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 18, 1999
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 71
<PAGE>
ENRON CORP. AND SUBSIDIARIES
Item 7. Financial Statements and Exhibits.
(a) Management's Discussion and Analysis of Financial
Condition and Results of Operations
(b) Financial Risk Management
(c) Financial Statements of Enron Corp. and its
Consolidated Subsidiaries for the fiscal year ended
December 31, 1998, including Report of Arthur
Andersen LLP, Independent Public Accountants
(d) Exhibit 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 18, 1999 By: RICHARD A. CAUSEY
Richard A. Causey
Senior Vice President and Chief
Accounting and Information and
Administrative Officer
<PAGE>
ENRON CORP. AND SUBSIDIARIES
TABLE OF CONTENTS
Page No.
Management's Discussion and Analysis of Financial
Condition and Results of Operations 4
Financial Risk Management 24
Information Regarding Forward Looking Statements 27
Report of Independent Public Accountants 28
Consolidated Income Statement for the years ended
December 31, 1998, 1997 and 1996 29
Consolidated Balance Sheet, December 31, 1998 and 1997 30
Consolidated Statement of Cash Flows for the years
ended December 31, 1998, 1997 and 1996 32
Consolidated Statement of Changes in Shareholders'
Equity Accounts for the years ended December 31,
1998, 1997 and 1996 33
Notes to Consolidated Financial Statements 34
Exhibits
Exhibit 23 - Consent of Arthur Andersen LLP 71
<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 1998 was $703 million compared to
$105 million in 1997 and $584 million in 1996. Enron's
operating segments include Exploration and Production (Enron
Oil & Gas Company), Transportation and Distribution (Gas
Pipeline Group and Portland General), Wholesale Energy
Operations and Services (Enron Capital & Trade Resources and
Enron International), Retail Energy Services (Enron Energy
Services) and Corporate and Other, which includes certain
new businesses. 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) 1998 1997 1996
<S> <C> <C> <C>
After-tax results before items impacting
comparability $ 698 $ 515 $ 493
Items impacting comparability:(a)
Gain on sale of 7% of Enron Energy
Services shares - 61 -
Gains on sales of Enron Oil & Gas
Company stock 45 - 90
Charge to reflect losses on
contracted MTBE production (40) (74) -
Charge to reflect impact of amended
J-Block gas contract - (463) -
Gains on sales of liquids and
gathering assets - 66 59
Reserve for qualified facilities
disposition - - (54)
Other - - (4)
Reported net income $ 703 $ 105 $ 584
<FN>
(a) Tax affected at 35%, except where a specific tax rate
applied.
</TABLE>
Diluted earnings per share of common stock were as
follows:
<TABLE>
<CAPTION>
1998 1997 1996
<S> <C> <C> <C>
Diluted earnings per share:
After-tax results before items
impacting comparability $2.01 $1.74 $1.82
Items impacting comparability:
Gain on sale of 7% of Enron
Energy Services shares - 0.21 -
Gains on sales of Enron Oil &
Gas Company stock 0.13 - 0.33
Charge to reflect losses on
contracted MTBE production (0.12) (0.25) -
Charge to reflect impact of
amended J-Block gas contract - (1.57) -
Gains on sales of liquids and
gathering assets - 0.22 0.22
Reserve for qualified facilities
disposition - - (0.20)
Other - - (0.01)
Effect of anti-dilution(a) - (0.03) -
Reported diluted earnings per share $2.02 $0.32 $2.16
<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) 1998 1997 1996
<S> <C> <C> <C>
Exploration and Production $ 128 $ 183 $ 200
Transportation and Distribution:
Gas Pipeline Group 351 466 524
Portland General 286 114 -
Wholesale Energy Operations
and Services 968 654 466
Retail Energy Services (119) (107) -
Corporate and Other (32) (745) 48
Reported income before interest,
minority interests and taxes $1,582 $ 565 $1,238
</TABLE>
Exploration and Production
Enron's exploration and production operations are
conducted by Enron Oil & Gas Company (EOG).
Wellhead volume and price statistics (including
intercompany amounts) are as follows:
<TABLE>
<CAPTION>
1998 1997 1996
<S> <C> <C> <C>
Natural gas volumes (MMcf/d)(a)
North America 776 758 706
Trinidad 139 113 124
India 56 18 -
Total 971 889 830
Average natural gas prices ($/Mcf)
North America $1.86 $2.20 $1.92
Trinidad 1.06 1.05 1.00
India 2.41 2.79 -
Composite 1.78 2.07 1.78
Crude oil/condensate volumes (MBbl/d)(a)
North America 16.6 14.2 11.6
Trinidad 3.0 3.4 5.2
India 5.1 2.3 2.8
Total 24.7 19.9 19.6
Average crude oil/condensate prices ($/Bbl)
North America $12.67 $19.33 $21.08
Trinidad 12.26 18.68 19.76
India 12.86 20.05 20.17
Composite 12.66 19.30 20.60
<FN>
(a) Million cubic feet per day or thousand barrels per day,
as applicable.
</TABLE>
The following analyzes the significant components of IBIT
for Exploration and Production:
<TABLE>
<CAPTION>
(In Millions) 1998 1997 1996
<S> <C> <C> <C>
Net revenues $769 $783 $730
Corporate hedging activities 19 (8) (4)
Operating expenses 219 210 181
Exploration expenses 121 102 89
Depreciation, depletion and amortization 315 278 251
Operating income 133 185 205
Other income, net (5) (2) (5)
Reported income before interest,
minority interests and taxes $128 $183 $200
</TABLE>
Net Revenues
Exploration and Production's revenues, net of gas sold in
connection with natural gas marketing, decreased $14 million
(2%) in 1998 after increasing $53 million (7%) in 1997. The
1998 change reflects lower average wellhead natural gas
prices and crude oil and condensate prices, partially offset
by increased production volumes of both natural gas and
crude oil and condensate. The 1997 increase reflected both
increased average wellhead natural gas prices and increased
production volumes. Other marketing activities, which
include hedging, trading and natural gas marketing
transactions by EOG, reduced net revenues by $4 million in
1998 and $61 million in 1997, compared with an increase of
$4 million in 1996. Net revenues also include gains on
sales of crude oil and gas reserves and related assets of
$26 million in 1998, $9 million in 1997 and $20 million in
1996.
Costs and Expenses
Operating expenses and depreciation, depletion and
amortization (DD&A) increased in 1998 and 1997 primarily due
to expanded operations and increased worldwide production
volumes in both years and a higher DD&A rate in North
America in 1998.
Exploration expenses increased 19% in 1998 and 15% in
1997 as compared to the prior year, primarily as a result of
increased exploratory drilling activities and expenses
related to lease acquisitions in North America.
Outlook
EOG plans to continue to focus a substantial portion of
its development and exploration expenditures in its major
producing areas in North America. In addition, EOG
anticipates additional spending for the continued
development of its projects in India, Trinidad and China.
In December 1998, Enron received an unsolicited
indication of interest from a third party with respect to
exploring a possible transaction pursuant to which the third
party would acquire Enron's shares of EOG common stock and
offer to acquire the remaining shares of outstanding EOG
common stock. There can be no assurance that any such
transaction will be consummated.
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), Enron's 50% interest in Florida Gas
Transmission Company (Florida Gas) and Enron's interest in
Northern Border Pipeline. Portland General results are
included for the period since the July 1, 1997 merger (see
Note 2 to the Consolidated Financial Statements).
Gas Pipeline Group. The following table summarizes total
volumes transported by each of Enron's interstate natural
gas pipelines.
<TABLE>
<CAPTION>
1998 1997 1996
<S> <C> <C> <C>
Total Volumes Transported (Bbtu/d)(a)
Northern Natural Gas 4,098 4,364 4,577
Transwestern Pipeline 1,608 1,416 1,341
Florida Gas Transmission 1,341 1,341 1,296
Northern Border Pipeline 1,770 1,800 1,801
<FN>
(a) Billion British thermal units per day. Amounts
reflect 100% of each entity's throughput volumes.
Florida Gas and Northern Border Pipeline are
unconsolidated affiliates.
</TABLE>
Significant components of IBIT are as follows:
<TABLE>
<CAPTION>
(In Millions) 1998 1997 1996
<S> <C> <C> <C>
Net revenues $640 $665 $719
Operating expenses 276 310 316
Depreciation and amortization 70 69 66
Equity in earnings 32 40 35
Other income, net 25 38 44
IBIT before items impacting
comparability 351 364 416
Gains on sales of liquids and
gathering assets - 102 90
Other - - 18
Reported income before interest
and taxes $351 $466 $524
</TABLE>
Net Revenues
Revenues, net of cost of sales, of Gas Pipeline Group
declined $25 million (4%) during 1998 and $54 million (8%)
during 1997 as compared to the applicable preceding year.
The decrease in net revenue in 1998 compared to 1997 was
primarily due to the warmer than normal winter in Northern's
service territory and the reduction of transition costs
recovered through a regulatory surcharge at Northern. 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.
Operating Expenses
Operating expenses of Gas Pipeline Group decreased $34
million (11%) during 1998, primarily as a result of the
reduction of transition costs at Northern and lower overhead
costs. Operating expenses declined $6 million (2%) during
1997, primarily due to a reduction of transition costs at
Northern.
Equity in Earnings
Equity in earnings of unconsolidated affiliates decreased
$8 million in 1998 after increasing $5 million during 1997
as compared to 1996. These changes were primarily due to
higher 1997 earnings from Citrus Corp. (Citrus), which holds
Enron's 50% interest in Florida Gas. Earnings from Citrus
were higher in 1997 due to a contract restructuring.
Other Income, Net
Other income, net decreased $13 million (34%) in 1998 as
compared to 1997 primarily as a result of income recognized
in 1997 related to liquids assets sold in 1997. Included in
1998 were gains of $21 million recognized from the
monetization of an interest in an equity investment,
substantially offset by charges related to litigation.
Items Impacting Comparability
Gains of $102 million were recognized in 1997 related to
the sales of liquids assets, including processing plants and
Enron's interest in Enron Liquids Pipeline L.P. During
1996, gains of $90 million related to the disposition of non-
strategic natural gas gathering facilities were recognized,
and gains of $18 million were recorded as a result of
favorable resolution of litigation.
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, as follows:
<TABLE>
<CAPTION>
(In Millions) 1998 1997(a)
<S> <C> <C>
Revenues $1,196 $746
Purchased power and fuel 451 389
Operating expenses 295 154
Depreciation and amortization 183 91
Other income, net 19 2
Reported income before interest
and taxes $ 286 $114
<FN>
(a) Represents the period from July 1, 1997 through
December 31, 1997.
</TABLE>
The 1998 results were impacted by a warmer than normal
winter and the transfer of the majority of its electricity
wholesale business to the Enron Wholesale segment, partially
offset by an increase in sales to retail customers.
Statistics for Portland General for 1998 and for the
period from July 1 through December 31, 1997 are as follows:
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Electricity Sales (Thousand MWh)(a)
Residential 7,101 3,379
Commercial 6,781 3,618
Industrial 3,562 2,166
Total Retail 17,444 9,163
Wholesale 10,869 13,448
Total Electricity Sales 28,313 22,611
Resource Mix
Coal 16% 10%
Combustion Turbine 12 5
Hydro 9 5
Total Generation 37 20
Firm Purchases 56 74
Secondary Purchases 7 6
Total Resources 100% 100%
Average Variable Power Cost (Mills/KWh)(b)
Generation 8.6 8.7
Firm Purchases 17.3 18.9
Secondary Purchases 23.6 13.2
Total Average Variable Power Cost 15.6 17.2
Retail Customers (end of period, thousands) 704 685
<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 1999,
including steady growth over 1998 levels.
Gas Pipeline Group continues to expand its pipeline
system to provide services to existing customers and new
markets. Florida Gas has an expansion planned to provide
new capacity of 270 MMcf/d into Southwest Florida by the
year 2001 and is evaluating other expansions to meet
Florida's expected strong growth in gas consumption. Future
results of Northern Border Pipeline will reflect its 700
MMcf/d extension of service to the Chicago market area. A
further expansion to Indiana through a 35-mile, 545 MMcf/d
extension of its pipeline will be placed in service in the
year 2000. Transwestern is considering expansions to bring
in additional supplies from the San Juan basin to
California.
Portland General anticipates continuing retail customer
growth in one of the fastest growing service territories in
the U.S. In late 1997, Portland General filed a Customer
Choice Plan proposal and rate case with the Oregon Public
Utility Commission (OPUC) which would open its service
territory to competition. Under the proposed Customer
Choice Plan, Portland General would separate its generation
business from its transmission and distribution businesses
and Portland General would become a regulated transmission
and distribution company focused on delivering, but not
selling, electricity. In July 1998, the OPUC staff issued
its position, disagreeing with Portland General's proposal
for full customer choice.
In January 1999, the OPUC issued an order, which is
contingent upon the adoption of certain regulatory changes
by the Oregon Legislature, with recommendations that
included allowing small retail customers a limited set of
options including the ability to continue to purchase rate-
regulated electricity, allowing most commercial and
industrial users to have the ability to choose their
electricity provider and allowing Portland General to sell
its coal- and gas-fired generation plants but rejecting
Portland General's request to sell its hydroelectric assets.
Additionally, the order requires Portland General, should it
choose to adopt OPUC's recommendations, to file a new rate
case. Portland General is reviewing the OPUC order, but
will not implement any of the recommendations until the
changes are agreed upon by all parties. The issue of
restructuring will be further addressed by the 1999 Oregon
Legislature. Portland General will support legislation that
creates a comprehensive approach to the electricity industry
that helps develop a market that is truly competitive.
Wholesale Energy Operations and Services
Enron's wholesale energy operations and services business
(Enron Wholesale) operates in North America, Europe and
other countries. Activities are conducted primarily by
Enron Capital & Trade Resources and Enron International.
Enron Wholesale is categorized into two business lines: (a)
Commodity Sales and Services and (b) Energy Assets and
Investments. Integrated energy-related products and
services related to these business lines are offered to
wholesale customers in varying degrees in each of Enron
Wholesale's markets.
Enron manages its commodity and asset portfolios in order
to maximize value, minimize the associated risks and provide
overall liquidity. In this process, Enron utilizes
portfolio and risk management disciplines including certain
hedging transactions to manage portions of its market
exposures (commodity, interest rate, foreign currency and
equity exposures). Enron Wholesale from time to time
monetizes its contract portfolios (producing cash and
transferring counterparty credit risk to third parties) and
sells interests in investments and assets.
The following table reflects IBIT for each business line:
<TABLE>
<CAPTION>
(In Millions) 1998 1997 1996
<S> <C> <C> <C>
Commodity Sales and Services $411 $249 $348
Energy Assets and Investments 709 565 263
Unallocated expenses (152) (160) (145)
Reported income before interest,
minority interests and taxes $968 $654 $466
</TABLE>
The following discussion analyzes the contributions to
IBIT for each business line.
Commodity Sales and Services. Enron Wholesale provides
reliable delivery of energy commodities at predictable
prices. The commodity sales and services operations
includes the purchase, sale, marketing and delivery of
natural gas, electricity, liquids and other commodities,
restructuring of existing long-term contracts and the
management of Enron's commodity contract portfolios. In
addition, Enron provides risk management products and
services to energy customers that hedge movements in price
and location-based price differentials. Enron's risk
management products and services are designed to provide
stability to customers in markets impacted by commodity
price volatility. Also included in this business is the
management of certain operating assets that directly relate
to this business, including domestic intrastate pipelines
and storage facilities.
Enron Wholesale markets and transports a substantial
quantity of energy commodities as reflected in the following
table (including intercompany amounts):
<TABLE>
<CAPTION>
1998 1997 1996
<S> <C> <C> <C>
Physical Volumes (BBtue/d)(a)(b)
Gas:
United States 7,418 7,654 6,998
Canada 3,486 2,263 1,406
Europe and Other 1,251 660 289
12,155 10,577 8,693
Transport Volumes 559 460 544
Total Gas Volumes 12,714 11,037 9,237
Crude Oil and Liquids 3,570 1,677 1,507
Electricity(c) 11,024 5,256 1,648
Total Physical Volumes (BBtue/d) 27,308 17,970 12,392
Electricity Volumes Marketed (Thousand MWh)
United States 401,843 191,746 60,150
Europe and Other 529 100 -
Total 402,372 191,846 60,150
Financial Settlements (Notional) (BBtue/d) 75,266 49,082 35,259
<FN>
(a) Billion British thermal units equivalent per day.
(b) Includes third-party transactions by Enron Energy
Services.
(c) Represents Electricity Volumes Marketed, converted to
BBtue/d.
</TABLE>
The earnings from commodity sales and services operations
increased 65% in 1998 as compared to 1997. The change is
primarily due to increased earnings from originations of
risk management products and services in North America,
including contract restructurings, and increased power
marketing earnings, where volumes have increased over 100%,
partially offset by fewer originations in Europe, lower
earnings related to domestic operating assets and higher
expenses.
The earnings from commodity sales and services operations
decreased 28% 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,
including originations with utilities and independent power
producers (IPPs) in 1997. Originations from long-term
contracts in North America decreased in 1997 for both
natural gas and power.
Energy Assets and Investments. Enron Wholesale's energy
assets and investments activities include investments in
debt and equity securities of oil and gas producers and
other energy-intensive companies. Additionally, Enron
Wholesale develops, constructs, operates and manages a large
portfolio of energy investments such as power plants and
natural gas pipelines. Earnings primarily result from
changes in the market value of merchant investments held
during the period, equity earnings and gains on sales or
restructurings of energy investments. See Note 4 to the
Consolidated Financial Statements for a summary of these
investments.
Earnings from energy assets and investments increased 25%
in 1998 as compared to 1997 primarily as a result of
earnings from the sale of interests in the Puerto Rico,
Turkey, Italy and U.K. power projects, from which Enron
realized the value created during the development and
construction phases, partially offset by development costs
and decreased earnings from the management of Enron
Wholesale's merchant investments. Some of these
transactions involved securitizations in which Enron
retained certain interests associated with the underlying
assets.
Earnings from energy assets and investments increased
115% 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 and earnings from the sale of interests in
U.K. power projects. Also contributing to the increase were
fees earned on projects in the U.K.
Unallocated Expenses. Net unallocated expenses include
rent, systems expenses and other support group costs.
Outlook
Enron anticipates continued growth in Enron Wholesale
during 1999 due to further expansion into new products and
markets. In the commodity sales and services business,
volumes are expected to continue to increase as Enron
maintains or increases its market share in the growing
unregulated U.S. power market and the European gas and power
markets. In addition, Enron expects to benefit from
opportunities related to its substantial portfolio of
commodity contracts. Enron also expects to continue
increased integration of financial products with its energy
commodity portfolio. In the energy assets and investments
business, Enron will continue to benefit from opportunities
related to its energy investments, including sales or
restructurings of appreciated investments, and in providing
capital to energy-intensive customers. Equity earnings from
operations are expected to increase as a result of
commencement of commercial operations of new power plants
and pipeline in early 1999 including the larger power
project in India.
At December 31, 1998, the following international
projects were under construction:
<TABLE>
<CAPTION>
Estimated
Commercial
Size/Capacity Operations Date
<S> <C> <C>
Pipeline(a)
Bolivia/Brazil (Phase I) 1,180 miles 2Q 1999
Power Plants(a)
Cuiaba - Brazil (Phase I) 150 MW(b) 1Q 1999
Dabhol - India (Phase I) 826 MW 1Q 1999
Piti - Guam 80 MW 1Q 1999
Sutton Bridge - U.K. 790 MW 1Q 1999
Trakya - Turkey 478 MW 1Q 1999
Corinto - Nicaragua 71 MW 2Q 1999
EcoElectrica - Puerto Rico 507 MW 3Q 1999
Nowa Sarzyna - Poland 116 MW 4Q 1999
Sarlux - Italy 551 MW 1Q 2000
<FN>
(a) Enron holds varying interests in these projects.
(b) Megawatts.
</TABLE>
Earnings from Enron Wholesale are dependent on the
origination and completion of transactions, some of which
are individually significant and which are impacted by
market conditions, the regulatory environment and customer
relationships. Enron Wholesale's transactions have
historically been based on a diverse product portfolio,
providing a solid base of earnings. Enron's strengths,
including its ability to identify and respond to customer
needs, access to extensive physical assets and its
integrated approach to meeting customers needs, are
important drivers of the expected continued earnings growth.
In addition, significant earnings are expected from Enron
Wholesale's commodity portfolio and investments, which are
subject to market fluctuations. External factors, such as
the amount of volatility in market prices, impact the
earnings opportunity associated with Enron Wholesale's
business. Risk related to these activities is managed using
naturally offsetting transactions and hedge transactions.
The effectiveness of Enron's risk management activities can
have a material impact on future earnings. See "Financial
Risk Management" for a discussion of market risk related to
Enron Wholesale.
Retail Energy Services
Enron Energy Services (Energy Services), formed in late
1996, is extending Enron's energy expertise to end-use
business customers. This includes sales of natural gas,
electricity and outsourcing energy management services
directly to commercial and industrial customers. Energy
Services reported losses before interest, minority interests
and taxes of $119 million in 1998 and $107 million in 1997
related to significant investments in building its sales and
service capabilities, developing products and services,
establishing a support system to service its contracts and
supporting Energy Services' regulatory efforts.
During 1998, Energy Services completed a significant
number of transactions which will provide future revenues
and margins. Energy Services revenues totaled $1.1 billion
during 1998, a 57% increase from 1997.
In late 1997, Enron sold approximately 7% of its
ownership of Energy Services for $130 million, to defray
startup costs and establish a valuation for this new
business. The transaction resulted in an after-tax gain of
$61 million, which has been reflected in Corporate and
Other. This sale of Energy Services ownership reflected a
total enterprise value of $1.9 billion. Since that time,
significant new customers and long-term contracts have been
obtained.
Outlook
During 1999, Enron anticipates continued growth in the
demand for energy outsourcing solutions. Energy Services
will focus on delivering these services to its existing
customers, while continuing to expand its commercial and
industrial customer base for total energy outsourcing.
Energy Services also plans to continue integrating its
service delivery capabilities, focusing on the development
of best practices, nation-wide procurement opportunities,
efficient use of capital and centralized decision making.
Energy Services expects reduced losses in 1999.
Corporate and Other
Corporate and Other includes results of Azurix Corp.,
which provides water and wastewater services, Enron
Communications, Inc. (ECI), which is building a national
Internet-protocol fiber-optic network to deliver high
content media to business customers, Enron Renewable Energy
Corp. (EREC), 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) 1998 1997 1996
<S> <C> <C> <C>
IBIT before items impacting comparability $ 7 $ (31) $ (22)
Items impacting comparability:
Gain on sale of 7% of Enron Energy
Services shares - 61 -
Gains on sales of Enron Oil & Gas
Company stock 22 - 178
Charge to reflect losses on contracted
MTBE production (61) (100) -
Charge to reflect impact of amended
J-Block gas contract - (675) -
Reserve for qualified facilities disposition - - (83)
Miscellaneous reserves and other items - - (25)
Reported income before interest and taxes $(32) $(745) $ 48
</TABLE>
Results in 1998 were favorably impacted by increased
earnings related to ECI from the sale of capacity on its
fiber-optic network and increases in the market value of
certain corporate-managed financial instruments, partially
offset by higher corporate expenses.
During 1998, Enron recognized a pre-tax gain of $22
million on the delivery of 10.5 million shares of EOG stock
held by Enron as repayment of mandatorily exchangeable debt.
Enron also recorded a $61 million charge to reflect losses
on contracted MTBE production.
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., and a $100 million
charge primarily to reflect losses on contracted MTBE
production. In 1996, a gain of $178 million was recognized,
primarily related to the sale of 12 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.
Interest and Related Charges, Net
Interest and related charges, net of interest
capitalized, increased $149 million in 1998 and $127 million
in 1997. The increase in 1998 as compared to 1997 was
primarily a result of higher debt levels, including the
issuance of approximately $2.1 billion in debt between
November 1997 and the end of 1998, mainly to finance capital
expenditures and investments. The 1998 interest expense
also reflects the impact of twelve months of interest
expense on debt related to the merger with Portland General.
The 1997 increase was primarily due to higher debt levels,
including debt of $1.1 billion from Portland General
following the merger on July 1, 1997 (see Note 2 to the
Consolidated Financial Statements). Interest capitalized,
which totaled $66 million, $18 million and $12 million for
1998, 1997, and 1996, respectively, increased in 1998 as a
result of the commencement of construction of several power
projects.
Dividends on Company-Obligated Preferred Securities of
Subsidiaries
Dividends on company-obligated preferred securities of
subsidiaries increased from $34 million in 1996 to $69
million in 1997 and to $77 million in 1998, 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 in 1997 for
securities of Portland General.
Minority Interests
Minority interests were $77 million in 1998 compared to
$80 million in 1997 and $75 million in 1996. Minority
interests in 1998 include EOG and the minority owner's share
of dividends on preferred stock issued in connection with
the formation of an Enron-controlled joint venture in late
1997. See Note 8 to the Consolidated Financial Statements.
Minority interests in 1997 and 1996 relate to EOG and Enron
Global Power & Pipelines, L.L.C. (EPP) until Enron's
acquisition of the EPP minority interest in November 1997.
Income Tax Expense
Income tax expense increased in 1998 as compared to 1997
primarily as a result of increased earnings, partially
offset by differences between the book and tax basis of
certain assets and stock sales.
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 losses on contracted MTBE production. In
addition, the 1997 tax provision was reduced for differences
between the book and tax basis of certain assets and stock
sales.
YEAR 2000
The Year 2000 problem results from the use in computer
hardware and software of two digits rather than four digits
to define the applicable year. The use of two digits was a
common practice for decades when computer storage and
processing was much more expensive than today. When
computer systems must process dates both before and after
January 1, 2000, two-digit year "fields" may create
processing ambiguities that can cause errors and system
failures. For example, computer programs that have date-
sensitive features may recognize a date represented by "00"
as the year 1900, instead of 2000. These errors or failures
may have limited effects, or the effects may be widespread,
depending on the computer chip, system or software, and its
location and function.
The effects of the Year 2000 problem are exacerbated
because of the interdependence of computer and
telecommunications systems in the United States and
throughout the world. This interdependence certainly is
true for Enron and Enron's suppliers, trading partners, and
customers, as well as for governments of countries around
the world where Enron does business.
State of Readiness
Enron's Board of Directors has been briefed about the
Year 2000 problems generally and as they may affect Enron.
The Board has adopted a Year 2000 plan (the "Plan") covering
all of Enron's business units. The aim of the Plan is to
take reasonable steps to prevent Enron's mission-critical
functions from being impaired due to the Year 2000 problem.
"Mission-critical" functions are those critical functions
whose loss would cause an immediate stoppage of or
significant impairment to major business areas (a major
business area is one of material importance to Enron's
business).
Implementation of Enron's Year 2000 plan is directly
supervised by a Senior Vice President who is aided by a Year
2000 Project Director. The Project Director coordinates the
implementation of the Plan among Enron's business units. As
part of the overall Plan, each business unit in turn has
developed, and is implementing, a Year 2000 plan specific to
it. Enron also has engaged outside consultants, technicians
and other external resources to aid in formulating and
implementing the Plan.
Enron is implementing the Plan, which will be modified as
events warrant. Under the Plan, Enron will continue to
inventory its mission-critical computer hardware and
software systems and embedded chips (computer chips with
date-related functions, contained in a wide variety of
devices); assess the effects of Year 2000 problems on the
mission-critical functions of Enron's business units; remedy
systems, software and embedded chips in an effort to avoid
material disruptions or other material adverse effects on
mission-critical functions, processes and systems; verify
and test the mission-critical systems to which remediation
efforts have been applied; and attempt to mitigate those
mission-critical aspects of the Year 2000 problem that are
not remediated by January 1, 2000, including the development
of contingency plans to cope with the mission-critical
consequences of Year 2000 problems that have not been
identified or remediated by that date.
The Plan recognizes that the computer,
telecommunications, and other systems ("Outside Systems") of
outside entities ("Outside Entities") have the potential for
major, mission-critical, adverse effects on the conduct of
Enron's business. Enron does not have control of these
Outside Entities or Outside Systems. (In some cases,
Outside Entities are foreign governments or businesses
located in foreign countries.) However, Enron's Plan
includes an ongoing process of identifying and contacting
Outside Entities whose systems, in Enron's judgment, have or
may have a substantial effect on Enron's ability to continue
to conduct the mission-critical aspects of its business
without disruption from Year 2000 problems. The Plan
envisions Enron attempting to inventory and assess the
extent to which these Outside Systems may not be "Year 2000
ready" or "Year 2000 compatible." Enron will attempt
reasonably to coordinate with these Outside Entities in an
ongoing effort to obtain assurance that the Outside Systems
that are mission-critical to Enron will be Year 2000
compatible well before January 1, 2000. Consequently, Enron
will work prudently with Outside Entities in a reasonable
attempt to inventory, assess, analyze, convert (where
necessary), test, and develop contingency plans for Enron's
connections to these mission-critical Outside Systems and to
ascertain the extent to which they are, or can be made to
be, Year 2000 ready and compatible with Enron's mission-
critical systems.
It is important to recognize that the processes of
inventorying, assessing, analyzing, converting (where
necessary), testing, and developing contingency plans for
mission-critical items in anticipation of the Year 2000
event are necessarily iterative processes. That is, the
steps are repeated as Enron learns more about the Year 2000
problem and its effects on Enron's internal systems and on
Outside Systems, and about the effects that embedded chips
may have on Enron's systems and Outside Systems. As the
steps are repeated, it is likely that new problems will be
identified and addressed. Enron anticipates that it will
continue with these processes through January 1, 2000 and,
if necessary based on experience, into the year 2000 in
order to assess and remediate problems that reasonably can
be identified only after the start of the new century.
As of February 15, 1999, Enron and all its business units
were at various stages in implementation of the Plan, as
shown in the following tables. The first table deals with
the Enron business units' mission-critical internal systems
(including embedded chips) and the second deals with the
business units' mission-critical Outside Systems of Outside
Entities. Any notation of "complete" conveys the fact only
that the initial iteration of this phase has been
substantially completed.
<TABLE>
Year 2000 Plan Readiness by Enron Business Unit
(Mission-Critical Internal Items)
<CAPTION>
Contingency
Inventory Assessment Analysis Conversion Testing Y2K-Ready Plan
<S> <C> <C> <C> <C> <C> <C> <C>
Exploration and
Production C IP IP IP IP IP IP
Transportation
and Distribution:
Gas Pipeline Group C C IP IP IP IP IP
Portland General C C C IP IP IP IP
Wholesale:
Domestic C C C IP IP IP IP
Europe C C C IP IP IP IP
Other International IP IP IP IP IP IP IP
Retail Energy Services C C IP IP IP IP IP
Corporate and Other IP IP IP IP IP IP IP
</TABLE>
<TABLE>
Year 2000 Plan Readiness by Enron Business Unit
(Mission-Critical Outside Entities)
<CAPTION>
Contingency
Inventory Assessment Analysis Conversion Testing Y2K-Ready Plan
<S> <C> <C> <C> <C> <C> <C> <C>
Exploration and
Production IP IP IP IP IP IP IP
Transportation
and Distribution:
Gas Pipeline Group C C IP IP IP IP IP
Portland General C C C IP IP IP IP
Wholesale:
Domestic C IP IP IP TBI IP TBI
Europe C C IP TBI TBI IP TBI
Other International IP IP IP IP IP IP IP
Retail Energy Services C C IP IP IP IP IP
Corporate and Other C IP IP IP IP IP IP
Legend: C = Complete IP = In Process TBI = To Be Initiated
</TABLE>
The following tables show, by business unit, historical and estimated
completion dates, as applicable, for the initial iteration of various stages of
the Plan. The first table deals with the Enron business units' mission-
critical internal systems (including embedded chips) and the second deals with
the business units' mission-critical Outside Systems of Outside Entities.
<TABLE>
Year 2000 Plan Completion Dates by Enron Business Unit
(Mission-Critical Internal Items)
<CAPTION>
Contingency
Inventory Assessment Analysis Conversion Testing Y2K-Ready Plan
<S> <C> <C> <C> <C> <C> <C> <C>
Exploration and
Production 12/98 3/99 3/99 6/99 9/99 9/99 9/99
Transportation
and Distribution:
Gas Pipeline Group 12/98 1/99 4/99 6/99 7/99 8/99 6/99
Portland General 12/97 10/98 10/98 6/99 6/99 6/99 6/99
Wholesale:
Domestic 6/98 8/98 12/98 6/99 6/99 6/99 9/99
Europe 7/98 8/98 8/98 4/99 4/99 7/99 7/99
Other International 3/99 3/99 4/99 6/99 7/99 8/99 6/99
Retail Energy Services 1/99 2/99 3/99 4/99 5/99 7/99 7/99
Corporate and Other 2/99 2/99 3/99 3/99 3/99 6/99 6/99
</TABLE>
<TABLE>
Year 2000 Plan Completion Dates by Enron Business Unit
(Mission-Critical Outside Entities)
<CAPTION>
Contingency
Inventory Assessment Analysis Conversion Testing Y2K-Ready Plan
<S> <C> <C> <C> <C> <C> <C> <C>
Exploration and
Production 3/99 6/99 6/99 9/99 9/99 9/99 9/99
Transportation
and Distribution:
Gas Pipeline Group 11/98 1/99 4/99 5/99 5/99 6/99 6/99
Portland General 10/98 11/98 11/98 6/99 6/99 6/99 6/99
Wholesale:
Domestic 7/98 3/99 5/99 7/99 9/99 9/99 9/99
Europe 6/98 7/98 3/99 8/99 8/99 8/99 8/99
Other International 2/99 2/99 4/99 6/99 7/99 8/99 6/99
Retail Energy Services 1/99 1/99 3/99 4/99 5/99 6/99 6/99
Corporate and Other 10/98 3/99 3/99 6/99 6/99 6/99 6/99
</TABLE>
Enron will continue to closely monitor work under the Plan and
to revise estimated completion dates for the initial iteration of
each listed process.
Costs to Address Year 2000 Issues
Under the Plan and otherwise, Enron has not incurred material
historical costs for Year 2000 awareness, inventory, assessment,
analysis, conversion, testing, or contingency planning. Further,
Enron anticipates that its future costs for these purposes,
including those for implementing its Year 2000 contingency plans,
will not be material.
Although management believes that its estimates are
reasonable, there can be no assurance, for the reasons stated in
the "Summary" section below, that the actual costs of
implementing the Plan will not differ materially from the
estimated costs or that Enron will not be materially adversely
affected by Year 2000 issues.
Year 2000 Risk Factors
Regulatory requirements. Certain of Enron's business units
operate in industries that are regulated by governmental
authorities. Enron expects to satisfy these regulatory
authorities' requirements for achieving Year 2000 readiness. If
Enron's reasonable expectations in this regard are in error, and
if a regulatory authority should order the temporary cessation of
Enron's operations in one or more of these areas, the adverse
effect on Enron could be material. Outside Entities could face
similar problems that materially adversely affect Enron.
Shortage of resources. Between now and Year 2000 there will
be increased competition for people with the technical and
managerial skills necessary to deal with the Year 2000 problem.
While Enron is taking substantial precautions to recruit and
retain sufficient people skilled in dealing with the Year 2000
problem and has hired consultants who bring additional skilled
people to deal with the Year 2000 problem as it affects Enron,
Enron could face shortages of skilled personnel or other
resources, such as Year 2000 ready computer chips, and these
shortages might delay or otherwise impair Enron's progress
towards making its mission-critical systems Year 2000 ready.
Outside Entities could face similar problems that materially
adversely affect Enron. Enron believes that the possible impact
of the shortage of skilled people is not, and will not be, unique
to Enron.
Potential shortcoming. Enron estimates that its mission-
critical systems, domestic and international, will be Year 2000-
ready substantially before January 1, 2000. However, there is no
assurance that the Plan will succeed in accomplishing its
purposes or that unforeseen circumstances will not arise during
implementation of the Plan that would materially and adversely
affect Enron.
Cascading effect. Enron and its business units are taking
reasonable steps to identify, assess, and, where appropriate,
replace devices that contain embedded chips. Despite these
reasonable efforts, Enron anticipates that it will not be able to
find and remediate all embedded chips in systems in Enron's
business units. Further, Enron anticipates that Outside Entities
on which Enron depends also will not be able to find and
remediate all embedded chips in their systems. Some of the
embedded chips that fail to operate or that produce anomalous
results may create system disruptions or failures. Some of these
disruptions or failures may spread from the systems in which they
are located to other systems in a cascade. These cascading
failures may have adverse effects upon Enron's ability to
maintain safe operations and may also have adverse effects upon
Enron's ability to serve its customers and otherwise to fulfill
certain contractual and other legal obligations. The embedded
chip problem is widely recognized as one of the more difficult
aspects of the Year 2000 problem across industries and throughout
the world. Enron believes that the possible adverse impact of
the embedded chip problem is not, and will not be, unique to
Enron.
Third parties. Enron cannot assure that suppliers upon which
it depends for essential goods and services will convert and test
their mission-critical systems and processes in a timely and
effective manner. Failure or delay to do so by all or some of
these entities, including U.S. federal, state or local
governments and foreign governments, could create substantial
disruptions having a material adverse affect on Enron's business.
Contingency Plans
As part of the Plan, Enron is developing contingency plans
that deal with two aspects of the Year 2000 problem: (1) that
Enron, despite its good-faith, reasonable efforts, may not have
satisfactorily remediated all of its internal mission-critical
systems; and (2) that Outside Systems may not be Year 2000 ready,
despite Enron's good-faith, reasonable efforts to work with
Outside Entities. Enron's contingency plans are being designed
to minimize the disruptions or other adverse effects resulting
from Year 2000 incompatibilities regarding these mission-critical
functions or systems, and to facilitate the early identification
and remediation of mission-critical Year 2000 problems that first
manifest themselves after January 1, 2000.
Enron's contingency plans will contemplate an assessment of
all its mission-critical internal information technology systems
and its internal operational systems that use computer-based
controls. This process will commence in the early minutes of
January 1, 2000, and continue for hours, days, or weeks as
circumstances require. Further, Enron will in that time frame
assess any mission-critical disruptions due to Year 2000-related
failures that are external to Enron. The assessment process will
cover, for example, loss of electrical power from utilities;
telecommunications services from carriers; or building access,
security, or elevator service in facilities occupied by Enron.
Enron's contingency plans include the creation of teams that
will be standing by on the evening of December 31, 1999, prepared
to respond rapidly and otherwise as necessary to mission-critical
Year 2000-related problems as soon as they become known. The
composition of teams that are assigned to deal with Year 2000
problems will vary according to the nature, mission-criticality,
and location of the problem. Because Enron operates
internationally, some of its Year 2000 contingency teams will be
stationed at Enron's mission-critical facilities overseas.
Worst Case Scenario
The Securities and Exchange Commission requires that public
companies forecast the most reasonably likely worst case Year
2000 scenario. Analysis of the most reasonably likely worst case
Year 2000 scenarios Enron may face leads to contemplation of the
following possibilities which, though unlikely in some or many
cases, must be included in any consideration of worst cases:
widespread failure of electrical, gas, and similar supplies by
utilities serving Enron domestically and internationally;
widespread disruption of the services of communications common
carriers domestically and internationally; similar disruption to
means and modes of transportation for Enron and its employees,
contractors, suppliers, and customers; significant disruption to
Enron's ability to gain access to, and remain working in, office
buildings and other facilities; the failure of substantial
numbers of Enron's mission-critical information (computer)
hardware and software systems, including both internal business
systems and systems (such as those with embedded chips)
controlling operational facilities such as electrical generation,
transmission, and distribution systems and oil and gas plants and
pipelines, domestically and internationally; and the failure,
domestically and internationally, of Outside Systems, the effects
of which would have a cumulative material adverse impact on
Enron's mission-critical systems. Among other things, Enron
could face substantial claims by customers or loss of revenues
due to service interruptions, inability to fulfill contractual
obligations, inability to account for certain revenues or
obligations or to bill customers accurately and on a timely
basis, and increased expenses associated with litigation,
stabilization of operations following mission-critical failures,
and the execution of contingency plans. Enron could also
experience an inability by customers, traders, and others to pay,
on a timely basis or at all, obligations owed to Enron. Under
these circumstances, the adverse effect on Enron, and the
diminution of Enron's revenues, would be material, although not
quantifiable at this time. Further in this scenario, the
cumulative effect of these failures could have a substantial
adverse effect on the economy, domestically and internationally.
The adverse effect on Enron, and the diminution of Enron's
revenues, from a domestic or global recession or depression also
is likely to be material, although not quantifiable at this time.
Enron will continue to monitor business conditions with the
aim of assessing and minimizing adverse effects, if any, that
result or may result from the Year 2000 problem.
Summary
Enron has a plan to deal with the Year 2000 challenge and
believes that it will be able to achieve substantial Year 2000
readiness with respect to the mission critical systems that it
controls. However, from a forward-looking perspective, the
extent and magnitude of the Year 2000 problem as it will affect
Enron, both before and for some period after January 1, 2000, are
difficult to predict or quantify for a number of reasons. Among
these are: the difficulty of locating "embedded" chips that may
be in a great variety of mission-critical hardware used for
process or flow control, environmental, transportation, access,
communications and other systems; the difficulty of inventorying,
assessing, remediating, verifying and testing Outside Systems;
the difficulty in locating all mission-critical software
(computer code) internal to Enron that is not Year 2000
compatible; and the unavailability of certain necessary internal
or external resources, including but not limited to trained
hardware and software engineers, technicians, and other personnel
to perform adequate remediation, verification and testing of
mission-critical Enron systems or Outside Systems. Accordingly,
there can be no assurance that all of Enron's systems and all
Outside Systems will be adequately remediated so that they are
Year 2000 ready by January 1, 2000, or by some earlier date, so
as not to create a material disruption to Enron's business. If,
despite Enron's reasonable efforts under its Year 2000 Plan,
there are mission-critical Year 2000-related failures that create
substantial disruptions to Enron's business, the adverse impact
on Enron's business could be material. Additionally, while
Enron's Year 2000 costs are not expected to be material, such
costs are difficult to estimate accurately because of
unanticipated vendor delays, technical difficulties, the impact
of tests of Outside Systems and similar events. Moreover, the
estimated costs of implementing the Plan do not take into account
the costs, if any, that might be incurred as a result of Year
2000-related failures that occur despite Enron's implementation
of the Plan.
NEW ACCOUNTING PRONOUNCEMENTS
On April 3, 1998, the AICPA issued Statement of Position 98-5
(SOP 98-5), "Reporting on the Costs of Start-Up Activities,"
which requires that costs for all start-up activities and
organization costs be expensed as incurred and not capitalized in
certain instances, as had previously been allowed. SOP 98-5 is
effective for financial statements for fiscal years beginning
after 1998 and initial adoption is required to be reflected as a
cumulative effect of accounting change. Although Enron continues
to evaluate the impact of adopting SOP 98-5, it expects to
recognize an after-tax charge of approximately $130 million in
the first quarter of 1999 related primarily to differences in
timing of commencement of capitalization of project development
costs compared to Enron's current policy. This charge will be
reflected net of tax as a separate line item in Enron's
Consolidated Income Statement.
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities."
SFAS No. 133 establishes accounting and reporting standards
requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded
on the balance sheet as either an asset or liability measured at
its fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document,
designate and assess the effectiveness of transactions that
receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after
June 15, 1999. A company may also implement the Statement as of
the beginning of any fiscal quarter after issuance, however, SFAS
No. 133 cannot be applied retroactively. Enron has not yet
determined the timing of adoption of SFAS No. 133. Enron
believes that SFAS No. 133 will not have a material impact on its
accounting for price risk management activities but has not yet
quantified the effect on its hedging activities or physical base
contracts.
In December 1998, the Emerging Issues Task Force reached
consensus on Issue No. 98-10, "Accounting for Contracts involved
in Energy Trading and Risk Management Activities" (EITF 98-10).
EITF 98-10 is effective for fiscal years beginning after December
15, 1998 and requires energy trading contracts to be recorded at
fair value on the balance sheet, with the changes in fair value
included in earnings. The effect of initial application of EITF
98-10 will be reported as a cumulative effect of a change in
accounting principle. Because Enron currently records its
trading activities at fair value, management believes that the
adoption of EITF 98-10 will not have a materially adverse impact
on its financial position or results of operations.
FINANCIAL CONDITION
<TABLE>
Cash Flows
<CAPTION>
(In Millions) 1998 1997 1996
<S> <C> <C> <C>
Cash provided by (used in):
Operating activities $ 1,640 $ 211 $ 884
Investing activities (3,965) (2,146) (1,074)
Financing activities 2,266 1,849 331
</TABLE>
Net cash provided by operating activities increased $1,429
million in 1998, reflecting positive operating cash flow from
Enron's major business segments other than Retail Energy
Services, which continued investing in its new business.
Operating cash flow in 1998 also included proceeds from sales of
interests in energy-related financial assets and cash from timing
and other changes related to Enron's commodity portfolio. New
investments in merchant assets and investments totaling $721
million partially offset these increases. See Note 4 to the
Consolidated Financial Statements. The decrease of $673 million
in 1997 was primarily a result of a cash payment of $440 million
made in connection with the resolution of the J-Block gas
contract.
Net cash used in investing activities primarily reflects
increased capital expenditures and equity investments, which
total $3,564 million in 1998, $2,092 million in 1997 and $1,483
million in 1996. See "Capital Expenditures and Equity
Investments" below. Partially offsetting these uses of cash were
proceeds from the sales of assets totaling $239 million in 1998,
$473 million in 1997 and $477 million in 1996. These proceeds
were primarily from the sales of liquids assets in 1997 and from
the sales of 12 million shares of EOG common stock held by Enron
and non-strategic gathering and processing assets in 1996.
Cash provided by financing activities in 1998 included $875
million from the net issuance of short- and long-term debt, $867
million from the issuance of common stock and $828 million
primarily from the sale of a minority interest in a subsidiary
(see Note 8 to the Consolidated Financial Statements), partially
offset by payments of $414 million for dividends. 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 8 to the Consolidated Financial
Statements). These inflows were partially offset by payments of
$354 million for cash dividends and $422 million for 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 in 1996 included
cash dividend payments of $281 million.
Working Capital
At December 31, 1998, Enron had a working capital deficit of
$174 million. Enron has credit facilities in place to fund
working capital requirements. At December 31, 1998, those credit
lines provided for up to $3.4 billion of committed and
uncommitted credit, of which $149 million was outstanding at
December 31, 1998. Certain of the credit agreements contain
prefunding covenants. However, such covenants are not expected
to 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>
1999
(In Millions) Estimate 1998 1997 1996
<S> <C> <C> <C> <C>
Exploration and Production(a) $ 550 $ 690 $ 626 $540
Transportation and Distribution 310 310 337 175
Wholesale Energy Operations
and Services 410 706 318 136
Retail Energy Services 40 75 36 -
Corporate and Other 300 124 75 13
Total $1,610 $1,905 $1,392 $864
<FN>
(a) Excludes exploration expenses of $70 million (estimate),
$89 million, $75 million and $68 million for 1999, 1998, 1997
and 1996, respectively.
</TABLE>
Capital expenditures increased $513 million in 1998 and $528
million during 1997 as compared to the previous year. During
1998, increased expenditures in Exploration and Production were
primarily a result of the acquisition of producing properties in
the Gulf of Mexico, and Enron Wholesale expenditures increased
primarily related to domestic and international power plant
construction. During 1997, 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 Enron Wholesale were send-or-pay payments totaling
$63 million in 1998 and $167 million in 1997 related to a
transportation agreement in the U.K.
Cash used for equity investments by the operating segments is
as follows:
<TABLE>
<CAPTION>
1999
(In Millions) Estimate 1998 1997 1996
<S> <C> <C> <C> <C>
Exploration and Production $ 80 $ - $ - $ -
Transportation and Distribution 120 27 3 -
Wholesale Energy Operations
and Services 600 703 580 511
Retail Energy Services 210 - - -
Corporate and Other 120 929 117 108
Total $1,130 $1,659 $700 $619
</TABLE>
Equity investments increased in 1998 as compared to 1997
primarily due to the acquisitions of Elektro and Wessex, net of
proceeds from transactions reducing Enron's interest in these
investments. See Note 9 to the Consolidated Financial
Statements.
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, short- and
long-term borrowings and proceeds from the sale of common stock
in February 1999.
CAPITALIZATION
Total capitalization at December 31, 1998 was $17.5 billion.
Debt as a percentage of total capitalization decreased to 41.9%
at December 31, 1998 as compared to 44.6% at December 31, 1997.
The decrease primarily reflects the issuance during 1998 of
approximately 17 million shares of common stock and the
conversion in late 1998 of 10.5 million Exchangeable Notes into
EOG shares held by Enron, partially offset by increased debt and
minority interests.
Enron is a party to certain financial contracts which contain
provisions for early settlement in the event of a significant
market price decline in which Enron's common stock falls below
certain levels (prices ranging from $15 to $37.84 per share) or
if the credit ratings for Enron's unsecured, senior long-term
debt obligations fall below investment grade. The impact of this
early settlement could include the issuance of additional shares
of Enron common stock.
Enron's senior unsecured long-term debt is currently rated
BBB+ by Standard & Poor's Corporation and Baa2 by Moody's
Investor Services. Enron's continued investment grade status is
critical to the success of its wholesale businesses as well as
its ability to maintain adequate liquidity. Enron's management
believes it will be able to maintain or improve its credit
rating.
In February 1999, Enron issued 13.8 million shares of common
stock in a public offering and approximately 3.8 million shares
of common stock in connection with the acquisition of certain
assets.
Enron has investments in entities whose functional currency is
denominated in Brazilian Reals. Subsequent to December 31, 1998
the exchange rate for Brazilian Reals to the U.S. dollar has
declined. As a result, Enron anticipates recording a non-cash
foreign currency translation adjustment, reducing shareholders'
equity, in the first quarter of 1999. Based on the exchange rate
in mid-February, the equity reduction would be approximately $600
million.
Item 7A. FINANCIAL RISK MANAGEMENT
Enron 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.
In order to mitigate the risk associated with its merchant
investments, Enron actively manages the systematic or market
risks inherent in the investments. Using various analytical
methods, Enron generally disaggregates and manages the equity
index, interest rate and commodity risks embedded in the
investments, leaving the specific asset or idiosyncratic risk
which is diversified among the investments.
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.
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 Wholesale businesses, 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 manage
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 manage 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 manage Enron's risk profile.
Equity Risk. Equity risk arises from the energy assets and
investments operations of Enron Wholesale, which provides capital
to customers through equity participations in various investment
activities. Enron manages this risk by disaggregating the market
risks (such as equity index, interest rate and commodity risks)
from the individual investments and managing these risks on a
portfolio basis through the use of futures, forwards, swaps and
options to ensure compliance with Enron's stated risk management
policies. The idiosyncratic risk or specific risk is managed on
both an individual and portfolio basis within the risk management
polices.
Enron measures the market risk in its investments 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 investments assuming
hypothetical movements in future market rates and no change in
positions. This is not necessarily indicative of actual results
which may occur.
Value at Risk
Enron has performed an entity-wide value at risk analysis of
virtually all of Enron's financial assets and liabilities. Enron
utilizes value at risk in its daily business to evaluate, measure
and manage its overall risk exposure. Value at risk incorporates
numerous variables that could impact the fair value of Enron's
investments, including commodity prices, interest rates, foreign
exchange rates, equity prices and associated volatilities, as
well as correlation within and across these variables. Enron's
methodology includes the use of delta/gamma approximations for
option positions and relies to a certain extent on historical
correlations across commodity groups. Enron estimates value at
risk commodity, interest rate and foreign exchange exposures
using a model based on 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 use of value at risk models allows management to aggregate
risks across the company, compare risk on a consistent basis and
identify the drivers of risk. Because of the inherent
limitations to value at risk, including the use of delta/gamma
approximations to value options, subjectivity in the choice of
liquidation period and reliance on historical data to calibrate
the models, Enron relies on value at risk as only one component
in its risk control process. In addition to using value at risk
measures, Enron performs regular stress and scenario analyses to
estimate the economic impact of sudden market moves on the value
of its portfolios. The results of the stress testing, along with
the professional judgment of experienced business and risk
managers, are used to supplement the value at risk methodology
and capture additional market-related risks, including
volatility, liquidity and event, concentration and correlation
risks.
The following table illustrates the value at risk for each
component of market risk:
<TABLE>
<CAPTION>
December 31, Year ended December 31, 1998
High Low
(In Millions) 1998 1997 Average(a) Valuation(a) Valuation(a)
<S> <C> <C> <C> <C> <C>
Trading Market Risk:
Commodity price $20 $25 $25 $47(b) $17
Interest rate - - 2 4 -
Foreign currency
exchange rate - 1 2 3 -
Equity 12 4 6 12 3
Non-Trading Market Risk(c):
Commodity price 10 9 13 19 6
Interest rate - - - 1 -
Foreign currency
exchange rate - 1 - - -
Equity - - - - -
<FN>
(a) The average values presents a twelve month average of the
month end values. The high and low valuations for each market
risk component represent the highest and lowest month end
value during 1998.
(b) In late June and early July 1998, significant price
swings in the U.S. power markets caused Enron's value at risk
to increase significantly for a period of less than a month
before returning to normal levels.
(c) Includes only the risk related to the financial
instruments that serve as hedges and does not include the
related underlying hedged item.
</TABLE>
Accounting Policies
Accounting policies for price risk management and hedging
activities are described in Note 1 to the Consolidated Financial
Statements.
INFORMATION REGARDING
FORWARD LOOKING STATEMENTS
This Annual Report includes forward looking statements within
the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Although
Enron believes that its expectations are based on reasonable
assumptions, it can give no assurance that its goals will be
achieved. Important factors that could cause actual results to
differ materially from those in the forward looking statements
herein include political developments in foreign countries; the
ability of Enron to penetrate new retail natural gas and
electricity markets in the United States and Europe; the timing
and extent of deregulation of energy markets in the United States
and in foreign jurisdictions; other regulatory developments in
the United States and in foreign countries, including tax
legislation and regulations; the extent of efforts by governments
to privatize natural gas and electric utilities and other
industries; the timing and extent of changes in commodity prices
for crude oil, natural gas, electricity, foreign currency and
interest rates; the extent of EOG's success in acquiring oil and
gas properties and in discovering, developing, producing and
marketing reserves; the timing and success of Enron's efforts to
develop international power, pipeline, water and other
infrastructure projects; the ability of counterparties to
financial risk management instruments and other contracts with
Enron to meet their financial commitments to Enron; Enron's
success in implementing its Year 2000 Plan, the effectiveness of
Enron's Year 2000 Plan, and the Year 2000 readiness of Outside
Entities; and Enron's ability to access the capital markets and
equity markets during the periods covered by the forward looking
statements, which will depend on general market conditions and
Enron's ability to maintain or increase the credit ratings for
its unsecured senior long-term debt obligations.
<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, 1998 and 1997, and the related consolidated
statements of income, comprehensive income, cash flows and
changes in shareholders' equity for each of the three years in
the period ended December 31, 1998. 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, 1998 and 1997,
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, 1998, in conformity with generally accepted
accounting principles.
Arthur Andersen LLP
Houston, Texas
March 5, 1999
<PAGE>
<TABLE>
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENT
<CAPTION>
Year Ended December 31,
(In Millions, except Per Share Amounts) 1998 1997 1996
<S> <C> <C> <C>
Revenues
Natural gas and other products $13,276 $13,211 $11,157
Electricity 13,939 5,101 980
Transportation 627 652 707
Other 3,418 1,309 445
Total Revenues 31,260 20,273 13,289
Costs and Expenses
Cost of gas, electricity and
other products 26,381 17,311 10,478
Operating expenses 2,352 1,406 1,421
Oil and gas exploration expenses 121 102 89
Depreciation, depletion and
amortization 827 600 474
Taxes, other than income taxes 201 164 137
Contract restructuring charge - 675 -
Total Costs and Expenses 29,882 20,258 12,599
Operating Income 1,378 15 690
Other Income and Deductions
Equity in earnings of unconsolidated
affiliates 97 216 215
Gains on sales of assets and investments 56 186 274
Other income, net 51 148 59
Income Before Interest, Minority
Interests and Income Taxes 1,582 565 1,238
Interest and Related Charges, net 550 401 274
Dividends on Company-Obligated Preferred
Securities of Subsidiaries 77 69 34
Minority Interests 77 80 75
Income Tax Expense (Benefit) 175 (90) 271
Net Income 703 105 584
Preferred Stock Dividends 17 17 16
Earnings on Common Stock $ 686 $ 88 $ 568
Earnings Per Share of Common Stock
Basic $ 2.14 $ 0.32 $ 2.31
Diluted $ 2.02 $ 0.32 $ 2.16
Average Number of Common Shares Used
in Computation
Basic 321 272 246
Diluted 348 277 270
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Year Ended December 31,
(In Millions) 1998 1997 1996
Earnings on Common Stock $ 686 $ 88 $ 568
Other comprehensive income:
Foreign currency translation adjustment (14) (21) 26
Total Comprehensive Income $ 672 $ 67 $ 594
<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) 1998 1997
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 111 $ 170
Trade receivables (net of allowance
for doubtful accounts of $14 and
$11, respectively) 2,060 1,372
Other receivables 833 454
Assets from price risk management
activities 1,904 1,346
Inventories 514 136
Other 511 635
Total Current Assets 5,933 4,113
Investments and Other Assets
Investments in and advances to
unconsolidated affiliates 4,433 2,656
Assets from price risk management
activities 1,941 1,038
Goodwill 1,949 1,910
Other 4,437 3,665
Total Investments and Other Assets 12,760 9,269
Property, Plant and Equipment, at cost
Exploration and Production, successful
efforts method 4,814 4,291
Transportation and Distribution 5,481 5,279
Wholesale Energy Operations and Services 4,858 3,879
Retail Energy Services 141 44
Corporate and Other 498 249
15,792 13,742
Less accumulated depreciation,
depletion and amortization 5,135 4,572
Property, Plant and Equipment, net 10,657 9,170
Total Assets $29,350 $22,552
<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, except Shares) 1998 1997
<S> <C> <C>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 2,380 $ 1,794
Liabilities from price risk
management activities 2,511 1,245
Other 1,216 817
Total Current Liabilities 6,107 3,856
Long-Term Debt 7,357 6,254
Deferred Credits and Other Liabilities
Deferred income taxes 2,357 2,039
Liabilities from price risk
management activities 1,421 876
Other 1,916 1,769
Total Deferred Credits and
Other Liabilities 5,694 4,684
Commitments and Contingencies
(Notes 3, 13, 14 and 15)
Minority Interests 2,143 1,147
Company-Obligated Preferred Securities
of Subsidiaries 1,001 993
Shareholders' Equity
Second preferred stock, cumulative, no par
value, 1,370,000 shares authorized,
1,319,848 shares and 1,337,645 shares of
Cumulative Second Preferred Convertible
Stock issued, respectively 132 134
Common stock, no par value, 600,000,000
shares authorized, 335,547,276 shares
and 318,297,276 shares issued,
respectively 5,117 4,224
Retained earnings 2,226 1,852
Accumulated other comprehensive income (162) (148)
Common stock held in treasury, 4,666,661
shares and 7,050,965 shares,
respectively (195) (269)
Other (70) (175)
Total Shareholders' Equity 7,048 5,618
Total Liabilities and Shareholders' Equity $29,350 $22,552
<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) 1998 1997 1996
<S> <C> <C> <C>
Cash Flows From Operating Activities
Reconciliation of net income to net
cash provided by operating activities
Net income $ 703 $ 105 $ 584
Depreciation, depletion and amortization 827 600 474
Oil and gas exploration expenses 121 102 89
Deferred income taxes 87 (174) 207
Gains on sales of assets and investments (82) (195) (274)
Changes in components of working
capital (233) (65) 142
Net assets from price risk management
activities 350 201 15
Merchant assets and investments:
Realized gains on sales (628) (136) -
Proceeds from sales 1,434 339 -
Additions (721) (308) (192)
Other operating activities (218) (258) (161)
Net Cash Provided by Operating
Activities 1,640 211 884
Cash Flows From Investing Activities
Capital expenditures (1,905) (1,392) (864)
Equity investments (1,659) (700) (619)
Proceeds from sales of investments and
other assets 239 473 477
Acquisition of subsidiary stock (180) - -
Business acquisitions, net of cash acquired
(see Note 2) (104) (82) -
Other investing activities (356) (445) (68)
Net Cash Used in Investing Activities (3,965) (2,146) (1,074)
Cash Flows From Financing Activities
Issuance of long-term debt 1,903 1,817 359
Repayment of long-term debt (870) (607) (294)
Net increase (decrease) in short-term
borrowings (158) 464 217
Issuance of company-obligated preferred
securities of subsidiaries 8 372 215
Issuance of common stock 867 - 102
Issuance of subsidiary equity 828 555 -
Dividends paid (414) (354) (281)
Net (acquisition) disposition of
treasury stock 13 (422) 5
Other financing activities 89 24 8
Net Cash Provided by Financing Activities 2,266 1,849 331
Increase (Decrease) in Cash and Cash
Equivalents (59) (86) 141
Cash and Cash Equivalents, Beginning
of Year 170 256 115
Cash and Cash Equivalents, End of Year $ 111 $ 170 $ 256
Changes in Components of Working Capital
Receivables $(1,055) $ 351 $ (678)
Inventories (372) 63 (53)
Payables 433 (366) 870
Other 761 (113) 3
Total $ (233) $ (65) $ 142
<FN>
The accompanying notes are an integral part of these consolidated financial
statements.
</TABLE>
<PAGE>
<TABLE>
ENRON CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
<CAPTION>
(In Millions, except Per Share 1998 1997 1996
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 1,338 $ 134 1,371 $ 137 1,375 $ 138
Exchange of common stock
for convertible preferred stock (18) (2) (33) (3) (4) (1)
Balance, end of year 1,320 $ 132 1,338 $ 134 1,371 $ 137
Common Stock
Balance, beginning of year 318,297 $4,224 255,945 $ 26 253,860 $ 25
Exchange of common stock
for convertible preferred stock - (7) 382 - 19 -
Issuances related to benefit
and dividend reinvestment plans - 45 - (3) - -
Sales of common stock 17,250 836 - - 2,066 1
Issuances of common stock in business
acquisitions (see Note 2) - - 61,970 2,281 - -
Issuance of no par stock in
reincorporation merger - - - 1,881 - -
Other - 19 - 39 - -
Balance, end of year 335,547 $5,117 318,297 $4,224 255,945 $ 26
Additional Paid-in Capital
Balance, beginning of year $ - $1,870 $1,791
Exchange of common stock
for convertible preferred stock - 1 (1)
Issuances related to benefit
and dividend reinvestment plans - (9) (16)
Sales of common stock - 18 109
Issuance of no par stock in
reincorporation merger - (1,881) -
Other - 1 (13)
Balance, end of year $ - $ - $1,870
Retained Earnings
Balance, beginning of year $1,852 $2,007 $1,651
Net income 703 105 584
Cash dividends
Common stock ($0.9625, $0.9125 and
$0.8625 per share in 1998,
1997 and 1996, respectively) (312) (243) (212)
Preferred stock ($13.1402, $12.4584,
and $11.7750 per share in 1998,
1997 and 1996, respectively) (17) (17) (16)
Balance, end of year $2,226 $1,852 $2,007
Accumulated Other Comprehensive Income -
Cumulative Foreign Currency
Translation Adjustment
Balance, beginning of year $ (148) $ (127) $ (153)
Translation adjustments (14) (21) 26
Balance, end of year $ (162) $ (148) $ (127)
Treasury Stock
Balance, beginning of year (7,051) $ (269) (821) $ (30) (2,618) $ (93)
Shares acquired (1,118) (61) (9,790) (374) (2,226) (85)
Exchange of common stock
for convertible preferred stock 243 9 70 3 46 2
Issuances related to benefit
and dividend reinvestment plans 3,213 124 2,838 106 2,249 81
Sales of treasury stock - - - - 1,728 65
Issuances of treasury stock in
business acquisitions (see Note 2) 46 2 652 26 - -
Balance, end of year (4,667) $ (195) (7,051) $ (269) (821) $ (30)
Other
Balance, beginning of year $ (175) $ (160) $ (194)
Issuances related to benefit
and dividend reinvestment plans 105 (15) 34
Balance, end of year $ (70) $ (175) $ (160)
Total Shareholders' Equity $7,048 $5,618 $3,723
<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.
Inventories. Inventories consist primarily of commodities,
priced at market.
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 5).
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. See Note 11 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 physical delivery
related costs, and are shown as "Assets and Liabilities From
Price Risk Management Activities" in the Consolidated Balance
Sheet. Unrealized gains and losses from newly originated
contracts, contract restructurings and the impact of price
movements are recognized as "Other Revenues." Changes in the
assets and liabilities from price risk management activities
result primarily from changes in the valuation of the portfolio
of contracts, newly originated transactions and the timing of
settlement relative to the receipt of cash for certain contracts.
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.
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.
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. 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.
Exploration costs and dry hole costs are included in the
Consolidated Statement of Cash Flows as investing activities.
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.
In the first quarter of 1999, Enron will adopt the AICPA
Statement of Position 98-5 (SOP 98-5), "Reporting on the Costs of
Start-Up Activities," which requires that all start-up costs be
expensed as incurred. Certain costs which are currently
classified as development costs will qualify as start-up costs
under SOP 98-5. Although Enron continues to evaluate the impact
of adopting SOP 98-5, it expects to recognize an after-tax charge
of approximately $130 million in the first quarter of 1999. The
cumulative effect of this accounting change will be reflected net
of tax as a separate line item in the Consolidated Income
Statement.
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. See Note 4.
Environmental Expenditures. Expenditures that relate to an
existing condition caused by past operations, and do not
contribute to current or future revenue generation, are expensed.
Environmental expenditures relating to current or future revenues
are expensed or capitalized as appropriate. Liabilities are
recorded when environmental assessments and/or clean-ups are
probable and the costs can be reasonably estimated.
Computer Software. Enron's accounting policy for the costs of
computer software (all of which is for internal use only) is to
capitalize direct costs of materials and services consumed in
developing or obtaining software, including payroll and payroll-
related costs for employees who are directly associated with and
who devote time to the software project. Costs may begin to be
capitalized once the application development stage has begun.
All other costs are expensed as incurred. Enron amortizes the
costs on a straight-line basis over the useful life of the
software. Impairment is evaluated based on changes in the
expected usefulness of the software. At December 31, 1998, Enron
has capitalized $189 million of software costs covering numerous
systems, including trading and settlement, billing and payroll
systems and upgrades.
Investments in Unconsolidated Affiliates. Investments in
unconsolidated affiliates are accounted for by the equity method,
except for certain equity investments resulting from Enron's
merchant investment activities which are included at market value
in "Other Investments" in the Consolidated Balance Sheet. Where
acquired assets are accounted for under the equity method based
on temporary control, earnings or losses related to the
investments to be sold are deferred until the time of the sale.
See Notes 4 and 9.
Foreign Currency Translation. For international subsidiaries,
asset and liability accounts are translated at year-end rates of
exchange and revenue and expenses are translated at average
exchange rates prevailing during the year. For subsidiaries
whose functional currency is deemed to be other than the U.S.
dollar, translation adjustments are included as a separate
component of other comprehensive income and shareholders' equity.
Currency transaction gains and losses are recorded in income.
Recently Issued Accounting Pronouncements. In 1998, the
Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities" and the Emerging
Issues Task Force reached a consensus on Issue No. 98-10,
"Accounting for Contracts involved in Energy Trading and Risk
Management Activities" (EITF 98-10).
SFAS No. 133 establishes accounting and reporting standards
requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded
on the balance sheet as either an asset or liability measured at
its fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document,
designate and assess the effectiveness of transactions that
receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after
June 15, 1999. A company may also implement the statement as of
the beginning of any fiscal quarter after issuance, however, SFAS
No. 133 cannot be applied retroactively. Enron has not yet
determined the timing of adoption of SFAS No. 133. Enron
believes that SFAS No. 133 will not have a material impact on its
accounting for price risk management activities but has not yet
quantified the effect on its hedging activities or physical base
contracts.
EITF 98-10 is effective for fiscal years beginning after
December 15, 1998 and requires energy trading contracts to be
recorded at fair value on the balance sheet, with the changes in
fair value included in earnings. The effect of initial
application of EITF 98-10 will be reported as a cumulative effect
of a change in accounting principle. Because Enron currently
records its trading activities at fair value, management believes
that the adoption of EITF 98-10 will not have a materially
adverse impact on its financial position or results of
operations.
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. 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.
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 by the minority shareholders. Additionally, during 1998 and
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 has
been reflected as goodwill in the Consolidated Balance Sheet and
is being amortized on a straight-line basis over 5 to 40 years.
Assets acquired, liabilities assumed and consideration paid as a
result of businesses acquired were as follows:
<TABLE>
<CAPTION>
(In Millions) 1998 1997
<S> <C> <C>
Fair value of assets acquired, other than cash $ 269 $3,829
Goodwill 94 1,847
Fair value of liabilities assumed (259) (3,235)
Common stock of Enron and subsidiary issued - (2,359)
Net cash paid $ 104 $ 82
</TABLE>
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>
During 1998, Enron, through wholly-owned subsidiaries,
acquired Elektro Eletricidade e Servicos S.A. (Elektro), Wessex
Water Plc (Wessex) and assets related to The ICI Group's Teesside
utilities and services business (the ICI assets) in separate cash
transactions. These acquisitions are being accounted for using
the equity method (see Note 9).
3 PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Trading Activities. Enron, through its Wholesale Energy
Operations and Services segment (Enron Wholesale), offers price
risk management services to energy-related businesses 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, 1998 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>
Commodities
Natural gas 6,694 5,989 25
Crude oil and liquids 5,545 5,001 11
Electricity 1,162 1,782 26
Other 583 893 10
Financial products
Interest rate(a) $6,574 $5,766 24
Foreign currency 2,719 2,699 17
Equity investments 2,633 363 17
<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>
Enron Wholesale includes sales and purchase commitments
associated with commodity contracts based on market prices
totaling 6,047 TBtue, with terms extending up to 22 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, 1998 was approximately 2.6
years.
Fair Value. The fair value of the financial instruments
related to price risk management activities as of December 31,
1998, 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 12/31/98 12/31/98(a)
(In Millions) Assets Liabilities Assets Liabilities
<S> <C> <C> <C> <C>
Natural gas $2,294 $1,876 $2,328 $1,728
Crude oil and liquids 1,053 1,470 731 764
Electricity 600 396 654 517
Other commodities 162 119 269 193
Equity 61 71 88 32
Total $4,170 $3,932 $4,070 $3,234
<FN>
(a) Computed using the ending balance at each month end.
</TABLE>
The income before interest, taxes and certain unallocated
expenses arising from price risk management activities for 1998
was $414 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, 1998 and 1997 are
summarized as follows:
<TABLE>
<CAPTION>
1998 1997
Investment Investment
(In Millions) Grade(a) Total Grade(a) Total
<S> <C> <C> <C> <C>
Gas and electric utilities $1,181 $1,251 $ 637 $ 676
Energy marketers 684 795 324 481
Financial institutions 505 505 413 416
Independent power producers 416 613 283 436
Oil and gas producers 365 549 280 435
Industrials 229 341 59 106
Other 101 116 118 116
Total $3,481 4,170 $2,114 2,666
Credit and other reserves (325) (282)
Assets from price risk
management activities(b) $3,845 $2,384
<FN>
(a) "Investment Grade" is primarily determined using publicly
available credit ratings along with consideration of
collateral, which encompass standby letters of credit, parent
company guarantees and property interests, including oil and
gas reserves. Included in "Investment Grade" are
counterparties with a minimum Standard & Poor's or Moody's
rating of BBB- or Baa3, respectively.
(b) Two and one customers' exposures at December 31, 1998 and
1997, 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.
Energy Commodity Price Swaps. At December 31, 1998, Enron was
a party to energy commodity price swaps covering 156 TBtu, 4 TBtu
and 56 TBtu of natural gas for the years 1999, 2000 and the
period 2001 through 2006, respectively, and 1.8 million barrels
of crude oil for the year 1999.
Interest Rate Swaps. At December 31, 1998, Enron had entered
into interest rate swap agreements with a notional principal
amount of $4.0 billion to manage interest rate exposure. These
swap agreements are scheduled to terminate $0.6 billion in 1999
and $3.4 billion in the period 2000 through 2014.
Foreign Currency Contracts. At December 31, 1998, foreign
currency contracts with a notional principal amount of $0.8
billion were outstanding. Such contracts will expire in the
period 2000 through 2009.
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, 1998 and
1997 were as follows:
<TABLE>
<CAPTION>
1998 1997
Carrying Estimated Carrying Estimated
(In Millions) Amount Fair Value Amount Fair Value
<S> <C> <C> <C> <C>
Long-term debt (Note 7) $7,357 $7,624 $6,254 $6,501
Company-obligated preferred
securities of subsidiaries
(Note 10) 1,001 1,019 993 1,024
Energy commodity price swaps - (5) - (31)
Interest rate swaps - 12 - 13
Foreign currency contracts - 1 - -
</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, where available, or based on the discounted
present value of cash flows using Enron's current borrowing rates
if not publicly traded; and (c) energy commodity price swaps,
interest rate swaps and foreign currency contracts - 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 MERCHANT ACTIVITIES
Merchant Investments. Through the Enron Wholesale segment,
Enron provides capital primarily to energy-related businesses
seeking debt or equity financing. The investments made by Enron
include public and private equity, debt, production payments and
interests in limited partnerships. These investments are managed
as a group, by disaggregating the market risks embedded in the
individual investments and managing them on a portfolio basis,
utilizing public equities, equity indices and commodities as
hedges of specific industry groups and interest rate swaps as
hedges of interest rate exposure, to reduce Enron's exposure to
overall market volatility. The specific investment or
idiosyncratic risks which remain are then managed and monitored
within the Enron risk management policies.
As part of its complement of services, and to add value to its
investments, Enron may have involvement with the investees'
business, including representation on the board of directors and
providing risk management products and services to the business.
The investments are recorded at market value in "Other Assets"
on the Consolidated Balance Sheet, with fair value adjustments
reflected in "Other Revenues" on the Consolidated Income
Statement. The valuation methodologies utilize market values of
publicly-traded securities, independent appraisals and cash flow
analyses.
Merchant Assets. Also included in Enron's wholesale business
are investments in merchant energy assets such as power plants,
natural gas pipelines and local gas and electric distribution
companies, primarily held through equity investments. Some of
these assets were developed and constructed by Enron, which may
also operate the facility for the joint venture. From time to
time, Enron sells interests in these energy-related financial
assets. Some of these sales are completed in securitizations, in
which Enron retains certain interests through swaps associated
with the underlying assets. Such swaps are adjusted to fair
value using quoted market prices, if available, or estimated fair
value based on management's best estimate of the present value of
future cash flow. These swaps are included in Price Risk
Management activities. See Note 3.
For the years ended December 31, 1998 and 1997, respectively,
pre-tax gains from sales of merchant assets and investments
totaling $628 million and $136 million are included in "Other
Revenues," and proceeds were $1,434 million and $339 million.
An analysis of the composition of Enron's wholesale merchant
investments and energy assets at December 31, 1998 and 1997 is as
follows:
<TABLE>
<CAPTION>
December 31,
(In Millions) 1998 1997
<S> <C> <C>
Merchant Investments
Held directly by Enron
Oil and gas exploration and
production $ 279 $ 147
Energy-intensive industries 331 139
Natural gas transportation 132 131
Other 334 80
1,076 497
Held through unconsolidated affiliates(a)
Oil and gas exploration and
production 610 553
Oil services 123 68
Other 50 -
783 621
1,859 1,118
Merchant Assets
Independent power plants 148 401
Natural gas transportation 38 31
Other - 46
186 478
Total $2,045 $1,596
<FN>
(a) Amounts represent Enron's interests.
</TABLE>
5 INCOME TAXES
The components of income before income taxes are as follows:
<TABLE>
<CAPTION>
(In Millions) 1998 1997 1996
<S> <C> <C> <C>
United States $197 $96 $551
Foreign 681 (81) 304
$878 $15 $855
</TABLE>
Total income tax expense (benefit) is summarized as follows:
<TABLE>
<CAPTION>
(In Millions) 1998 1997 1996
<S> <C> <C> <C>
Payable currently -
Federal $ 30 $ 29 $ 16
State 8 9 11
Foreign 50 46 37
88 84 64
Payment deferred -
Federal (14) (39) 174
State 11 (42) (1)
Foreign 90 (93) 34
87 (174) 207
Total income tax expense
(benefit) $175 $ (90) $271
</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) 1998 1997 1996
<S> <C> <C> <C> <C>
Statutory federal income tax provision 35.0% $ 5 35.0% 35.0%
Net state income taxes 1.7 (21) (140.0) 0.8
Tight gas sands tax credit (1.4) (12) (80.0) (1.8)
Equity earnings (4.3) (38) (253.3) (3.3)
Minority interest 0.8 28 186.7 3.1
Assets and stock sale differences (14.2) (79) (526.7) 1.8
Cash value in life insurance (1.1) (7) (46.7) (3.2)
Goodwill amortization 2.0 9 60.0 -
Other 1.5 25 166.7 (0.7)
20.0% $(90) (598.3)% 31.7%
</TABLE>
The principal components of Enron's net deferred income tax
liability are as follows:
<TABLE>
<CAPTION>
December 31,
(In Millions) 1998 1997
<S> <C> <C>
Deferred income tax assets -
Alternative minimum tax credit carryforward $ 238 $ 247
Net operating loss carryforward 605 361
Other 111 218
954 826
Deferred income tax liabilities -
Depreciation, depletion and amortization 1,940 2,036
Price risk management activities 645 457
Other 700 588
3,285 3,081
Net deferred income tax liabilities(a) $2,331 $2,255
<FN>
(a) Includes $(26) million and $216 million in other current
liabilities for 1998 and 1997, respectively.
</TABLE>
Enron has an alternative minimum tax (AMT) credit carryforward
of approximately $238 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 federal consolidated net operating loss
carryforward for tax purposes of approximately $1.4 billion,
which will begin to expire in 2011. Enron has a net operating
loss carryforward applicable to non-U.S. subsidiaries of
approximately $353 million of which $237 million can be carried
forward indefinitely. The remaining $116 million will begin to
expire in 2002 but is projected to be utilized before its
expiration period. The benefits of the domestic and foreign net
operating losses have been recognized as deferred tax assets.
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 $840 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.
6 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) 1998 1997 1996
<S> <C> <C> <C>
Income taxes (net of refunds) $ 73 $ 68 $ 89
Interest (net of amounts capitalized) 585 420 290
</TABLE>
Non-Cash Transactions. In December 1998, Enron exchanged its
6.25% Exchangeable Notes for 10.5 million shares of EOG common
stock.
During 1997, Enron issued common stock in connection with
business acquisitions. See Note 2.
7 CREDIT FACILITIES AND DEBT
Enron has credit facilities with domestic and foreign banks
which provide for an aggregate of $1.67 billion in long-term
committed credit and $1.37 billion in short-term committed
credit. Expiration dates of the committed facilities range from
April 1999 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. At December 31, 1998, $149
million was outstanding under these facilities.
Enron has also entered into agreements which provide for
uncommitted lines of credit totaling $335 million at December 31,
1998. 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,
1998, no amounts were outstanding under the uncommitted lines.
In addition to borrowing from banks on a short-term basis,
Enron and certain of its subsidiaries sell commercial paper to
provide financing for various corporate purposes. As of December
31, 1998 and 1997, short-term borrowings of $680 million and $825
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, 1998 and
1997, $541 million and $462 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, 1998 and 1997 were 5.5% and 6.0%, respectively.
Detailed information on long-term debt is as follows:
<TABLE>
<CAPTION>
December 31,
(In Millions) 1998 1997
<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
6.40% to 10.00% due 1998 to 2028 3,342 2,492
Floating rate notes due 1999 to 2037 400 350
Other 38 67
Northern Natural Gas Company
Notes payable
6.75% to 8.00% due 1999 to 2008 500 350
Transwestern Pipeline Company
Notes payable
7.55% to 9.20% due 1998 to 2004 147 150
Portland General Electric Company
First mortgage bonds
5.65% to 9.46% due 1998 to 2023 502 564
Pollution control bonds
3.50% to 7.13% due 2010 to 2033 200 192
Other 160 172
Enron Oil & Gas Company
Notes payable
Floating rate notes due 1998 to 2001 105 120
5.44% to 9.10% due 1998 to 2028 675 390
Other 302 37
Amount reclassified from short-term debt 680 825
Unamortized debt discount and premium (44) (33)
Total long-term debt $7,357 $6,254
</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 were exchanged in December
1998 for 10.5 million shares of EOG common stock held by Enron.
The aggregate annual maturities of long-term debt outstanding
at December 31, 1998 were $541 million, $413 million, $666
million, $182 million and $656 million for 1999 through 2003,
respectively.
8 MINORITY INTERESTS
Enron's minority interests primarily include amounts related
to EOG and two joint ventures. Also included was EPP prior to
Enron's acquisition of the EPP minority interest in November 1997
(see Note 2).
In December 1998, Enron formed a wholly-owned limited
partnership for the purpose of holding $1.6 billion of assets
contributed by various business units. That partnership
contributed $850 million of assets to a second newly-formed
limited partnership in exchange for a 53% interest; a third party
investor contributed $750 million in exchange for a 47% interest.
The assets held by the wholly-owned limited partnership represent
collateral for a $750 million note receivable held by the other
newly-formed limited partnership. 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. 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.
These entities are separate legal entities from Enron and have
separate assets and liabilities. Absent certain defaults or
other specified events, Enron has the option to acquire the
minority holders' interests in the entities. If Enron does not
acquire the minority holders' interests before December 2005 or
December 2002, respectively, or earlier upon certain specified
events, the entities will liquidate their assets and dissolve.
These entities are included in Enron's consolidated financial
statements and the third-party investors' interests are included
in "Minority Interests" in the Consolidated Balance Sheet.
9 UNCONSOLIDATED AFFILIATES
Enron's investment in and advances to unconsolidated
affiliates which are accounted for by the equity method is as
follows:
<TABLE>
<CAPTION>
Net
Ownership December 31,
(In Millions) Interest 1998 1997
<S> <C> <C> <C>
Azurix Corp.(a) 50% $ 918 $ -
Citrus Corp.(b) 50% 455 432
Companhia Distribuidora de Gas do Rio
de Janeiro, S.A.(c) 25% 192 194
Dabhol Power Company(c) 50% 285 -
Enron Teesside Operations Limited(c) 100% 118 -
Jacare Electrical Distribution Trust(c) 51% 447 -
Joint Energy Development Investments L.P.
(JEDI)(c)(d) 50% 356 392
Transportadora de Gas del Sur S.A.(c) 35% 463 472
Other 1,199 1,166
$4,433(e) $2,656
<FN>
(a) Included in the Corporate and Other segment.
(b) Included in the Transportation and Distribution segment.
(c) Included in the Wholesale Energy Operations and Services
segment.
(d) JEDI accounts for its investments at fair value.
(e) At December 31, 1998, the unamortized excess of Enron's
investment in unconsolidated affiliates was $203 million,
which is being amortized over the expected lives of the
investments.
</TABLE>
Enron's equity in earnings (losses) of unconsolidated
affiliates is as follows:
<TABLE>
<CAPTION>
(In Millions) 1998 1997 1996
<S> <C> <C> <C>
Citrus Corp. $ 23 $ 27 $ 22
Joint Energy Development Investments L.P. (45) 68 71
Transportadora de Gas del Sur S.A. 36 45 29
Other 83 76 93
$ 97 $216 $215
</TABLE>
Summarized combined financial information of Enron's
unconsolidated affiliates is presented below:
<TABLE>
<CAPTION>
December 31,
(In Millions) 1998 1997
<S> <C> <C>
Balance sheet
Current assets(a) $ 2,309 $3,611
Property, plant and equipment, net 12,640 8,851
Other noncurrent assets 7,176 1,089
Current liabilities(a) 3,501 1,861
Long-term debt(a) 7,621 5,694
Other noncurrent liabilities 2,016 1,295
Owners' equity 8,897 4,701
<FN>
(a) Includes $196 million and $0 million receivable from
Enron and $296 million and $569 million payable to Enron at
December 31, 1998 and 1997, respectively.
</TABLE>
<TABLE>
<CAPTION>
(In Millions) 1998 1997 1996
<S> <C> <C> <C>
Income statement(a)
Operating revenues $8,508 $11,183 $11,676
Operating expenses 7,244 10,246 10,567
Net income 142 336 464
Distributions paid to Enron 87 118 84
<FN>
(a) Enron recognized revenues from unconsolidated affiliates
of $142 million in 1998, $219 million in 1997 and $253 million
in 1996.
</TABLE>
In August 1998, Enron, through a wholly-owned subsidiary,
completed the acquisition of a controlling interest in Elektro,
Brazil's sixth largest electricity distributor, for approximately
$1.3 billion. Elektro serves approximately 1.5 million customers
through approximately 51,000 miles of distribution lines in the
state of Sao Paulo. Enron's interest in Elektro is held by
Jacare Electrical Distribution Trust. In October 1998, Enron,
through a wholly-owned subsidiary, acquired Wessex, which
provides water supply and wastewater services in southern
England, for approximately $2.4 billion. Wessex is held through
Azurix Corp. On December 31, 1998, Enron's wholly-owned
subsidiary, Enron Teesside Operations Limited (ETOL), acquired
assets from The ICI Group for approximately $500 million. The
acquisition of the ICI assets allows ETOL to supply steam, water,
power and other utility services to large industrial customers in
the U.K.
Although Enron initially owned more than 50 percent of the
voting interest in each of these entities, they are reported
using the equity method as a result of management's intent to
ultimately hold a voting interest of not more than 50 percent.
In December 1998, Enron completed financial restructuring of
Enron's ownership interest in Wessex, reducing its interest to
50%, and financially closed the Elektro financial restructuring,
reducing its interest in the subsidiary that holds Elektro to
51%. Enron will transfer an additional 1% interest in Elektro
following the receipt of certain regulatory approvals, which are
expected in the first half of 1999.
Proceeds of approximately $1.6 billion received from the
Elektro and Wessex financial restructurings were used to repay
debt incurred in the initial acquisitions. In connection with
the financings, Enron committed to cause the sale of its
convertible preferred stock, with the number of common shares
issuable upon conversion determined based on future common stock
prices, if certain debt obligations of the related entities
acquiring such interests are defaulted upon, or in certain
events, including, among other things, Enron's credit ratings
falling below specified levels. If the sale of stock is not
sufficient to retire such obligations, Enron would be liable for
the shortfall. The obligations will mature in December 2000 and
2001 for Elektro and Wessex, respectively.
Enron has investments in entities whose functional currency is
denominated in Brazilian Reals. Subsequent to December 31, 1998,
the exchange rate for Brazilian Reals to the U.S. dollar has
declined. As a result, Enron anticipates recording a non-cash
foreign currency translation adjustment, reducing shareholders'
equity, in the first quarter of 1999. Based on the exchange rate
in mid-February, the equity reduction would be approximately $600
million.
From time to time, Enron has entered into various
administrative service, management, construction, supply and
operating agreements with its unconsolidated affiliates. Enron's
management believes that its existing agreements and transactions
are reasonable compared to those which could have been obtained
from third parties.
10 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, 1998, Enron had
outstanding 1,319,848 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 1998,
1997 and 1996, 17,797 shares, 33,069 shares and 4,780 shares,
respectively, of the Convertible Preferred Stock were converted
into common stock.
Company-Obligated Preferred Securities of Subsidiaries. Summarized
information for Enron's Company-Obligated Preferred Securities of
Subsidiaries is as follows:
<TABLE>
<CAPTION>
Liquidation
December 31, Value
(In Millions, except Per Share Amounts and Shares) 1998 1997 Per Share
<S> <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) 150 150 25
Enron Capital Trust III
Adjustable-Rate Capital Trust Securities
(200,000 preferred securities)(b) 200 200 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 59 51
$1,001 $993
<FN>
(a) Redeemable under certain circumstances after specified
dates.
(b) Mature in 2046.
(c) Mandatorily redeemable in 2006.
</TABLE>
11 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) 1998 1997 1996
<S> <C> <C> <C>
Numerator:
Net income $ 703 $ 105 $ 584
Preferred stock dividends (17) (17) (16)
Numerator for basic earnings per
share - income available to common
shareholders 686 88 568
Effect of dilutive securities:
Preferred stock dividends(a) 17 - 16
Numerator for diluted earnings per
share - income available to common
shareholders after assumed conversions $ 703 $ 88 $ 584
Denominator:
Denominator for basic earnings per
share - weighted-average shares 321 272 246
Effect of dilutive securities:
Preferred stock (a) 18 - 19
Stock options 9 5 5
Dilutive potential common shares 27 5 24
Denominator for diluted earnings per
share - adjusted weighted-average
shares and assumed conversions 348 277 270
Basic earnings per share $2.14 $0.32 $2.31
Diluted earnings per share $2.02 $0.32 $2.16
<FN>
(a) For 1997, the dividends and conversion of preferred stock
have been excluded from the computation because conversion is
antidilutive.
</TABLE>
Enron has outstanding certain instruments that are potentially
convertible into common stock but which do not qualify as
dilutive securities for computation of earnings per share. See
Notes 8 and 9 for further description of these instruments.
In February 1999, Enron issued 13.8 million shares of common
stock in a public offering and approximately 3.8 million shares
of common stock in connection with the acquisition of certain
assets.
Forward Contracts and Options. At December 31, 1998, Enron
had forward contracts to purchase 6.7 million shares of Enron
Corp. common stock at an average price of $43.37 per share.
Enron may purchase the shares pursuant to the forward contracts
with 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 unless they are antidilutive.
At December 31, 1998, Enron had issued put options for
approximately nine million shares at a weighted average exercise
price of $54.73. If exercised by the counterparty, Enron may
purchase the shares pursuant to the put options for the
difference between the exercise price and the market price, in
either cash or an equivalent value of Enron common stock. These
put options have been included in the diluted earnings per share
calculation.
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 1998, 1997 and 1996 was $58
million, $14 million and $4 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, Enron's net income and earnings per
share would have been $674 million ($2.04 per share basic, $1.94
per share diluted) in 1998, $66 million ($0.18 per share basic,
$0.18 per share diluted) in 1997 and $562 million ($2.22 per
share basic, $2.07 per share diluted) in 1996.
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 1998, 1997 and 1996,
respectively: (i) dividend yield of 2.5%, 2.5% and 2.3%; (ii)
expected volatility of 18.3%, 17.4% and 23.8%; (iii) risk-free
interest rates of 5.0%, 5.9% and 5.9%; and (iv) expected lives of
3.8 years, 3.7 years and 4.0 years.
Enron has three 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>
1998 1997 1996
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 39,429 $35.77 25,476 $32.69 22,493 $29.02
Granted(a) 7,851 49.97 17,658 38.63 7,370 39.71
Exercised (6,536) 31.39 (2,165) 23.29 (3,615) 24.41
Forfeited (749) 39.54 (1,514) 35.25 (749) 31.66
Expired (193) 39.52 (26) 34.59 (23) 30.65
Outstanding,
end of year 39,802 39.19 39,429 $35.77 25,476 $32.69
Exercisable,
end of year 22,971 $36.31 21,252 $33.55 12,883 $30.65
Available for grant,
end of year(b) 5,249 13,047 6,505
Weighted average
fair value of
options granted $ 8.39 $ 7.10 $ 9.44
<FN>
(a) Includes 1,768,074 shares issued in 1997 in connection with
business acquisitions discussed in Note 2.
(b) Includes up to 5,248,835 shares, 12,246,040 shares and
5,232,218 shares as of December 31, 1998, 1997 and 1996,
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, 1998 (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 12/31/98 Life Price at 12/31/98 Price
<C> <C> <C> <C> <C> <C>
$10.69 to $30.25 4,119 4.1 $25.94 3,708 $25.66
30.50 to 36.06 6,779 4.9 31.71 5,498 31.87
36.75 to 39.88 10,310 6.9 37.73 6,322 37.73
40.00 to 45.00 12,810 6.3 42.21 6,489 42.32
46.38 to 57.06 5,784 9.2 53.33 954 52.46
$10.69 to 57.06 39,802 6.4 $39.19 22,971 $36.31
</TABLE>
Restricted Stock Plan. Under Enron's Restricted Stock Plan,
participants may be granted stock without cost to the
participant. The shares granted under this plan vest to the
participants at various times ranging from immediate vesting to
vesting at the end of a five-year period. Upon vesting, the
shares are released to the participants. The following
summarizes shares of restricted stock under this plan:
<TABLE>
<CAPTION>
(Shares in Thousands) 1998 1997 1996
<S> <C> <C> <C>
Outstanding, beginning of year 2,537 825 159
Granted 1,061 2,088 1,772
Released to participants (532) (321) (1,062)
Forfeited or expired (49) (55) (44)
Outstanding, end of year 3,017 2,537 825
Available for grant, end of year 5,249 12,246 5,232
Weighted average fair value of
restricted stock granted $47.40 $38.26 $37.04
</TABLE>
12 PENSION AND OTHER BENEFITS
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.
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, 1998 and 1997, 10,919,050
shares and 13,508,794 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.
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.
Enron provides certain postretirement 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 these
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.
Enron adopted SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits," in 1998. This
statement changed the disclosure requirements, but not the method
of measurement or recognition of these obligations. The
following table sets forth information related to changes in the
benefit obligations, changes in plan assets, a reconciliation of
the funded status of the plans and components of the expense
recognized related to Enron's pension and other postretirement
plans:
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
(In Millions) 1998 1997 1998 1997
<S> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation, beginning of year $617 $308 $148 $144
Service cost 27 22 2 2
Interest cost 44 32 9 10
Plan participants' contributions - - 3 3
Plan amendments - - 3 (4)
Actuarial loss (gain) 26 35 (16) (14)
Acquisitions and divestitures - 255 - 27
Benefits paid (27) (35) (15) (20)
Benefit obligation, end of year $687 $617 $134 $148
Change in plan assets
Fair value of plan assets, beginning
of year(a) $727 $315 $ 54 $ 15
Actual return on plan assets 41 84 3 3
Acquisitions and divestitures - 360 - 32
Employer contribution 33 3 8 8
Plan participants' contributions - - 3 3
Benefits paid (27) (35) (8) (7)
Fair value of plan assets, end of year(a) $774 $727 $ 60 $ 54
Reconciliation of funded status, end of year
Funded status, end of year $ 87 $110 $(74) $(94)
Unrecognized transition obligation (asset) (18) (24) 58 62
Unrecognized prior service cost 33 35 17 22
Unrecognized net actuarial loss (gain) 79 34 (10) 6
Prepaid (accrued) benefit cost $181 $155 $ (9) $ (4)
Weighted-average assumptions at December 31
Discount rate 6.75% 7.25% 6.75% 7.25%
Expected return on plan assets (pre-tax) (b) (b) (c) (c)
Rate of compensation increase (d) (d) (d) (d)
Components of net periodic benefit cost
Service cost $ 27 $ 22 $ 2 $ 2
Interest cost 44 32 9 10
Expected return on plan assets (63) (43) (3) (2)
Amortization of transition obligation
(asset) (6) (6) 4 4
Amortization of prior service cost 5 5 1 1
Recognized net actuarial loss (gain) 2 2 - 1
Net periodic benefit cost $ 9 $ 12 $ 13 $ 16
<FN>
(a) Includes plan assets of the ESOP of $139 million and $135
million at December 31, 1998 and 1997, respectively.
(b) Long-term rate of return on assets is assumed to be 10.5%
for the Enron Retirement Plan and 9.0% for the Portland
General Plan.
(c) Long-term rate of return on assets is assumed to be 7.5%
for the Enron assets and 9.5% for the Portland General assets.
(d) Rate of compensation increase is assumed to be 4.0% for
the Enron Plan and 4.0% to 9.5% for the Portland General Plan.
</TABLE>
Included in the above amounts are the unfunded obligations for
the supplemental executive retirement plans. At December 31,
1998 and 1997, respectively, the projected benefit obligation for
these unfunded plans was $54 million and $48 million and the fair
value of assets was $2 million and $1 million.
The measurement date of the Enron Plan and the ESOP is
September 30, and the measurement date of the Portland General
Plan and the postretirement benefit plans is December 31. The
funded status as of the valuation date of the Enron Plan, the
Portland General Plan, the ESOP and the postretirement benefit
plans reconciles with the amount detailed above which is included
in "Other Assets" on the Consolidated Balance Sheet.
For measurement purposes, a 7.0% annual rate of increase in the
per capita cost of covered health care benefits was assumed for
1999. The rate was assumed to decrease to 5.0% by 2003. Assumed
health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percentage
point change in assumed health care cost trend rates would have
the following effects:
<TABLE>
<CAPTION>
1-Percentage 1-Percentage
(In Millions) Point Increase Point Decrease
<S> <C> <C>
Effect on total of service and
interest cost components $0.4 $(0.4)
Effect on postretirement benefit
obligation 5.4 (4.5)
</TABLE>
Additionally, certain Enron subsidiaries maintain various
incentive based compensation plans for which participants may
receive a combination of cash or stock options of the
subsidiaries, 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 Utility 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 were
$241 million and $283 million at December 31, 1998 and 1997,
respectively, which are expected to be recovered over varying
time periods.
The electric utility operations' net regulatory assets at
December 31, 1998 and 1997, respectively, were $494 million and
$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. On May 1, 1998, Northern Natural Gas
Company (Northern) filed a general rate case proceeding with the
FERC which fulfilled a commitment made in a previous settlement.
The rate case included an annual increase of $35 million to
Northern's revenues over 1997. The FERC accepted the rate case
for filing and suspended the filed rates. Northern implemented
the filed rates effective November 1, 1998, subject to refund.
Transwestern Pipeline Company implemented on November 1, 1998,
a rate escalation of settled transportation rates, per a May 1996
settlement.
Electric Utility Operations. 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, 1998, PGE's regulatory asset related to
recovery of Trojan costs from customers was $438 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
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 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, operated a propane/air
distribution system in the vicinity. Although San Juan did not
provide service to the building, the investigation report of the
National Transportation Safety Board (NTSB) concluded that the
probable cause of the incident was propane leaking from San
Juan's distribution system. San Juan and Enron strongly disagree
with the NTSB findings. The NTSB investigation found no path of
migration of propane from San Juan's system to the building and
no forensic evidence that propane fueled the explosion. Enron,
San Juan, several San Juan affiliates and third parties have been
named as defendants in numerous lawsuits filed in U.S. District
Court for the district of Puerto Rico and the Commonwealth court
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, among
others, 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 Investment Recovery. In early 1993, PGE ceased
commercial operation of Trojan. 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 was 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. On June 24, 1998, the
Court of Appeals of the State of Oregon ruled that the OPUC does
not have the authority to allow PGE to recover a rate of return
on its undepreciated investment in the Trojan generating
facility. The court upheld the OPUC's authorization of PGE's
recovery of its undepreciated investment in Trojan.
PGE has filed a petition for review with the Oregon Supreme
Court. The OPUC has also filed such a petition for review. Also
on August 26, 1998, the Utility Reform Project filed a Petition
for Review with the Oregon Supreme Court seeking review of that
portion of the Oregon Court of Appeals decision relating to PGE's
recovery of its undepreciated investment in Trojan. Enron cannot
predict the outcome of these actions. Additionally, due to
uncertainties in the regulatory process, management cannot
predict, with certainty, what ultimate rate-making action the
OPUC will take regarding PGE's recovery of a rate of return on
its Trojan investment. 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.
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. To date, the EPA has identified no other
potentially responsible parties with respect to this 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. Enron completed
the final removal actions at the site in November 1998, and
expects to conclude all remaining site activities in the spring
of 1999. In 1998, Enron's expenses related to the Decorah Site
were $300,000 as compared with $400,000 in 1997. 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.
Enron has also received from the EPA an Order issued under
CERCLA alleging that Enron and two other parties are responsible
for the cost of demolition and proper disposal of two 110 foot
towers that apparently had been used in the manufacture of carbon
dioxide at a site called the "City Bumper Site" in Cincinnati,
Ohio. The carbon dioxide plant, according to agency documents,
was in operation from 1926 to 1966. Houston Natural Gas
Corporation, a predecessor of Enron Corp., merged with Liquid
Carbonic Industries (LCI) on January 31, 1969. Liquid Carbonic
Corporation (LCC), a subsidiary of LCI, had title to the site.
Twenty-eight days after the merger, on February 28, 1969, the
site was sold to a third party. In 1984, LCC was sold to an
unaffiliated party in a stock sale. Although Enron does not
admit liability with respect to any costs at this site, it agreed
to cooperate with the EPA and other potentially responsible
parties to undertake the work contemplated by EPA's Order. The
tower demolition and removal activities were completed in October
1998, and a final project report has been prepared for submission
to the EPA. In 1998, Enron's expenses related to the City Bumper
Site were $600,000. Enron does not expect to incur material
expenditures in connection with this site.
Enron's natural gas pipeline companies conduct soil and
groundwater remediation of a number of their facilities. In
1998, these expenses were $1.3 million as compared with $1.7
million in 1997. Enron does not expect to incur material
expenditures in connection with soil and groundwater remediation.
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, 1998, the estimated
aggregate amounts of such required future payments were $53
million, $67 million, $69 million, $71 million and $72 million
for 1999 through 2003, respectively, and $601 million for later
years.
The costs recognized under firm transportation agreements,
including commodity charges on actual quantities shipped, totaled
$30 million, $27 million and $25 million in 1998, 1997 and 1996,
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, 1998 were $208 million, $210 million, $324 million,
$148 million and $131 million for 1999 through 2003,
respectively, and $954 million for later years. Guarantees under
the leases total $1,039 million at December 31, 1998.
Total rent expense incurred during 1998, 1997 and 1996 was
$147 million, $156 million and $149 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 affiliates in connection with
letters of credit issued on behalf of those unconsolidated
affiliates. At December 31, 1998, a total of $209 million of
such guarantees were outstanding, including $44 million on behalf
of EOTT. In addition, Enron is a guarantor on certain
liabilities of unconsolidated affiliates and other companies
totaling approximately $755 million, including $366 million
related to EOTT trade obligations. The EOTT letters of credit
and guarantees of trade obligations are secured by the assets of
EOTT. Enron has also guaranteed $453 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 1999 planned capital
expenditures and equity investments.
16 QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data is as follows:
<TABLE>
<CAPTION>
(In Millions, Except First Second Third Fourth Total
Per Share Amounts) Quarter Quarter Quarter Quarter Year
<S> <C> <C> <C> <C> <C>
1998
Revenues $5,682 $6,557 $11,320 $7,701 $31,260
Income before
interest, minority
interests and income taxes 471 345 405 361 1,582
Net income 214 145 168 176 703
Earnings per share:
Basic $ 0.69 $ 0.44 $ 0.50 $ 0.52 $ 2.14(a)
Diluted 0.65 0.42 0.47 0.49 2.02(a)
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)
<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 adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information," during the fourth quarter of
1998. SFAS No. 131 establishes standards for reporting
information about operating segments in annual financial
statements and requires selected information about operating
segments in interim financial reports. Operating segments are
defined as components of an enterprise about which separate
financial information is available and evaluated regularly by the
chief operating decision maker, or decision making group, in
deciding how to allocate resources and in assessing performance.
Enron's chief operating decision making group is the Management
Committee, which consists of the Chairman, President, and other
key officers.
The segments described below aggregate similar businesses
together based on such factors as regulatory environment,
products and services and customers.
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 - Regulated industries.
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
industrial sectors, including the outsourcing of energy-related
activities.
Corporate and Other - Includes operation of water,
telecommunications and renewable energy businesses and clean
fuels plants, as well as Enron's investment in crude oil
transportation activities.
Financial information by geographic and business segment
follows for each of the three years in the period ended December
31, 1998.
Geographic Segments
<TABLE>
<CAPTION>
Year Ended December 31,
(In Millions) 1998 1997 1996
<S> <C> <C> <C>
Operating revenues from
unaffiliated customers
United States $25,247 $17,328 $11,262
Foreign 6,013 2,945 2,027
$31,260 $20,273 $13,289
Income (loss) before interest,
minority interests and income
taxes
United States $ 1,008 $ 601 $ 938
Foreign 574 (36) 300
$ 1,582 $ 565 $ 1,238
Long-lived assets
United States $ 9,382 $ 8,425 $ 6,490
Foreign 1,275 745 622
$10,657 $ 9,170 $ 7,112
</TABLE>
<TABLE>
Business Segments
<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>
1998
Unaffiliated revenues(a) $ 750 $1,833 $27,220 $1,072 $ 385 $31,260
Intersegment revenues(b) 134 16 505 - (655) -
Total revenues 884 1,849 27,725 1,072 (270) 31,260
Depreciation, depletion and
amortization 315 253 195 31 33 827
Operating income (loss) 133 562 880 (124) (73) 1,378
Equity in earnings of
unconsolidated affiliates - 33 42 (2) 24 97
Interest income 1 3 61 - 17 82
Other income, net (6) 39 (15) 7 - 25
Income (loss) before interest,
minority interests and
income taxes 128 637 968 (119) (32) 1,582
Capital expenditures 690 310 706 75 124 1,905
Identifiable assets 3,001 6,955 12,205 747 2,009 24,917
Investments in and advances to
unconsolidated affiliates - 661 2,632 - 1,140 4,433
Total assets $3,001 $7,616 $14,837 $ 747 $3,149 $29,350
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 affiliates - 40 172 (1) 5 216
Interest income 2 3 52 - 11 68
Other income, net (4) 139 54 (1) 78 266
Income (loss) before interest,
minority interests and
income taxes 183 580 654 (107) (745) 565
Capital expenditures 626 337 318 36 75 1,392
Identifiable assets 2,668 7,115 8,661 322 1,130 19,896
Investments in and advances to
unconsolidated affiliates - 521 1,932 - 203 2,656
Total assets $2,668 $7,636 $10,593 $ 322 $1,333 $22,552
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 affiliates - 35 168 - 12 215
Interest income 2 4 28 - 7 41
Other income, net (7) 148 (17) - 168 292
Income before interest,
minority interests and
income taxes 200 524 466 - 48 1,238
Capital expenditures 540 175 136 - 13 864
Identifiable assets 2,371 2,363 8,879 - 823 14,436
Investments in and advances to
unconsolidated affiliates - 516 1,005 - 180 1,701
Total assets $2,371 $2,879 $ 9,884 $ - $1,003 $16,137
<FN>
(a) Unaffiliated revenues include sales to unconsolidated affiliates.
(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 46%, 45%, 47% and 39% at December 31, 1998, 1997,
1996 and 1995, respectively.
<TABLE>
Capitalized Costs Relating to Oil and Gas Producing Activities
<CAPTION>
December 31,
(In Millions) 1998 1997
<S> <C> <C>
Proved properties $ 4,630 $ 4,070
Unproved properties 184 221
Total 4,814 4,291
Accumulated depreciation,
depletion and amortization (2,138) (1,904)
Net capitalized costs $ 2,676 $ 2,387
</TABLE>
<TABLE>
Costs Incurred in Oil and Gas Property Acquisition, Exploration
and Development Activities(a)
<CAPTION>
(In Millions) United States Foreign Total
<S> <C> <C> <C>
1998
Acquisition of properties
Unproved $ 33 $ 3 $ 36
Proved 198 13 211
Total 231 16 247
Exploration 82 55 137
Development 298 97 395
Total $611 $168 $779
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
<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, 1998:
<TABLE>
<CAPTION>
(In Millions) United States Foreign Total
<S> <C> <C> <C>
1998
Operating revenues
Associated companies $118 $ 15 $133
Trade 432 193 625
Gains on sales of
reserves and related
assets 29 (3) 26
Total 579 205 784
Exploration expenses,
including dry hole costs 64 25 89
Production costs 99 45 144
Impairment of unproved
oil and gas properties 30 2 32
Depreciation, depletion and
amortization 265 49 314
Income before income taxes 121 84 205
Income tax expense 23 45 68
Results of operations $ 98 $ 39 $137
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
<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, 1998, 1997 and 1996 were based on studies performed by
Enron's engineering staff for reserves in the United States,
Canada, Trinidad, India and China. Opinions by DeGolyer and
MacNaughton, independent petroleum consultants, for the years
ended December 31, 1998, 1997 and 1996 covered producing areas,
in the United States, Canada and Trinidad, containing 39%, 54%
and 64%, respectively, of proved reserves, excluding deep
Paleozoic reserves, of Enron on a net-equivalent-cubic-feet-of-
gas basis. These opinions 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.
<TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves
<CAPTION>
(In Millions) United States Foreign Total
<S> <C> <C> <C>
1998
Future cash inflows(a) $ 5,471 $ 4,724 $10,195
Future production costs (1,281) (1,351) (2,632)
Future development costs (316) (608) (924)
Future net cash flows before
income taxes 3,874 2,765 6,639
Future income taxes (904) (970) (1,874)
Future net cash flows 2,970 1,795 4,765
Discount to present value at
10% annual rate (1,399) (845) (2,244)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(a) $ 1,571 $ 950 $ 2,521
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 $ 751 $ 2,301
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 $ 577 $ 3,069
<FN>
(a) Based on year-end market prices determined at the point
of delivery from the producing unit. Based on natural gas and
crude oil prices as of March 1, 1999, the standardized measure
of discounted future net cash flows for operations in the
United States would have been lower by approximately 23%.
Changes in other producing areas and changes in reported
quantities were not material.
</TABLE>
<TABLE>
Changes in Standardized Measure of Discounted Future Net Cash
Flows
<CAPTION>
(In Millions) United States Foreign Total
<C> <C> <C> <C>
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)
Sales and transfers of oil
and gas produced, net
of production costs (424) (164) (588)
Net changes in prices and
production costs (34) (136) (170)
Extensions, discoveries, additions
and improved recovery, net of
related costs 326 440 766
Development costs incurred 60 56 116
Revisions of estimated development
costs (27) (80) (107)
Revisions of previous quantity
estimates (35) 32 (3)
Accretion of discount 174 113 287
Net change in income taxes 48 (6) 42
Purchases of reserves in place 157 20 177
Sales of reserves in place (34) - (34)
Changes in timing and other (190) (76) (266)
December 31, 1998 $1,571(a) $950 $2,521(a)
<FN>
(a) Includes approximately $155 million, $86 million and $344
million (discounted, pre-tax) related to the reserves in the
Big Piney deep Paleozoic formations at December 31, 1998, 1997
and 1996, 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, 1995 1,218.1(a) 544.0 1,762.1(a)
December 31, 1996 1,325.7(a) 814.3 2,140.0(a)
December 31, 1997 1,349.0(a) 986.3 2,335.3(a)
December 31, 1998 1,429.7(a) 1,077.8 2,507.5(a)
Liquids (MBbl)(b)
December 31, 1995 19,977 23,654 43,631
December 31, 1996 24,868 26,411 51,279
December 31, 1997 27,707 39,108 66,815
December 31, 1998 33,045 45,719 78,764
Natural gas (Bcf)
Net proved reserves at
December 31, 1995 2,654.1(a) 634.4 3,288.5(a)
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) 890.7 3,637.2(a)
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(a) 1,195.5 3,980.3(a)
Revisions of previous
estimates (55.9) 34.1 (21.8)
Purchases in place 123.0 54.9 177.9
Extensions, discoveries and
other additions 272.8 1,200.6 1,473.4
Sales in place (37.5) - (37.5)
Production (233.8) (109.6) (343.4)
Net proved reserves at
December 31, 1998 2,853.4(a) 2,375.5 5,228.9(a)
</TABLE>
<TABLE>
<CAPTION>
United States Foreign Total
<C> <C> <C> <C>
Liquids (MBbl)(b)
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
Revisions of previous
estimates (152) 1,583 1,431
Purchases in place 3,104 - 3,104
Extensions, discoveries and
other additions 9,396 24,467 33,863
Sales in place (1,039) - (1,039)
Production (6,131) (4,309) (10,440)
Net proved reserves at
December 31, 1998 36,827 67,743 104,570
<FN>
(a) Includes 1,180 Bcf related to net proved deep Paleozoic
natural gas reserves.
(b) Includes crude oil, condensate and natural gas liquids.
</TABLE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated March 5, 1999 included in
this Form 8-K, into Enron Corp.'s previously filed
Registration Statement File Nos. 33-13397 (Savings Plan), 33-
34796 (Savings Plan), 33-52261 (Savings Plan), 33-27893
(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), 333-70465
(Debt Securities, Common Stock, Preferred Stock and
Depositary Shares), 333-44133 (244,283 Shares of Common
Stock), 333-38253 (176,634 Shares of Common Stock) and 333-
48193 (1994 Deferral Plan).
ARTHUR ANDERSEN LLP
Houston, Texas
March 18, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 111
<SECURITIES> 0
<RECEIVABLES> 2,831
<ALLOWANCES> 0
<INVENTORY> 514
<CURRENT-ASSETS> 5,933
<PP&E> 15,792
<DEPRECIATION> 5,135
<TOTAL-ASSETS> 29,350
<CURRENT-LIABILITIES> 6,107
<BONDS> 7,357
0
132
<COMMON> 5,117
<OTHER-SE> 1,799
<TOTAL-LIABILITY-AND-EQUITY> 29,350
<SALES> 27,215
<TOTAL-REVENUES> 31,260
<CGS> 26,381
<TOTAL-COSTS> 29,882
<OTHER-EXPENSES> (204)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 550
<INCOME-PRETAX> 878
<INCOME-TAX> 175
<INCOME-CONTINUING> 703
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 703
<EPS-PRIMARY> 2.14
<EPS-DILUTED> 2.02
</TABLE>
