-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, OGZC0q0zTY4Cx9j/Xhw2CiiiuthqHkeK+dlp4xD6B6KXge6lBumW9z6N4CziSppo KzJ+zCVWqXuE7YZP3kKauw== 0001024401-99-000004.txt : 19990319 0001024401-99-000004.hdr.sgml : 19990319 ACCESSION NUMBER: 0001024401-99-000004 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19981231 ITEM INFORMATION: FILED AS OF DATE: 19990318 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENRON CORP/OR/ CENTRAL INDEX KEY: 0001024401 STANDARD INDUSTRIAL CLASSIFICATION: WHOLESALE-PETROLEUM & PETROLEUM PRODUCTS (NO BULK STATIONS) [5172] IRS NUMBER: 470255140 STATE OF INCORPORATION: OR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-13159 FILM NUMBER: 99568150 BUSINESS ADDRESS: STREET 1: 1400 SMITH ST CITY: HOUSTON STATE: TX ZIP: 77002-7369 BUSINESS PHONE: 7138536161 MAIL ADDRESS: STREET 1: 1400 SMITH ST CITY: HOUSTON STATE: TX ZIP: 75002-7369 FORMER COMPANY: FORMER CONFORMED NAME: ENRON OREGON CORP DATE OF NAME CHANGE: 19961008 8-K 1 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 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 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 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:
(In Millions) 1998 1997 1996 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 (a) Tax affected at 35%, except where a specific tax rate applied.
Diluted earnings per share of common stock were as follows:
1998 1997 1996 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 (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.
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):
(In Millions) 1998 1997 1996 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 $1,238
Exploration and Production Enron's exploration and production operations are conducted by Enron Oil & Gas Company (EOG). Wellhead volume and price statistics (including intercompany amounts) are as follows:
1998 1997 1996 Natural gas volumes (MMcf/d)(a) North America 776 758 706 Trinidad 139 113 124 India 56 18 - Total 971 889 830 Average natural gas prices ($/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 (a) Million cubic feet per day or thousand barrels per day, as applicable.
The following analyzes the significant components of IBIT for Exploration and Production:
(In Millions) 1998 1997 1996 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
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.
1998 1997 1996 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 (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.
Significant components of IBIT are as follows:
(In Millions) 1998 1997 1996 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
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:
(In Millions) 1998 1997(a) 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 (a) Represents the period from July 1, 1997 through December 31, 1997.
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:
1998 1997 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 (a) Thousand megawatt-hours. (b) Mills (1/10 cent) per kilowatt-hour.
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:
(In Millions) 1998 1997 1996 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
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):
1998 1997 1996 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 (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.
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:
Estimated Commercial Size/Capacity Operations Date 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 (a) Enron holds varying interests in these projects. (b) Megawatts.
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:
(In Millions) 1998 1997 1996 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
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. Year 2000 Plan Readiness by Enron Business Unit (Mission-Critical Internal Items)
Contingency Inventory Assessment Analysis Conversion Testing Y2K-Ready Plan 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
Year 2000 Plan Readiness by Enron Business Unit (Mission-Critical Outside Entities)
Contingency Inventory Assessment Analysis Conversion Testing Y2K-Ready Plan 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
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. Year 2000 Plan Completion Dates by Enron Business Unit (Mission-Critical Internal Items)
Contingency Inventory Assessment Analysis Conversion Testing Y2K-Ready Plan 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
Year 2000 Plan Completion Dates by Enron Business Unit (Mission-Critical Outside Entities)
Contingency Inventory Assessment Analysis Conversion Testing Y2K-Ready Plan 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
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 Cash Flows
(In Millions) 1998 1997 1996 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
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:
1999 (In Millions) Estimate 1998 1997 1996 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 (a) Excludes exploration expenses of $70 million (estimate), $89 million, $75 million and $68 million for 1999, 1998, 1997 and 1996, respectively.
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:
1999 (In Millions) Estimate 1998 1997 1996 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
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:
December 31, Year ended December 31, 1998 High Low (In Millions) 1998 1997 Average(a) Valuation(a) Valuation(a) 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 - - - - - (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.
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. 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 ENRON CORP. AND SUBSIDIARIES CONSOLIDATED INCOME STATEMENT
Year Ended December 31, (In Millions, except Per Share Amounts) 1998 1997 1996 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 The accompanying notes are an integral part of these consolidated financial statements.
ENRON CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET
December 31, (In Millions) 1998 1997 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 The accompanying notes are an integral part of these consolidated financial statements.
ENRON CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET
December 31, (In Millions, except Shares) 1998 1997 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 The accompanying notes are an integral part of these consolidated financial statements.
ENRON CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31, (In Millions) 1998 1997 1996 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 The accompanying notes are an integral part of these consolidated financial statements.
ENRON CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
(In Millions, except Per Share 1998 1997 1996 Amounts; Shares in Thousands) Shares Amount Shares Amount Shares Amount 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 The accompanying notes are an integral part of these consolidated financial statements.
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:
(In Millions) 1998 1997 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
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.
(In Millions, except Per Share Amounts) 1997 1996 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
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):
Fixed Price Fixed Price Maximum Payor Receiver Terms in years 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 (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.
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:
Average Fair Value Fair Value for the Year Ended as of 12/31/98 12/31/98(a) (In Millions) Assets Liabilities Assets Liabilities 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 (a) Computed using the ending balance at each month end.
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:
1998 1997 Investment Investment (In Millions) Grade(a) Total Grade(a) Total 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 (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.
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:
1998 1997 Carrying Estimated Carrying Estimated (In Millions) Amount Fair Value Amount Fair Value 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 - -
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:
December 31, (In Millions) 1998 1997 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 (a) Amounts represent Enron's interests.
5 INCOME TAXES The components of income before income taxes are as follows:
(In Millions) 1998 1997 1996 United States $197 $96 $551 Foreign 681 (81) 304 $878 $15 $855
Total income tax expense (benefit) is summarized as follows:
(In Millions) 1998 1997 1996 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
The differences between taxes computed at the U.S. federal statutory tax rate and Enron's effective income tax rate are as follows:
(In Millions, except Percentages) 1998 1997 1996 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%
The principal components of Enron's net deferred income tax liability are as follows:
December 31, (In Millions) 1998 1997 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 (a) Includes $(26) million and $216 million in other current liabilities for 1998 and 1997, respectively.
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:
(In Millions) 1998 1997 1996 Income taxes (net of refunds) $ 73 $ 68 $ 89 Interest (net of amounts capitalized) 585 420 290
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:
December 31, (In Millions) 1998 1997 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
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:
Net Ownership December 31, (In Millions) Interest 1998 1997 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 (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.
Enron's equity in earnings (losses) of unconsolidated affiliates is as follows:
(In Millions) 1998 1997 1996 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
Summarized combined financial information of Enron's unconsolidated affiliates is presented below:
December 31, (In Millions) 1998 1997 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 (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.
(In Millions) 1998 1997 1996 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 (a) Enron recognized revenues from unconsolidated affiliates of $142 million in 1998, $219 million in 1997 and $253 million in 1996.
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:
Liquidation December 31, Value (In Millions, except Per Share Amounts and Shares) 1998 1997 Per Share 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 (a) Redeemable under certain circumstances after specified dates. (b) Mature in 2046. (c) Mandatorily redeemable in 2006.
11 COMMON STOCK Earnings Per Share. The computation of basic and diluted earnings per share is as follows:
Year Ended December 31, (In Millions, except per share amounts) 1998 1997 1996 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 (a) For 1997, the dividends and conversion of preferred stock have been excluded from the computation because conversion is antidilutive.
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:
1998 1997 1996 Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise (Shares in Thousands) Shares Price Shares Price Shares Price 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 (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.
The following table summarizes information about stock options outstanding at December 31, 1998 (shares in thousands):
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 $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
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:
(Shares in Thousands) 1998 1997 1996 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
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:
Pension Benefits Other Benefits (In Millions) 1998 1997 1998 1997 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 (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.
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:
1-Percentage 1-Percentage (In Millions) Point Increase Point Decrease Effect on total of service and interest cost components $0.4 $(0.4) Effect on postretirement benefit obligation 5.4 (4.5)
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:
(In Millions, Except First Second Third Fourth Total Per Share Amounts) Quarter Quarter Quarter Quarter Year 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) (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.
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
Year Ended December 31, (In Millions) 1998 1997 1996 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
Business Segments
Wholesale Exploration Transportation Energy Retail Corporate and and Operations Energy and (In Millions) Production Distribution and Services Services Other(c) Total 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 (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.
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. Capitalized Costs Relating to Oil and Gas Producing Activities
December 31, (In Millions) 1998 1997 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
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities(a)
(In Millions) United States Foreign Total 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 (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.
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:
(In Millions) United States Foreign Total 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 (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.
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. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
(In Millions) United States Foreign Total 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 (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.
Changes in Standardized Measure of Discounted Future Net Cash Flows
(In Millions) United States Foreign Total 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) (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.
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:
United States Foreign Total 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)
United States Foreign Total 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 (a) Includes 1,180 Bcf related to net proved deep Paleozoic natural gas reserves. (b) Includes crude oil, condensate and natural gas liquids.
EX-23 2 CONSENTS OF EXPERTS AND COUNSEL 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 EX-27 3 ARTICLE 5 FDS FOR YEAR-END 1998
5 1,000,000 12-MOS DEC-31-1998 DEC-31-1998 111 0 2,831 0 514 5,933 15,792 5,135 29,350 6,107 7,357 0 132 5,117 1,799 29,350 27,215 31,260 26,381 29,882 (204) 0 550 878 175 703 0 0 0 703 2.14 2.02
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