oil and gas operations with
regard to required segment reporting, but are not part of
required disclosures about oil and gas producing activities.
</TABLE>
Oil and Gas Reserve Information
The following summarizes the policies used by Enron in
preparing the accompanying oil and gas supplemental reserve
disclosures, Standardized Measure of Discounted Future Net
Cash Flows Relating to Proved Oil and Gas Reserves and
reconciliation of such standardized measure from period to
period.
Estimates of proved and proved developed reserves at
December 31, 1995, 1994 and 1993 were based on studies
performed by Enron's engineering staff for reserves in the
United States, Canada, Trinidad and India. Opinions by
DeGolyer and MacNaughton, independent petroleum consultants,
for the years ended December 31, 1995, 1994 and 1993
covering producing areas, in the United States and Canada,
containing 73%, 59% and 65%, respectively, of proved
reserves of Enron on a net-equivalent-cubic-feet-of-gas
basis, indicate that the estimates of proved reserves
prepared by Enron's engineering staff for the properties
reviewed by DeGolyer and MacNaughton, when compared in total
on a net-equivalent-cubic-feet-of-gas basis, do not differ
by more than 5% from those prepared by DeGolyer and
MacNaughton's engineering staff. All reports by DeGolyer and
MacNaughton were developed utilizing geological and
engineering data provided by Enron.
The standardized measure of discounted future net cash flows
does not purport, nor should it be interpreted, to present
the fair market value of Enron's crude oil and natural gas
reserves. An estimate of fair value would also take into
account, among other things, the recovery of reserves not
presently classified as proved reserves, anticipated future
changes in prices and costs and a discount factor more
representative of the time value of money and the risks
inherent in reserve estimates.
Enron's presentation of estimated proved oil and gas
reserves has been restated to exclude, for each of the years
presented, those quantities attributable to future
deliveries required under a volumetric production payment.
In order to calculate such amounts, Enron has assumed that
deliveries under the volumetric production payment are made
as scheduled at expected British thermal unit factors, and
that delivery commitments are satisfied through delivery of
actual volumes as opposed to cash settlements.
<TABLE>
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
<CAPTION>
(In Thousands) United States Canada Trinidad India Total
<S> <C> <C> <C> <C> <C> <C>
1995
Future cash inflows(a) $3,996,029 $ 502,803 $ 395,328 $ 396,130 $ 5,290,290
Future production costs (747,064) (203,906) (152,287) (202,410) (1,305,667)
Future development costs (297,859) (7,153) (3,610) (13,500) (322,122)
Future net cash flows before
income taxes 2,951,106 291,744 239,431 180,220 3,662,501
Future income taxes (695,843) (46,310) (105,188) (81,349) (928,690)
Future net cash flows 2,255,263 245,434 134,243 98,871 2,733,811
Discount to present value at
10% annual rate (1,015,123) (68,861) (19,217) (45,470) (1,148,671)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $1,240,140(b) $ 176,573 $ 115,026 $ 53,401 $ 1,585,140(b)
1994
Future cash inflows(a) $2,315,215 $ 487,050 $ 317,758 $ 168,370 $ 3,288,393
Future production costs (606,932) (196,275) (87,479) (105,840) (996,526)
Future development costs (135,768) (9,596) (1,781) (4,500) (151,645)
Future net cash flows before
income taxes) 1,572,515 281,179 228,498 58,030 2,140,222
Future income taxes (208,163) (57,220) (102,171) (22,482) (390,036)
Future net cash flows 1,364,352 223,959 126,327 35,548 1,750,186
Discount to present value at
10% annual rate (401,547) (67,018) (22,897) (14,730) (506,192)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 962,805(b) $ 156,941 $ 103,430 $ 20,818 $ 1,243,994(b)
1993
Future cash inflows(a) $3,154,790 $ 592,845 $ 147,542 $ - $ 3,895,177
Future production costs (639,760) (230,230) (45,385) - (915,375)
Future development costs (165,473) (21,001) (7,582) - (194,056)
Future net cash flows before
income taxes 2,349,557 341,614 94,575 - 2,785,746
Future income taxes (487,017) (91,718) (35,477) - (614,212)
Future net cash flows 1,862,540 249,896 59,098 - 2,171,534
Discount to present value at
10% annual rate (600,172) (90,125) (9,519) - (699,816)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $1,262,368(b) $ 159,771 $ 49,579 $ - $ 1,471,718(b)
<FN>
(a) Based on year-end market prices determined at the
point of delivery from the producing unit.
(b) Excludes $36.0 million, $60.3 million, $105.3
million and $127.7 million at December 31, 1995, 1994, 1993
and 1992, respectively, associated with a volumetric
production payment sold effective October 1, 1992, as
amended, to be delivered over a seventy-eight month period
beginning October 1, 1992 (see Note 7).
</TABLE>
<TABLE>
Changes in Standardized Measure of Discounted Future Net
Cash Flows
<CAPTION>
(In Thousands) United States Canada Trinidad India Total
<C> <C> <C> <C> <C> <C>
December 31, 1992 $1,183,692 $125,419 $ - $ - $1,309,111
Sales and transfers of oil
and gas produced, net of
production costs (388,251) (28,802) 287 - (416,766)
Net changes in prices and
production costs 158,102 28,400 - - 186,502
Extensions, discoveries, additions
and improved recovery, net of
related costs 275,722 27,785 74,191 - 377,698
Development costs incurred 58,500 13,900 - - 72,400
Revisions of estimated development
costs 32,196 (1,345) - - 30,851
Revisions of previous quantity
estimates (26,118) 5,668 - - (20,450)
Accretion of discount 128,461 15,348 - - 143,809
Net change in income taxes (76,755) (9,795) (24,899) - (111,449)
Purchases of reserves in place 9,462 2,707 - - 12,169
Sales of reserves in place (36,919) (1,140) - - (38,059)
Changes in timing and other (55,724) (18,374) - - (74,098)
December 31, 1993 $1,262,368 $159,771 $ 49,579 $ - $1,471,718
Sales and transfers of oil
and gas produced, net
of production costs (339,809) (37,693) (30,825) (483) (408,810)
Net changes in prices and
production costs (506,273) (65,287) 11,002 - (560,558)
Extensions, discoveries, additions
and improved recovery, net of
related costs 225,366 51,006 96,515 - 372,887
Development costs incurred 69,900 6,700 7,582 - 84,182
Revisions of estimated development
costs 6,792 5,931 - - 12,723
Revisions of previous quantity
estimates (2,909) (3,407) 14,077 - 7,761
Accretion of discount 145,119 19,762 7,448 - 172,329
Net change in income taxes 167,983 19,966 (45,789) (7,752) 134,408
Purchases of reserves in place 16,651 3,404 - 29,053 49,108
Sales of reserves in place (27,980) (461) - - (28,441)
Changes in timing and other (54,403) (2,751) (6,159) - (63,313)
December 31, 1994 $ 962,805 $156,941 $103,430 $20,818 $1,243,994
Sales and transfers of oil
and gas produced, net
of production costs (268,463) (29,883) (63,510) (4,858) (366,714)
Net changes in prices and
production costs 12,079 (5,698) (37,035) 7,857 (22,797)
Extensions, discoveries, additions
and improved recovery, net of
related costs 376,474(a) 38,028 53,674 46,180 514,356(a)
Development costs incurred 29,100 2,600 1,800 - 33,500
Revisions of estimated development
costs 920 139 28,771 4,500 34,330
Revisions of previous quantity
estimates 5,694 (5,217) 10,142 (29) 10,590
Accretion of discount 97,248 17,483 17,412 2,857 135,000
Net change in income taxes (132,614) 10,592 (8,048) (28,127) (158,197)
Purchases of reserves in place 193,711 - - - 193,711
Sales of reserves in place (54,441) (569) - - (55,010)
Changes in timing and other 17,627 (7,843) 8,390 4,203 22,377
December 31, 1995 $1,240,140 $176,573 $115,026 $53,401 $1,585,140
<FN>
(a) Includes approximately $77 million related to the
reserves in the Big Piney deep Paleozoic formations.
</TABLE>
Reserve Quantity Information
Enron's estimates of proved developed and net proved
reserves of crude oil, condensate, natural gas liquids and
natural gas and of changes in net proved reserves were as
follows:
<TABLE>
<CAPTION>
United States Canada Trinidad India Total
<C> <C> <C> <C> <C> <C>
Net proved developed reserves
Natural gas (Bcf)
December 31, 1992 1,054.1(a) 194.4 - - 1,248.5(a)
December 31, 1993 1,079.8(a) 250.6 71.4 - 1,401.8(a)
December 31, 1994 1,128.2(a) 288.3 206.2 - 1,622.7(a)
December 31, 1995 1,218.1(a)(b) 310.1 233.9 - 1,762.1(a)(b)
Liquids (MBbl)(c)
December 31, 1992 12,762(a) 5,329 - - 18,091(a)
December 31, 1993 11,165(a) 5,409 1,591 - 18,165(a)
December 31, 1994 16,770(a) 7,073 4,429 7,585 35,857(a)
December 31, 1995 19,977(a) 6,505 5,607 11,542 43,631(a)
Natural gas (Bcf)
Net proved reserves at
December 31, 1992 1,326.1(a) 232.5 - - 1,558.6(a)
Revisions of previous estimates (31.3) 11.0 - - (20.3)
Purchases in place 9.2 2.6 - - 11.8
Extensions, discoveries and
other additions 234.9 47.7 101.3 - 383.9
Sales in place (13.7) (1.5) - - (15.2)
Production (212.0) (21.3) (0.8) - (234.1)
Net proved reserves at
December 31, 1993 1,313.2(a) 271.0 100.5 - 1,684.7(a)
Revisions of previous estimates (17.1) (6.5) 15.0 - (8.6)
Purchases in place 18.8 9.2 - 29.3 57.3
Extensions, discoveries and
other additions 233.8 50.2 113.9 - 397.9
Sales in place (29.3) (1.0) - - (30.3)
Production (212.0) (26.3) (23.2) - (261.5)
Net proved reserves at
December 31, 1994 1,307.4(a) 296.6 206.2 29.3 1,839.5(a)
Revisions of previous estimates 10.1 (8.1) 17.5 (29.3) (9.8)
Purchases in place 174.8 - - - 174.8
Extensions, discoveries and
other additions 1,391.6(b) 54.8 60.8 75.0 1,582.2(b)
Sales in place (38.1) (1.7) - - (39.8)
Production (191.7) (27.7) (39.0) - (258.4)
Net proved reserves at
December 31, 1995 2,654.1(a)(b) 313.9 245.5 75.0 3,288.5(a)(b)
Liquids (MBbl)(c)
Net proved reserves at
December 31, 1992 13,865 5,358 - - 19,223
Revisions of previous estimates 1,490 (536) - - 954
Purchases in place 15 489 - - 504
Extensions, discoveries and
other additions 3,552 1,115 2,251 - 6,918
Sales in place (3,230) (23) - - (3,253)
Production (2,520) (932) (33) - (3,485)
Net proved reserves at
December 31, 1993 13,172 5,471 2,218 - 20,861
Revisions of previous estimates 2,179 (177) 455 - 2,457
Purchases in place 358 - - 7,617 7,975
Extensions, discoveries and
other additions 5,332 2,848 2,687 - 10,867
Sales in place (257) - - - (257)
Production (2,997) (905) (931) (32) (4,865)
Net proved reserves at
December 31, 1994 17,787 7,237 4,429 7,585 37,038
Revisions of previous estimates (413) (351) 396 4,874 4,506
Purchases in place 4,264 - - - 4,264
Extensions, discoveries and
other additions 8,703 729 3,896 - 13,328
Sales in place (1,241) (9) - - (1,250)
Production (3,701) (1,021) (1,851) (917) (7,490)
Net proved reserves at
December 31, 1995 25,399 6,585 6,870 11,542 50,396
<FN>
(a) Excludes approximately 54.2 Bcf, 70.9 Bcf, 87.5 Bcf
and 114.3 Bcf at December 31, 1995, 1994 , 1993 and 1992,
respectively, associated with a volumetric production
payment sold effective October 1, 1992, as amended, to be
delivered over a seventy-eight month period beginning
October 1, 1992 (see Note 7).
(b) Includes 1,180.0 Bcf related to net proved Deep
Paleozoic natural gas reserves.
(c) Includes crude oil, condensate and natural gas
liquids.
</TABLE>
<TABLE>
Enron Corp. and Subsidiaries
SUPPLEMENTAL FINANCIAL INFORMATION (UNAUDITED)
Quarterly Results
<CAPTION>
Income Before
Interest, Minority Fully
(In Thousands, Operating Gross Interest and Primary Earnings Diluted Earnings
Except Per Share Amounts) Revenues Profit Income Taxes Net Income Per Share(a) Per Share(a)
<S> <C> <C> <C> <C> <C> <C>
1995
First Quarter $2,303,949 $684,516 $371,442 $194,950 $.79 $.73
Second Quarter 2,149,346 598,866 230,447 94,045 .37 .35
Third Quarter 2,185,805 629,256 239,328 100,583 .40 .37
Fourth Quarter 2,549,897 542,873 323,865 130,116 .52 .49
1994
First Quarter $2,455,726 $673,333 $336,066 $173,063 $.70 $.65
Second Quarter 1,910,709 539,167 168,703 75,601 .30 .28
Third Quarter 2,030,663 553,774 204,569 95,995 .38 .36
Fourth Quarter 2,586,625 700,340 235,054 108,751 .43 .41
<FN>
(a) The sum of earnings per share for the four quarters
may not equal the total earnings per share for the year due
to changes in the average number of common shares
outstanding.
</TABLE>
<TABLE>
Exhibit 11
ENRON CORP. AND SUBSIDIARIES
Calculation of Earnings Per Share
(Unaudited)
<CAPTION>
Year Ended December 31,
1995 1994 1993
(in thousands except
per share amounts)
<S> <C> <C> <C>
Primary Earnings Per Share
Earnings on common stock
Net income $519,694 $453,410 $332,522
Preferred stock dividends (15,414) (15,038) (16,919)
$504,280 $438,372 $315,603
Average number of common shares outstanding 243,669 243,395 239,019
Primary earnings per share of common stock $ 2.07 $ 1.80 $ 1.32
Fully Diluted Earnings Per Share
Adjusted earnings on common stock
Net income $519,694 $453,410 $332,522
Preferred stock dividends (15,414) (15,038) (16,919)
Add back:
Dividends on convertible preferred stock 15,414 15,038 16,919
$519,694 $453,410 $332,522
Average number of common shares outstanding
on a fully diluted basis
Average number of common shares outstanding 243,669 243,395 239,019
Additional shares issuable upon:
Conversion of preferred stock 19,004 19,420 22,379
Exercise of stock options reduced by the
number of shares which could have been
purchased with the proceeds from exercise
of such options 5,373 3,122 3,930
268,046 265,937 265,328
Fully diluted earnings per share of
common stock $ 1.94 $ 1.70 $ 1.25
</TABLE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report dated February 16, 1996 included
in this Form 8-K into Enron Corp.'s previously filed
Registration Statement Nos. 33-13397 (Savings Plan), 33-
34796 (Savings Plan), 33-52261 (Savings Plan), 33-13498
(1986 Stock Option Plan), 33-35065 (Employee Stock Ownership
Plan), 33-27893 (1988 Stock Option Plan), 33-46459 ($700
million Senior Subordinated Debt Securities), 33-55580
(569,354 Shares of Common Stock), 33-52768 (Enron Corp. 1991
Stock Plan), 33-49839 (1,253,768 Shares of Common Stock), 33-
52143 (955,640 Shares of Common Stock), 33-54405 (350,585
Shares of Common Stock), 33-53877 (Enron Corp. Debt
Securities and Second Preferred Stock and Enron Capital
Resources, L.P. Preferred Shares), 33-57903 (617,452 Shares
of Common Stock), 33-60821 (Enron Corp. 1994 Stock Plan) and
33-60417 (Enron Corp. Debt Securities and Second Preferred
Stock and Enron Capital Resources, L.P. Preferred
Securities).
ARTHUR ANDERSEN LLP
Houston, Texas
March 8, 1996
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 114,917
<SECURITIES> 0
<RECEIVABLES> 1,426,499
<ALLOWANCES> 0
<INVENTORY> 111,463
<CURRENT-ASSETS> 2,726,907
<PP&E> 11,107,181
<DEPRECIATION> 4,238,746
<TOTAL-ASSETS> 13,238,935
<CURRENT-LIABILITIES> 2,431,992
<BONDS> 3,064,839
0
137,550
<COMMON> 25,386
<OTHER-SE> 3,002,280
<TOTAL-LIABILITY-AND-EQUITY> 13,238,935
<SALES> 7,529,357
<TOTAL-REVENUES> 9,188,997
<CGS> 6,733,486
<TOTAL-COSTS> 8,570,995
<OTHER-EXPENSES> (547,080)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 284,029
<INCOME-PRETAX> 805,138
<INCOME-TAX> 285,444
<INCOME-CONTINUING> 519,694
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 519,694
<EPS-PRIMARY> 2.07
<EPS-DILUTED> 1.94
</TABLE>
