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 19, 1998
Commission File Number 1-13159
ENRON CORP.
(Exact name of registrant as specified in its charter)
Oregon 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 59
<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, 1997, including Report of Arthur
Andersen LLP, Independent Public Accountants.
(b) Exhibits.
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 19, 1998 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 21
Consolidated Income Statement for the years ended
December 31, 1997, 1996 and 1995 22
Consolidated Balance Sheet, December 31, 1997 and 1996 23
Consolidated Statement of Cash Flows for the years
ended December 31, 1997, 1996 and 1995 25
Consolidated Statement of Changes in Shareholders'
Equity Accounts for the years ended December 31,
1997, 1996 and 1995 26
Notes to Consolidated Financial Statements 27
Exhibits
Exhibit 23 - Consent of Arthur Andersen LLP 59
<PAGE>
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 1997 was $105 million compared to $584
million in 1996 and $520 million in 1995. The results of
operations discussion focuses on core businesses, the new retail
energy services business (primarily serving commercial and light
industrial end-use customers) and items impacting comparability
of operations. Core businesses include Exploration and
Production (Enron Oil & Gas Company), Transportation and
Distribution (Gas Pipeline Group and Portland General) and
Wholesale Energy Operations and Services (Enron Capital & Trade
Resources, Enron International and Enron Engineering &
Construction). The results of Portland General have been
included in Enron's Consolidated Financial Statements beginning
July 1, 1997. See Note 2 to the Consolidated Financial
Statements. Items impacting comparability are discussed in the
respective segment results. Net income includes the following:
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
After-tax results from:
Core businesses $ 585 $ 493 $ 489
Retail Energy Services:
Results(a) (70) - -
Gain on sale of 7% of Enron Energy
Services (EES) shares 61 - -
(9) - -
576 493 489
Items impacting comparability:(a)
Charge to reflect impact of amended
J-Block gas contract (463) - -
Charge to reflect depressed MTBE
margins on committed production (74) - (49)
Gains on sales of liquids and
gathering assets 66 59 43
Gains on sales of Enron Oil & Gas
Company stock - 90 161
Reserve for qualified facilities
disposition - (54) -
Miscellaneous reserves and other
items - (4) (124)
Reported net income $ 105 $ 584 $ 520
<FN>
(a) Tax affected at 35%, except where a specific tax rate
applied.
</TABLE>
Basic and diluted earnings per share of common stock were as
follows:
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Reported basic earnings per share $0.32 $2.31 $2.07
Diluted earnings per share:
Results from core businesses $1.98 $1.82 $1.82
Retail Energy Services:
Results (0.24) - -
Gain on sale of 7% of EES shares 0.21 - -
Items impacting comparability:
Charge to reflect impact of
amended J-Block gas contract (1.57) - -
Charge to reflect depressed MTBE
margins on committed production (0.25) - (0.18)
Gains on sales of liquids and
gathering assets 0.22 0.22 0.16
Gains on sales of Enron Oil & Gas
Company stock - 0.33 0.60
Reserve for qualified facilities
disposition - (0.20) -
Miscellaneous reserves and other
items - (0.01) (0.46)
Effect of anti-dilution(a) (0.03) - -
Reported diluted earnings per share $0.32 $2.16 $1.94
<FN>
(a) For 1997, the conversion of preferred shares to common
shares for purposes of the diluted earnings per share
calculation was anti-dilutive by $0.03 per share. However, in
order to present comparable results, per share amounts for
each earnings component were calculated using 295 million
shares, which assumes the conversion of preferred shares to
common shares.
</TABLE>
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 (see Note 17 to the Consolidated Financial Statements):
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Exploration and Production $ 183 $ 200 $ 241
Transportation and Distribution:
Gas Pipeline Group 466 524 359
Portland General 114 - -
Wholesale Energy Operations
and Services 654 466 401
Retail Energy Services (107) - -
Corporate and Other (745) 48 164
Reported income before interest,
minority interests and taxes $ 565 $1,238 $1,165
</TABLE>
Exploration and Production
Enron's exploration and production operations are conducted by
Enron Oil & Gas Company (EOG). IBIT of Exploration and
Production totaled $183 million, $200 million and $241 million
for 1997, 1996 and 1995, respectively.
Wellhead volume and price statistics (including intercompany
amounts) are as follows:
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Natural gas volumes (MMcf/d)(a)
North America(b) 758 706 636
Trinidad 113 124 107
India 18 - -
Total 889 830 743
Average natural gas prices ($/Mcf)
North America(c) $2.20 $1.92 $1.34
Trinidad 1.05 1.00 0.97
India 2.79 - -
Composite 2.07 1.78 1.29
Crude oil/condensate volumes
(MBbl/d)(a)
North America 14.2 11.6 11.5
Trinidad 3.4 5.2 5.1
India 2.3 2.8 2.5
Total 19.9 19.6 19.1
Average crude oil/condensate prices
($/Bbl)
North America $19.33 $21.08 $17.09
Trinidad 18.68 19.76 16.07
India 20.05 20.17 16.81
Composite 19.30 20.60 16.78
<FN>
(a) Million cubic feet per day or thousand barrels per day, as
applicable.
(b) Includes an annual average of 48 MMcf/d in 1997, 1996 and
1995 delivered under the terms of a volumetric production
payment agreement effective October 1, 1992, as amended.
(c) Includes an average equivalent wellhead value of $1.73 per
Mcf in 1997, $1.17 per Mcf in 1996 and $0.80 per Mcf in 1995
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 Exploration and Production:
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Net revenues $783 $730 $648
Corporate hedging activities (8) (4) 45
Operating expenses 150 133 126
Exploration expenses 102 89 79
Depreciation, depletion and
amortization 278 251 216
Taxes, other than income taxes 60 48 32
Operating income 185 205 240
Other income, net (2) (5) 1
Reported income before interest,
minority interests and taxes $183 $200 $241
</TABLE>
Net Revenues
Exploration and Production's revenues, net of gas sold in
connection with natural gas marketing, increased $53 million (7%)
in 1997 and $82 million (13%) in 1996. The 1997 and 1996
increases reflected both increased average wellhead natural gas
prices and increased production volumes. The 1996 volumes
increased from 1995 primarily from the elimination of 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, reduced net revenues by $61
million in 1997, compared with increases of $4 million in 1996
and $105 million in 1995. Net revenues also include gains on
sales of crude oil and gas reserves and related assets of $9
million in 1997, $20 million in 1996 and $63 million in 1995.
Costs and Expenses
Operating expenses, depreciation, depletion and amortization
and taxes other than income taxes increased in 1997 and 1996 due
primarily to the increased production activity.
Exploration expenses increased 15% in 1997 and 13% in 1996 as
compared to the prior year, primarily as a result of increased
exploratory drilling activities and lease acquisitions in North
America.
Outlook
EOG plans to continue its significant investments in
development and certain exploration expenditures in its major
producing areas in North America. In addition, EOG anticipates
increased spending for the continued development of its
significant international projects in India, Venezuela, Trinidad
and China. Enron has hedged its net exposure to EOG's natural
gas prices for 1998 production and will continue to assess
opportunities for hedging future production.
Transportation and Distribution
Transportation and Distribution consists of Gas Pipeline Group
and Portland General. Gas Pipeline Group includes Enron's
interstate natural gas pipelines, primarily Northern Natural Gas
Company (Northern), Transwestern Pipeline Company (Transwestern)
and Enron's 50% interest in Florida Gas Transmission Company
(Florida Gas). Portland General primarily reflects the results
of Portland General Electric Company (PGE) since the July 1, 1997
merger (see Note 2 to the Consolidated Financial Statements).
Gas Pipeline Group. Significant components of IBIT are as
follows:
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Net revenues $665 $719 $745
Operating expenses 310 316 343
Depreciation and amortization 69 66 82
Equity in earnings 40 35 46
Other income, net 38 44 9
IBIT before items impacting
comparability 364 416 375
Gains on sales of liquids and
gathering assets 102 90 67
Miscellaneous reserves and other items - 18 (83)
Reported income before interest
and taxes $466 $524 $359
</TABLE>
Net Revenues
Revenues, net of cost of sales, of Gas Pipeline Group declined
$54 million (8%) during 1997 and $26 million (3%) during 1996 as
compared to the applicable preceding year. The decrease in net
revenues in 1997 compared to 1996 was primarily due to the sale
of natural gas liquids assets in early 1997 and the turnback of
capacity at Transwestern, resulting in reduced transportation
revenues beginning in November 1996. The decrease in net
revenues from 1995 to 1996 was primarily a result of the sale of
gathering facilities in 1995 and the first quarter of 1996. In
addition, revenues decreased 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.
Operating Expenses
Operating expenses of Gas Pipeline Group declined $6 million
(2%) during 1997, primarily due to a reduction of transition
costs to be recovered in regulatory surcharges at Northern. Gas
Pipeline Group's operating expenses declined $27 million (8%) in
1996 compared with 1995 due primarily to the favorable resolution
of environmental contingencies previously accrued, combined with
reduced expenses related to the gathering facilities sold in 1995
and early 1996 and a decrease in amortization of deferred
contract reformation costs by Northern.
Depreciation and amortization declined $16 million (20%) in
1996 compared with 1995 due primarily to the sale of gathering
facilities in 1995 and the first quarter of 1996.
Equity in Earnings
Equity in earnings of unconsolidated subsidiaries increased $5
million (14%) during 1997 as compared to 1996 after decreasing
$11 million (24%) during 1996 as compared to 1995. The increase
in 1997 was primarily due to increased equity earnings related to
Enron's interest in Citrus Corp., which holds Enron's 50%
interest in Florida Gas. The decrease in equity earnings in 1996
was primarily due to lower earnings from Enron's interest in
Trailblazer Pipeline Company due to the recognition in 1995 of
income from a settlement with a transportation customer.
Items Impacting Comparability
During 1997, gains of $102 million were recognized related to
the sales of liquids assets, including processing plants and
Enron's interest in the Enron Liquids Pipeline L.P. Gains of $90
million related to the disposition of non-strategic natural gas
gathering facilities were recognized in 1996, and gains of $67
million were recorded from the sale of gathering assets and a
processing facility in 1995. In 1996, reported IBIT included $18
million as a result of favorable resolution of litigation.
Regulatory and contingency adjustments totaling $83 million were
recorded in 1995.
Portland General. Results for Portland General have been
included in Enron's Consolidated Financial Statements beginning
July 1, 1997. Since that date, Portland General realized IBIT of
$114 million, as follows:
<TABLE>
<CAPTION>
(In Millions) 1997
<S> <C>
Revenues $746
Purchased power and fuel 389
Operating expenses 154
Depreciation and amortization 91
Other income, net 2
Reported income before interest and taxes $114
</TABLE>
Statistics for PGE for the period from July 1 through December
31, 1997 and 1996 (including amounts for 1996 for comparative
purposes only) are as follows:
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
Electricity Sales (Thousand MWh)(a)
Residential 3,379 3,421
Commercial 3,618 3,450
Industrial 2,166 2,020
Total Retail 9,163 8,891
Wholesale 15,041 5,949
Total Electricity Sales 24,204 14,840
Resource Mix
Coal 10% 15%
Combustion Turbine 5 11
Hydro 5 8
Total Generation 20 34
Firm Purchases 74 55
Secondary Purchases 6 11
Total Resources 100% 100%
Average Variable Power Cost (Mills/KWh)(b)
Generation 8.7 7.7
Firm Purchases 18.9 16.5
Secondary Purchases 13.2 12.3
Total Average Variable Power Cost 16.5 13.1
Retail Customers (end of period, thousands) 685 668
<FN>
(a) Thousand megawatt-hours.
(b) Mills (1/10 cent) per kilowatt-hour.
</TABLE>
Outlook
Transportation and Distribution should continue to provide
stable earnings and cash flows during 1998, including steady
growth over 1997 levels.
Various expansion projects underway or proposed by Gas
Pipeline Group should contribute future earnings when completed.
Over the next three years, Northern is planning expansions which
would add 300-400 million cubic feet of gas per day (MMcf/d) of
incremental capacity. Transwestern plans to expand its pipeline
capacity and access new gas supplies by approximately 200-300
MMcf/d. Florida Gas also plans to expand its capacity by 150
MMcf/d to serve its growing markets by the year 2000.
Additionally, Gas Pipeline Group will continue to monitor its
overall cost structure.
PGE anticipates continuing retail customer growth in one of
the fastest growing service territories in the U.S. In late
1997, PGE filed a Customer Choice Plan proposal with the Oregon
Public Utility Commission (OPUC) which would give all of its
customers a choice of electricity providers as early as December
1998. Under the proposed Customer Choice Plan, PGE will separate
its generation business from its transmission and distribution
businesses and PGE will become a regulated transmission and
distribution company focused on delivering, but not selling,
electricity. The separation of the generation business is
proposed to be accomplished by selling PGE's generating assets,
either to an Enron affiliate or third parties. In preparation
for electric deregulation, PGE has begun to leverage from the
operational experiences of Enron's Gas Pipeline Group which has
previously transitioned from providing merchant services to
providing transportation services.
Enron is unable to predict what changes may be required by the
OPUC for approval or when the OPUC will approve a Customer Choice
Plan.
Wholesale Energy Operations and Services
Enron's Wholesale Energy Operations and Services businesses
are conducted primarily by Enron Capital & Trade Resources (ECT)
and Enron International (EI). These businesses provide
integrated energy-related products and services to wholesale
customers worldwide, including the development, construction and
operation of power plants, natural gas pipelines and other energy
related assets, energy commodity sales and services, risk
management products and financial services. This segment also
includes results of Enron Engineering & Construction (EE&C),
Enron Global Power and Pipelines L.L.C. (EPP) and Enron Americas,
Inc. Enron acquired the minority interest in EPP in November
1997 (see Note 2 to the Consolidated Financial Statements).
Wholesale Energy Operations and Services (Wholesale) can be
categorized into four business lines: Asset Development and
Construction, Cash and Physical, Risk Management and Finance and
Investing. The following table reflects IBIT for each business
line:
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Asset Development and Construction $ 77 $ 60 $ 37
Cash and Physical 310 324 206
Risk Management 143 105 193
Finance and Investing 284 122 103
Unallocated expenses (160) (145) (138)
Reported income before interest,
minority interests and taxes $654 $466 $401
</TABLE>
The following discussion analyzes the contributions to IBIT
and the outlook for each of the business lines.
Asset Development and Construction. This line of business
includes the development and construction of power plants,
pipelines and other energy infrastructure, including the results
of EE&C.
At December 31, 1997, the following projects were under
construction:
Estimated
Commercial
Size/Capacity Operations Date
Pipeline
Bolivia/Brazil (Phase I) 1,180 miles 1Q 1999
Power Plants
Cuiaba - Brazil (Phase I) 150 MW(a) 3Q 1998
Dabhol - India (Phase I) 826 MW 4Q 1998
Piti - Guam 80 MW 1Q 1999
Sutton Bridge - U.K. 790 MW 1Q 1999
Trakya - Turkey 478 MW 1Q 1999
EcoElectrica - Puerto Rico 507 MW 4Q 1999
Nowa Sarzyna - Poland 116 MW 4Q 1999
Sarlux - Italy 551 MW 1Q 2000
(a) Megawatts.
Earnings from the asset development and construction
business increased 28% in 1997 from 1996, primarily as a result
of fees earned on projects in the U.K. and Puerto Rico in 1997.
The earnings from this business increased 62% in 1996 compared
with 1995 primarily due to increased earnings on capital employed
related to development projects.
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 Enron's
contract portfolio and earnings related to the operating assets
of this segment, including EPP operations. Also included are the
effects of actual settlements of long-term physical and notional
quantity-based contracts.
Wholesale markets and transports a substantial quantity of
energy commodities as reflected in the following table (including
intercompany amounts):
<TABLE>
<CAPTION>
1997 1996 1995
<C> <C> <C> <C>
Physical Volumes (BBtue/d)(a)(b)
Gas:
United States 7,654 6,998 6,405
Canada 2,263 1,406 803
Europe 660 289 -
10,577 8,693 7,208
Transport Volumes 460 544 580
Total Gas Volumes 11,037 9,237 7,788
Oil 690 320 439
Liquids 987 1,187 526
Total Physical Volumes 12,714 10,744 8,753
Electricity Volumes Marketed
(Thousand MWh) 192,323 60,150 7,767
Financial Settlements (Notional)
(BBtue/d) 49,069 35,259 32,938
<FN>
(a) Billion British thermal units equivalent per day.
(b) Includes third-party transactions by Enron Energy Services.
</TABLE>
The cash and physical business includes Enron's interest in
the following operating assets:
Acquisition/
Size/Capacity Operations Date
Pipelines
Houston Pipe Line - U.S. 5,243 mi/2.5 Bcf/d 2Q 1985
Transportadora de Gas del Sur -
Argentina 4,104 mi/1.9 Bcf/d 4Q 1992
Louisiana Resources - U.S. 540 mi/750 MMcf/d 2Q 1993
Centragas - Colombia 357 mi/110 MMcf/d 1Q 1996
Transredes - Bolivia 3,093 mi/320 MMcf/d(a) 2Q 1997
Power Plants
Puerto Quetzel - Guatemala 110 MW 1Q 1993
Teesside - U.K. 1,875 MW 1Q 1993
Batangas - Philippines 110 MW 3Q 1993
Bitterfeld - Germany 125 MW 4Q 1993
Subic Bay - Philippines 116 MW 1Q 1994
Puerto Plata - Dominican Republic 185 MW 3Q 1994,
1Q 1996
Hainan Island - China 154 MW 3Q 1996
Local Distribution Companies
CEG - Brazil N/A 3Q 1997
Riogas - Brazil N/A 3Q 1997
GasPart - Brazil N/A 4Q 1997
(a) Capacity also includes 35 MB/d of liquids.
The earnings from cash and physical operations decreased 4%
in 1997 as compared to 1996 primarily due to lower domestic gas
and power margins in 1997 compared with 1996. Although volumes
were higher in 1997, greater seasonal volatility of domestic
natural gas prices provided higher margins in 1996. Domestic
liquids marketing activity was also lower in 1997 compared with
1996. These decreases were partially offset by increased activity
in the European markets related to natural gas and power
contracts. Increased earnings from the operation of
international power plants and pipelines and domestic natural gas
assets also contributed to the results.
The earnings from this business increased 57% in 1996 as
compared to 1995 primarily due to earnings from higher natural
gas volumes and margins and increased earnings from the
management of Wholesale's commodity portfolio. 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 Enron continued to expand its role as
an electricity marketer.
Risk Management. Wholesale's risk management operations
consist of market origination activity on new long-term contracts
(transactions greater than one year) and restructuring of
existing long-term contracts, including development activity
related to such contracts.
Earnings from risk management increased 36% in 1997 as
compared to 1996 primarily due to strong originations and related
activities with utilities and independent power producers (IPPs)
in the European market. This increase was partially offset by
lower originations from long-term contracts in North America for
both natural gas and power.
Earnings from this business decreased 46% in 1996 as compared
to 1995 primarily due to lower originations from long-term
contracts with domestic utilities and 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.
Finance and Investing. The finance and investing operations
provide a variety of capital products to its worldwide customers,
including volumetric production payments, loans and equity
investments. These products are offered directly or through
joint ventures. Financings arranged and production payments were
$561 million, $755 million and $382 million in 1997, 1996 and
1995, respectively.
Additionally, the finance and investing business includes the
management of Wholesale's capital investments, both operating and
financial, as well as certain of Enron's equity investments.
Accordingly, the results of this business include earnings from
changes in the composition and market value of these investments.
Market value changes result from both underlying operating
strengths and favorable conditions in the equity markets.
Exposures related to these investments are managed through
certain hedging transactions as well as through the overall
diversity of the investments.
Earnings from the finance and investing operations increased
133% in 1997 compared with 1996 due primarily to a significant
increase in the market value of its investments, including the
positive impact of a change in the structure of a joint venture
investment, as well as increased earnings from originations.
Earnings from the finance and investing operations increased
18% in 1996 compared to 1995 primarily due to increases in the
market value of its investments.
Unallocated Expenses. Net unallocated expenses such as rent,
systems expenses and other support group costs increased in both
1997 and 1996 due to continued expansion into new markets and
system upgrades.
Outlook
Enron anticipates continued growth in Wholesale during 1998.
Asset development and construction earnings are expected to
increase as a result of Enron's extensive portfolio of projects
in various stages of development. In the cash and physical
business, volumes are expected to continue to increase. In
addition, the existence of a 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. Earnings from risk management are expected to increase
as Enron continues to pursue opportunities in the European
marketplace and continues to increase integration of financial
products and its energy commodity portfolio worldwide. In the
finance and investing business, Enron will continue to expand its
products and services in its role as a full-service provider of
various types of capital. Further expansion into new products
and international markets is expected to increase results in all
of these businesses.
Earnings from Wholesale are dependent on the completion of
transactions, some of which are individually significant, which
are impacted by market conditions, the regulatory environment and
customer relations. Wholesale's transactions have historically
been based on a diverse product portfolio, providing a solid base
of earnings. The outlook for potential future transactions is
currently very favorable. Enron's strengths, including its
ability to identify and respond to customer needs, access to
extensive physical assets and its integrated approach to
international business, are expected to result in continued
earnings growth. In addition, earnings are expected from
Wholesale's commodity portfolio and investments, which are
subject to market fluctuations; risk related to these activities
is managed using hedge transactions. See "Financial Risk
Management" for a discussion of market risk related to Wholesale.
Retail Energy Services
Enron Energy Services (EES) was formed in late 1996 to provide
direct energy sales and services to end-use customers in the U.S.
natural gas and electricity markets, particularly in the
commercial and light industrial sectors. EES has participated
successfully in selected natural gas and electric retail
marketing pilots and continues to make significant progress in
expanding its customer base and contracting activities. EES
reported losses before interest, minority interests and taxes of
$107 million in 1997 related to significant investments in
building its sales force, developing products and services,
establishing a support system to service its contracts and
supporting EES's regulatory efforts.
In late 1997, Enron sold approximately 7% of its ownership of
EES for $130 million, to defray startup costs and establish a
valuation for this new business. The transaction resulted in a
gain of $61 million, which has been reflected in Corporate and
Other. This sale of EES ownership was based on a total
enterprise value of $1.9 billion.
Outlook
During 1998, EES will continue its focus on commercial and
light industrial customers in the energy market, while developing
new energy products and expanding its customer base. EES also
plans to continue its efforts to improve the regulatory
environment for retail gas and electricity, both on state and
federal levels, strengthen its marketing and sales organization
and continue to enhance its transaction support capabilities.
EES expects that 1998 losses will approximate those incurred in
1997.
Corporate and Other
Corporate and Other includes results of Enron Renewable Energy
Corp., EOTT Energy Corp. (EOTT) and the operations of Enron's
methanol and MTBE plants. Significant components of IBIT are as
follows:
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
IBIT before items impacting comparability $ (31) $ (22) $ (35)
Gain on sale of 7% of EES shares 61 - -
Items impacting comparability:
Charge to reflect impact of amended
J-Block gas contract (675) - -
Charge to reflect depressed MTBE
margins on committed production (100) - (75)
Gains on sales of Enron Oil & Gas
Company stock - 178 367
Reserve for qualified facilities
disposition - (83) -
Charge primarily related to conversion of
compensation plan - - (74)
Miscellaneous reserves and other items - (25) (19)
Reported income before interest and taxes $(745) $ 48 $ 164
</TABLE>
During 1997, Enron recorded a non-recurring charge of $675
million, primarily reflecting the impact of Enron's amended J-
Block gas contract in the U.K. (see Note 14 to the Consolidated
Financial Statements), and a $100 million charge primarily to
reflect depressed MTBE margins on committed production. In 1996
and 1995, respectively, gains of $178 million and $367 million
were recognized, primarily related to the sale of 12 million and
31 million outstanding shares of EOG stock held by Enron. The
1996 results included an $83 million reserve related to the
required disposition of certain assets in connection with the
merger with Portland General. The 1995 results included a $75
million charge to reflect depressed MTBE margins on committed
production and $74 million of charges primarily related to the
conversion of a compensation plan to more closely align
employees' interests to Enron common stock.
Enron continues to assess and modify its computer systems to
ensure they will operate properly in the year 2000. Enron
management anticipates that these Year 2000 costs, which will be
incurred over the next two years, will not have a material impact
on Enron's financial position or results of operations.
Interest and Related Charges, net
Interest and related charges, net, is reported net of interest
capitalized of $18 million, $12 million and $10 million for 1997,
1996 and 1995, respectively. The net expense increased $127
million in 1997 after decreasing $10 million in 1996. The 1997
increase was primarily due to higher debt levels, including debt
of $1.1 billion from PGE following the merger on July 1, 1997
(see Note 2 to the Consolidated Financial Statements). The 1996
decrease was primarily due to lower average interest rates
combined with lower average debt balances.
Dividends on Company-Obligated Preferred Securities of Subsidiaries
Dividends on company-obligated preferred securities of
subsidiaries increased from $32 million in 1995 to $34 million in
1996 and $69 million in 1997, primarily due to the issuance of
$215 million and $372 million of additional preferred securities
by Enron subsidiaries during 1996 and 1997, respectively.
Company-obligated preferred securities of subsidiaries also
increased by $29 million at July 1, 1997 for securities of PGE.
See Notes 2 and 9 to the Consolidated Financial Statements.
Minority Interests
Minority interests increased $31 million to $75 million in
1996 compared to 1995, primarily due to the reduction of Enron's
interest in EOG following the sales in 1996 and December 1995 of
an aggregate 43 million shares of EOG common stock held by Enron.
Income Tax Expense
Income tax expense decreased for 1997 as compared to 1996
primarily as a result of pretax losses due to the non-recurring
charges for the restructuring of Enron's J-Block contract and for
depressed MTBE margins on committed production. In addition, the
1997 tax provision was reduced for differences between the book
and tax basis of certain asset and stock sales. Income tax
expense decreased in 1996 compared with 1995 as a result of
benefits from the reduction of the deferred tax liability due to
the reevaluation of federal and state deferred tax requirements.
FINANCIAL CONDITION
<TABLE>
Cash Flows
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Cash provided by (used in):
Operating activities $ 501 $ 1,040 $(15)
Investing activiti es (2,436) (1,230) 13
Financing activities 1,849 331 (15)
</TABLE>
Net cash provided by operating activities decreased $539
million in 1997 primarily as a result of a cash payment of $440
million made in connection with the resolution of the J-Block gas
contract. 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 under Enron's
receivables sales program at year-end 1996 as compared to 1995.
Net cash used in investing activities in 1997 primarily
reflects increased capital expenditures, which total $1,413
million. See "Capital Expenditures and Equity Investments"
below. Equity investments of $944 million in 1997 primarily
include investments in international power and pipeline projects.
Partially offsetting these uses of cash were proceeds of $473
million from the sales of assets, primarily from the sales of
liquids assets. Net cash used in investing activities in 1996
reflects equity investments of $761 million and capital
expenditures of $878 million. Equity investments in 1996
primarily include investments in international power and pipeline
projects, EOTT and Joint Energy Development Investments, L.P.
(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.
Cash provided by financing activities in 1997 was generated
from net issuances of $1,674 million of short- and long-term
debt, $372 million of preferred securities by subsidiary
companies and $555 million of subsidiary equity (see Note 7 to
the Consolidated Financial Statements). These inflows were
partially offset by payments of $354 million for cash dividends
and $422 million for the purchase of treasury stock. Primary
cash inflows from financing activities during 1996 included $282
million from the net issuance of short- and long-term debt, $215
million from the issuance of preferred securities by subsidiary
companies and $102 million from the issuance of Enron common
stock. Cash outflows included cash dividend payments of $281
million.
Working Capital
At December 31, 1997, Enron had working capital of $257
million. If a working capital deficit should occur, Enron has
credit facilities in place to fund working capital requirements.
At December 31, 1997, those credit lines provided for up to $3.7
billion of committed and uncommitted credit, of which $35 million
was outstanding at December 31, 1997. 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 and Equity Investments
Capital expenditures by operating segment are as follows:
<TABLE>
<CAPTION>
1998
(In Millions) Estimate 1997 1996 1995
<S> <C> <C> <C> <C>
Exploration and Production(a) $ 660 $ 626 $540 $464
Transportation and Distribution 480 337 175 127
Wholesale Energy Operations
and Services 220 339 150 152
Retail Energy Services 70 36 - -
Corporate and Other 70 75 13 34
Total $1,500 $1,413 $878 $777
<FN>
(a) Excludes exploration expenses of $75 million (estimate),
$75 million, $68 million and $55 million for 1998, 1997, 1996
and 1995, respectively.
</TABLE>
Capital expenditures increased $535 million during 1997 as
compared to 1996. Increased expenditures in Exploration and
Production reflect increased development expenditures in the
United States and increased property acquisitions in Canada.
Transportation and Distribution expenditures increased due to
expansion projects by the interstate natural gas pipelines.
Included in 1997 in Wholesale were send-or-pay payments totaling
$167 million related to a transportation agreement in the United
Kingdom.
Equity investments by the operating segments are as follows:
<TABLE>
<CAPTION>
1998
(In Millions) Estimate 1997 1996 1995
<S> <C> <C> <C> <C>
Exploration and Production $ - $ - $ - $ -
Transportation and Distribution 10 3 - -
Wholesale Energy Operations
and Services 440 824 653 143
Retail Energy Services - - - -
Corporate and Other 350 117 108 27
Total $800 $944 $761 $170
</TABLE>
Equity investments increased $183 million in 1997 compared
with 1996 primarily due to investments by Wholesale in Brazilian
gas distribution companies.
The level of spending for capital expenditures and equity
investments will vary depending upon conditions in the energy
markets, related economic conditions and identified
opportunities. Management expects that the capital spending
program will be funded by a combination of internally generated
funds, proceeds from dispositions of selected assets and short-
and long-term borrowings.
FINANCIAL RISK MANAGEMENT
Wholesale offers price risk management services primarily
related to commodities associated with the energy sector (natural
gas, crude oil, natural gas liquids and electricity). These
services are provided through a variety of financial instruments
including forward contracts, which may involve physical delivery
of an energy commodity, swap agreements, which may 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. Interest
rate risks and foreign currency risks associated with the fair
value of its energy commodities portfolio are managed in this
segment using a variety of financial instruments, including
financial futures, swaps and options.
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.
Management of the market risks associated with its portfolio
of transactions is critical to the success of Enron. Therefore,
comprehensive risk management processes, policies and procedures
have been established to monitor and control these market risks.
Enron manages market risk on a portfolio basis, subject to
parameters established by its Board of Directors. Market risks
are monitored by an independent 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. Enron's fixed price commodity contract
portfolio is typically balanced to within an annual average of 1%
of the total notional physical and financial transaction volumes
marketed.
Enron measures the market risk in its portfolios on a daily
basis utilizing value at risk and other methodologies. The
quantification of market risk using value at risk provides a
consistent measure of risk across diverse energy markets and
products. The use of these methodologies requires a number of key
assumptions including the selection of a confidence level for
expected losses, the holding period for liquidation and the
treatment of risks outside the value at risk methodologies,
including liquidity risk and event risk. Value at risk
represents an estimate of reasonably possible net losses in
earnings that would be recognized on its portfolios assuming
hypothetical movements in future market rates and is not
necessarily indicative of actual results which may occur.
In addition to using value at risk measures, Enron performs
regular scenario analyses to estimate the economic impact of a
sudden market movement on the value of its portfolios (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.
Market Risk
The use of financial instruments by Enron's businesses may
expose Enron to market and credit risks resulting from adverse
changes in commodity and equity prices, interest rates and
foreign exchange rates. For Enron's price risk management
portfolio, the major market risks are discussed below:
Commodity Price Risk. Commodity price risk is a consequence
of providing price risk management services to customers as well
as owning and operating production facilities. As discussed
above, Enron actively manages this risk on a portfolio basis to
ensure compliance with Enron's stated risk management policies.
Forwards, futures, swaps and options are utilized to alter
Enron's consolidated exposure to price fluctuations related to
production from its production facilities.
Interest Rate Risk. Interest rate risk is also a consequence
of providing price risk management services to customers and
having variable rate debt obligations, as changing interest rates
impact the discounted value of future cash flows. Enron utilizes
swaps, forwards, futures and options to minimize its interest
rate risk.
Foreign Currency Exchange Rate Risk. Foreign currency exchange
rate risk is the result of Enron's international operations and
price risk management services provided to its worldwide customer
base. The primary purpose of Enron's foreign currency hedging
activities is to protect against the volatility associated with
foreign currency purchase and sale transactions. Enron primarily
utilizes forward exchange contracts, futures and purchased
options to reduce Enron's risk profile.
Equity Risk. Equity risk arises from the finance and investing
operations of Wholesale, which provides capital to customers
through equity participations in various investment activities.
Enron manages this risk on an overall basis, including the use of
futures, forwards, swaps and options, to ensure compliance with
Enron's stated risk management policies.
Accounting Policies
Accounting policies for price risk management and hedging
activities are described in Note 1 to the Consolidated Financial
Statements.
Value at Risk
Enron has performed an entity-wide value at risk analysis of
virtually all of Enron's financial assets and liabilities. The
value at risk for commodity, interest rate and foreign currency
exposures described above is calculated using a "Monte Carlo"
simulation of delta/gamma positions which captures a significant
portion of the exposure related to option positions. The value
at risk for equity exposure discussed above is based on J.P.
Morgan's RiskMetrics(TM) approach utilizing historical estimates of
volatility and correlation. Both value at risk methods utilize a
one-day holding period and a 95% confidence level. Cross-
commodity correlations are used as appropriate.
The following table illustrates the value at risk for each
component of market risk at December 31, 1997:
<TABLE>
<CAPTION>
(In Millions) Wholesale Non-Trading
<S> <C> <C>
Market Risk
Commodity price $25 $9(a)
Interest rate - -
Foreign currency exchange rate 1 1
Equity 4 -
<FN>
(a) Includes only the risk related to the financial
instruments that serve as hedges and does not include the
related underlying hedged production.
</TABLE>
CAPITALIZATION
Total capitalization at December 31, 1997 was $14.0 billion.
Debt as a percentage of total capitalization increased to 44.6%
at December 31, 1997 as compared to 39.8% at December 31, 1996.
The increase primarily reflects increased debt, partially offset
by the issuance during 1997 of approximately 50.5 million and
11.5 million shares of common stock in connection with the
acquisitions of Portland General Corporation and the minority
interest in EPP, respectively (see Note 2 to the Consolidated
Financial Statements). Assuming the 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 43.5% at December 31, 1997.
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
ability to penetrate new retail natural gas and electricity
markets in the United States and Europe, 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. (an Oregon corporation) and subsidiaries as of
December 31, 1997 and 1996, and the related consolidated
statements of income, cash flows and changes in shareholders'
equity for each of the three years in the period ended December
31, 1997. 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, 1997 and 1996,
and the results of their operations, cash flows and changes in
shareholders' equity for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted
accounting principles.
Arthur Andersen LLP
Houston, Texas
February 23, 1998
<PAGE>
<TABLE>
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENT
<CAPTION>
(In Millions, Year Ended December 31,
except Per Share Amounts) 1997 1996 1995
<S> <C> <C> <C>
Revenues
Natural gas and other products $13,211 $11,157 $7,529
Electricity 5,101 980 179
Transportation 652 707 692
Other 1,309 445 789
Total Revenues 20,273 13,289 9,189
Costs and Expenses
Cost of gas, electricity and
other products 17,311 10,478 6,733
Operating expenses 1,406 1,421 1,218
Oil and gas exploration expenses 102 89 79
Depreciation, depletion and
amortization 600 474 432
Taxes, other than income taxes 164 137 109
Contract restructuring charge 675 - -
Total Costs and Expenses 20,258 12,599 8,571
Operating Income 15 690 618
Other Income and Deductions
Equity in earnings of
unconsolidated subsidiaries 216 215 86
Gains on sales of assets and
investments 186 274 467
Other income, net 148 59 (6)
Income Before Interest, Minority
Interests and Income Taxes 565 1,238 1,165
Interest and Related Charges, net 401 274 284
Dividends on Company-Obligated
Preferred Securities of Subsidiaries 69 34 32
Minority Interests 80 75 44
Income Tax Expense (Benefit) (90) 271 285
Net Income 105 584 520
Preferred Stock Dividends 17 16 16
Earnings on Common Stock $ 88 $ 568 $ 504
Earnings Per Share of Common Stock
Basic $ 0.32 $ 2.31 $ 2.07
Diluted $ 0.32 $ 2.16 $ 1.94
Average Number of Common Shares
Used in Computation
Basic 272 246 244
Diluted 277 270 268
<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) 1997 1996
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 170 $ 256
Trade receivables (net of allowance
for doubtful accounts of $11 and
$6, respectively) 1,697 1,841
Other receivables 454 414
Assets from price risk management
activities 1,577 841
Other 771 627
Total Current Assets 4,669 3,979
Investments and Other Assets
Investments in and advances to
unconsolidated subsidiaries 2,656 1,701
Assets from price risk management
activities 1,352 1,632
Goodwill 1,910 87
Other 3,665 1,626
Total Investments and Other Assets 9,583 5,046
Property, Plant and Equipment, at cost
Exploration and Production, successful
efforts accounting 4,291 3,753
Transportation and Distribution 5,279 3,494
Wholesale Energy Operations and
Services 3,879 3,967
Retail Energy Services 44 -
Corporate and Other 249 134
13,742 11,348
Less accumulated depreciation,
depletion and amortization 4,572 4,236
Property, Plant and Equipment, net 9,170 7,112
Total Assets $23,422 $16,137
<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) 1997 1996
<S> <C> <C>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 2,119 $ 2,035
Liabilities from price risk
management activities 1,476 1,029
Other 817 644
Total Current Liabilities 4,412 3,708
Long-Term Debt 6,254 3,349
Deferred Credits and Other Liabilities
Deferred income taxes 2,039 2,290
Liabilities from price risk
management activities 1,190 980
Other 1,769 740
Total Deferred Credits and
Other Liabilities 4,998 4,010
Commitments and Contingencies
(Notes 3, 13, 14 and 15)
Minority Interests 1,147 755
Company-Obligated Preferred Securities
of Subsidiaries 993 592
Shareholders' Equity
Second preferred stock, cumulative, no par
value and $1 par value, respectively,
1,370,000 shares and 5,000,000 shares
authorized, 1,337,645 shares and 1,370,714
shares of Cumulative Second Preferred
Convertible Stock issued, respectively 134 137
Common stock, no par value and $0.10 par
value, respectively, 600,000,000 shares
authorized, 318,297,276 shares and
255,945,304 shares issued, respectively 4,224 26
Additional paid-in capital - 1,870
Retained earnings 1,852 2,007
Cumulative foreign currency translation
adjustment (148) (127)
Common stock held in treasury, 7,050,965
shares and 821,155 shares, respectively (269) (30)
Other (including Flexible Equity Trust) (175) (160)
Total Shareholders' Equity 5,618 3,723
Total Liabilities and Shareholders' Equity $23,422 $16,137
<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) 1997 1996 1995
<S> <C> <C> <C>
Cash Flows From Operating Activities
Reconciliation of net income to net
cash provided by (used in) operating
activities
Net income $ 105 $ 584 $ 520
Depreciation, depletion and
amortization 600 474 432
Oil and gas exploration expenses 102 89 79
Deferred income taxes (174) 207 216
Gains on sales of assets and investments (195) (274) (530)
Changes in components of working
capital (65) 142 (834)
Net assets from price risk management
activities 201 15 (98)
Amortization of production payment
transaction (43) (43) (43)
Other, net (30) (154) 243
Net Cash Provided by (Used in) Operating
Activities 501 1,040 (15)
Cash Flows From Investing Activities
Proceeds from sales of investments and
other assets 473 477 996
Capital expenditures (1,413) (878) (777)
Equity investments (944) (761) (170)
Business acquisitions, net of cash acquired
(see Note 2) (82) - -
Other, net (470) (68) (36)
Net Cash Provided by (Used in)
Investing Activities (2,436) (1,230) 13
Cash Flows From Financing Activities
Net increase (decrease) in
short-term borrowings 464 217 (250)
Issuance of long-term debt 1,817 359 967
Repayment of long-term debt (607) (294) (448)
Issuance of company-obligated preferred
securities of subsidiaries 372 215 -
Issuance of common stock - 102 20
Issuance of subsidiary equity 555 - -
Dividends paid (354) (281) (254)
Net (acquisition) disposition of
treasury stock (422) 5 (64)
Other, net 24 8 14
Net Cash Provided by (Used in)
Financing Activities 1,849 331 (15)
Increase (Decrease) in Cash and Cash
Equivalents (86) 141 (17)
Cash and Cash Equivalents, Beginning
of Year 256 115 132
Cash and Cash Equivalents, End of Year $ 170 $ 256 $ 115
Changes in Components of Working Capital
Receivables $ 26 $ (678) $(639)
Payables (41) 870 126
Other (50) (50) (321)
Total $ (65) $ 142 $(834)
<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
<CAPTION>
(In Millions, except Per Share 1997 1996 1995
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 1,371 $ 137 1,375 $ 138 1,405 $ 141
Exchange of common stock
for convertible preferred stock (33) (3) (4) (1) (30) (3)
Balance, end of year 1,338 $ 134 1,371 $ 137 1,375 $ 138
Common Stock
Balance, beginning of year 255,945 $ 26 253,860 $ 25 253,070 $ 25
Exchange of common stock
for convertible preferred stock 382 - 19 - 219 -
Issuances related to benefit
and dividend reinvestment plans - (3) - - 197 -
Sales of common stock - - 2,066 1 374 -
Issuances of common stock in business
acquisitions (see Note 2) 61,970 2,281 - - - -
Issuance of no par stock in
reincorporation merger (see
Note 2) - 1,881 - - - -
Other - 39 - - - -
Balance, end of year 318,297 $4,224 255,945 $ 26 253,860 $ 25
Additional Paid-in Capital
Balance, beginning of year $1,870 $1,791 $1,788
Exchange of common stock
for convertible preferred stock 1 (1) (3)
Issuances related to benefit
and dividend reinvestment plans (9) (16) (5)
Sales of common stock 18 109 15
Issuance of no par stock in
reincorporation merger (see
Note 2) (1,881) - -
Other 1 (13) (4)
Balance, end of year $ - $1,870 $1,791
Retained Earnings
Balance, beginning of year $2,007 $1,651 $1,351
Net income 105 584 520
Cash dividends
Common stock ($0.9125, $0.8625 and
$0.8125 per share in 1997,
1996 and 1995, respectively) (243) (212) (204)
Preferred stock ($12.4584, $11.7750,
and $11.0922 per share in 1997,
1996 and 1995, respectively) (17) (16) (16)
Balance, end of year $1,852 $2,007 $1,651
Cumulative Foreign Currency
Translation Adjustment
Balance, beginning of year $ (127) $ (153) $ (159)
Translation adjustments (21) 26 6
Balance, end of year $ (148) $ (127) $ (153)
Treasury Stock
Balance, beginning of year (821) $ (30) (2,618) $ (93) (1,395) $ (41)
Shares acquired (9,790) (374) (2,226) (85) (3,496) (118)
Exchange of common stock
for convertible preferred stock 70 3 46 2 183 5
Issuances related to benefit
and dividend reinvestment plans 2,838 106 2,249 81 2,090 61
Sales of treasury stock - - 1,728 65 - -
Issuances of treasury stock in
business acquisitions (see Note 2) 652 26 - - - -
Balance, end of year (7,051) $ (269) (821) $ (30) (2,618) $ (93)
Other
Balance, beginning of year $ (160) $ (194) $ (225)
Issuances related to benefit
and dividend reinvestment plans (15) 34 30
Other - - 1
Balance, end of year $ (175) $ (160) $ (194)
Total Shareholders' Equity $5,618 $3,723 $3,165
<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.
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.
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.
Depreciation, Depletion and Amortization. The provision for
depreciation and amortization with respect to operations other
than oil and gas producing activities is computed using the
straight-line or regulatorily mandated method, based on estimated
economic lives. Composite depreciation rates are applied to
functional groups of property having similar economic
characteristics. The cost of utility property units retired,
other than land, is charged to accumulated depreciation.
Provisions for depreciation, depletion and amortization of
proved oil and gas properties are calculated using the units-of-
production method.
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. In accordance with Statement of Financial
Accounting Standards (SFAS) No. 128 - "Earnings per Share," basic
earnings per share is computed based upon the weighted-average
number of common shares outstanding during the periods. Diluted
earnings per share is computed based upon the weighted-average
number of common shares plus the assumed issuance of common
shares for all potentially dilutive securities. 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 for additional
information and a reconciliation of the basic and diluted
earnings per share computations.
Accounting for Price Risk Management. Enron engages in price
risk management activities for both trading and non-trading
purposes. Financial instruments utilized in connection with
trading activities are accounted for using the mark-to-market
method. Under the mark-to-market method of 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." 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. Prepaid transportation costs
are included in "Other Assets" in the Consolidated Balance Sheet.
Financial instruments are also utilized for non-trading
purposes to hedge the impact of market fluctuations on assets,
liabilities, production and other contractual commitments. Hedge
accounting is utilized in non-trading activities when there is a
high degree of correlation between price movements in the
derivative and the item designated as being hedged. In instances
where the anticipated correlation of price movements does not
occur, hedge accounting is terminated and future changes in the
value of the financial instruments are recognized as gains or
losses. If the hedged item is sold, the value of the financial
instrument is recognized in income. Gains and losses on
financial instruments used for hedging purposes are recognized in
the Consolidated Income Statement in the same manner as the
hedged item and are recognized in the Consolidated Balance Sheet
as "Other Assets" or "Other Liabilities".
The cash flow impact of financial instruments is reflected as
cash flows from operating activities in the Consolidated
Statement of Cash Flows. 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. All
development wells and related production equipment and lease
acquisition costs are capitalized when incurred. Unproved
properties are assessed regularly and any impairment in value is
recognized as appropriate. Lease rentals and exploration costs,
other than the costs of drilling exploratory wells, are expensed
as incurred. Unsuccessful exploratory wells are expensed when
determined to be non-productive.
Gains and losses associated with the sale of natural gas and
crude oil reserves in place with related assets are classified as
"Other Revenues" in the Consolidated Income Statement.
Accounting for Development Activity. Enron capitalizes
project development costs which may be recovered through
development cost reimbursements from joint venture partners or
other third parties, written off against development fees
received or included as part of an investment in those ventures
in which Enron continues to participate. Accumulated project
development costs are otherwise expensed in the period that
management determines it is probable that the costs will not be
recovered.
Development revenue results from development fees, recognized
when realizable under the development agreement; long-term
construction contracts, recognized using the percentage-of-
completion method; and the operation and ownership of various
projects. 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.
Investments in Unconsolidated Subsidiaries. Investments in
unconsolidated subsidiaries are accounted for by the equity
method, except for certain equity investments resulting from
Enron's merchant banking activities which are included at market
value in "Other Investments" in the Consolidated Balance Sheet.
The valuation methodologies utilize market values of publicly-
traded securities, independent appraisals and cash flow analyses.
Reclassifications. Certain reclassifications have been made
to the consolidated financial statements for prior years to
conform with the current presentation.
2 BUSINESS ACQUISITIONS
Effective July 1, 1997, Enron merged with Portland General
Corporation (PGC) in a stock-for-stock transaction. PGC, through
its wholly-owned subsidiary Portland General Electric Company
(PGE), serves retail electric customers in northwest Oregon as
well as wholesale electricity customers throughout the western
United States. Enron issued approximately 50.5 million common
shares, valued at $36.88 per share, to shareholders of PGC in a
ratio of 0.9825 share of Enron common stock for each share of PGC
common stock and assumed PGC's outstanding debt of approximately
$1.1 billion. In connection with the merger, Enron
reincorporated in Oregon and reissued its capital stock without
par value.
On November 18, 1997, Enron acquired the minority interest in
Enron Global Power & Pipelines L.L.C. (EPP) in a stock-for-stock
transaction. Enron issued approximately 11.5 million common
shares, valued at $36.09 per share, to shareholders of EPP in a
ratio of 0.9189 share of Enron common stock for each EPP share
held. Additionally, during 1997, Enron acquired renewable
energy, telecommunications and energy management businesses for
cash, Enron and subsidiary stock and notes.
Enron has accounted for these acquisitions using the purchase
method of accounting as of the effective date of each
transaction. Accordingly, the purchase price of each transaction
has been allocated to the assets and liabilities acquired based
upon the estimated fair value of those assets and liabilities as
of the acquisition date. The excess of the aggregate purchase
price over estimated fair value of the net assets acquired,
approximately $1.8 billion, has been reflected as goodwill in the
Consolidated Financial Statements and is being amortized on a
straight-line basis over 30 to 40 years. Assets acquired,
liabilities assumed and consideration paid as a result of
businesses acquired were as follows:
<TABLE>
<CAPTION>
(In Millions)
<S> <C>
Fair value of assets acquired, other than cash $ 3,829
Goodwill 1,847
Fair value of liabilities assumed (3,235)
Common stock of Enron and subsidiary issued (2,359)
Net cash paid $ 82
</TABLE>
The allocation of purchase price related to the determination
of reserves for certain contractual and legal contingencies for
the PGC merger is preliminary pending completion of Enron's final
studies and evaluations. Enron does not anticipate that the
final evaluation of these issues will materially affect the
allocation of the purchase price.
The following summary presents unaudited pro forma
consolidated results of operations as if the business
acquisitions had occurred at the beginning of each period
presented. The pro forma results are for illustrative purposes
only and are not necessarily indicative of the operating results
that would have occurred had the business acquisitions been
consummated at that date, nor are they necessarily indicative of
future operating results.
<TABLE>
<CAPTION>
(In Millions, except Per Share Amounts) 1997 1996
<S> <C> <C>
Revenues $20,950 $14,401
Income before interest, minority
interests and income taxes 716 1,511
Net income 181 691
Earnings per share
Basic $ 0.53 $ 2.20
Diluted 0.52 2.08
</TABLE>
3 PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Trading Activities. Enron, through its Wholesale Energy
Operations and Services segment (Wholesale), offers price risk
management services to the energy sector through a variety of
financial and other 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. Interest rate risks and foreign
currency risks associated with the fair value of the energy
commodities portfolio are managed using a variety of financial
instruments, including financial futures.
Notional Amounts and Terms. The notional amounts and terms of
these financial instruments at December 31, 1997 are shown 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 4,515 3,927 26
Crude oil and liquids 3,405 3,169 9
Electricity 1,456 2,637 22
Financial products
Interest rate(a) $4,094 $7,174 25
Foreign currency 3,006 1,950 18
Equity investments 972 487 4
<FN>
(a) The interest rate fixed price receiver includes the net
notional dollar value of the interest rate sensitive component
of the combined commodity portfolio. The remaining interest
rate fixed price receiver and the entire interest rate fixed
price payor represent 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.
</TABLE>
Wholesale includes sales and purchase commitments associated
with contracts based on market prices totaling 3,725 TBtue, with
terms extending up to 18 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 Enron'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 Enron's fixed
price portfolio as of December 31, 1997 was approximately 2.7
years.
Fair Value. The fair value of the financial instruments
related to price risk management activities as of December 31,
1997, 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>
Average Fair Value
Fair Value for the Year Ended
as of 12/31/97 12/31/97(a)
(In Millions) Assets Liabilities Assets Liabilities
<S> <C> <C> <C> <C>
Natural gas $2,173 $1,655 $2,196 $1,538
Crude oil and liquids 337 395 323 431
Electricity 641 560 578 423
Equity 60 56 62 72
Total $3,211 $2,666 $3,159 $2,464
<FN>
(a) Computed using the ending balance at each month end.
</TABLE>
The net gain arising from price risk management activities for
1997 was $360 million.
Credit Risk. In conjunction with the valuation of its
financial instruments, Enron provides reserves for risks
associated with such activity, including 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. Enron 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.
The counterparties associated with assets from price risk
management activities as of December 31, 1997 and 1996 are
summarized as follows:
<TABLE>
<CAPTION>
1997 1996
Investment Investment
(In Millions) Grade(a) Total Grade(a) Total
<S> <C> <C> <C> <C>
Independent power producers $ 353 $ 529 $ 358 $ 461
Oil and gas producers 351 529 422 791
Energy marketers 403 585 466 598
Gas and electric utilities 747 815 495 524
Financial institutions 483 486 191 191
Industrials 76 128 35 48
Other 137 139 108 109
Total $2,550 3,211 $2,075 2,722
Credit and other reserves (282) (249)
Assets from price risk
management activities(b) $2,929 $2,473
<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) One and two customers' exposures at December 31, 1997 and
1996, 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 Enron'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. Based on Enron's
policies, its exposures and its credit and other reserves, 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 swaps and other contracts primarily for the purpose of
hedging the impact of market fluctuations on assets, liabilities,
production or other contractual commitments.
Interest Rate Swaps. At December 31, 1997, Enron had entered
into interest rate swap agreements with a notional principal
amount of $2.8 billion to manage interest rate exposure. Swap
agreements relating to notional amounts of $1.0 billion and $1.8
billion are scheduled to terminate in 1998 and thereafter,
respectively.
Energy Commodity Price Swaps. At December 31, 1997, Enron was
a party to energy commodity price swaps covering 141 TBtu, 4 TBtu
and 42 TBtu of natural gas for the years 1998, 1999 and the
period 2000 through 2005, respectively, and 2 million and 1
million barrels of crude oil for the years 1998 and 1999,
respectively.
Credit Risk. While notional amounts are used to express the
volume of various financial instruments, the amounts potentially
subject to credit risk, in the event of nonperformance by the
third parties, are substantially smaller. Counterparties to
forwards, futures and other contracts are equivalent to
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.
Enron has 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 its
portfolio of receivables is well diversified and that such
diversification minimizes any potential credit risk. Receivables
are generally not collateralized.
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, 1997 and
1996 were as follows:
<TABLE>
<CAPTION>
1997 1996
Carrying Estimated Carrying Estimated
(In Millions) Amount Fair Value Amount Fair Value
<S> <C> <C> <C> <C>
Long-term debt (Note 6) $6,254 $6,501 $3,349 $3,508
Company-obligated preferred
securities of subsidiaries
(Note 9) 993 1,024 592 607
Interest rate swaps - 13 - (11)
Energy commodity price swaps - (31) - (64)
</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 securities 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 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.
The fair market value of cash and cash equivalents, trade and
other receivables, accounts payable, equity investments accounted
for at fair value and equity swaps 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) 1997 1996 1995
<S> <C> <C> <C>
United States $96 $551 $622
Foreign (81) 304 183
$15 $855 $805
</TABLE>
Total income tax expense (benefit) is summarized as follows:
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Payable currently -
Federal $ 29 $ 16 $ 29
State 9 11 26
Foreign 46 37 14
84 64 69
Payment deferred -
Federal (39) 174 158
State (42) (1) 30
Foreign (93) 34 28
(174) 207 216
Total income tax expense (benefit) $ (90) $271 $285
</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>
(In Millions, except Percentages) 1997 1996 1995
<C> <C> <C> <C> <C>
Statutory federal income tax provision $ 5 35.0% 35.0% 35.0%
Net state income taxes (21) (140.0) 0.8 4.5
Tight gas sands tax credit (12) (80.0) (1.8) (2.8)
Equity earnings (38) (253.3) (3.3) (3.8)
Minority interest 28 186.7 3.1 1.9
Asset and stock sale differences (79) (526.7) 1.8 2.1
Cash value in life insurance (7) (46.7) (3.2) -
Goodwill amortization 9 60.0 - -
Other 25 166.7 (0.7) (1.4)
$(90) (598.3)% 31.7% 35.5%
</TABLE>
The principal components of Enron's net deferred income tax
liability are as follows:
<TABLE>
<CAPTION>
December 31,
(In Millions) 1997 1996
<S> <C> <C>
Deferred income tax assets -
Alternative minimum tax credit
carryforward $ 247 $ 235
Net operating loss carryforward 361 78
Other 218 65
826 378
Deferred income tax liabilities -
Depreciation, depletion and
amortization 2,036 1,622
Price risk management activities 457 536
Other 588 638
3,081 2,796
Net deferred income tax liabilities(a) $2,255 $2,418
<FN>
(a) Includes $216 million and $128 million in other current
liabilities for 1997 and 1996, respectively.
</TABLE>
Enron has an alternative minimum tax (AMT) credit carryforward
of approximately $247 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 $745 million which will
begin to expire in 2011. Enron has a net operating loss
carryforward applicable to non-U.S. subsidiaries of approximately
$300 million that can be carried forward indefinitely. The
benefits of these net operating losses have been recognized as a
deferred tax asset.
U.S. and foreign income taxes have been provided for earnings
of foreign subsidiary companies that are expected to be remitted
to the U.S. Foreign subsidiaries' cumulative undistributed
earnings of approximately $300 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) 1997 1996 1995
<S> <C> <C> <C>
Income taxes (net of refunds) $ 68 $ 89 $ 13
Interest (net of amounts capitalized) 420 290 296
</TABLE>
During 1997, Enron issued common stock in connection with
business acquisitions. See Note 2.
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 $1.5 billion in long-term
committed credit and $1.4 billion in short-term committed credit.
Expiration dates of the committed facilities range from May 1998
to June 2002. 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 1997, $25 million was
outstanding under these facilities.
Enron has also entered into agreements which provide for
uncommitted lines of credit totaling $817 million at December 31,
1997. 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,
1997, $10 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, 1997 and 1996, short-term borrowings of $825 million and $298
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, 1997 and
1996, $462 million and $175 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, 1997 and 1996 were 6.0% and 7.0%, respectively.
Detailed information on long-term debt is as follows:
<TABLE>
<CAPTION>
December 31,
(In Millions) 1997 1996
<S> <C> <C>
Enron Corp.
Debentures
6.75% to 8.25% due 2005 to 2012 $ 350 $ 350
Notes payable
6.25% - exchangeable notes due 1998 228 228
6.45% to 10.00% due 1998 to 2023 2,492 1,542
Floating rate notes due 1999 to 2037 350 -
Other 67 4
Northern Natural Gas Company
Notes payable
6.875% to 8.00% due 1999 to 2005 350 350
Transwestern Pipeline Company
Notes payable
7.55% to 9.20% due 1998 to 2004 150 150
Portland General Electric Company
First mortgage bonds
5.65% to 9.46% due 1998 to 2023 564 -
Pollution control bonds
Variable rate due 2010 to 2031 192 -
Other 172 -
Enron Oil & Gas Company
Notes payable
Floating rate notes due 1998 to 2001 120 190
5.44% to 9.10% due 1998 to 2007 390 210
Enron Europe Limited
Other 37 41
Amount reclassified from short-term debt 825 298
Unamortized debt discount and premium (33) (14)
Total long-term debt $6,254 $3,349
</TABLE>
The indenture securing PGE's First Mortgage Bonds constitutes
a direct first mortgage lien on substantially all electric
utility property and franchises, other than expressly excepted
property.
The Enron 6.25% Exchangeable Notes are mandatorily
exchangeable in December 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 with shares of EOG common stock.
The aggregate annual maturities of long-term debt outstanding
at December 31, 1997 were $462 million, $508 million, $161
million, $664 million and $180 million for 1998 through 2002,
respectively.
7 MINORITY INTEREST
Enron's minority interest primarily includes EOG and EPP prior
to Enron's acquisition of the EPP minority interest in November
1997 (see Note 2).
Also in 1997, Enron and a third-party investor contributed
approximately $579 million and $500 million, respectively, for
interests in an Enron-controlled joint venture. The joint
venture purchased 250,000 shares of junior convertible preferred
stock from Enron and made demand loans to Enron. Each share of
junior convertible preferred stock has a cumulative, market-based
dividend, is convertible at the option of the holder (currently
the Enron-controlled joint venture) initially into 100 shares of
Enron stock, subject to certain adjustments, and has a
liquidation value of $4,000 per share, subject to certain
adjustments. The joint venture is a separate legal entity from
Enron and has separate assets and liabilities. Absent certain
defaults or other specified events, Enron has the option to
acquire the investor's interest in the joint venture. If Enron
does not acquire the investor's interest before December 2002, or
earlier upon certain specified events, the joint venture will
liquidate its assets and dissolve. The joint venture is included
in Enron's consolidated financial statements and the third-party
investor's investment in the joint venture is included in
minority interest.
8 UNCONSOLIDATED SUBSIDIARIES
Enron's investment in and advances to unconsolidated
subsidiaries which are accounted for by the equity method is as
follows:
<TABLE>
<CAPTION>
Ownership December 31,
(In Millions) Interest 1997 1996
<S> <C> <C> <C>
Citrus Corp.(a) 50% $ 432 $ 405
Compania Estadual de Gas do Rio de
Janeiro, S.A.(b) 25% 194 -
EOTT Energy Partners, L.P. (EOTT)(c) 49% 143 130
Joint Energy Development Investments
L.P. (JEDI)(b)(d) 50% 392 320
Teesside Power Limited(b) 50%(e) 151 106
Transportadora de Gas del Sur S.A.(b) 35% 472 188
Transredes Transporte de
Hidrocarburos S.A.(b) 25% 137 -
Other 735 552
$2,656 $1,701
<FN>
(a) Included in the Transportation and Distribution segment.
(b) Included in the Wholesale Energy Operations and Services
segment.
(c) Included in the Corporate and Other segment.
(d) JEDI accounts for its investments at fair value.
(e) Net of minority interests, the ownership is 31%.
</TABLE>
Enron's equity in earnings (losses) of unconsolidated
subsidiaries is as follows:
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Citrus Corp. $ 27 $ 22 $ 27
Compania Estadual de Gas do Rio de
Janeiro, S.A. 1 - -
EOTT Energy Partners, L.P. (2) 9 (23)
Joint Energy Development Investments L.P. 68 71 4
Teesside Power Limited 20 29 18
Transportadora de Gas del Sur S.A. 45 29 22
Transredes Transporte de Hidrocarburos S.A. 5 - -
Other 52 55 38
$216 $215 $ 86
</TABLE>
Summarized combined financial information of Enron's
unconsolidated subsidiaries is presented below:
<TABLE>
<CAPTION>
December 31,
(In Millions) 1997 1996
<S> <C> <C>
Balance sheet
Current assets $2,481 $2,587
Property, plant and equipment, net 8,851 8,064
Other noncurrent assets 1,356 902
Current liabilities 1,855 2,381
Long-term debt 5,234 5,230
Other noncurrent liabilities 1,295 1,139
Owners' equity 4,304 2,803
</TABLE>
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Income statement
Operating revenues $11,183 $11,676 $8,258
Operating expenses 10,246 10,567 7,335
Net income 336 464 226
Distributions paid to Enron 68 84 68
</TABLE>
9 PREFERRED STOCK
Preferred Stock. Following Enron's reincorporation in Oregon
on July 1, 1997, Enron has authorized 16,500,000 shares of
preferred stock, no par value. At December 31, 1997, Enron had
outstanding 1,337,645 shares of Cumulative Second Preferred
Convertible Stock (the Convertible Preferred Stock), no 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 1997,
1996 and 1995, 33,069 shares, 4,780 shares and 29,489 shares,
respectively, of the Convertible Preferred Stock were converted
into common stock.
Company-Obligated Preferred Securities of Subsidiaries. Summar
ized information for Enron's Company-Obligated Preferred
Securities of Subsidiaries is as follows:
<TABLE>
<CAPTION>
Liquidation
(In Millions, except December 31, Value
Per Share Amounts and Shares) 1997 1996 Per Share
<C> <C> <C> <C>
Enron Capital LLC
8% Cumulative Guaranteed Monthly Income
Preferred Shares (MIPS)
(8,550,000 shares)(a) $214 $214 $ 25
Enron Capital Trust I
8.3% Trust Originated Preferred Securities
(8,000,000 preferred securities)(a) 200 200 25
Enron Capital Trust II
8 1/8% Trust Originated Preferred Securities
(6,000,000 preferred securities)(a) 150 - 25
Enron Capital Trust III
Adjustable-Rate Capital Trust Securities
(200,000 preferred securities)(b) 200 - 1,000
Enron Equity Corp.
8.57% Preferred Stock (880 shares)(a) 88 88 100,000
7.39% Preferred Stock (150 shares)(a)(c) 15 15 100,000
Enron Capital Resources, L.P.
9% Cumulative Preferred Securities, Series A
(3,000,000 preferred securities)(a) 75 75 25
Other 51 -
$993 $592
<FN>
(a) Redeemable under certain circumstances after specified
dates.
(b) Mature in 2046.
(c) Mandatorily redeemable in 2006.
</TABLE>
10 COMMON STOCK
Earnings Per Share. The computation of basic and diluted
earnings per share is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In Millions, except per share amounts) 1997 1996 1995
<S> <C> <C> <C>
Numerator:
Net income $ 105 $ 584 $ 520
Preferred stock dividends (17) (16) (16)
Numerator for basic earnings per
share - income available to common
shareholders 88 568 504
Effect of dilutive securities:
Preferred stock dividends(a) - 16 16
Numerator for diluted earnings per
share - income available to common
shareholders after assumed conversions $ 88 $ 584 $ 520
Denominator:
Denominator for basic earnings per
share - weighted-average shares 272 246 244
Effect of dilutive securities:
Preferred stock (a) - 19 19
Stock options 5 5 5
Dilutive potential common shares 5 24 24
Denominator for diluted earnings per
share - adjusted weighted-average
shares and assumed conversions 277 270 268
Basic earnings per share $0.32 $2.31 $2.07
Diluted earnings per share $0.32 $2.16 $1.94
<FN>
(a) For 1997, the dividends and conversion of preferred stock
have been excluded from the computation because it is
antidilutive.
</TABLE>
Forward Contracts and Options. At December 31, 1997, Enron
had forward contracts to purchase 6.7 million shares of Enron
Corp. common stock at an average price of $42.00 per share.
Enron may settle the forward contracts in cash or an equivalent
value of Enron common stock until April 2001. Shares potentially
deliverable to the counterparty under the contracts are assumed
to be outstanding in calculating diluted earnings per share.
In 1997, Enron granted options to EOG to purchase 3.2 million
shares of Enron common stock (exercise price of $39.1875) in
connection with certain agreements between Enron and EOG. The
options vested 25% immediately with 15% vesting in 1998 and the
remainder vesting equally in 1999 through 2004.
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, no
compensation expense has been recognized for the fixed stock
option plans. Compensation expense charged against income for
the restricted stock plan for 1997, 1996 and 1995 was $14
million, $4 million and $2 million, respectively. 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 SFAS No. 123 -
"Accounting for Stock-Based Compensation," Enron's net income and
earnings per share would have been $66 million ($0.18 per share
basic, $0.18 per share diluted) in 1997, $562 million ($2.22 per
share basic, $2.07 per share diluted) in 1996 and $514 million
($2.05 per share basic, $1.92 per share 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.
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 1997, 1996 and 1995,
respectively: (i) dividend yield of 2.5%, 2.3% and 2.4%; (ii)
expected volatility of 17.4%, 23.8% and 24.3%; (iii) risk-free
interest rates of 5.9%, 5.9% and 6.4%; and (iv) expected lives of
3.7 years, 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>
1997 1996 1995
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 25,476 $32.69 22,493 $29.02 24,246 $27.38
Granted(a) 17,658 38.63 7,370 39.71 2,971 34.27
Exercised (2,165) 41.06 (3,615) 24.41 (3,137) 20.91
Forfeited (1,514) 35.25 (749) 31.66 (1,586) 29.89
Expired (26) 34.59 (23) 30.65 (1) 23.42
Outstanding,
end of year 39,429 $35.77 25,476 $32.69 22,493 $29.02
Exercisable,
end of year 21,252 $33.55 12,883 $30.65 9,599 $26.11
Available for grant,
end of year(b) 13,047 6,505 7,831
Weighted average
fair value of
options granted $7.10 $9.44 $7.86
<FN>
(a) Includes 1,768,074 shares issued in connection with business
acquisitions discussed in Note 2.
(b) Includes up to 12,246,040 shares, 5,232,218 shares and
5,209,620 shares as of December 31, 1997, 1996 and 1995,
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, 1997 (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 12/31/97 Life Price at 12/31/97 Price
<C> <C> <C> <C> <C> <C>
$ 9.13 to $29.75 5,421 5 years $24.17 5,044 $23.86
30.13 to 34.75 10,143 6 years 31.56 5,798 31.67
35.38 to 39.88 11,397 8 years 37.59 5,239 37.86
40.00 to 45.00 12,468 7 years 42.55 5,171 42.79
$ 9.13 to $45.00 39,429 7 years $35.77 21,252 $33.55
</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) 1997 1996 1995
<S> <C> <C> <C>
Outstanding, beginning of year 825 159 194
Granted 2,088 1,772 45
Issued (321) (1,062) (70)
Forfeited or expired (55) (44) (10)
Outstanding, end of year 2,537 825 159
Available for grant, end of year 12,246 5,232 5,210
Weighted average fair value of
restricted stock granted $38.26 $37.04 $31.36
</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. During 1997, 1996 and 1995, respectively, 258,658
shares, 2,233,867 shares and 1,049,403 shares were released to
fund employee benefits.
11 RETIREMENT BENEFITS PLAN AND ESOP
Enron maintains a retirement plan (the Enron Plan) which is a
noncontributory defined benefit plan covering substantially all
employees in the United States and certain employees in foreign
countries. The benefit accrual is in the form of a cash balance
of 5% of annual base pay beginning January 1, 1996. Prior to
1996, the benefit formula was based on final average pay and
years of service.
Portland General has a noncontributory defined benefit pension
plan (the Portland General Plan) covering substantially all of
its employees. Benefits under the Plan are based on years of
service, final average pay and covered compensation.
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, 1997 and 1996, 13,508,794
shares and 15,976,195 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) 1997 1996 1995
<S> <C> <C> <C>
Service cost - benefits earned
during the year $ 22 $14 $ 1
Interest cost on projected
benefit obligation 32 23 21
Actual return on plan assets (84) (34) (32)
Amortization and deferrals 42 9 9
Pension expense (income) $ 12 $ 12 $ (1)
</TABLE>
The measurement date of the Enron Plan and the ESOP is
September 30, and the measurement date of the Portland General
Plan is December 31. The funded status as of the valuation date
of the Enron Plan, the Portland General 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) 1997 1996
<S> <C> <C>
Actuarial present value of
accumulated benefit obligation
Vested $(552) $(301)
Nonvested (20) (4)
Additional amounts related
to projected wage increases (45) (5)
Projected benefit obligation (617) (310)
Plan assets at fair value(a) 727 315
Plan assets in excess of
projected benefit obligation 110 5
Unrecognized net loss 34 46
Unrecognized prior service cost 35 36
Unrecognized net asset at transition (24) (30)
Contributions - 1
Prepaid pension cost at December 31 $ 155 $ 58
Discount rate 7.25% 7.5%
Long-term rate of return on assets (b) 10.5%
Rate of increase in wages (c) 4.0%
<FN>
(a) Includes plan assets of the ESOP of $135 million and $137
million for the years 1997 and 1996, respectively.
(b) Long-term rate of return on assets is assumed to be 10.5%
for the Enron Plan and 9.0% for the Portland General Plan.
(c) Rate of increase in wages is assumed to be 4.0% for the
Enron Plan and 4.0% to 9.5% for the Portland General Plan.
</TABLE>
Assets of the Enron Plan and the Portland General 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 plans
which are expected to be recoverable through rates by its
regulated pipelines and electric utility operations.
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) 1997 1996
<S> <C> <C>
Actuarial present value of accumulated
postretirement benefit obligation (APBO)
Retirees $(121) $(126)
Fully eligible active plan
participants (5) (2)
Other employees (22) (16)
Total APBO (148) (144)
Plan assets at fair value 54 15
APBO in excess of plan assets (94) (129)
Unrecognized transition obligation 62 66
Unrecognized prior service costs 22 20
Unrecognized net loss 6 33
Accrued postretirement benefit obligation $ (4) $ (10)
Discount rate 7.25% 7.5%
Long-term rate of return on assets,
before taxes (a) 7.5%
Health care cost trend rate (b) 11.0%
<FN>
(a) Long-term rate of return on assets, before taxes, is
assumed to be 7.5% for the Enron assets and 9.5% for the
Portland General assets.
(b) Health care cost trend rate is assumed to be 8.0% for
Enron and 7.5% for Portland General. These rates are assumed
to decrease to 5.0% by 2003.
</TABLE>
The components of net periodic postretirement benefit expense
are as follows:
<TABLE>
<CAPTION>
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Service costs $ 2 $ 1 $ 1
Interest costs 10 10 9
Amortization and deferrals 4 6 6
Postretirement benefit expense $16 $17 $16
</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.
Additionally, Enron maintains various incentive based
compensation plans for which participants may receive a
combination of cash, restricted stock or stock options based upon
the achievement of certain performance goals.
13 RATES AND REGULATORY ISSUES
Rates and regulatory issues related to certain of Enron's
natural gas pipelines and its electric utility operations are
subject to final determination by various regulatory agencies.
The domestic interstate pipeline operations are regulated by the
Federal Energy Regulatory Commission (FERC) and the electric
utility operations are regulated by the FERC and the Oregon
Public Utilities Commission (OPUC). As a result, these
operations are subject to the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation,"
which recognizes the economic effects of regulation and,
accordingly, Enron has recorded regulatory assets and liabilities
related to such operations.
The regulated pipelines operations' net regulatory assets at
December 31, 1997 and 1996, respectively, were $283 million and
$312 million, which included transition costs incurred related to
FERC Order 636 of $41 million and $86 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.
The electric utility operations' net regulatory assets at
December 31, 1997, were $561 million. Based on rates in place at
December 31, 1997, Enron estimates that it will collect the
majority of these regulatory assets within the next 10 years and
substantially all of these regulatory assets within the next 20
years.
Pipeline Operations. Enron's regulated pipelines have all
successfully completed their transitions under FERC Order 636.
Any future transition costs not recoverable through the
pipelines' FERC tariffs are not expected to be substantial.
Electric Utility Operations. On September 2, 1997 and
December 1, 1997, pursuant to the OPUC's condition to its
approval of the Enron/PGC merger, PGE submitted to the OPUC a
Customer Choice Plan and rate case to open its service territory
to competition. This plan will separate PGE's potentially
competitive businesses, primarily the generation of electricity,
from its regulated businesses and allow customers to choose their
energy provider. The separation of the generation business is
proposed to be accomplished by selling PGE's generating assets,
either to an Enron affiliate or third parties. Enron is unable
to predict what changes may be required by the OPUC for approval
or when the OPUC will approve a Customer Choice Plan.
PGE is a 67.5% owner of the Trojan Nuclear Plant (Trojan). In
March 1995, the OPUC issued an order authorizing PGE to recover
all of the estimated costs of decommissioning Trojan and 87% of
its remaining investment in the plant. At December 31, 1997,
PGE's regulatory asset related to recovery of Trojan costs from
customers was $488 million. Amounts are to be collected over
Trojan's original license period ending in 2011. As discussed in
Note 14, the OPUC's order and the agency's authority to grant
recovery of the Trojan investment under Oregon law are being
challenged in state courts.
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 a party to various claims and litigation, the
significant items of which are discussed below. Although no
assurances can be given, Enron believes, based on its experience
to date and after considering appropriate reserves that have been
established, that the ultimate resolution of such items,
individually or in the aggregate, will not have a materially
adverse impact on Enron's financial position or 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 claims. The
Court of Appeals has affirmed the trial court's order granting
class certification. An appeal to the Texas Supreme Court will
be pursued. 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 June 2, 1997, Enron announced the resolution of all
contractual issues involving the J-Block contract in the U.K.
North Sea with the J-Block producers, Phillips Petroleum Company
United Kingdom Limited, BG Exploration & Production Limited and
Agip (U.K.) Limited. The J-Block contracts are long-term gas
contracts that an Enron subsidiary entered into in March 1993
with the J-Block producers. As consideration for amending the
contract, Enron made a cash payment of approximately $440 million
to the producers. Enron recorded a second quarter non-recurring
contract restructuring charge of $675 million ($463 million after
tax), primarily reflecting the impact of the amended contract.
Such resolution concluded all J-Block litigation between Enron
and the J-Block producers.
On June 3, 1997, the London Commercial Court ruled in favor of
the "CATS" parties in their dispute over the availability of the
CATS (Central Area Transmission System) transportation
facilities. The CATS parties sued Teesside Gas Transportation
Limited (TGTL), an Enron subsidiary, and Enron (on the basis of
its guarantee of TGTL's obligations under the transportation
agreement between TGTL and the CATS parties) for allegedly
failing to make quarterly "send-or-pay" payments under the
transportation agreement. TGTL had refused to make these
payments based upon its position that the transportation
facilities were not available as required by the contract. The
effect of the Court's decision is that TGTL has released withheld
"send-or-pay" payments to the CATS parties in the amount of
approximately 81 million Pounds Sterling, plus interest and
costs. The judgment has no effect on the above referenced
settlement of the J-Block gas sales agreements. Enron is
appealing the decision of the London Commercial Court in the CATS
litigation. Enron believes that the ultimate resolution of this
matter will not have a materially adverse effect on its financial
position or results of operations.
On November 21, 1996, an explosion occurred in or around the
Humberto Vidal Building in San Juan, Puerto Rico. The explosion
resulted in fatalities, bodily injuries and damage to the
building and surrounding property. San Juan Gas Company, Inc.
(San Juan), an Enron subsidiary, operates a natural gas
distribution system in the vicinity. Although San Juan did not
provide gas service to the building, the investigation report of
the National Transportation Safety Board (NTSB) has tentatively
concluded that the incident was caused by gas leaking from San
Juan's distribution system. San Juan and Enron strongly disagree
with the NTSB findings principally because the NTSB investigation
(i) found no path of migration of gas from San Juan's system to
the building and (ii) discovered no scientific evidence that
propane gas was the explosive fuel. Enron and San Juan have been
named as defendants in a number a lawsuits filed in U.S. District
Court for the district of Puerto Rico and Commonwealth courts of
Puerto Rico. These suits, which seek damages for wrongful death,
personal injury, business interruption and property damage,
allege that negligence of Enron and San Juan caused the
explosion. Enron and San Juan are vigorously contesting the
claims. Although no assurances can be given, Enron believes that
the ultimate resolution of these matters will not have a material
adverse effect on its financial position or results of
operations.
Trojan Nuclear Plant. In early 1993, PGE ceased commercial
operation of Trojan. Since plant closure, PGE has committed
itself to a safe and economical transition toward a
decommissioned plant. PGE has received approval of its
decommissioning plan submitted to the Nuclear Regulatory
Commission and Oregon Energy Facilities Siting Council. PGE's
remaining cost to decommission and close Trojan of $313 million
has been reflected in "Other Liabilities" in the Consolidated
Balance Sheet.
Trojan Investment Recovery. In April 1996 a circuit court
judge in Marion County, Oregon, found that the OPUC could not
authorize PGE to collect a return on its undepreciated investment
in Trojan, contradicting a November 1994 ruling from the same
court. The ruling was the result of an appeal of PGE's 1995
general rate order which granted PGE recovery of, and a return
on, 87% of its remaining investment in Trojan.
The 1994 ruling was appealed to the Oregon Court of Appeals
and stayed pending the appeal of the Commission's March 1995
order. Both PGE and the OPUC have separately appealed the April
1996 ruling, which appeals were combined with the appeal of the
November 1994 ruling at the Oregon Court of Appeals.
Enron believes that the authorized recovery of and return on
the Trojan investment and decommissioning costs will be upheld
and that these legal challenges will not have a materially
adverse impact on its financial position or results of
operations.
Environmental Matters. Enron is subject to extensive federal,
state and local environmental laws and regulations. These laws
and regulations require expenditures in connection with the
construction of new facilities, the operation of existing
facilities and for remediation at various operating sites. The
implementation of the Clean Air Act Amendments is expected to
result in increased operating expenses. These increased
operating expenses are not expected to have a material impact on
Enron's financial position or results of operations.
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. 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 and remove impacted subsurface soils
in certain areas of the tract where the plant was formerly
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.
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, 1997, the estimated
aggregate amounts of such required future payments were $100
million, $114 million, $118 million, $122 million and $133
million for 1998 through 2002, respectively, and $942 million for
later years.
The costs recognized under firm transportation agreements,
including commodity charges on actual quantities shipped, totaled
$27 million, $25 million and $18 million in 1997, 1996 and 1995,
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 $36
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, 1997 were $142 million, $117 million, $114 million,
$63 million and $46 million for 1998 through 2002, respectively,
and $228 million for later years. Guarantees under the leases
total $1,029 million at December 31, 1997.
Total rent expense incurred during 1997, 1996 and 1995 was
$156 million, $149 million and $147 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, 1997, a total of $278 million of
such guarantees were outstanding, including $92 million on behalf
of EOTT. In addition, Enron is a guarantor on certain
liabilities of unconsolidated subsidiaries and other companies
totaling approximately $873 million, including $402 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 $486 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 1998 planned capital
expenditures and equity investments.
16 QUARTERLY FINANCIAL DATA (Unaudited)
<TABLE>
Summarized quarterly financial data is as follows:
<CAPTION>
(In Millions, Except First Second Third Fourth Total
Per Share Amounts) Quarter Quarter Quarter Quarter Year
<S> <C> <C> <C> <C> <C>
1997
Revenues $5,344 $3,251 $5,806 $5,872 $20,273
Income (loss) before
interest, minority
interests and income taxes 429 (548) 311 373 565
Net income (loss) 222 (420) 134 169 105
Earnings (loss) per share:
Basic $0.88 $(1.71) $0.44 $0.55 $0.32(a)
Diluted 0.81 (1.71) 0.42 0.53 0.32(a)
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:
Basic $0.86 $0.46 $0.48 $0.52 $2.31(a)
Diluted 0.80 0.43 0.45 0.48 2.16(a)
<FN>
(a) The sum of earnings per share for the four quarters may not
equal earnings per share for the total year due to changes in
the average number of common shares outstanding.
Additionally, certain items in the diluted earnings per share
computation were antidilutive in the second quarter and total
year 1997.
</TABLE>
17 GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION
Enron's operations are classified into the following business
segments:
Exploration and Production - Natural gas and crude oil
exploration and production primarily in the United States,
Canada, Trinidad and India.
Transportation and Distribution - Interstate transmission of
natural gas. Management and operation of pipelines. Electric
utility operations.
Wholesale Energy Operations and Services - Energy commodity
sales and services, risk management products and financial
services to wholesale customers. Development, acquisition and
operation of power plants, natural gas pipelines and other energy
related assets.
Retail Energy Services - Sale of natural gas and electricity
directly to end-use customers, particularly in the commercial and
light industrial sectors.
Corporate and Other - Includes operation of renewable energy
businesses and clean fuels plants, as well as Enron's investment
in crude oil transportation activities.
Enron's business segment information has been reclassified
from prior years to reflect the realignment of Enron's
operations. Financial information by geographic and business
segment follows for each of the three years in the period ended
December 31, 1997.
Geographic Segments
<TABLE>
<CAPTION>
Year Ended December 31,
(In Millions) 1997 1996 1995
<S> <C> <C> <C>
Operating revenues from
unaffiliated customers
United States $17,328 $11,262 $ 7,855
Foreign 2,945 2,027 1,334
$20,273 $13,289 $ 9,189
Intersegment sales
United States $ 23 $ 72 $ 24
Foreign 176 128 159
$ 199 $ 200 $ 183
Operating income (loss)
United States $ 173 $ 490 $ 487
Foreign (158) 200 131
$ 15 $ 690 $ 618
Income (loss) before interest,
minority interests and income
taxes
United States $ 601 $ 938 $ 969
Foreign (36) 300 196
$ 565 $ 1,238 $ 1,165
Identifiable assets
United States $17,003 $11,580 $10,695
Foreign 3,763 2,856 1,327
$20,766 $14,436 $12,022
</TABLE>
Business Segments
<TABLE>
<CAPTION>
Wholesale
Exploration Transportation Energy Retail Corporate
and and Operations Energy and
(In Millions) Production Distribution and Services Services Other(c) Total
<S> <C> <C> <C> <C> <C> <C>
1997
Unaffiliated revenues(a) $ 789 $1,402 $17,344 $ 683 $ 55 $20,273
Intersegment revenues(b) 108 14 678 2 (802) -
Total revenues 897 1,416 18,022 685 (747) 20,273
Depreciation, depletion and
amortization 278 160 133 7 22 600
Operating income (loss) 185 398 376 (105) (839) 15
Equity in earnings of
unconsolidated subsidiaries - 40 172 (1) 5 216
Other income, net (2) 142 106 (1) 89 334
Income (loss) before interest,
minority interests and
income taxes 183 580 654 (107) (745) 565
Capital expenditures 626 337 339 36 75 1,413
Identifiable assets 2,668 7,115 9,531 322 1,130 20,766
Investments in and advances to
unconsolidated subsidiaries - 521 1,932 - 203 2,656
Total assets $2,668 $7,636 $11,463 $ 322 $1,333 $23,422
1996
Unaffiliated revenues(a) $ 647 $ 702 $11,413 $ 513 $ 14 $13,289
Intersegment revenues(b) 177 23 491 15 (706) -
Total revenues 824 725 11,904 528 (692) 13,289
Depreciation, depletion and
amortization 251 66 138 - 19 474
Operating income (loss) 205 337 287 - (139) 690
Equity in earnings of
unconsolidated subsidiaries - 35 168 - 12 215
Other income, net (5) 152 11 - 175 333
Income before interest,
minority interests and
income taxes 200 524 466 - 48 1,238
Capital expenditures 540 175 150 - 13 878
Identifiable assets 2,371 2,363 8,879 - 823 14,436
Investments in and advances to
unconsolidated subsidiaries - 516 1,005 - 180 1,701
Total assets $2,371 $2,879 $ 9,884 $ - $1,003 $16,137
1995
Unaffiliated revenues(a) $ 481 $ 758 $ 7,531 $ 400 $ 19 $ 9,189
Intersegment revenues(b) 278 55 166 - (499) -
Total revenues 759 813 7,697 400 (480) 9,189
Depreciation, depletion and
amortization 216 82 132 - 2 432
Operating income (loss) 240 279 291 - (192) 618
Equity in earnings of
unconsolidated subsidiaries - 46 64 - (24) 86
Other income, net 1 34 46 - 380 461
Income before interest,
minority interests and
income taxes 241 359 401 - 164 1,165
Capital expenditures 464 127 152 - 34 777
Identifiable assets 2,067 2,305 6,741 - 909 12,022
Investments in and advances to
unconsolidated subsidiaries - 495 625 - 97 1,217
Total assets $2,067 $2,800 $ 7,366 $ - $1,006 $13,239
<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) Includes consolidating eliminations.
</TABLE>
18 OIL AND GAS PRODUCING ACTIVITIES (Unaudited except for
Results of Operations for Oil and Gas Producing Activities)
The following information regarding Enron's oil and gas
producing activities should be read in conjunction with Note 1.
This information includes amounts attributable to a minority
interest of 45%, 47%, 39% and 20% at December 31, 1997, 1996,
1995 and 1994, respectively.
Capitalized Costs Relating to Oil and Gas Producing Activities
<TABLE>
<CAPTION>
December 31,
(In Millions) 1997 1996
<S> <C> <C>
Proved properties $ 4,070 $ 3,593
Unproved properties 221 160
Total 4,291 3,753
Accumulated depreciation,
depletion and amortization (1,904) (1,653)
Net capitalized costs $ 2,387 $ 2,100
</TABLE>
Costs Incurred in Oil and Gas Property Acquisition, Exploration
and Development Activities(a)
<TABLE>
<CAPTION>
(In Millions) United States Foreign Total
<S> <C> <C> <C>
1997
Acquisition of properties
Unproved $ 69 $ 8 $ 77
Proved 43 38 81
Total 112 46 158
Exploration 74 27 101
Development 333 109 442
Total $519 $182 $701
1996
Acquisition of properties
Unproved $ 39 $ 6 $ 45
Proved 69 - 69
Total 108 6 114
Exploration 61 27 88
Development 283 123 406
Total $452 $156 $608
1995
Acquisition of properties
Unproved $ 16 $ 6 $ 22
Proved 123 5 128
Total 139 11 150
Exploration 48 25 73
Development 217 79 296
Total $404 $115 $519
<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, 1997:
<TABLE>
<CAPTION>
(In Millions) United States Foreign Total
<S> <C> <C> <C>
1997
Operating revenues
Associated companies $207 $ 15 $222
Trade 449 160 609
Gains on sales of
reserves and related
assets 4 5 9
Total 660 180 840
Exploration expenses,
including dry hole costs 51 24 75
Production costs 106 43 149
Impairment of unproved
oil and gas properties 24 3 27
Depreciation, depletion and
amortization 239 39 278
Income before income taxes 240 71 311
Income tax expense 69 40 109
Results of operations $171 $ 31 $202
1996
Operating revenues
Associated companies $253 $ 14 $267
Trade 282 153 435
Gains on sales of
reserves and related
assets 19 1 20
Total 554 168 722
Exploration expenses,
including dry hole costs 45 23 68
Production costs 77 42 119
Impairment of unproved
oil and gas properties 19 2 21
Depreciation, depletion and
amortization 209 42 251
Income before income taxes 204 59 263
Income tax expense 54 39 93
Results of operations $150 $ 20 $170
1995
Operating revenues
Associated companies $224 $ 7 $231
Trade 122 124 246
Gains on sales of
reserves and related
assets 63 - 63
Total 409 131 540
Exploration expenses,
including dry hole costs 35 20 55
Production costs 64 32 96
Impairment of unproved
oil and gas properties 22 2 24
Depreciation, depletion and
amortization 181 35 216
Income before income taxes 107 42 149
Income tax expense 1 29 30
Results of operations $106 $ 13 $119
<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, 1997, 1996 and 1995 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, 1997, 1996 and 1995 covering producing areas,
in the United States and Canada, containing 54%, 64% and 60%,
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 MacNaughton 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 Foreign Total
<S> <C> <C> <C>
1997
Future cash inflows(a) $ 5,187 $2,994 $ 8,181
Future production costs (1,138) (836) (1,974)
Future development costs (313) (124) (437)
Future net cash flows before
income taxes 3,736 2,034 5,770
Future income taxes (888) (810) (1,698)
Future net cash flows 2,848 1,224 4,072
Discount to present value at
10% annual rate (1,298) (473) (1,771)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 1,550(b) $ 751 $ 2,301(b)
1996
Future cash inflows(a) $ 9,391 $2,288 $11,679
Future production costs (1,640) (856) (2,496)
Future development costs (306) (10) (316)
Future net cash flows before
income taxes 7,445 1,422 8,867
Future income taxes (2,260) (572) (2,832)
Future net cash flows 5,185 850 6,035
Discount to present value at
10% annual rate (2,693) (273) (2,966)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 2,492(b) $ 577 $ 3,069(b)
1995
Future cash inflows(a) $ 3,996 $1,294 $ 5,290
Future production costs (747) (558) (1,305)
Future development costs (298) (24) (322)
Future net cash flows before
income taxes 2,951 712 3,663
Future income taxes (696) (233) (929)
Future net cash flows 2,255 479 2,734
Discount to present value at
10% annual rate (1,015) (134) (1,149)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 1,240(b) $ 345 $ 1,585(b)
<FN>
(a) Based on year-end market prices determined at the point
of delivery from the producing unit.
(b) Excludes $18 million, $75 million and $36 million at
December 31, 1997, 1996 and 1995, respectively, associated
with a volumetric production payment sold effective October 1,
1992, as amended, to be delivered over a 78 month period
beginning October 1, 1992.
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash
Flows
<TABLE>
<CAPTION>
(In Millions) United States Foreign Total
<C> <C> <C> <C>
December 31, 1994 $ 963 $281 $1,244
Sales and transfers of oil
and gas produced, net
of production costs (268) (99) (367)
Net changes in prices and
production costs 12 (35) (23)
Extensions, discoveries, additions
and improved recovery, net of
related costs 376(a) 138 514(a)
Development costs incurred 29 5 34
Revisions of estimated development
costs 1 33 34
Revisions of previous quantity
estimates 6 5 11
Accretion of discount 97 38 135
Net change in income taxes (133) (25) (158)
Purchases of reserves in place 194 - 194
Sales of reserves in place (54) (1) (55)
Changes in timing and other 17 5 22
December 31, 1995 $1,240(a) $345 $1,585(a)
Sales and transfers of oil
and gas produced, net
of production costs (437) (126) (563)
Net changes in prices and
production costs 1,817 172 1,989
Extensions, discoveries, additions
and improved recovery, net of
related costs 581 275 856
Development costs incurred 58 4 62
Revisions of estimated development
costs (14) 12 (2)
Revisions of previous quantity
estimates 7 79 86
Accretion of discount 137 47 184
Net change in income taxes (656) (191) (847)
Purchases of reserves in place 162 - 162
Sales of reserves in place (103) (3) (106)
Changes in timing and other (300) (37) (337)
December 31, 1996 $2,492(a) $577 $3,069(a)
Sales and transfers of oil
and gas produced, net
of production costs (519) (132) (651)
Net changes in prices and
production costs (1,664) (50) (1,714)
Extensions, discoveries, additions
and improved recovery, net of
related costs 374 300 674
Development costs incurred 52 2 54
Revisions of estimated development
costs 4 (28) (24)
Revisions of previous quantity
estimates (17) 26 9
Accretion of discount 328 89 417
Net change in income taxes 606 (67) 539
Purchases of reserves in place 44 53 97
Sales of reserves in place (29) - (29)
Changes in timing and other (121) (19) (140)
December 31, 1997 $1,550(a) $751 $2,301(a)
<FN>
(a) Includes approximately $86 million, $344 million and $77
million related to the reserves in the Big Piney deep
Paleozoic formations at December 31, 1997, 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 Foreign Total
<C> <C> <C> <C>
Net proved developed
reserves
Natural gas (Bcf)
December 31, 1994 1,128.2(a) 494.5 1,622.7(a)
December 31, 1995 1,218.1(a)(b) 544.0 1,762.1(a)(b)
December 31, 1996 1,325.7(a)(b) 814.3 2,140.0(a)(b)
December 31, 1997 1,349.0(a)(b) 986.3 2,335.3(a)(b)
Liquids (MBbl)(c)
December 31, 1994 16,770(a) 19,087 35,857(a)
December 31, 1995 19,977(a) 23,654 43,631(a)
December 31, 1996 24,868(a) 26,411 51,279(a)
December 31, 1997 27,707(a) 39,108 66,815(a)
Natural gas (Bcf)
Net proved reserves at
December 31, 1994 1,307.4(a) 532.1 1,839.5(a)
Revisions of previous
estimates 10.1 (19.9) (9.8)
Purchases in place 174.8 - 174.8
Extensions, discoveries
and other additions 1,391.6(b) 190.6 1,582.2(b)
Sales in place (38.1) (1.7) (39.8)
Production (191.7) (66.7) (258.4)
Net proved reserves at
December 31, 1995 2,654.1(a)(b) 634.4 3,288.5(a)(b)
Revisions of previous
estimates 3.6 76.7 80.3
Purchases in place 100.6 0.9 101.5
Extensions, discoveries
and other additions 256.8 264.5 521.3
Sales in place (58.4) (4.3) (62.7)
Production (210.2) (81.5) (291.7)
Net proved reserves at
December 31, 1996 2,746.5(a)(b) 890.7 3,637.2(a)(b)
Revisions of previous
estimates (50.8) 23.2 (27.6)
Purchases in place 60.0 67.6 127.6
Extensions, discoveries
and other additions 275.9 299.0 574.9
Sales in place (17.7) (0.4) (18.1)
Production (229.1) (84.6) (313.7)
Net proved reserves at
December 31, 1997 2,784.8 1,195.5 3,980.3
</TABLE>
<TABLE>
<CAPTION>
United States Foreign Total
<C> <C> <C> <C>
Liquids (MBbl)(c)
Net proved reserves at
December 31, 1994 17,787 19,251 37,038
Revisions of previous
estimates (413) 4,919 4,506
Purchases in place 4,264 - 4,264
Extensions, discoveries
and other additions 8,703 4,625 13,328
Sales in place (1,241) (9) (1,250)
Production (3,701) (3,789) (7,490)
Net proved reserves at
December 31, 1995 25,399 24,997 50,396
Revisions of previous
estimates 339 2,026 2,365
Purchases in place 312 2 314
Extensions, discoveries
and other additions 7,103 3,779 10,882
Sales in place (447) (121) (568)
Production (3,830) (4,272) (8,102)
Net proved reserves at
December 31, 1996 28,876 26,411 55,287
Revisions of previous
estimates 3,515 213 3,728
Purchases in place 127 1,123 1,250
Extensions, discoveries
and other additions 6,037 21,713 27,750
Sales in place (1,683) - (1,683)
Production (5,223) (3,458) (8,681)
Net proved reserves at
December 31, 1997 31,649 46,002 77,651
<FN>
(a) Excludes approximately 21 Bcf, 38 Bcf, 54 Bcf and 71 Bcf
at December 31, 1997, 1996, 1995 and 1994, respectively,
associated with a volumetric production payment sold effective
October 1, 1992, as amended, to be delivered over a 78 month
period beginning October 1, 1992.
(b) Includes 1,180 Bcf related to net proved deep Paleozoic
natural gas reserves.
(c) Includes crude oil, condensate and natural gas liquids.
</TABLE>
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated February 23, 1998
included in this Form 10-K, into Enron Corp.'s previously
filed Registration Statements 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), 33-52768 (1991 Stock Plan), 33-52143 (955,640 Shares
of Common Stock), 33-60821 (1994 Stock Plan), 333-22739
(347,793 Shares of Common Stock), 333-19253 (Stock Option
Plan for Zond Exchange Agreements), 333-42645 (Debt
Securities Warrants to Purchase Common Stock, Preferred
Stock and Depositary Shares), 333-44133 (244,283 Shares
of Common Stock) and 333-38253 (176,634 Shares of Common Stock).
ARTHUR ANDERSEN LLP
Houston, Texas
March 13, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 170
<SECURITIES> 0
<RECEIVABLES> 1,988
<ALLOWANCES> 0
<INVENTORY> 136
<CURRENT-ASSETS> 4,669
<PP&E> 13,742
<DEPRECIATION> 4,572
<TOTAL-ASSETS> 23,422
<CURRENT-LIABILITIES> 4,412
<BONDS> 6,254
0
134
<COMMON> 4,224
<OTHER-SE> 1,260
<TOTAL-LIABILITY-AND-EQUITY> 23,422
<SALES> 18,312
<TOTAL-REVENUES> 20,273
<CGS> 17,311
<TOTAL-COSTS> 20,258
<OTHER-EXPENSES> (550)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 401
<INCOME-PRETAX> 15
<INCOME-TAX> (90)
<INCOME-CONTINUING> 105
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 105
<EPS-PRIMARY> 0.32
<EPS-DILUTED> 0.32
</TABLE>
