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 17, 1997
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 56
<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, 1996, including Report of Arthur
Andersen LLP, Independent Public Accountants.
(b) Exhibits.
11 Calculation of Earnings Per Share
23 Consent of Arthur Andersen LLP
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 17, 1997 By: Richard A. Causey
Richard A. Causey
Senior Vice President and Chief
Accounting and Information Officer
<PAGE>
ENRON CORP. AND SUBSIDIARIES
TABLE OF CONTENTS
Page No.
Management's Discussion and Analysis 4
Report of Independent Public Accountants 16
Consolidated Income Statement for the years ended
December 31, 1996, 1995 and 1994 17
Consolidated Balance Sheet, December 31, 1996 and 1995 18
Consolidated Statement of Cash Flows for the years
ended December 31, 1996, 1995 and 1994 20
Consolidated Statement of Changes in Shareholders'
Equity Accounts for the years ended December 31,
1996, 1995 and 1994 21
Notes to Consolidated Financial Statements 22
Exhibits
Exhibit 11 - Calculation of Earnings Per Share 55
Exhibit 23 - Consent of Arthur Andersen LLP 56
<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 1996 was $584 million compared to $520
million in 1995 and $453 million in 1994. Net income for all
three years reflects improved income before interest, minority
interests and income taxes as compared to the applicable
preceding year, partially offset by higher minority interests.
Primary earnings per share of common stock was $2.31 in 1996
as compared to $2.07 in 1995 and $1.80 in 1994.
Income Before Interest, Minority Interests and Income Taxes
The following table presents income before interest, minority
interests and income taxes (IBIT) for each of Enron's operating
segments:
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Transportation and Operation $ 570 $ 359 $403
Domestic Gas and Power Services 280 157 202
International Operations and Development 152 142 148
Exploration and Production 200 241 198
Corporate and Other 36 266 (7)
Total $1,238 $1,165 $944
</TABLE>
Transportation and Operation
The transportation and operation segment is comprised of the
Enron Gas Pipeline Group, which includes results of Northern
Natural Gas Company (Northern), Transwestern Pipeline Company
(Transwestern) and Enron's 50% interest in Florida Gas
Transmission Company (Florida Gas); and Enron Ventures Corp.,
which includes results of Enron Engineering & Construction and
the operation of clean fuels plants. Results from Enron's
investment in crude oil marketing and transportation operations
conducted by EOTT Energy Partners, L.P. (EOTT) are also included
in this segment.
The transportation and operation segment's IBIT increased $211
million in 1996 as compared to 1995 due to higher earnings from
the Enron Gas Pipeline Group, increased equity earnings from EOTT
and an increase in gains from the sale of non-strategic gas
gathering and processing assets ($94 million in 1996 compared
with $67 million in 1995). IBIT decreased in 1995 as compared to
1994 primarily as a result of lower earnings from the Enron Gas
Pipeline Group, primarily due to charges in 1995 of $83 million
related to regulatory reserves and other contingencies, and lower
equity earnings from EOTT following a $19 million charge to
reflect the discontinuance of EOTT's West Coast processing and
asphalt marketing operations, partially offset by the gains of
$67 million from the sale of non-strategic gathering and
processing assets. The following discussion analyzes the
significant changes in the various components of IBIT for this
segment:
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Revenues
Enron Gas Pipeline Group $760 $787 $901
Enron Ventures Corp. 46 44 47
EOTT - - 28
Total Revenues 806 831 976
Cost of gas and other products 4 41 72
Operating expenses 301 361 442
Depreciation and amortization 82 83 88
Taxes, other than income taxes 52 47 47
Equity in earnings of unconsolidated
subsidiaries 47 23 49
Other income, net 156 37 27
Income before interest, minority
interests and income taxes $570 $359 $403
</TABLE>
Revenues
Enron Gas Pipeline Group. Revenues of the interstate natural
gas pipelines declined $27 million (3%) during 1996 and $114
million (13%) during 1995 as compared to the applicable preceding
year. The decrease in revenues from 1995 to 1996 was primarily a
result of the sale of gathering facilities in 1995 and the first
quarter of 1996 and reduced sales revenue at Northern in 1996 as
a result of a planned reduction of transition cost recoveries
related to the termination of its merchant function pursuant to
the Federal Energy Regulatory Commission's (FERC) Order 636. The
decrease in revenues from 1994 to 1995 primarily reflects
completion of the recovery of certain transition costs by
Northern. Transport revenues were virtually unchanged in 1996
after declining 9% in 1995 as compared to the prior year.
Transport volumes for Northern and Transwestern totaled 5.9
trillion British thermal units per day (TBtu/d) in 1996, 5.6
TBtu/d in 1995 and 5.5 TBtu/d in 1994. Higher revenues from
increased transport volumes were more than offset by the
reduction in average transport rates due in part to the reduction
of certain transition cost recoveries.
EOTT. Net revenues from EOTT decreased $28 million in 1995
as a result of the reduced ownership interest effective in March
1994. See Note 8 to the Consolidated Financial Statements.
Cost of Gas and Other Products Sold
The cost of gas and other products sold by the transportation
and operation segment decreased by $37 million (90%) during 1996
as compared to 1995 and $31 million (43%) during 1995 as compared
to 1994 primarily as a result of decreased gas purchases
following the termination of the merchant function by Northern.
Operating Expenses
Operating expenses of the transportation and operation segment
declined $60 million (17%) during 1996 and $81 million (18%)
during 1995. The 1996 decline primarily reflects lower operating
expenses on the interstate pipelines primarily as a result of
favorable resolution of environmental contingencies previously
accrued, combined with reduced expenses related to gathering
facilities sold during 1995 and the first quarter of 1996 and a
decrease in amortization of deferred contract reformation costs
by Northern. The 1995 decline primarily reflects a decrease of
$64 million in amortization of deferred contract reformation
costs due to the completion by Northern of the recovery of
certain transition costs in early 1995, combined with lower
transmission, compression and storage transition costs.
Additionally, operating expenses decreased as a result of the
decreased ownership interest in EOTT. These declines were
partially offset by $39 million in regulatory and contingency
adjustments in 1995.
Other Income and Deductions
Equity in earnings of unconsolidated subsidiaries increased by
$24 million to $47 million during 1996 as compared to 1995 after
decreasing by $26 million (53%) during 1995 as compared to 1994.
Earnings from EOTT increased to $9 million in 1996 compared with
a loss of $23 million in 1995, which included a $19 million
charge to reflect the discontinuance of EOTT's West Coast
processing and asphalt marketing operations in 1995. The
increase in equity earnings in 1996 was partially offset by
decreased earnings from Enron's interest in Trailblazer Pipeline
Company due to the recognition in 1995 of income from a
settlement with a transportation customer.
Other income, net, of $156 million was realized in 1996 as
compared to $37 million in 1995 and $27 million in 1994. The
1996 amount includes $94 million in gains related to the
disposition of non-strategic natural gas gathering facilities and
$18 million of income from the favorable resolution of
litigation. The 1995 amount includes $67 million in gains from
the sale of gathering assets and a processing facility, partially
offset by $42 million in regulatory and contingency adjustments.
Outlook
The transportation and operation segment should continue to
provide stable earnings and cash flows during 1997. Various
expansion projects underway or proposed by the Enron Gas Pipeline
Group should enhance future earnings when completed. Northern
filed with the FERC for an expansion project that will increase
peak day firm transportation service into the U.S. upper midwest
markets by approximately 350 million cubic feet of gas per day
(MMcf/d) over the next five years. Additionally, Enron Gas
Pipeline Group will continue to concentrate on reducing its
overall cost structure and Enron Ventures Corp. will actively
promote engineering and construction services to provide
incremental earnings.
During the first quarter of 1997, Enron completed sales of the
stock of Enron Liquids Pipeline Company, the general partner and
15% owner and operator of Enron Liquids Pipeline, L.P., and the
stock of Enron Louisiana Energy Company. Also during the first
quarter of 1997, Enron announced that it had agreed to sell its
Bushton, Kansas natural gas processing facility and its Hugoton
Basin gathering assets in Kansas. This transaction is expected
to close during the first half of 1997.
Domestic Gas and Power Services
The domestic gas and power activities are conducted primarily
by Enron Capital & Trade Resources (ECT) and include the
marketing, purchasing and financing of natural gas, natural gas
liquids, crude oil, electricity and other energy commodities and
the management of the portfolio of commitments arising from these
activities. In addition, Enron Energy Services has been created
to serve the retail natural gas and electricity markets.
ECT's services can be categorized into three business lines:
Cash and Physical, Risk Management and Finance. The following
table reflects IBIT for each business line:
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Cash and Physical $243 $146 $170
Risk Management 105 193 151
Finance 77 31 13
Unallocated expenses (145) (138) (132)
Total before non-recurring charge 280 232 202
Charge for clean fuels plant operations - (75) -
Total $280 $157 $202
</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.
ECT markets a substantial quantity of energy commodities as
reflected in the following table (including intercompany
amounts):
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Natural gas and crude oil
Physical/notional quantities (BBtue/d)(a)
Firm(b) 6,435 5,392 4,895
Interruptible 2,578 2,255 2,039
Transport volumes 544 580 538
Subtotal 9,557 8,227 7,472
Financial settlements (notional) 35,259 32,938 16,459
Total 44,816 41,165 23,931
Electricity (Thousand megawatt hours)
Owned production 3,122 3,441 3,481
Transaction volumes marketed 60,150 7,767 1,221
<FN>
(a) Billion British thermal units equivalent per day.
(b) Commitments to deliver a specified volume of gas at a fixed
or market responsive price.
</TABLE>
The earnings from this business increased 66% in 1996
primarily due to earnings from higher natural gas volumes and
margins and increased earnings from the management of ECT's
portfolio of contracts. Earnings from the marketing and
processing of natural gas liquids also increased in 1996. These
increases were partially offset by a decrease in earnings from
natural gas assets. Electricity volumes substantially increased
as ECT continued to expand its role as an electricity marketer.
The earnings from cash and physical operations decreased 14%
in 1995 as compared to 1994 as a result of lower margins in
liquids marketing and an increase in clean fuels operating
expenses. Earnings from the marketing of physical natural gas
also declined in 1995 as compared to 1994 due to lower margins in
all but the fourth quarter. Partially offsetting these declines
in earnings were increased earnings from electricity marketing,
the sale of certain physical assets and the management of ECT's
contract portfolio.
During 1997, ECT anticipates continued growth in the cash and
physical business over the 1996 results. The existence of its
substantial portfolio of contracts as well as the ability to
benefit from the relationships between the financial and physical
markets and the natural gas and electricity markets provide
substantial opportunities for earnings. Continued seasonal
volatility of natural gas prices will provide additional
opportunities for increased earnings.
Risk Management. ECT's risk management operations consist of
long-term energy commodity contracts (transactions greater than
one year). ECT originates new contracts for customers in the
energy industry and evaluates and restructures its existing
contracts on an on-going basis to develop additional products and
services to meet its customers' changing needs. Fixed price
contract market activity totaled 3,671 trillion British thermal
units equivalent (TBtue), 5,952 TBtue and 6,615 TBtue for 1996,
1995 and 1994, respectively.
Earnings from this business decreased 46% in 1996 as compared
to 1995 primarily due to lower originations from long-term
contracts with utilities and independent power producers (IPPs).
Earnings from the restructuring of existing long-term contracts
were also lower in 1996 as compared to 1995. These decreases
were partially offset by increased originations with IPPs in the
European market.
Earnings from risk management increased 28% in 1995 as
compared to 1994 due primarily to earnings related to the
restructuring of existing long-term contracts with IPPs and local
distribution companies. Growth in originations from the Canadian
operations also contributed to the earnings increase. For 1995,
originations with utilities were lower than in 1994.
ECT expects earnings from risk management to increase in 1997
as compared to 1996 as it continues to pursue opportunities in
the European marketplace and continues to increase integration of
financial products and its energy commodity portfolio, resulting
in highly structured transactions.
Finance. ECT's finance operations provide a variety of
capital products to the energy sector including volumetric
production payments, loans and equity investments. These
products are offered by ECT directly or through ECT ventures such
as Joint Energy Development Investments Limited Partnership
(JEDI). JEDI is a limited partnership 50% owned by Enron which
was formed to acquire and own energy investments. Financings
arranged and production payments were $755 million, $382 million
and $503 million in 1996, 1995 and 1994, respectively.
Earnings from the finance operations increased 148% in 1996
compared to 1995 primarily due to increased earnings from its
equity investment in JEDI, which benefited from favorable
conditions in the equity markets.
Earnings from the finance operations increased 138% in 1995
compared with 1994 due primarily to the partial sale of ECT's
interests in certain equity investments and earnings associated
with the restructuring of long-term gas supply contracts with an
IPP. This was partially offset by lower earnings from production
payments arranged.
In 1997, ECT will continue to expand its products and services
in its role as a full-service provider of various types of
capital. In addition, earnings are expected from equity-based
investments which are carried by JEDI at fair value and are
therefore subject to market fluctuations.
Unallocated Expenses. ECT's net unallocated expenses such as
rent, systems expenses and other support group costs increased in
both 1996 and 1995 due to continued expansion into new markets
and system upgrades. ECT expects its unallocated expenses to
increase during 1997 as it continues to expand into new markets.
Charge for Clean Fuels Plant Operations. During the fourth
quarter of 1995, ECT provided for expected losses of $75 million
on its clean fuels plant operations resulting from higher natural
gas prices and lower MTBE prices because of soft demand for MTBE.
International Operations and Development
Enron's international operations and development activities
are conducted by Enron International (EI). Such activities
include the development of power, pipeline and other energy
infrastructure in emerging markets. Additionally, EI manages and
operates the projects once commercial operation has been
achieved. The segment includes results of Enron Global Power &
Pipelines L.L.C. (EPP) and Enron Americas, Inc. IBIT for this
group totaled $152 million in 1996, $142 million during 1995 and
$148 million in 1994. The following discussion analyzes the
significant changes in the various components of IBIT for this
segment.
Net Revenues
Revenues net of cost of sales for the international operations
and development segment decreased by $55 million (27%) in 1996 as
compared to 1995 after increasing $32 million (19%) during 1995.
The decline in net revenues in 1996 primarily reflects the
inclusion in 1995 of $48 million of revenues realized as a result
of the satisfaction of Enron's support obligations related to the
formation of EPP as well as the effect of transferring certain
liquids marketing operations to the domestic gas and power
services segment in January 1996. In addition to revenues from
asset management and operations and international development
activities, net revenues in 1996 included $31 million from the
promotion of a portion of Enron's interest in its power assets at
Teesside in the United Kingdom, compared with $24 million and $28
million recognized on similar transactions related to power and
liquids processing assets at Teesside in 1995 and 1994,
respectively. The increase in net revenues in 1995 primarily
reflects marketing revenues and increased international
development and asset management revenues, partially offset by
lower revenues recognized in connection with the formation of
EPP.
Costs and Expenses
Operating expenses for this segment decreased $26 million
(27%) during 1996 after increasing $16 million (21%) during 1995.
The decrease in 1996 was primarily due to the transfer of
marketing operations previously discussed, partially offset by
increased international activities. The increase in 1995 was
primarily a result of higher operating expenses incurred in
connection with increased activities in the power operations
area.
Depreciation expense of this segment decreased $12 million
(44%) in 1996 as compared to 1995 primarily due to the transfer
of marketing operations. Depreciation expense increased $12
million (80%) during 1995 as compared to 1994 as a result of
increased international project activities.
Other Income and Deductions
Equity in earnings of unconsolidated subsidiaries of the
international operations and development segment increased $26
million to $84 million in 1996, primarily as a result of
increased earnings from Teesside and international power and
pipeline projects which became operational in 1996. Equity in
earnings of unconsolidated subsidiaries increased $13 million
(29%) during 1995 as compared to 1994 primarily as a result of
increased earnings from Teesside and improved results from Enron
Americas' Venezuelan manufacturing operations.
Other income, net, was $10 million in 1996, $9 million in 1995
and $30 million in 1994. The 1994 amount included foreign
currency gains realized by Enron Americas.
Outlook
The objective of EI is to develop, finance, own and operate
integrated energy projects in emerging markets through the
utilization of Enron's extensive portfolio of products and
services. Growth opportunities in the emerging international
markets are expected to result from the current and projected
demand for energy infrastructure and merchant, finance and risk
management services.
Exploration and Production
Enron's exploration and production operations are conducted by
Enron Oil & Gas Company (EOG). IBIT of the exploration and
production segment totaled $200 million during 1996 as compared
to $241 million during 1995 and $198 million during 1994.
Wellhead volume and price statistics (including intercompany
amounts) are as follows:
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Natural gas volumes (MMcf/d)(a)
North America(b) 706 636 686
Trinidad 124 107 63
Total 830 743 749
Average natural gas prices ($/Mcf)
North America(c) $1.92 $1.34 $1.68
Trinidad 1.00 0.97 0.93
Composite 1.78 1.29 1.62
Crude oil/condensate volumes (MBbl/d)(a)
North America 11.6 11.5 10.0
Trinidad 5.2 5.1 2.5
India 2.8 2.5 0.1
Total 19.6 19.1 12.6
Average crude oil/condensate prices ($/Bbl)
North America $21.08 $17.09 $15.65
Trinidad 19.76 16.07 15.50
India 20.17 16.81 15.70
Composite 20.60 16.78 15.62
<FN>
(a) Million cubic feet per day or thousand barrels per day, as
applicable.
(b) Includes an annual average of 48 MMcf/d in 1996, 1995 and
1994 delivered under the terms of a volumetric production
payment agreement effective October 1, 1992, as amended.
(c) Includes an average equivalent wellhead value of $1.17 per
Mcf in 1996, $0.80 per Mcf in 1995 and $1.27 per Mcf in 1994
for the volumes detailed in Note (b) above, net of
transportation costs.
</TABLE>
The following analyzes the significant changes in the various
components of IBIT for the exploration and production segment:
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Net revenues $726 $693 $661
Operating expenses 133 126 112
Exploration expenses 89 79 84
Depreciation, depletion and
amortization 251 216 242
Taxes, other than income taxes 48 32 28
Operating income 205 240 195
Other income, net (5) 1 3
IBIT $200 $241 $198
</TABLE>
Net Revenues
The exploration and production segment's revenues net of gas
sold in connection with natural gas marketing increased $33
million (5%) in 1996 and $32 million (5%) in 1995. The 1996
increase was primarily as a result of increased wellhead natural
gas prices and volumes. These volumes increased primarily as a
result of eliminating voluntary curtailments in the United States
in 1996 due to significant increases in wellhead natural gas
prices. Other marketing activities, which include hedging,
trading and natural gas marketing transactions by EOG, provided
$4 million in net revenues in 1996, compared with $105 million in
1995.
During 1995, the impact of reduced wellhead natural gas prices
and volumes, due primarily to voluntary curtailments of wellhead
natural gas volumes, was more than offset by increased earnings
from other marketing activities. Wellhead crude oil and
condensate average prices and volumes increased in 1995,
primarily reflecting new production onstream offshore India and
higher volumes offshore Trinidad and in North America. Other
marketing activities provided $105 million in net revenues in
1995, compared with $50 million in 1994.
Hedges placed by Enron on commodity positions not hedged by
EOG resulted in a loss of $4 million in 1996 compared with gains
of $45 million in 1995 and $35 million in 1994. Net revenues also
include gains on sales of oil and gas reserves and related assets
of $20 million in 1996, $63 million in 1995 and $54 million in
1994.
Costs and Expenses
Operating expense, depreciation, depletion and amortization
(DD&A) and taxes other than income taxes increased in 1996 due
primarily to the increased production activity. Operating
expenses and taxes other than income taxes were higher in 1995
compared to 1994 due to international production activity, while
DD&A declined in that period due to the decline in North America
volumes, which have a higher DD&A rate.
Outlook
EOG plans to continue to focus a substantial portion of its
development and certain exploration expenditures in its major
producing areas in North America. However, EOG anticipates
spending an increasing part of its available funds in the further
development of opportunities in India, Venezuela and Trinidad.
In addition, EOG will continue limited exploratory expenditures
in new areas outside of North America.
Corporate and Other
The corporate and other segment's IBIT was $36 million in 1996
and $266 million in 1995 as compared to expense of $7 million in
1994. Results from this segment in 1996 and 1995 reflect income
of $178 million and $367 million, respectively, primarily related
to the sale of 12 million and 31 million outstanding shares of
EOG stock held by Enron, which reduced Enron's interest in EOG
from 80% to 53% (see Note 16 to the Consolidated Financial
Statements). In a separate transaction, Enron entered into a
total return equity swap on 7.8 million shares of EOG. The
effect of this transaction is to expose Enron to future changes
in EOG's market value related to the 7.8 million shares.
The 1996 results included an $83 million reserve related to the
required disposition of certain assets in connection with the
planned merger with Portland General Corporation. See
"Capitalization" below. The 1995 results also included amounts
recognized following the resolution of certain litigation,
partially offset by $74 million of charges primarily related to
the conversion of a compensation plan to more closely align
employees' interests to Enron common stock.
Interest and Related Charges, net
Interest and related charges, net, is shown on the
Consolidated Income Statement net of interest capitalized of $12
million, $10 million and $10 million during 1996, 1995 and 1994,
respectively. The net expense decreased $10 million in 1996
after increasing $11 million in 1995. The 1996 decrease was
primarily due to lower average interest rates combined with lower
average debt balances. The 1995 increase was primarily due to
higher debt levels and increased interest rates.
Dividends on Company-Obligated Preferred Stock of Subsidiaries
Dividends on company-obligated preferred stock of subsidiaries
increased from $20 million in 1994 to $32 million in 1995 and $34
million in 1996, primarily due to the issuance of $215 million of
additional preferred stock by Enron subsidiaries. See Note 9 to
the Consolidated Financial Statements.
Minority Interests
Minority interests increased $31 million in 1996 compared to
1995, primarily due to the reduction of Enron's interest in EOG
from 80% in late 1995 to 53% in December 1996 following the sales
in 1996 and December 1995 of an aggregate 43 million shares of
EOG common stock held by Enron. Minority interests increased $13
million during 1995 as compared to 1994 primarily as a result of
the sale in the fourth quarter of 1994 of approximately 48% of
Enron's interest in EPP.
Income Tax Expense
Income tax expense decreased during 1996 as compared to 1995
after increasing during 1995 as compared to 1994. The 1996
income tax provision includes benefits from the reduction of the
deferred income tax liability due to the reevaluation of Federal
and state deferred tax requirements. Income tax expense
increased during 1995 compared to the prior year due to increased
pretax income, a decrease in tight gas sand Federal tax credits
and the higher effective tax rate on the sale of EOG shares by
Enron in 1995.
FINANCIAL CONDITION
Cash Flows
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Cash provided by (used in):
Operating activities $ 1,040 $(15) $ 460
Investing activities (1,230) 13 (560)
Financing activities 331 (15) 92
</TABLE>
Net cash provided by operating activities increased in 1996
primarily as a result of reduced working capital requirements
reflecting increased trade payables combined with an increase in
the sale of trade receivables at year end 1996 as compared to
1995. Cash from operating activities declined during 1995 as a
result of increased working capital requirements. The change in
working capital requirements in 1995 primarily reflects a higher
level of year-end receivables as a result of reduced sales of
receivables under Enron's receivables sales program and increased
customer receivables due to a higher level of year-end activity.
The impact of higher receivables was partially offset by
increased year-end trade payables.
Net cash used in investing activities in 1996 reflects equity
investments of $761 million and property additions of $855
million. Equity investments in 1996 primarily include
investments in international power and pipeline projects, EOTT
and JEDI. These uses of cash were offset by proceeds of $477
million from sales of assets, including 12 million shares of EOG
common stock held by Enron and non-strategic gathering and
processing assets. Net cash provided by investing activities in
1995 reflects proceeds from asset sales of $996 million largely
offset by property additions of $731 million and equity
investments of $170 million. Asset sales during 1995 included
the sale of 31 million shares of EOG common stock held by Enron
as well as sales of oil and gas properties and non-strategic
processing and gathering assets. Equity investments primarily
include investments in international power and pipeline projects
and in JEDI.
Primary cash inflows from financing activities during 1996
included $576 million from the issuance of short- and long-term
debt, $215 million from the issuance of preferred stock by
subsidiary companies and $102 million from the issuance of Enron
common stock. Cash outflows included $294 million for the
repayment of debt combined with cash dividend payments of $281
million. During 1995 cash inflows from the issuance of long-term
debt totaled $967 million. These inflows were more than offset
by a $698 million decrease in combined short- and long-term debt,
cash dividend payments of $254 million and a net $64 million
repurchase of Enron Corp. common stock under the terms of Enron's
stock repurchase authorization.
Working Capital
At December 31, 1996, Enron had working capital of $271
million. Should a working capital deficit occur, Enron would be
able to fund such a deficit through the utilization of credit
facilities which, at December 31, 1996, provided for up to $1.9
billion of committed and uncommitted credit, of which $191
million was outstanding at December 31, 1996. Certain of the
credit agreements contain prefunding covenants. However, such
covenants are not expected to materially restrict Enron's access
to funds under these agreements. In addition, Enron sells
commercial paper and has agreements to sell trade accounts
receivable, thus providing financing to meet seasonal working
capital needs. Management believes that the sources of funding
described above are sufficient to meet short- and long-term
liquidity needs not met by cash flows from operations.
Capital Expenditures
Capital expenditures by operating segment are detailed as
follows:
<TABLE>
<CAPTION>
1997
(In Millions) Estimate 1996 1995 1994
<S> <C> <C> <C> <C>
Transportation and Operation $260 $187 $129 $125
Domestic Gas and Power Services 140 112 118 83
International Operations and
Development 10 33 58 14
Exploration and Production(a) 500 540 464 442
Corporate and Other 30 6 8 5
Total $940 $878 $777 $669
<FN>
(a) Excludes exploration expenses of $100 million (estimate),
$68 million, $55 million and $59 million for 1997, 1996, 1995
and 1994, respectively.
</TABLE>
Capital expenditures increased $101 million during 1996 as
compared to 1995 primarily as a result of increased expenditures
in the exploration and production segment reflecting increased
development expenditures in the United States and India,
partially offset by reduced development expenditures in Trinidad.
Capital expenditures during 1997 are expected to total
approximately $940 million. However, the overall level of
capital spending as well as spending by individual business
segments will vary depending upon conditions in the energy
markets and other related economic conditions. In addition,
equity investments are expected to be approximately $660 million,
primarily relating to equity financing activities by ECT and
expenditures in the international segment in connection with
power and pipeline projects. Management believes that the
capital spending program will be funded by a combination of
internally generated funds, proceeds from dispositions of
selected assets and long- and short-term borrowings.
Capitalization
Total capitalization at December 31, 1996 was $8.4 billion.
Debt as a percentage of total capitalization decreased to 39.8%
at December 31, 1996 as compared to 42.8% at December 31, 1995.
The improvement primarily reflects increased retained earnings.
Assuming the mandatory conversion in late 1998 of 10.5 million
Exchangeable Notes into EOG shares held by Enron, the pro-forma
debt to capitalization percentage would be approximately 37.8% at
December 31, 1996.
Enron has signed an agreement to merge with Portland General
Corporation (PGC) in a stock-for-stock transaction. Enron
proposes to issue approximately 51 million common shares to
shareholders of PGC in a one for one exchange of shares, as a
result of which Enron will be the surviving corporation. The
merger is conditioned, among other things, upon securing certain
regulatory approvals. See Note 2 to the Consolidated Financial
Statements.
INFORMATION REGARDING
FORWARD LOOKING STATEMENTS
This Annual Report includes forward looking statements within
the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Although
Enron believes that its expectations are based on reasonable
assumptions, it can give no assurance that its goals will be
achieved. Important factors that could cause actual results to
differ materially from those in the forward looking statements
herein include political developments in foreign countries, the
pace of deregulation of retail natural gas and electricity
markets in the United States, the timing and extent of changes in
commodity prices for crude oil, natural gas, electricity and
interest rates, the extent of EOG's success in acquiring oil and
gas properties and in discovering, developing and producing
reserves, the timing and success of Enron's efforts to develop
international power, pipeline and other infrastructure projects
and conditions of the capital markets and equity markets during
the periods covered by the forward looking statements.
<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, 1996 and 1995, and the related consolidated
statements of income, cash flows and changes in shareholders'
equity accounts for each of the three years in the period ended
December 31, 1996. These financial statements are the
responsibility of Enron Corp.'s management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial 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, 1996 and 1995,
and the results of their operations, cash flows and changes in
shareholders' equity accounts for each of the three years in the
period ended December 31, 1996, in conformity with generally
accepted accounting principles.
Arthur Andersen LLP
Houston, Texas
February 17, 1997
<PAGE>
<TABLE>
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENT
<CAPTION>
Year Ended December 31,
(In Millions, Except Per Share Amounts) 1996 1995 1994
<S> <C> <C> <C>
Revenues
Natural gas, electricity and other
products $12,137 $7,708 $7,519
Transportation 707 692 754
Other 445 789 711
Total Revenues 13,289 9,189 8,984
Costs and Expenses
Cost of gas, electricity and
other products 10,478 6,733 6,517
Operating expenses 1,421 1,218 1,124
Oil and gas exploration expenses 89 79 84
Depreciation, depletion and
amortization 474 432 441
Taxes, other than income taxes 137 109 102
Total Costs and Expenses 12,599 8,571 8,268
Operating Income 690 618 716
Other Income and Deductions
Equity in earnings of unconsolidated
subsidiaries 215 86 112
Other income, net 333 461 116
Income Before Interest, Minority
Interests and Income Taxes 1,238 1,165 944
Interest and Related Charges, net 274 284 273
Dividends on Company-Obligated Preferred
Stock of Subsidiaries 34 32 20
Minority Interests 75 44 31
Income Taxes 271 285 167
Net Income 584 520 453
Preferred Stock Dividends 16 16 15
Earnings on Common Stock $ 568 $ 504 $ 438
Earnings Per Share of Common Stock
Primary $ 2.31 $ 2.07 $ 1.80
Fully Diluted $ 2.16 $ 1.94 $ 1.70
Average Number of Common Shares Used
in Primary Computation 246 244 243
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
<CAPTION>
December 31,
(In Millions) 1996 1995
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 256 $ 115
Trade receivables (net of allowance
for doubtful accounts of $6 and
$12, respectively) 1,841 1,116
Other receivables 328 311
Transportation and exchange gas
receivable 86 150
Inventories 164 111
Assets from price risk management
activities 841 580
Other 463 344
Total Current Assets 3,979 2,727
Investments and Other Assets
Investments in and advances to
unconsolidated subsidiaries 1,701 1,217
Assets from price risk management
activities 1,632 1,197
Other 1,713 1,230
Total Investments and Other Assets 5,046 3,644
Property, Plant and Equipment, at cost
Transportation and operation 3,554 3,640
Domestic gas and power services 3,853 3,797
International operations and
development 104 182
Exploration and production, successful
efforts accounting 3,753 3,381
Corporate and other 84 107
11,348 11,107
Less accumulated depreciation,
depletion and amortization 4,236 4,239
Net Property, Plant and Equipment 7,112 6,868
Total Assets $16,137 $13,239
<FN>
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
<CAPTION>
(In Millions, Except Per December 31,
Share Amounts and Shares) 1996 1995
<S> <C> <C>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 1,955 $ 1,021
Transportation and exchange gas
payable 80 144
Accrued taxes 70 121
Accrued interest 56 52
Liabilities from price risk
management activities 1,029 708
Other 518 386
Total Current Liabilities 3,708 2,432
Long-Term Debt 3,349 3,065
Deferred Credits and Other Liabilities
Deferred income taxes 2,290 2,186
Liabilities from price risk
management activities 980 590
Other 740 875
Total Deferred Credits and
Other Liabilities 4,010 3,651
Commitments and Contingencies
(Notes 2, 3, 8, 13, 14 and 15)
Minority Interests 755 549
Company-Obligated Preferred Stock
of Subsidiaries 592 377
Shareholders' Equity
Preferred stock, cumulative, $100 par
value, 1,500,000 shares authorized,
no shares issued - -
Second preferred stock, cumulative, $1 par
value, 5,000,000 shares authorized,
1,370,714 shares and 1,375,494 shares
of Cumulative Second Preferred Convertible
Stock issued, respectively 137 138
Preference stock, cumulative, $1 par value,
10,000,000 shares authorized, no shares
issued - -
Common stock, $0.10 par value, 600,000,000
shares authorized, 255,945,304 shares and
253,860,360 shares issued, respectively 26 25
Additional paid-in capital 1,870 1,791
Retained earnings 2,007 1,651
Cumulative foreign currency translation
adjustment (127) (153)
Common stock held in treasury, 821,155
shares and 2,618,034 shares, respectively (30) (93)
Other (including Flexible Equity Trust) (160) (194)
Total Shareholders' Equity 3,723 3,165
Total Liabilities and Shareholders' Equity $16,137 $13,239
<FN>
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<CAPTION>
Year Ended December 31,
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Cash Flows From Operating Activities
Reconciliation of net income to net
cash provided by (used in) operating
activities
Net income $ 584 $ 520 $ 453
Depreciation, depletion and
amortization 474 432 441
Oil and gas exploration expenses 89 79 84
Deferred income taxes 207 216 93
Gains on sales of assets (274) (530) (91)
Regulatory, litigation and other
contingency adjustments 23 112 (25)
Changes in components of working
capital 142 (834) (142)
Net assets from price risk management
activities 15 (98) (153)
Amortization of production payment
transaction (43) (43) (43)
Other, net (177) 131 (157)
Net Cash Provided by (Used in) Operating
Activities 1,040 (15) 460
Cash Flows From Investing Activities
Proceeds from sales of investments and
other assets 477 996 440
Additions to property, plant and
equipment (855) (731) (661)
Equity investments (761) (170) (272)
Other, net (91) (82) (67)
Net Cash Provided by (Used in)
Investing Activities (1,230) 13 (560)
Cash Flows From Financing Activities
Net increase (decrease) in
short-term borrowings 217 (250) 115
Issuance of long-term debt 359 967 190
Repayment of long-term debt (294) (448) (162)
Issuance of company-obligated
preferred stock of subsidiaries 215 - 163
Issuance of common stock 102 20 67
Dividends paid (281) (254) (231)
Net acquisition (disposition) of
treasury stock 5 (64) (41)
Other, net 8 14 (9)
Net Cash Provided by (Used in)
Financing Activities 331 (15) 92
Increase (Decrease) in Cash and Cash
Equivalents 141 (17) (8)
Cash and Cash Equivalents, Beginning
of Year 115 132 140
Cash and Cash Equivalents, End of Year $ 256 $ 115 $ 132
Changes in Components of Working Capital
Receivables $ (678) $(639) $(250)
Inventories (53) 27 (25)
Payables 870 126 (92)
Accrued taxes (51) 30 12
Accrued interest 4 (7) 5
Other 50 (371) 208
Total $ 142 $(834) $(142)
<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
</TABLE>
<PAGE>
<TABLE>
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY ACCOUNTS
(Dollars in Millions, Except Per 1996 1995 1994
Share Amounts; Shares in Thousands) Shares Amount Shares Amount Shares Amount
<S> <C> <C> <C> <C> <C> <C>
Cumulative Second Preferred
Convertible Stock
Balance, beginning of year 1,375 $ 138 1,405 $ 141 1,497 $ 150
Exchange of common stock
for convertible preferred stock (4) (1) (30) (3) (92) (9)
Balance, end of year 1,371 $ 137 1,375 $ 138 1,405 $ 141
Common Stock
Balance, beginning of year 253,860 $ 25 253,070 $ 25 249,095 $ 25
Exchange of common stock
for convertible preferred stock 19 - 219 - 1,252 -
Issuances related to benefit
and dividend reinvestment plans - - 197 - 1,303 -
Sales of common stock 2,066 1 374 - 1,420 -
Balance, end of year 255,945 $ 26 253,860 $ 25 253,070 $ 25
Additional Paid-in Capital
Balance, beginning of year $1,791 $1,788 $1,708
Exchange of common stock
for convertible preferred stock (1) (3) 9
Issuances related to benefit
and dividend reinvestment plans (16) (5) 30
Sales of common stock 109 15 51
Other (13) (4) (10)
Balance, end of year $1,870 $1,791 $1,788
Retained Earnings
Balance, beginning of year $1,651 $1,351 $1,105
Net income 584 520 453
Cash dividends
Common stock ($0.8625, $0.8125
and $0.7625 per share, in 1996,
1995 and 1994, respectively) (212) (204) (192)
Preferred stock ($11.7750,
$11.0922 and $10.6054 per
share in 1996, 1995 and 1994,
respectively) (16) (16) (15)
Balance, end of year $2,007 $1,651 $1,351
Cumulative Foreign Currency
Translation Adjustment
Balance, beginning of year $ (153) $ (159) $ (139)
Translation adjustments 26 6 (20)
Balance, end of year $ (127) $ (153) $ (159)
Treasury Stock
Balance, beginning of year (2,618) $ (93) (1,395) $ (41) - $ -
Shares acquired (2,226) (85) (3,496) (118) (1,898) (56)
Exchange of common stock
for convertible preferred stock 46 2 183 5 - -
Issuances related to benefit
and dividend reinvestment plans 2,249 81 2,090 61 48 1
Sales of treasury stock 1,728 65 - - 455 14
Balance, end of year (821) $ (30) (2,618) $ (93) (1,395) $ (41)
Other
Balance, beginning of year $ (194) $ (225) $ (226)
Issuances related to benefit
and dividend reinvestment plans 34 30 1
Other - 1 -
Balance, end of year $ (160) $ (194) $ (225)
Total Shareholders' Equity $3,723 $3,165 $2,880
<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
</TABLE>
<PAGE>
ENRON CORP. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation Policy and Use of Estimates. The accounting and
financial reporting policies of Enron Corp. and its subsidiaries
conform to generally accepted accounting principles and prevailing
industry practices. The consolidated financial statements
include the accounts of all majority-owned subsidiaries of Enron
Corp. after the elimination of significant intercompany accounts
and transactions. Investments in unconsolidated subsidiaries are
accounted for by the equity method.
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
"Enron" is used from time to time herein as a collective
reference to Enron Corp. and its subsidiaries and affiliates. In
material respects, the businesses of Enron are conducted by Enron
Corp.'s subsidiaries and affiliates whose operations are managed
by their respective officers.
Cash Equivalents. Enron records as cash equivalents all
highly liquid short-term investments with original maturities of
three months or less.
Inventories. Inventories consisting primarily of natural gas
in storage of $73 million and $55 million and crude oil and
liquid petroleum products of $84 million and $50 million at
December 31, 1996 and 1995, respectively, are priced at the lower
of cost or market.
Depreciation, Depletion and Amortization. The provision for
depreciation and amortization with respect to operations other
than oil and gas producing activities (see below) is computed
using the straight-line or Federal Energy Regulatory Commission
(FERC) mandated method based on estimated economic lives.
Composite depreciation rates are applied to functional groups of
property having similar economic characteristics.
Provisions for depreciation, depletion and amortization of
proved oil and gas properties are calculated using the units-of-
production method. Estimated future dismantlement, restoration
and abandonment costs, net of salvage credits, are taken into
account in determining depreciation, depletion and amortization.
Income Taxes. Enron accounts for income taxes using an asset
and liability approach under which deferred tax assets and
liabilities are recognized based on anticipated future tax
consequences attributable to differences between financial
statement carrying amounts of assets and liabilities and their
respective tax bases (see Note 4).
Earnings Per Share. Primary earnings per share is computed on
the basis of the average number of common shares outstanding
during the periods. Common shares held by the Enron Corp.
Flexible Equity Trust are not included in the computation of
earnings per share until such shares are released to fund
employee benefits (see Note 10). Dilutive common stock
equivalents are not material and are not included in the
computation of primary earnings per share. Fully diluted
earnings per share is computed based upon the average number of
common stock and common stock equivalent shares outstanding plus
the average number of common shares issuable upon the assumed
conversion of convertible securities.
Accounting for Price Risk Management. Enron engages in price
risk management activities for both trading and non-trading
purposes. Activities for trading purposes, generally consisting
of services provided to the energy sector through Enron Capital &
Trade Resources (ECT), are accounted for using the mark-to-market
method. Under such method, changes in the market value of
outstanding financial instruments are recognized as gain or loss
in the period of change. The market prices used to value these
transactions reflect management's best estimate considering
various factors including closing exchange and over-the-counter
quotations, time value and volatility factors underlying the
commitments. The values are adjusted to reflect the potential
impact of liquidating Enron's position in an orderly manner over
a reasonable period of time under present market conditions.
Activities for non-trading purposes consist of transactions
entered into by Enron's other business units to hedge the impact
of market fluctuations on assets, liabilities, production or
other contractual commitments. Changes in the market value of
these transactions are deferred until the gain or loss on the
hedged item is recognized. See Note 3 for further discussion of
Enron's price risk management activities.
Accounting for Oil and Gas Producing Activities. Enron
accounts for oil and gas exploration and production activities
under the successful efforts method of accounting. Under such
method, oil and gas lease acquisition costs are capitalized when
incurred. Unproved properties with significant acquisition costs
are assessed quarterly on a property-by-property basis and any
impairment in value is recognized. Amortization of any remaining
costs of such leases begins at a point prior to the end of the
lease term depending upon the length of such term. Unproved
properties with acquisition costs that are not individually
significant are aggregated, and the portion of such costs
estimated to be nonproductive, based on historical experience, is
amortized over the average holding period. If the unproved
properties are determined to be productive, the appropriate
related costs are transferred to proved oil and gas properties.
Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of
drilling exploratory wells, are charged to expense as incurred.
The costs of drilling exploratory wells are capitalized pending
determination of whether the wells have discovered proved
commercial reserves. If proved commercial reserves are not
discovered, such drilling costs are expensed. The costs of all
development wells and related equipment used in the production of
crude oil and natural gas are capitalized.
Gains and losses associated with the sale of crude oil and
natural gas reserves in place with related assets are classified
as "Other Revenues" in the Consolidated Income Statement.
Accounting for Development Activity. Enron's project
development costs consist of fees, licenses and permits, site
testing, bid costs and other charges, including salaries and
employee expenses, incurred in developing domestic and
international projects. These costs may be recovered through
development cost reimbursements from joint venture partners or
other third parties, written off against development fees
received, or may be included as part of an investment in those
ventures where Enron continues to participate. Accumulated costs
of project development are otherwise expensed in the period that
management determines it is probable that the costs will not be
recovered.
Development revenue results from Enron's participation in the
development, construction, operation and ownership of various
projects. Revenue from development fees is recognized when
realizable under the development agreement. Revenue from long-
term construction contracts is recognized using the percentage-of-
completion method and is primarily based on project costs
incurred compared with total estimated costs. Estimated contract
earnings are reviewed and revised periodically as the work
progresses. Development and construction revenues earned from
joint ventures in which Enron holds an equity interest are
deferred to the extent of Enron's ownership interest and
recognized over the life of the facility owned by the joint
venture on a straight-line basis. Proceeds from the sale of all
or part of Enron's investment in development projects are
recognized as revenues at the time of sale to the extent that
such sales proceeds exceed the proportionate carrying amount of
the investment.
Foreign Currency Translation. For international subsidiaries,
asset and liability accounts are translated at year-end rates of
exchange and revenue and expenses are translated at average
exchange rates prevailing during the year. For subsidiaries
whose functional currency is deemed to be other than the U.S.
dollar, translation adjustments are included as a separate
component of shareholders' equity. Currency transaction gains
and losses are recorded in income.
Reclassifications. Certain reclassifications have been made
to the consolidated financial statements for prior years to
conform with the current presentation.
2 PROPOSED MERGER
Enron announced on July 22, 1996 that it had signed an
agreement to merge with Portland General Corporation (PGC) in a
stock-for-stock transaction. PGC is an electric utility holding
company, serving retail electric customers in northwest Oregon as
well as wholesale electricity customers throughout the western
United States. Enron proposes to issue approximately 51 million
common shares to shareholders of PGC in a one for one exchange of
shares, as a result of which Enron will be the surviving
corporation. Enron will consolidate PGC's debt of approximately
$1.1 billion and account for the transaction on a purchase
accounting basis.
In separate shareholder meetings held on November 12, 1996,
75% of the Enron common shares and 77% of PGC common shares were
voted in favor of the merger. The merger is conditioned, among
other things, upon securing regulatory approval from the
Oregon Public Utilities Commission (OPUC) consistent with certain
conditions in the Enron/PGC merger agreement. The FERC approved
the merger on February 26, 1997. A decision on Enron's merger
approval application pending before the OPUC is expected in 1997.
3 PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Trading Activities. Enron, through ECT, offers price risk
management services to the energy sector. These services
primarily relate to commodities associated with the energy sector
(natural gas, crude oil, natural gas liquids and electricity).
ECT provides these services through a variety of financial
instruments including forward contracts involving physical
delivery of an energy commodity, swap agreements, which require
payments to (or receipt of payments from) counterparties based on
the differential between a fixed and variable price for the
commodity, options and other contractual arrangements. ECT also
manages interest rate risks and foreign currency risks associated
with the fair value of its energy commodities portfolio. A
variety of financial instruments, including financial futures,
are used for this purpose.
ECT accounts for these activities using the mark-to-market
method of accounting. Under mark-to-market accounting, forwards,
swaps, options and other financial instruments with third parties
are reflected at market value, net of future servicing costs,
with resulting unrealized gains and losses recorded as "Assets
and Liabilities From Price Risk Management Activities" in the
Consolidated Balance Sheet. Terms regarding cash settlements of
these contracts vary with respect to the actual timing of cash
receipts and payments. The amounts shown in the Consolidated
Balance Sheet related to price risk management activities also
include assets or liabilities which arise as a result of the
actual timing of settlements related to these contracts. Current
period changes in the assets and liabilities from price risk
management activities (resulting primarily from newly originated
transactions, restructuring and the impact of price movements)
are recognized as net gains or losses in "Other Revenues."
Notional Amounts and Terms. The notional amounts and terms
of these financial instruments at December 31, 1996 are set forth
below (volumes in trillions of British thermal units equivalent
(TBtue), dollars in millions):
<TABLE>
<CAPTION>
Fixed Price Fixed Price Maximum
Payor Receiver Terms in years
<S> <C> <C> <C>
Energy commodities
Natural gas 7,562 7,017 18
Crude oil and liquids 889 556 11
Electricity 852 2,127 15
Financial products
Interest rate(a) $12,530 $1,915 19
Foreign currency 412 422 18
Equity investments(b) 432 809 5
<FN>
(a) The interest rate fixed price receiver represents the net
notional dollar value of the interest rate sensitive component
of the combined commodity portfolio. The interest rate fixed
price payor represents the notional contract amount of a
portfolio of various financial instruments used to hedge the
net present value of the commodity portfolio. For a given
unit of price protection, different financial instruments
require different notional amounts. For example,
approximately $730 million notional strip of Eurodollar
futures contracts are equivalent to $100 million of two year
U.S. Treasury notes. Although the notional amounts vary, the
two instruments offer essentially the same price behavior for
a given move in interest rates. Similarly, the Fixed Price
Payor and Fixed Price Receiver notional amounts listed above
are significantly different but offer the same price risk
behavior. Further, because these positions are offsetting,
little financial exposure occurs to movements in interest
rates.
(b) Includes equity swaps entered into by all of Enron.
</TABLE>
ECT also has sales and purchase commitments associated with
contracts based on market prices totaling 4,477 TBtue, with terms
extending up to 19 years.
Notional amounts reflect the volume of transactions but do not
represent the amounts exchanged by the parties to the financial
instruments. Accordingly, notional amounts do not accurately
measure ECT's exposure to market or credit risks. The maximum
terms in years detailed above are not indicative of likely future
cash flows as these positions may be offset in the markets at any
time in response to the company's risk management needs.
The volumetric weighted average maturity of ECT's entire
portfolio of price risk management activities as of December 31,
1996 was approximately 2.8 years.
Fair Value. The fair value of the financial instruments as of
December 31, 1996, which include energy commodities and the
related foreign currency and interest rate instruments, and the
average fair value of those instruments held during the year are
set forth below:
<TABLE>
<CAPTION>
Fair Value Average Fair Value
as of for the Year Ended
12/31/96 12/31/96(a)
(In Millions) Assets Liabilities Assets Liabilities
<S> <C> <C> <C> <C>
Natural gas $1,959 $1,248 $1,750 $923
Crude oil and liquids 443 578 361 420
Electricity 320 183 182 98
<FN>
(a) Computed using the ending balance at each month end.
</TABLE>
The net change in the value of ECT's portfolio of price risk
management activities for the year ended December 31, 1996,
exclusive of the effects of monetizing certain assets from price
risk management activities and primarily attributable to
financial instruments fixing energy commodity pricing, was $208
million and is included in "Other Revenues". Essentially all of
ECT's operations relate to providing price risk management
services. Accordingly, earnings for this operating segment
appropriately reflect the net gain arising from trading
activities for the year ended December 31, 1996.
Market Risk. To provide solutions to energy problems
worldwide, ECT serves a diverse customer group that includes
independent power producers, industrials, gas and electric
utilities, oil and gas producers, financial institutions and
other energy marketers. This broad customer mix generates a need
for a variety of financial structures, products and terms. This
diversity requires ECT to manage, on a portfolio basis, the
resulting market risks inherent in these transactions subject to
parameters established by Enron's Board of Directors. Market
risks are monitored by a risk control group operating separately
from the units that create or actively manage these risk
exposures to ensure compliance with Enron's stated risk
management policies at both the corporate and subsidiary levels.
Risk measurement is also supplemented with stress testing and
scenario analysis. ECT's fixed price contract portfolio is
typically balanced to within an annual average of 1% of the total
notional physical and financial transaction volumes marketed.
ECT measures the risk in its portfolio on a daily basis in
accordance with value-at-risk and other methodologies, which
simulate forward price curves in the energy markets to estimate
the size and probability of future potential losses. The
quantification of market risk using value-at-risk provides a
consistent measure of risk across diverse energy markets and
products. The use of this methodology requires a number of key
assumptions including the selection of a confidence level for
losses, the holding period chosen for the value-at-risk
calculation and the treatment of risks outside the value-at-risk
methodologies, including liquidity risk and event risk.
ECT expresses value-at-risk as a percentage of Enron's
earnings based on a 95% confidence level using one day holding
periods. On a one day basis as of December 31, 1996, ECT's value-
at-risk for its price risk management activities was less than 2%
(unaudited) of Enron's total income before interest, minority
interests and income taxes. Since this is not an absolute
measure of risk under all conditions for all products, ECT
performs alternative scenario analyses to estimate the economic
impact of a sudden market movement on the value of the trading
portfolio (stress testing). The results of the stress testing,
along with the professional judgments of experienced business and
risk managers, are used to supplement the value-at-risk
methodology and capture additional market-related risks,
including liquidity, event, concentration and correlation
reliance risk.
Based upon the ongoing policies and controls discussed above,
Enron does not anticipate a materially adverse effect on
financial position or results of operations as a result of market
fluctuations.
Credit Risk. Credit risk relates to the risk of loss that
Enron would incur as a result of nonperformance by counterparties
pursuant to the terms of their contractual obligations. The
counterparties associated with ECT's assets from price risk
management activities as of December 31, 1996 and 1995 are
summarized as follows:
<TABLE>
<CAPTION>
Assets from Price Risk Management Activities
December 31, 1996
Investment Below
(In Millions) Grade(a) Investment Grade Total
<S> <C> <C> <C>
Independent power producers $ 358 $103 $ 461
Oil and gas producers 422 369 791
Energy marketers 466 132 598
Gas and electric utilities 495 29 524
Financial institutions 191 - 191
Industrials 35 13 48
Other 108 1 109
Total $2,075 $647 2,722
Credit and other reserves (249)
Assets from price risk
management activities(b) $2,473
</TABLE>
<TABLE>
<CAPTION>
Assets from Price Risk Management Activities
December 31, 1995
Investment Below
(In Millions) Grade(a) Investment Grade Total
<S> <C> <C> <C>
Independent power producers $ 573 $105 $ 678
Oil and gas producers 318 109 427
Energy marketers 132 103 235
Gas and electric utilities 234 45 279
Financial institutions 38 5 43
Industrials 35 43 78
Other 202 42 244
Total $1,532 $452 1,984
Credit and other reserves (207)
Assets from price risk
management activities(b) $1,777
<FN>
(a) "Investment Grade" is primarily determined using publicly
available credit ratings along with consideration of
collateral, which encompass standby letters of credit, parent
company guarantees and property interests, including oil and
gas reserves. Included in "Investment Grade" are
counterparties with a minimum Standard & Poor's or Moody's
rating of BBB- or Baa3, respectively.
(b) Two and three customers' exposures at December 31, 1996
and 1995, respectively, comprise greater than 5% of Assets
From Price Risk Management Activities. All are included above
as Investment Grade.
</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 primarily for the
purpose of hedging the impact of market fluctuations on assets,
liabilities, production or other contractual commitments.
Changes in the market value of these hedge transactions are
deferred until the gain or loss is recognized on the hedged item.
For example, interest rate swaps and options are utilized to
synthetically convert floating rate liabilities to fixed and to
convert fixed rate liabilities to floating. Natural gas and
crude oil swaps and options are utilized to alter Enron's
consolidated exposure to price fluctuations in the exploration
and production segment of the business.
Interest Rate Swaps. At December 31, 1996, Enron had entered
into interest rate swap agreements with a notional principal
amount of $3.6 billion to manage interest rate exposure. Swap
agreements relating to notional amounts of $1.9 billion and $1.7
billion are scheduled to terminate in 1998 and thereafter,
respectively.
Energy Commodity Price Swaps. At December 31, 1996, Enron was
a party to energy commodity price swaps covering 10 TBtu, 100
TBtu and 161 TBtu of natural gas for the years 1997, 1998 and the
period 1999 through 2004, respectively, and 2 million, 2 million
and 1 million barrels of crude oil for the years 1997, 1998 and
the period 1999 through 2000, respectively.
Credit Risk. While notional amounts are used to express the
volume of various derivative financial instruments, the amounts
potentially subject to credit risk, in the event of
nonperformance by the third parties, are substantially smaller.
Counterparties to the forwards, futures and other contracts
discussed above are investment grade financial institutions.
Accordingly, Enron does not anticipate any material impact to its
financial position or results of operations as a result of
nonperformance by the third parties on financial instruments
related to non-trading activities.
Financial Instruments. The carrying amounts and estimated
fair values of Enron's financial instruments, excluding trading
activities which are marked to market, at December 31, 1996 and
1995 were as follows:
<TABLE>
<CAPTION>
1996 1995
Carrying Estimated Carrying Estimated
(In Millions) Amount Fair Value Amount Fair Value
<S> <C> <C> <C> <C>
Long-term debt (Note 6) $3,349 $3,508 $3,065 $3,360
Company-obligated preferred
stock of subsidiaries (Note 9) 592 607 377 386
Interest rate swaps - (11) - (18)
Energy commodity price swaps - (64) - 90
</TABLE>
Enron uses the following methods and assumptions in estimating
fair values: (a) long-term debt - the carrying amount of variable-
rate debt approximates fair value, the fair value of marketable
debt is based on quoted market prices, and the fair value of
other debt is based on the discounted present value of cash flows
using Enron's current borrowing rates; (b) Company-obligated
preferred stock of subsidiaries - the fair value is based on
quoted market prices; and (c) interest rate swaps and energy
commodity price swaps - estimated fair values have been
determined by using available market data and valuation
methodologies. Judgment is necessarily required in interpreting
market data and the use of different market assumptions or
estimation methodologies may affect the estimated fair value
amounts (see "Non-Trading Activities" above).
The fair market value of cash and cash equivalents, accounts
receivable and accounts payable are not materially different from
their carrying amounts.
Guarantees of liabilities of unconsolidated entities and
residual value guarantees have no carrying value and fair values
which are not readily determinable (see Note 15).
4 INCOME TAXES
The components of income before income taxes are as follows:
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
U.S. $551 $622 $415
Foreign 304 183 205
$855 $805 $620
</TABLE>
Total income tax expense is summarized as follows:
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Payable currently -
Federal $ 16 $ 29 $ 49
State 11 26 14
Foreign 37 14 11
64 69 74
Payment deferred -
Federal 174 158 78
State (1) 30 (6)
Foreign 34 28 21
207 216 93
Total Income Tax Expense $271 $285 $167
</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>
1996 1995 1994
<S> <C> <C> <C>
Statutory Federal income tax rate 35.0 % 35.0 % 35.0 %
Net state income taxes 0.8 % 4.5 % 0.8 %
Tight gas sands tax credit (1.8)% (2.8)% (5.9)%
Equity earnings (3.3)% (3.8)% (3.7)%
Minority interest 3.1 % 1.9 % 1.7 %
Asset and stock sale differences 1.8 % 2.1 % -
Cash value in life insurance (3.2)% - -
Other (0.7)% (1.4)% (1.0)%
Effective income tax rate 31.7 % 35.5 % 26.9 %
</TABLE>
The principal components of Enron's net deferred income tax
liability at December 31, 1996 and 1995 were as follows:
<TABLE>
<CAPTION>
(In Millions) 1996 1995
<S> <C> <C>
Deferred income tax assets -
Alternative minimum tax credit
carryforward $ 235 $ 231
Other 143 84
378 315
Deferred income tax liabilities -
Depreciation, depletion and
amortization 1,622 1,617
Price risk management activities 536 427
Other 638 470
2,796 2,514
Net deferred income tax liabilities(a) $2,418 $2,199
<FN>
(a) Includes $128 million and $13 million in other current
liabilities for 1996 and 1995, respectively.
</TABLE>
Enron has an alternative minimum tax (AMT) credit carryforward
of approximately $235 million which can be used to offset regular
income taxes payable in future years. The AMT credit has an
indefinite carryforward period.
Enron has a consolidated net operating loss carryforward for
Federal tax purposes of approximately $222 million. The loss
carryforward will be available in full until 2011. The benefit
of this net operating loss has been recognized as a deferred tax
asset.
U.S. and foreign taxes have been provided for earnings of
foreign subsidiary companies that are expected to be remitted to
the parent company. Foreign subsidiaries' cumulative
undistributed earnings of approximately $475 million are
considered to be indefinitely reinvested outside the U.S. and,
accordingly, no U.S. income taxes have been provided thereon. In
the event of a distribution of those earnings in the form of
dividends, Enron may be subject to both foreign withholding taxes
and U.S. income taxes net of allowable foreign tax credits.
5 SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for income taxes and interest expense, including
fees incurred on sales of accounts receivable, is as follows:
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Income taxes (net of refunds) $ 89 $ 13 $ 57
Interest (net of amounts capitalized) 290 296 268
</TABLE>
In March 1995, a subsidiary of Enron Oil & Gas Company (EOG)
issued redeemable preferred stock with a liquidation/redemption
value of $19 million in exchange for certain oil and gas
properties. These preferred shares were exchanged in 1995 for
633,333 shares of Enron's common stock.
6 CREDIT FACILITIES AND DEBT
Enron has credit facilities with domestic and foreign banks
which provide for an aggregate of $1.2 billion in long-term
committed credit. Expiration dates of the committed facilities
range from June 2001 to November 2001. Interest rates on
borrowings are based upon the London Interbank Offered Rate,
certificate of deposit rates or other short-term interest rates.
Certain credit facilities contain covenants which must be met to
borrow funds. Such debt covenants are not anticipated to
materially restrict Enron's ability to borrow funds under such
facilities. Compensating balances are not required, but Enron is
required to pay a commitment or facility fee. During 1996, no
amounts were outstanding under these facilities.
Enron has also entered into agreements which provide for
uncommitted lines of credit totaling $720 million at December 31,
1996. The uncommitted lines have no stated expiration dates.
Neither compensating balances nor commitment fees are required as
borrowings under the uncommitted credit lines are available
subject to agreement by the participating banks. At December 31,
1996, $191 million was outstanding under the uncommitted lines.
In addition to borrowing from banks on a short-term basis,
Enron and certain of its subsidiaries sell commercial paper to
provide financing for various corporate purposes. As of December
31, 1996 and 1995, short-term borrowings of $298 million and $15
million, respectively, have been reclassified as long-term debt
based upon the availability of committed credit facilities with
expiration dates exceeding one year and management's intent to
maintain such amounts in excess of one year subject to overall
reductions in debt levels. Similarly, at December 31, 1996 and
1995, $175 million and $286 million, respectively, of long-term
debt due within one year remained classified as long-term.
Weighted average interest rates on short-term debt outstanding at
December 31, 1996 and 1995 were 7.0% and 6.3%, respectively.
Detailed information on long-term debt is as follows:
<TABLE>
<CAPTION>
December 31,
(In Millions) 1996 1995
<C> <C> <C>
Enron Corp.
Debentures
6.75% due 2005 - senior subordinated $ 200 $ 200
8.25% due 2012 - senior subordinated 150 150
Notes payable
8.10% to 9.25% due 1996 - 250
6.25% - exchangeable notes due 1998 228 228
8.50% to 10.00% due from 1998 to 2001 450 450
6.75% to 9.875% due from 2003 to 2007 992 992
7% due 2023 100 100
Other 4 10
Northern Natural Gas Company
Notes payable
8.00% due 1999 250 250
6.875% due 2005 100 100
Transwestern Pipeline Company
Notes payable
7.55% to 9.10% due 2000 123 123
9.20% due from 1998 to 2004 27 27
Enron Oil & Gas Company
Notes payable
9.10% due 1998 40 70
5.86% to 6.70% due from 2001 to 2006 255 -
Other 105 78
Enron Europe Limited
Other 41 39
Amount reclassified from short-term debt 298 15
Unamortized debt discount and premium (14) (17)
Total long-term debt $3,349 $3,065
</TABLE>
The Enron 6.25% Exchangeable Notes are mandatorily
exchangeable in 1998 into shares of EOG common stock at a
specified exchange rate or, at Enron's option, for cash with an
equal value. Enron currently intends to satisfy the exchange
obligation by delivering shares of EOG common stock.
The aggregate annual maturities of long-term debt outstanding
at December 31, 1996 were $175 million, $391 million, $328
million, $131 million and $314 million for 1997 through 2001,
respectively.
7 ACCOUNTS RECEIVABLE SALES
Enron has entered into an agreement which provides for the
sale of trade accounts receivable with limited recourse
provisions and the rights to certain recoverable pipeline
transition surcharges expiring January 31, 1999. Sales of trade
receivables under these agreements totaled $250 million and $100
million at December 31, 1996 and 1995, respectively.
The fees incurred on the sales of accounts receivable totaled
$8 million, $23 million and $20 million for 1996, 1995 and 1994,
respectively, and are included in "Interest and Related Charges,
net."
Enron affiliates have concentrations of customers in the
electric and gas utility and oil and gas exploration and
production industries. These concentrations of customers may
impact Enron's overall exposure to credit risk, either positively
or negatively, in that the customers may be similarly affected by
changes in economic or other conditions. However, Enron's
management believes that the portfolio of receivables is well
diversified and that such diversification minimizes any potential
credit risk. Receivables are generally not collateralized.
8 UNCONSOLIDATED SUBSIDIARIES
Summarized combined financial information of Enron's
unconsolidated subsidiaries is presented below:
<TABLE>
<CAPTION>
December 31,
(In Millions) 1996 1995
<S> <C> <C>
Balance sheet
Current assets $2,587 $1,777
Property, plant and equipment, net 8,064 7,814
Other noncurrent assets 902 968
Current liabilities 2,381 2,050
Long-term debt 5,230 4,982
Other noncurrent liabilities 1,139 1,142
Owners' equity 2,803 2,385
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Income statement
Operating revenues $11,676 $8,258 $7,103
Operating expenses 10,567 7,335 6,422
Net income 464 226 290
Distributions paid to Enron 84 68 81
</TABLE>
Enron's equity in earnings (losses) of unconsolidated
subsidiaries is as follows:
<TABLE>
<CAPTION>
Ownership Year Ended December 31,
(In Millions) Interest 1996 1995 1994
<S> <C> <C> <C> <C>
Citrus Corp. 50% $ 22 $27 $ 27
EOTT Energy Partners, L.P. 49% 9 (23) 5
Joint Energy Development
Investments L.P. 50% 71 4 7
Teesside Power Limited 50%(a) 29 18 13
Transportadora de Gas del Sur S.A. 35%(a) 29 22 23
Other 55 38 37
$215 $86 $112
<FN>
(a) Net of minority interests, the ownership is 28% for
Teesside Power Limited and 24% for Transportadora de Gas del
Sur S.A.
</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 Company (Florida Gas), placed into service its Phase
III pipeline expansion. The Phase III expansion increased
Florida Gas' firm average delivery capacity by 530 million cubic
feet per day to 1.5 billion cubic feet per day.
EOTT Energy Partners, L.P. During March 1994, EOTT Energy
Corp., a wholly-owned subsidiary of Enron, exchanged its crude
oil marketing and transportation operations with EOTT Energy
Partners, L.P. (EOTT) for common and subordinated units and a 2%
general partnership interest. The common units were subsequently
sold in an underwritten public offering. Enron purchased
additional units during 1995 and 1996 to increase its ownership
from 42% to 49%.
Enron is committed to provide support for EOTT's common unit
distributions, if needed, up to a total of $29 million through
March 1998 through the purchase of Additional Partnership
Interests. Letters of credit and trade guarantees issued on
behalf of EOTT which were outstanding at December 31, 1996 are
discussed in Note 15.
Joint Energy Development Investments L.P. (JEDI). JEDI, a
limited partnership which acquires and owns energy investments,
was formed in 1993 with an Enron subsidiary and the California
Public Employee Retirement System (CalPERS) each owning a 50%
interest. Enron and CalPERS committed to each invest $250
million of capital in JEDI through 1996, all of which has been
contributed as of December 31, 1996.
JEDI's capital investments are carried at fair value. For
publicly traded securities, fair value is based upon quoted
market prices. For securities that are not publicly traded,
estimates of the fair value are made based upon review of the
investee's financial results, condition and prospects.
Teesside Power Limited (Teesside). Enron has reduced its
effective interest in Teesside, a joint venture cogeneration
company which owns a 1,875 megawatt independent power facility in
northeast England, from 50% in 1994 to 28% in 1996. An affiliate
of Enron operates the facility. Enron has guaranteed Teesside's
obligation for certain grid charges and other amounts which could
become due under certain power sales agreements. The notional
amount of such guarantees is included in Note 15.
Under the terms of certain gas supply agreements extending
through 2008, Teesside is obligated to take-or-pay for an average
of up to 240 billion British thermal units (BBtu) of natural gas
per day at indexed prices. Enron has guaranteed 70% of
Teesside's payment obligation under the gas supply agreements.
Enron believes there are alternative markets for such gas should
the gas not be taken by Teesside.
Transportadora de Gas del Sur S.A. Enron holds an effective
35% interest, including 18% through Enron Global Power &
Pipelines L.L.C., in Compania de Inversiones de Energia S.A., an
Argentine corporation which owns 70% of Transportadora de Gas del
Sur S.A. (TGS). TGS is the owner and operator of a 4,104 mile
natural gas pipeline system in Argentina which connects major gas
fields in southern and western Argentina with distributors of gas
in those areas and in the greater Buenos Aires area, the
principal population center of Argentina. TGS is one of two
transmission systems in Argentina.
9 PREFERRED STOCK
Preferred and Preference Stock. At December 31, 1996, Enron
had outstanding 1,370,714 shares of Cumulative Second Preferred
Convertible Stock (the Convertible Preferred Stock), $1 par
value. The Convertible Preferred Stock pays dividends at an
amount equal to the higher of $10.50 per share or the equivalent
dividend that would be paid if shares of the Convertible
Preferred Stock were converted to common stock. Each share of
the Convertible Preferred Stock is convertible at any time at the
option of the holder thereof into 13.652 shares of Enron's common
stock, subject to certain adjustments. The Convertible Preferred
Stock is currently subject to redemption at Enron's option at a
price of $100 per share plus accrued dividends. During 1996,
1995 and 1994, 4,780 shares, 29,489 shares, and 91,694 shares,
respectively, of the Convertible Preferred Stock were converted
into common stock.
Company-Obligated Preferred Stock of Subsidiaries. Summarized
information for Enron's Company-Obligated Preferred Stock of
Subsidiaries is as follows:
<TABLE>
<CAPTION>
Liquidation
(In Millions, Except Per Share December 31, Value
Amounts and Shares) 1996 1995 Per Share
<C> <C> <C> <C>
Enron Capital Trust I(a)
8.3% Trust Originated Preferred Securities
(8,000,000 shares)(b) $200 $ - $ 25
Enron Capital Resources, L.P.(c)
9% Cumulative Preferred Securities, Series A
(3,000,000 shares)(b) 75 75 25
Enron Capital LLC(d)
8% Cumulative Monthly Income Preferred
Shares (MIPS) (8,550,000 shares)(b) 214 214 25
Enron Equity Corp.(d)
8.57% Preferred Stock (880 shares)(b) 88 88 100,000
7.39% Preferred Stock (150 shares)(b)(e) 15 - 100,000
$592 $377
<FN>
(a) Delaware grantor trust.
(b) Redeemable at Enron's option under certain circumstances
after specified dates.
(c) Enron is sole general partner.
(d) Wholly-owned subsidiary of Enron.
(e) Mandatorily redeemable on April 30, 2006.
</TABLE>
10 COMMON STOCK
Stock Option Plans. Enron applies Accounting Principles
Board (APB) Opinion 25 and related interpretations in accounting
for its stock option plans. In accordance with APB Opinion 25,
compensation expense charged against income for the restricted
stock plan for 1996, 1995 and 1994 was immaterial and no
compensation expense has been recognized for the fixed stock
option plans. Had compensation cost for Enron's stock option
compensation plans been determined based on the fair value at the
grant dates for awards under those plans consistent with the
method of the Statement of Financial Accounting Standards (SFAS)
No. 123 - "Accounting for Stock-Based Compensation," Enron's net
income and earnings per share would have been $562 million ($2.22
per share primary, $2.07 per share fully diluted) in 1996 and
$514 million ($2.05 per share primary, $1.92 per share fully
diluted) in 1995.
Because the SFAS No. 123 method of accounting has not been
applied to options granted prior to January 1, 1995, the
resulting pro forma compensation cost may not be representative
of the pro forma amounts to be expected in future years.
For purposes of the SFAS No. 123 disclosure, the fair value of
each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model with weighted-average
assumptions for grants in 1996 and 1995, respectively: (i)
dividend yield of 2.3% and 2.4%; (ii) expected volatility of
23.8% and 24.3%; (iii) risk-free interest rates of 5.9% and 6.4%;
and (iv) expected lives of 4.0 years and 3.7 years.
Enron has four fixed option plans (the Plans) under which
options for shares of Enron's common stock have been or may be
granted to officers, employees and non-employee members of the
Board of Directors. Options granted may be either incentive
stock options or nonqualified stock options and are granted at
not less than the fair market value of the stock at the time of
grant. The Plans provide for options to be granted with a stock
appreciation rights feature; however, Enron does not presently
intend to issue options with this feature. Under the Plans,
Enron may grant options with a maximum term of 10 years. Options
vest under varying schedules.
Summarized information for Enron's Plans is as follows:
<TABLE>
<CAPTION>
1996 1995 1994
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
(Shares in Thousands) Shares Price Shares Price Shares Price
<S> <C> <C> <C> <C> <C> <C>
Outstanding,
beginning of year 22,493 $29.02 24,246 $27.38 9,680 $19.64
Granted(a) 7,370 39.71 2,971 34.27 15,806 31.19
Exercised (3,615) 24.41 (3,137) 20.91 (1,019) 13.50
Forfeited (749) 31.66 (1,586) 29.89 (221) 24.82
Expired (23) 30.65 (1) 23.42 - -
Outstanding,
end of year 25,476 $32.69 22,493 $29.02 24,246 $27.38
Exercisable,
end of year 12,883 $30.65 9,599 $26.11 7,184 $22.22
Available for grant,
end of year(b) 6,505 7,831 9,252
Weighted average
fair value of
options granted $9.44 $7.86
<FN>
(a) Includes options granted on December 31, 1996, December 29,
1995 and December 30, 1994 for 815,650 shares, 997,095 shares
and 9,717,750 shares, respectively, under all-employee stock
option grants for the years 1995 through 2000.
(b) Includes up to 5,232,218 shares, 5,209,620 shares and
5,245,100 shares as of December 31, 1996, 1995 and 1994,
respectively, which may be issued either as restricted stock
or pursuant to stock options.
</TABLE>
The following table summarizes information about stock options
outstanding at December 31, 1996 (shares in thousands):
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
Weighted
Average Weighted Weighted
Number Remaining Average Number Average
Range of Outstanding Contractual Exercise Exercisable Exercise
Exercise Prices at 12/31/96 Life Price at 12/31/96 Price
<C> <C> <C> <C> <C> <C>
$ 9.13 to $28.50 3,725 5 years $22.10 3,064 $20.96
29.00 to 30.25 2,258 6 years 29.67 1,364 29.53
30.50 to 30.50 7,477 8 years 30.50 2,727 30.50
30.88 to 34.00 3,413 4 years 33.83 2,613 33.81
34.25 to 38.13 4,827 7 years 37.21 2,475 37.04
39.13 to 40.88 1,099 9 years 39.64 208 39.65
43.13 to 45.00 2,677 7 years 43.13 432 43.70
$ 9.13 to $45.00 25,476 7 years $32.69 12,883 $30.65
</TABLE>
Restricted Stock Plan. Under Enron's Restricted Stock Plan,
participants may be granted stock without cost to the
participant. The shares issued under this plan vest to the
participants at various times ranging from immediate vesting to
vesting at the end of a five year period. The following
summarizes shares of restricted stock under this plan:
<TABLE>
<CAPTION>
(Shares in Thousands) 1996 1995 1994
<S> <C> <C> <C>
Outstanding, beginning of year 159 194 222
Granted 1,772 45 30
Issued (1,062) (70) (56)
Forfeited or expired (44) (10) (2)
Outstanding, end of year 825 159 194
Available for grant, end of year 5,232 5,210 5,245
Weighted average fair value of
restricted stock granted $37.04 $31.36 $32.89
</TABLE>
Flexible Equity Trust (the Trust). In December 1993, Enron
established the Trust to fund a portion of its obligations
arising from its various employee compensation and benefit plans.
Enron issued 7.5 million shares of common stock to the Trust in
exchange for cash and an interest bearing promissory note. The
note held by Enron is reflected as a reduction of shareholders'
equity. Common shares held by the Trust are not included in the
computation of earnings per share until such shares are released
to fund employee benefits. During 1996 and 1995, respectively,
2,233,867 shares and 1,049,403 shares were released to fund
employee benefits.
Forward Contracts. At December 31, 1996, Enron has forward
contracts to purchase 4.3 million shares of Enron Corp. common
stock at an average price of $39.25 per share. Enron has the
option to settle the forward contracts in cash or an equivalent
value of Enron common stock over the next five years. Shares
potentially deliverable to the counterparty under the contracts
are treated as common stock equivalents for purposes of
determining earnings per share.
11 RETIREMENT BENEFITS PLAN AND ESOP
Enron maintains a retirement plan (the Enron Plan) which is a
noncontributory defined benefit plan covering substantially all
employees in the United States and certain employees in foreign
countries. Through December 31, 1994, participants in the Enron
Plan with five years or more of service were entitled to
retirement benefits in the form of an annuity based on a formula
that uses a percentage of final average pay and years of service.
In connection with a change to the retirement benefit formula,
Enron amended the Enron Plan providing, among other things, that
all employees became fully vested in retirement benefits earned
through December 31, 1994. The formula in place prior to January
1, 1995 was suspended and replaced with a benefit accrual in the
form of a cash balance of 5% of annual base pay beginning January
1, 1996.
Enron also maintains a noncontributory employee stock
ownership plan (ESOP) which covers all eligible employees.
Allocations to individual employees' retirement accounts within
the ESOP offset a portion of benefits earned under the Enron
Plan. All shares included in the ESOP have been allocated to the
employee accounts. At December 31, 1996 and 1995, 15,976,195 shares
and 20,895,553 shares, respectively, of Enron common stock were held
by the ESOP, a portion of which may be used to offset benefits
under the Enron Plan.
The components of pension expense are as follows:
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Service cost - benefits earned
during the year $ 14 $ 1 $ 16
Interest cost on projected
benefit obligation 23 21 26
Actual return on plan assets (34) (32) (22)
Amortization and deferrals 9 9 (12)
Pension expense (income) $ 12 $(1) $ 8
</TABLE>
The measurement date of the Enron Plan and the ESOP is
September 30. The funded status as of the valuation date of the
Enron Plan and the ESOP reconciles with the amount detailed below
which is included in "Other Assets" on the Consolidated Balance
Sheet.
<TABLE>
<CAPTION>
(In Millions) 1996 1995
<S> <C> <C>
Actuarial present value of accumulated
benefit obligation
Vested $(301) $(276)
Nonvested (4) (27)
Additional amounts related
to projected wage increases (5) (11)
Projected benefit obligation (310) (314)
Plan assets at fair value(a) 315 295
Plan assets in excess of (less than)
projected benefit obligation 5 (19)
Unrecognized net loss 46 53
Unrecognized prior service cost 36 44
Unrecognized net asset at transition (30) (36)
Contributions 1 1
Prepaid pension cost at December 31 $ 58 $ 43
Discount rate 7.5% 7.5%
Long-term rate of return on assets 10.5% 10.5%
Rate of increase in wages 4.0% 4.0%
<FN>
(a) Includes plan assets of the ESOP of $137 million and $152
million for the years 1996 and 1995, respectively.
</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 Millions) 1996 1995
<S> <C> <C>
Actuarial present value of accumulated
postretirement benefit obligation (APBO)
Retirees $(126) $(114)
Fully eligible active plan
participants (2) (2)
Other employees (16) (15)
Total APBO (144) (131)
Plan assets at fair value 15 10
APBO in excess of plan assets (129) (121)
Unrecognized transition obligation 66 70
Unrecognized prior service costs 20 19
Unrecognized net loss 33 26
Accrued postretirement benefit obligation $ (10) $ (6)
Discount rate 7.5% 7.5%
Health care cost trend rate(a) 11.0% 11.7%
<FN>
(a) This rate is assumed to decrease to 5.0% over 9 years.
</TABLE>
The components of net periodic postretirement benefit expense
are as follows:
<TABLE>
<CAPTION>
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Service costs $ 1 $ 1 $ 1
Interest costs 10 9 8
Amortization and deferrals 6 6 6
Postretirement benefit expense $17 $16 $15
</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 $9 million and $1 million, respectively.
13 NATURAL GAS RATES AND REGULATORY ISSUES
Regulatory issues and rates on Enron's regulated pipelines are
subject to final determination by the FERC. Enron's regulated
pipelines currently apply accounting standards that recognize the
economic effects of regulation and, accordingly, have recorded
regulatory assets and liabilities related to their operations.
Enron evaluates the applicability of regulatory accounting and
the recoverability of these assets through rate or other
contractual mechanisms on an ongoing basis. Net regulatory
assets at December 31, 1996 and 1995, respectively, were $312
million and $291 million, which included transition costs
incurred related to FERC Order 636 of $86 million and $125
million. The regulatory assets related to the FERC Order 636
transition costs are scheduled to be primarily recovered from
customers by the end of 1998, while the remaining assets are
expected to be recovered over varying time periods.
Enron's regulated pipelines have all successfully completed
their transitions under FERC Order 636 although future transition
costs may be incurred subject to ongoing negotiations and market
factors. On March 1, 1995, Northern filed a general rate case
proceeding with the FERC which fulfilled a commitment made during
its FERC Order 636 restructuring proceeding. On March 15, 1996,
Northern filed a settlement which resulted in Northern
withdrawing the general rate case, thus leaving the previously
effective rates in effect. The Commission approved this
settlement on July 31, 1996.
Transwestern filed a settlement on May 21, 1996 (the May 21
Settlement) which modified, in part, the 1995 Global Settlement
in which Transwestern and its customers resolved, among other
things, the turnback of approximately 450,000 MMBtu/d of capacity
by Southern California Gas Company, effective November 1, 1996.
The May 21 Settlement resolved all matters regarding pending
transition costs and provided for a rate reduction of settled
transportation rates, which are subject to escalation, effective
on November 1, 1998. The Commission approved the May 21
Settlement on October 16, 1996.
Enron believes, based upon its experience to date and after
considering appropriate reserves that have been established, that
the ultimate resolution of pending regulatory matters will not
have a material impact on Enron's financial position or results
of operations.
14 LITIGATION AND OTHER CONTINGENCIES
Enron is party to various claims and litigation, the
significant items of which are discussed below. Although no
assurances can be given, Enron believes, based on its experience
to date and after considering appropriate reserves that have been
established, that the ultimate resolution of such items,
individually or in the aggregate, will not have a materially
adverse impact on Enron's financial position or, except as
discussed below, its results of operations.
Litigation. In 1995, several parties (the Plaintiffs) filed
suit in Harris County District Court in Houston, Texas against
Intratex Gas Company (Intratex), Houston Pipe Line Company and
Panhandle Gas Company (collectively, the Enron Defendants), each
of which is a wholly-owned subsidiary of Enron. The Plaintiffs
were either sellers or royalty owners under numerous gas purchase
contracts with Intratex, many of which have terminated. Early in
1996, the case was severed by the Court into two matters to be
tried (or otherwise resolved) separately. In the first matter,
the Plaintiffs alleged that the Enron Defendants committed fraud
and negligent misrepresentation in connection with the "Panhandle
program," a special marketing program established in the early
1980s. This case was tried in October 1996 and resulted in a
verdict for the Enron Defendants. In the second matter, the
Plaintiffs allege that the Enron Defendants violated state
regulatory requirements and certain gas purchase contracts by
failing to take the Plaintiffs' gas ratably with other producers'
gas at certain times between 1978 and 1988. The court has
certified a class action with respect to ratability issues. The
Enron Defendants have appealed the court's decision to certify a
class action. The Enron Defendants deny the Plaintiffs' claims
and have asserted various affirmative defenses, including the
statute of limitations. The Enron Defendants believe that they
have strong legal and factual defenses, and intend to vigorously
contest the claims. Although no assurances can be given, Enron
believes that the ultimate resolution of these matters will not
have a materially adverse effect on its financial position or
results of operations.
On March 29, 1996, Enron and two of its wholly-owned
subsidiaries filed suit in the state district court of Harris
County, Texas seeking a ruling that the Capacity Reservation and
Transportation Agreement (CRTA) dated September 10, 1990 between
Teesside Gas Transportation Limited (TGTL), an Enron subsidiary,
and the "CATS" parties has terminated due to consistent material
breaches of that agreement by the CATS parties. The suit was
removed to the federal district court in Houston, Texas.
Proceedings in the Houston lawsuit have been enjoined by an
English court. Enron is appealing the injunction. In April
1996, TGTL, reserving its position in the Houston lawsuit,
notified the CATS parties in accordance with the provisions of
the CRTA that as a result of their failure to make available the
Transportation Service (as defined in the contract) by April 1,
1996, the CRTA was terminated. The CATS parties were to have
provided transportation under the CRTA to ship gas through the
Central Area Transmission System (CATS) pipeline, owned by the
CATS parties. In a separate lawsuit filed in the English court,
the CATS parties are suing TGTL and Enron (on the basis of its
guarantee of TGTL's obligations under the CRTA) for allegedly
failing to make quarterly "send-or-pay" payments under the CRTA.
TGTL refused to make these payments for the same reasons that it
terminated the CRTA: its position is that the Transportation
Service (as defined in the CRTA) was not available. Termination
of the CRTA may lead to termination of the "J-Block Contracts."
Trial on these matters commenced in the English court on
October 28, 1996. The trial concluded in early March 1997, and a
decision is anticipated in June 1997.
The J-Block Contracts are long-term gas contracts that Enron
entered into in March 1993 with Phillips Petroleum Company United
Kingdom Limited, British Gas Exploration and Production Limited
and Agip (U.K.) Limited to purchase future gas production from
the J-Block field which is located in the North Sea offshore the
United Kingdom. Such agreements provide for Enron to take or pay
for certain quantities of gas at a fixed price (with possible
escalations throughout the contract period) on an annual basis.
The contract price is in excess of market prices as of February
1997, however, United Kingdom natural gas prices have been volatile.
The agreements provide that gas paid for, but not taken, can be
recovered in later contract years. In September 1995, Enron
announced that, in accordance with its contractual rights, it had
notified the J-Block sellers that Enron's nominations for gas
from the J-Block fields were estimated to be zero from the first
delivery date of September 25, 1996 through September 30, 1997.
In addition, in accordance with its contractual rights, Enron
made no estimated nominations for J-Block gas under the J-Block
Contracts for the contract year ending September 30, 1998. While
not challenging these actions, the J-Block sellers have, in a
proceeding commenced in English court on March 29, 1996, sought a
declaration that Enron should have agreed to a "Commissioning
Date" (which might trigger Enron's take-or-pay obligations) of
earlier than September 25, 1996, the date set forth in the J-
Block Contracts as the Commissioning Date in the absence of an
agreement on a earlier date. In October 1996, an English Court
of Appeal ruled that Enron was not obligated to agree on an
earlier Commissioning Date, thus making the contract period
ending September 30, 1997 the first year in which Enron has a
potential take-or-pay obligation. This ruling is being appealed
to the House of Lords by the J-Block sellers.
Enron continues to believe that there are many reasons for
the parties to resolve any contract issues commercially, but
efforts have not been successful to date. Unsuccessful settlement
discussions, adverse litigation outcomes or market conditions could
result in a material adverse impact on earnings in any given period.
However, although no assurances can be given, based upon information
currently available and Enron's expectation of the ultimate outcome
of the matters discussed above, Enron anticipates that the J-Block
and CRTA contracts will not have a materially adverse effect on its
financial position.
Environmental Matters. Enron is subject to extensive Federal,
state and local environmental laws and regulations. These laws
and regulations require expenditures in connection with the
construction of new facilities, the operation of existing
facilities and for remediation at various operating sites. The
implementation of the Clean Air Act Amendments is expected to
result in increased operating expenses. These increased
operating expenses are not expected to have a material impact on
Enron's financial position or results of operations.
The Environmental Protection Agency (EPA) has informed Enron
that it is a potentially responsible party at the Decorah Former
Manufactured Gas Plant Site (the Decorah Site) in Decorah, Iowa,
pursuant to the provisions of the Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA, also commonly
known as Superfund). The manufactured gas plant in Decorah
ceased operations in 1951. A predecessor company of Enron
purchased the Decorah Site in 1963 to connect its natural gas
pipeline to the local distribution pipeline system servicing the
city of Decorah. Enron's predecessor did not operate the gas
plant and sold the Decorah Site in 1965. The EPA alleges that
hazardous substances were released to the environment during the
period in which Enron's predecessor owned the site, and that
Enron's predecessor assumed the liabilities of the company that
operated the plant. Enron contests these allegations. The EPA
is interested in determining whether materials from the plant
have adversely affected subsurface soils at the Decorah Site.
Enron has entered into a consent order with the EPA by which it
has agreed, although admitting no liability, to replace affected
topsoil in certain areas of the tract where the plant was
formerly located and to take deep soil samples in those areas
where subsurface contamination would most likely be located. To
date, the EPA has identified no other potentially responsible
parties with respect to this site. Enron believes that expenses
incurred in connection with this matter will not have a
materially adverse effect on its financial position or results of
operations.
Other. In connection with a Power Purchase Agreement between
Dabhol Power Company, Enron's 80%-owned subsidiary, and the
Maharashtra State Electricity Board (MSEB), Dabhol Power Company
began developing Phase I of an electricity generating power plant
south of Bombay, State of Maharashtra, India (the Project). On
August 3, 1995, after construction had begun, a new coalition
government in the State of Maharashtra announced the State
government's intention to terminate the Project, and construction
ceased on August 8, 1995. In response to these actions, Dabhol
Power Company commenced arbitration proceedings in London against
the State government for the actions it had taken to terminate
the Project, seeking to recover all of its construction and other
expenses in addition to lost profits. After the arbitration
proceedings had begun, Dabhol Power Company began renegotiating
the Power Purchase Agreement with MSEB and the Maharashtra state
government. Such renegotiations, which have been successfully
completed, have resulted in a restructured transaction (that
includes both Phase I and Phase II and that increases the planned
capacity of the facility) on terms that are acceptable to Enron.
All approvals for the restructured transaction have been received
and, in December 1996, construction resumed on the project and
Dabhol Power Company terminated the arbitration proceedings.
15 COMMITMENTS
Firm Transportation Obligations. Enron has firm
transportation agreements with various joint venture pipelines.
Under these agreements, Enron must make specified minimum
payments each month. At December 31, 1996, the estimated
aggregate amounts of such required future payments were $33
million, $33 million, $33 million, $34 million and $35 million
for 1997 through 2001, respectively, and $335 million for later
years. These amounts exclude disputed payments allegedly due in
1996 and future years totaling $994 million related to the CRTA
which Enron believes has terminated. See Note 14.
The costs incurred under firm transportation agreements,
including commodity charges on actual quantities shipped, totaled
$30 million, $18 million and $20 million in 1996, 1995 and 1994,
respectively. Enron has assigned firm transportation contracts
with two of its joint ventures to third parties and guaranteed
minimum payments under the contracts averaging approximately $35
million annually through 2001 and $3 million in 2002.
Other Commitments. Enron leases property, operating
facilities and equipment under various operating leases, certain
of which contain renewal and purchase options and residual value
guarantees. Future commitments related to these items at
December 31, 1996 were $141 million, $108 million, $80 million,
$72 million and $69 million for 1997 through 2001, respectively,
and $255 million for later years. Guarantees under the leases
total $982 million at December 31, 1996.
Total rent expense incurred during 1996, 1995 and 1994 was
$149 million, $147 million and $125 million, respectively.
Enron guarantees certain long-term contracts for the sale of
electrical power and steam from a cogeneration facility owned by
one of Enron's equity investees. Under terms of the contracts,
which initially extend through June 1999, Enron could be liable
for penalties should, under certain conditions, the contracts be
terminated early. Enron also guarantees the performance of
certain of its unconsolidated subsidiaries in connection with
letters of credit issued on behalf of those unconsolidated
subsidiaries. At December 31, 1996, a total of $449 million of
such guarantees were outstanding, including $182 million on
behalf of EOTT. In addition, Enron is a guarantor on certain
liabilities of unconsolidated subsidiaries and other companies
totaling approximately $820 million, including $424 million
related to EOTT trade obligations. The EOTT letters of credit
and guarantees of trade obligations are fully secured by the
assets of EOTT. Enron has also guaranteed $187 million in lease
obligations for which it has been indemnified by an "Investment
Grade" company. Management does not consider it likely that
Enron would be required to perform or otherwise incur any losses
associated with the above guarantees. In addition, certain
commitments have been made related to 1997 planned capital
expenditures and equity investments.
16 OTHER INCOME, NET
The components of Other income, net are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Sales of assets and investments $274 $467 $ 37
Regulatory, contingency
and other adjustments 25 (20) 18
Foreign currency - (1) 8
Litigation adjustments and
settlements, net 19 (8) (1)
Interest income 40 27 39
Other (25) (4) 15
$333 $461 $116
</TABLE>
During 1996, Enron sold approximately 12 million shares of EOG
common stock. Proceeds from the sales totaled $307 million.
Enron's ownership interest in EOG at December 31, 1996 was 53%.
In December 1995, Enron sold 31 million outstanding shares of its
EOG common stock, reducing its ownership interest from 80% to
61%. Enron received net proceeds totaling $650 million.
17 QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows:
<TABLE>
<CAPTION>
(In Millions, Except First Second Third Fourth Total
Per Share Amounts) Quarter Quarter Quarter Quarter Year
Quarterly Results
<S> <C> <C> <C> <C> <C>
1996
Revenues $ 3,054 $ 2,961 $ 3,225 $ 4,049 $13,289
Income before interest,
minority interests and
income taxes 415 265 262 296 1,238
Net income 213 117 123 131 584
Earnings per share:
Primary $0.86 $0.46 $0.48 $0.52 $2.31(a)
Fully diluted 0.80 0.43 0.45 0.48 2.16(a)
1995
Revenues $ 2,304 $ 2,149 $ 2,186 $ 2,550 $ 9,189
Income before interest,
minority interests and
income taxes 371 230 239 325 1,165
Net income 195 94 101 130 520
Earnings per share:
Primary $0.79 $0.37 $0.40 $0.52 $2.07(a)
Fully diluted 0.73 0.35 0.37 0.49 1.94(a)
<FN>
(a) The sum of earnings per share for the four quarters may not equal the
total earnings per share for the year due to changes in the average
number of common shares outstanding.
</TABLE>
18 GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION
Enron's operations are classified into four business segments:
Transportation and Operation - Interstate transmission of
natural gas. Construction, management and operation of pipelines
and clean fuels plants. Investment in crude oil transportation
activities.
Domestic Gas and Power Services - Purchasing, marketing and
financing of natural gas, natural gas liquids, crude oil and
electricity. Price risk management in connection with natural
gas, natural gas liquids, crude oil and electricity transactions.
Intrastate natural gas pipelines. Development, acquisition and
promotion of natural gas fired power plants in North America.
Extraction of natural gas liquids.
International Operations and Development - Independent (non-
utility) development, acquisition and promotion of power plants,
natural gas liquids facilities and pipelines outside of North
America.
Exploration and Production - Natural gas and crude oil
exploration and production primarily in the United States,
Canada, Trinidad and India.
Financial information by geographic and business segment
follows for each of the three years in the period ended December
31, 1996.
Geographic Segments
<TABLE>
<CAPTION>
Year Ended December 31,
(In Millions) 1996 1995 1994
<S> <C> <C> <C>
Operating revenues from
unaffiliated customers
United States $11,262 $ 7,855 $ 7,604
Foreign 2,027 1,334 1,380
$13,289 $ 9,189 $ 8,984
Intersegment sales
United States $ 72 $ 24 $ 49
Foreign 128 159 116
$ 200 $ 183 $ 165
Operating income
United States $ 490 $ 487 $ 609
Foreign 200 131 107
$ 690 $ 618 $ 716
Income before interest, minority
interests and income taxes
United States $ 938 $ 969 $ 755
Foreign 300 196 189
$ 1,238 $ 1,165 $ 944
Identifiable assets
United States $11,580 $10,695 $ 9,597
Foreign 2,856 1,327 1,304
$14,436 $12,022 $10,901
</TABLE>
Business Segments
<TABLE>
<CAPTION>
Domestic International
Transportation Gas Operations Exploration Corporate
and and Power and and and
(In Millions) Operation Services Development Production Other(c)(d) Total
<S> <C> <C> <C> <C> <C> <C>
1996
Unaffiliated revenues(a) $ 748 $11,681 $ 213 $ 647 $ - $13,289
Intersegment revenues(b) 58 167 - 177 (402) -
Total revenues 806 11,848 213 824 (402) 13,289
Depreciation, depletion and
amortization 82 123 15 251 3 474
Operating income (loss) 367 197 58 205 (137) 690
Equity in earnings of
unconsolidated subsidiaries 47 84 84 - - 215
Other income, net 156 (1) 10 (5) 173 333
Income before interest,
minority interests and
income taxes 570 280 152 200 36 1,238
Additions to property, plant
and equipment 181 112 16 540 6 855
Identifiable assets 2,569 7,958 827 2,371 711 14,436
Investments in and advances to
unconsolidated subsidiaries 563 484 521 - 133 1,701
Total assets $3,132 $ 8,442 $1,348 $2,371 $ 844 $16,137
1995
Unaffiliated revenues(a) $ 805 $ 7,064 $ 839 $ 481 $ - $ 9,189
Intersegment revenues(b) 26 (103) 44 278 (245) -
Total revenues 831 6,961 883 759 (245) 9,189
Depreciation, depletion and
amortization 83 104 27 216 2 432
Operating income (loss) 299 115 75 240 (111) 618
Equity in earnings of
unconsolidated subsidiaries 23 6 58 - (1) 86
Other income, net 37 36 9 1 378 461
Income before interest,
minority interests and
income taxes 359 157 142 241 266 1,165
Additions to property, plant
and equipment 121 98 58 464 8 749
Identifiable assets 2,361 5,991 814 2,067 789 12,022
Investments in and advances to
unconsolidated subsidiaries 533 157 468 - 59 1,217
Total assets $2,894 $ 6,148 $1,282 $2,067 $ 848 $13,239
1994
Unaffiliated revenues(a) $ 937 $ 7,166 $ 392 $ 489 $ - $ 8,984
Intersegment revenues(b) 39 13 7 290 (349) -
Total revenues 976 7,179 399 779 (349) 8,984
Depreciation, depletion and
amortization 88 94 15 242 2 441
Operating income (loss) 327 164 73 195 (43) 716
Equity in earnings of
unconsolidated subsidiaries 49 18 45 - - 112
Other income, net 27 20 30 3 36 116
Income before interest,
minority interests and
income taxes 403 202 148 198 (7) 944
Additions to property, plant
and equipment 117 83 14 442 5 661
Identifiable assets 2,388 5,803 450 1,824 436 10,901
Investments in and advances to
unconsolidated subsidiaries 528 162 351 - 24 1,065
Total assets $2,916 $ 5,965 $ 801 $1,824 $ 460 $11,966
<FN>
(a) Unaffiliated revenues include sales to unconsolidated subsidiaries.
(b) Intersegment sales are made at prices comparable to those received
from unaffiliated customers and in some instances are affected by
regulatory considerations.
(c) Corporate and Other assets consist of cash and cash equivalents,
investments in marketable securities, receivables transferred from
subsidiaries in connection with the receivables sale program and
miscellaneous other assets.
(d) Includes consolidating eliminations.
</TABLE>
19 OIL AND GAS PRODUCING ACTIVITIES (Unaudited except for
Results of Operations for Oil and Gas Producing Activities)
The following information regarding Enron's oil and gas
producing activities should be read in conjunction with Note 1.
This information includes amounts attributable to a minority
interest of 47% at December 31, 1996, 39% at December 31, 1995
and 20% at December 31, 1994 and 1993.
Capitalized Costs Relating to Oil and Gas Producing Activities
<TABLE>
<CAPTION>
December 31,
(In Millions) 1996 1995
<S> <C> <C>
Proved properties $ 3,593 $ 3,254
Unproved properties 160 127
Total 3,753 3,381
Accumulated depreciation,
depletion and amortization (1,653) (1,499)
Net capitalized costs $ 2,100 $ 1,882
</TABLE>
Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities(a)
<TABLE>
<CAPTION>
Foreign
(In Millions) United States Canada Trinidad India Other Total
<S> <C> <C> <C> <C> <C> <C>
1996
Acquisition of properties
Unproved $ 39 $ 4 $ 2 $ - $ - $ 45
Proved 69 - - - - 69
Total 108 4 2 - - 114
Exploration 61 8 2 4 17 92
Development 283 26 7 79 7 402
Total $452 $38 $11 $83 $24 $608
1995
Acquisition of properties
Unproved $ 16 $ 5 $ - $ - $ 1 $ 22
Proved 123 - - 5 - 128
Total 139 5 - 5 1 150
Exploration 48 7 - - 18 73
Development 217 28 33 17 1 296
Total $404 $40 $33 $22 $20 $519
1994
Acquisition of properties
Unproved $ 46 $ 6 $ - $ - $ - $ 52
Proved 17 5 - 13 - 35
Total 63 11 - 13 - 87
Exploration 71 8 1 2 11 93
Development 223 36 61 - 1 321
Total $357 $55 $62 $15 $12 $501
<FN>
(a) Costs have been categorized on the basis of Financial Accounting
Standards Board definitions which include costs of oil and gas producing
activities whether capitalized or charged to expense as incurred.
</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,
1996:
<TABLE>
<CAPTION>
Foreign
(In Millions) United States Canada Trinidad India Other Total
<S> <C> <C> <C> <C> <C> <C>
1996
Operating revenues
Associated companies $253 $14 $ - $ - $ - $267
Trade 282 48 84 21 - 435
Gains on sales of
reserves and related
assets 19 1 - - - 20
Total 554 63 84 21 - 722
Exploration expenses,
including dry hole costs 45 5 2 1 15 68
Production costs 77 17 15 10 - 119
Impairment of unproved
oil and gas properties 19 2 - - - 21
Depreciation, depletion and
amortization 209 25 15 1 1 251
Income (loss) before
income taxes 204 14 52 9 (16) 263
Income tax expense (benefit) 54 6 29 4 - 93
Results of operations $150 $ 8 $23 $ 5 $(16) $170
1995
Operating revenues
Associated companies $224 $ 7 $ - $ - $ - $231
Trade 122 37 72 15 - 246
Gains on sales of
reserves and related
assets 63 - - - - 63
Total 409 44 72 15 - 540
Exploration expenses,
including dry hole costs 35 4 - - 16 55
Production costs 64 13 8 11 - 96
Impairment of unproved
oil and gas properties 22 2 - - - 24
Depreciation, depletion and
amortization 181 20 15 - - 216
Income (loss) before
income taxes 107 5 49 4 (16) 149
Income tax expense (benefit) 1 1 27 2 (1) 30
Results of operations $106 $ 4 $22 $ 2 $(15) $119
1994
Operating revenues
Associated companies $316 $ 8 $ - $ - $ - $324
Trade 115 42 36 1 - 194
Gains on sales of
reserves and related
assets 54 - - - - 54
Total 485 50 36 1 - 572
Exploration expenses,
including dry hole costs 42 4 1 3 9 59
Production costs 69 13 5 - - 87
Impairment of unproved
oil and gas properties 24 1 - - - 25
Depreciation, depletion and
amortization 218 17 7 - - 242
Income (loss) before
income taxes 132 15 23 (2) (9) 159
Income tax expense (benefit) (8) 6 12 (1) (3) 6
Results of operations $140 $ 9 $11 $(1) $(6) $153
<FN>
(a) Excludes net revenues associated with other marketing activities,
interest charges, general corporate expenses and certain gathering and
handling fees, which are not part of required disclosures about oil and
gas producing activities.
</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, 1996, 1995 and 1994 were based on studies performed by
Enron's engineering staff for reserves in the United States,
Canada, Trinidad and India. Opinions by DeGolyer and
MacNaughton, independent petroleum consultants, for the years
ended December 31, 1996, 1995 and 1994 covering producing areas,
in the United States and Canada, containing 64%, 60% and 59%,
respectively, of proved reserves, excluding deep Paleozoic
reserves, of Enron on a net-equivalent-cubic-feet-of-gas basis,
indicate that the estimates of proved reserves prepared by
Enron's engineering staff for the properties reviewed by DeGolyer
and MacNaughton, when compared in total on a net-equivalent-cubic-
feet-of-gas basis, do not differ by more than 5% from those
prepared by DeGolyer and MacNaughton's engineering staff. In
addition, the deep Paleozoic reserves were covered by the opinion
of DeGolyer and McNaughton at December 31, 1995. All reports by
DeGolyer and MacNaughton were developed utilizing geological and
engineering data provided by Enron.
The standardized measure of discounted future net cash flows
does not purport, nor should it be interpreted, to present the
fair market value of Enron's crude oil and natural gas reserves.
An estimate of fair value would also take into account, among
other things, the recovery of reserves not presently classified
as proved reserves, anticipated future changes in prices and
costs and a discount factor more representative of the time value
of money and the risks inherent in reserve estimates.
Enron's presentation of estimated proved oil and gas reserves
excludes, for each of the years presented, those quantities
attributable to future deliveries required under a volumetric
production payment. In order to calculate such amounts, Enron
has assumed that deliveries under the volumetric production payment
are made as scheduled at expected British thermal unit factors,
and that delivery commitments are satisfied through delivery of
actual volumes as opposed to cash settlements.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
<TABLE>
<CAPTION>
(In Millions) United States Canada Trinidad India Total
<S> <C> <C> <C> <C> <C>
1996
Future cash inflows(a) $ 9,391 $ 715 $ 709 $ 864 $11,679
Future production costs (1,640) (281) (237) (338) (2,496)
Future development costs (306) (9) (1) - (316)
Future net cash flows before
income taxes 7,445 425 471 526 8,867
Future income taxes (2,260) (99) (246) (227) (2,832)
Future net cash flows 5,185 326 225 299 6,035
Discount to present value at
10% annual rate (2,693) (100) (68) (105) (2,966)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 2,492(b) $ 226 $ 157 $ 194 $ 3,069(b)
1995
Future cash inflows(a) $3,996 $ 503 $ 395 $ 396 $ 5,290
Future production costs (747) (204) (152) (202) (1,305)
Future development costs (298) (7) (4) (13) (322)
Future net cash flows before
income taxes 2,951 292 239 181 3,663
Future income taxes (696) (46) (105) (82) (929)
Future net cash flows 2,255 246 134 99 2,734
Discount to present value at
10% annual rate (1,015) (69) (19) (46) (1,149)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $1,240(b) $ 177 $ 115 $ 53 $ 1,585(b)
1994
Future cash inflows(a) $2,315 $ 487 $ 318 $ 168 $ 3,288
Future production costs (607) (196) (87) (106) (996)
Future development costs (136) (10) (2) (4) (152)
Future net cash flows before
income taxes 1,572 281 229 58 2,140
Future income taxes (208) (57) (103) (22) (390)
Future net cash flows 1,364 224 126 36 1,750
Discount to present value at
10% annual rate (401) (67) (23) (15) (506)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 963(b) $ 157 $ 103 $ 21 $ 1,244(b)
<FN>
(a) Based on year-end market prices determined at the point of delivery
from the producing unit.
(b) Excludes $75 million, $36 million and $60 million at December 31,
1996, 1995 and 1994, respectively, associated with a volumetric
production payment sold effective October 1, 1992, as amended, to be
delivered over a seventy-eight month period beginning October 1, 1992.
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows
<TABLE>
<CAPTION>
(In Millions) United States Canada Trinidad India Total
<C> <C> <C> <C> <C> <C>
December 31, 1993 $1,262 $160 $ 50 $ - $1,472
Sales and transfers of oil
and gas produced, net
of production costs (340) (38) (31) - (409)
Net changes in prices and
production costs (506) (66) 11 - (561)
Extensions, discoveries, additions
and improved recovery, net of
related costs 225 51 97 - 373
Development costs incurred 70 7 7 - 84
Revisions of estimated development
costs 7 6 - - 13
Revisions of previous quantity
estimates (3) (3) 14 - 8
Accretion of discount 145 20 7 - 172
Net change in income taxes 168 20 (46) (8) 134
Purchases of reserves in place 17 3 - 29 49
Sales of reserves in place (28) - - - (28)
Changes in timing and other (54) (3) (6) - (63)
December 31, 1994 $ 963 $157 $103 $ 21 $1,244
Sales and transfers of oil
and gas produced, net
of production costs (268) (30) (64) (5) (367)
Net changes in prices and
production costs 12 (6) (37) 8 (23)
Extensions, discoveries, additions
and improved recovery, net of
related costs 376(a) 38 54 46 514(a)
Development costs incurred 29 3 2 - 34
Revisions of estimated development
costs 1 - 29 4 34
Revisions of previous quantity
estimates 6 (5) 10 - 11
Accretion of discount 97 18 17 3 135
Net change in income taxes (133) 11 (8) (28) (158)
Purchases of reserves in place 194 - - - 194
Sales of reserves in place (54) (1) - - (55)
Changes in timing and other 17 (8) 9 4 22
December 31, 1995 $1,240(a) $177 $115 $ 53 $1,585(a)
Sales and transfers of oil
and gas produced, net
of production costs (437) (46) (69) (11) (563)
Net changes in prices and
production costs 1,817 58 60 54 1,989
Extensions, discoveries, additions
and improved recovery, net of
related costs 581 63 62 150 856
Development costs incurred 58 2 2 - 62
Revisions of estimated development
costs (14) (3) 1 14 (2)
Revisions of previous quantity
estimates 7 (1) 80 - 86
Accretion of discount 137 18 20 9 184
Net change in income taxes (656) (30) (74) (87) (847)
Purchases of reserves in place 162 - - - 162
Sales of reserves in place (103) (3) - - (106)
Changes in timing and other (300) (9) (40) 12 (337)
December 31, 1996 $2,492(a) $226 $157 $194 $3,069(a)
<FN>
(a) Includes approximately $344 million and $77 million related to the
reserves in the Big Piney deep Paleozoic formations at December 31, 1996
and 1995, respectively.
</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, 1993 1,079.8(a) 250.6 71.4 - 1,401.8(a)
December 31, 1994 1,128.2(a) 288.3 206.2 - 1,622.7(a)
December 31, 1995 1,218.1(a)(b) 310.1 233.9 - 1,762.1(a)(b)
December 31, 1996 1,325.7(a)(b) 319.5 370.2 124.6 2,140.0(a)(b)
Liquids (MBbl)(c)
December 31, 1993 11,165(a) 5,409 1,591 - 18,165(a)
December 31, 1994 16,770(a) 7,073 4,429 7,585 35,857(a)
December 31, 1995 19,977(a) 6,505 5,607 11,542 43,631(a)
December 31, 1996 24,868(a) 7,452 8,168 10,791 51,279(a)
Natural gas (Bcf)
Net proved reserves at
December 31, 1993 1,313.2(a) 271.0 100.5 - 1,684.7(a)
Revisions of previous
estimates (17.1) (6.5) 15.0 - (8.6)
Purchases in place 18.8 9.2 - 29.3 57.3
Extensions, discoveries and
other additions 233.8 50.2 113.9 - 397.9
Sales in place (29.3) (1.0) - - (30.3)
Production (212.0) (26.3) (23.2) - (261.5)
Net proved reserves at
December 31, 1994 1,307.4(a) 296.6 206.2 29.3 1,839.5(a)
Revisions of previous
estimates 10.1 (8.1) 17.5 (29.3) (9.8)
Purchases in place 174.8 - - - 174.8
Extensions, discoveries and
other additions 1,391.6(b) 54.8 60.8 75.0 1,582.2(b)
Sales in place (38.1) (1.7) - - (39.8)
Production (191.7) (27.7) (39.0) - (258.4)
Net proved reserves at
December 31, 1995 2,654.1(a)(b) 313.9 245.5 75.0 3,288.5(a)(b)
Revisions of previous
estimates 3.6 (2.9) 79.6 - 80.3
Purchases in place 100.6 0.9 - - 101.5
Extensions, discoveries and
other additions 256.8 49.2 90.7 124.6 521.3
Sales in place (58.4) (4.3) - - (62.7)
Production (210.2) (35.9) (45.6) - (291.7)
Net proved reserves at
December 31, 1996 2,746.5(a)(b) 320.9 370.2 199.6 3,637.2(a)(b)
</TABLE>
<TABLE>
<CAPTION>
United States Canada Trinidad India Total
<C> <C> <C> <C> <C> <C>
Liquids (MBbl)(c)
Net proved reserves at
December 31, 1993 13,172 5,471 2,218 - 20,861
Revisions of previous
estimates 2,179 (177) 455 - 2,457
Purchases in place 358 - - 7,617 7,975
Extensions, discoveries and
other additions 5,332 2,848 2,687 - 10,867
Sales in place (257) - - - (257)
Production (2,997) (905) (931) (32) (4,865)
Net proved reserves at
December 31, 1994 17,787 7,237 4,429 7,585 37,038
Revisions of previous
estimates (413) (351) 396 4,874 4,506
Purchases in place 4,264 - - - 4,264
Extensions, discoveries and
other additions 8,703 729 3,896 - 13,328
Sales in place (1,241) (9) - - (1,250)
Production (3,701) (1,021) (1,851) (917) (7,490)
Net proved reserves at
December 31, 1995 25,399 6,585 6,870 11,542 50,396
Revisions of previous
estimates 339 191 1,835 - 2,365
Purchases in place 312 2 - - 314
Extensions, discoveries and
other additions 7,103 2,116 1,388 275 10,882
Sales in place (447) (121) - - (568)
Production (3,830) (1,321) (1,925) (1,026) (8,102)
Net proved reserves at
December 31, 1996 28,876 7,452 8,168 10,791 55,287
<FN>
(a) Excludes approximately 37.5 Bcf, 54.2 Bcf, 70.9 Bcf and 87.5 Bcf at
December 31, 1996, 1995, 1994 and 1993, respectively, associated with a
volumetric production payment sold effective October 1, 1992, as
amended, to be delivered over a seventy-eight month period beginning
October 1, 1992.
(b) Includes 1,180.0 Bcf related to net proved Deep Paleozoic natural
gas reserves.
(c) Includes crude oil, condensate and natural gas liquids.
</TABLE>
<TABLE>
Exhibit 11
ENRON CORP. AND SUBSIDIARIES
Calculation of Earnings Per Share
(Unaudited)
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in millions except
per share amounts)
<S> <C> <C> <C>
Primary Earnings Per Share
Earnings on common stock
Net income $ 584 $ 520 $ 453
Preferred stock dividends (16) (16) (15)
$ 568 $ 504 $ 438
Average number of common shares outstanding 246 244 243
Primary earnings per share of common stock $2.31 $2.07 $1.80
Fully Diluted Earnings Per Share
Adjusted earnings on common stock
Net income $ 584 $ 520 $ 453
Preferred stock dividends (16) (16) (15)
Add back:
Dividends on convertible preferred stock 16 16 15
$ 584 $ 520 $ 453
Average number of common shares outstanding
on a fully diluted basis
Average number of common shares outstanding 246 244 243
Additional shares issuable upon:
Conversion of preferred stock 18 19 20
Exercise of stock options reduced by the number
of shares which could have been purchased with
the proceeds from exercise of such options 7 5 3
271 268 266
Fully diluted earnings per share of common stock $2.16 $1.94 $1.70
</TABLE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report dated February 17, 1997
included in this Form 8-K into Enron Corp.'s previously
filed Registration Statement File Nos. 33-13397 (Savings
Plan), 33-34796 (Savings Plan), 33-52261 (Savings Plan), 33-
13498 (1986 Stock Option Plan), 33-27893 (1988 Stock Option
Plan), 33-46459 ($700 million Senior Subordinated Debt
Securities), 33-52768 (Enron Corp. 1991 Stock Plan), 33-
52143 (955,640 Shares of Common Stock), 33-57903 (617,452
Shares of Common Stock), 33-60821 (Enron Corp. 1994 Stock
Plan), 33-60417 (Enron Corp. Debt Securities and Second
Preferred Stock and Enron Capital Resources, L.P. Preferred
Securities), 333-22739 (330,968 Shares of Common Stock), 333-
13791 and 333-13791-01 (Shares of Common Stock of Enron
Corp. or Enron Oregon Corp. to be issued in exchange for
outstanding Shares of Common Stock of Portland General
Corporation) and 333-19253 (Enron Corp. Stock Option Plan
for Zond Exchange Agreements).
ARTHUR ANDERSEN LLP
Houston, Texas
March 17, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 256
<SECURITIES> 0
<RECEIVABLES> 2,169
<ALLOWANCES> 0
<INVENTORY> 164
<CURRENT-ASSETS> 3,979
<PP&E> 11,348
<DEPRECIATION> 4,236
<TOTAL-ASSETS> 16,137
<CURRENT-LIABILITIES> 3,708
<BONDS> 3,349
0
137
<COMMON> 26
<OTHER-SE> 3,560
<TOTAL-LIABILITY-AND-EQUITY> 16,137
<SALES> 12,137
<TOTAL-REVENUES> 13,289
<CGS> 10,478
<TOTAL-COSTS> 12,599
<OTHER-EXPENSES> (548)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 274
<INCOME-PRETAX> 855
<INCOME-TAX> 271
<INCOME-CONTINUING> 584
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 584
<EPS-PRIMARY> 2.31
<EPS-DILUTED> 2.16
</TABLE>
