-----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, I+Orpg8mlX3pNm7za3ZieWcyOqEFh8i8boa/SGI132Fc34A10TBOotKrb3k+q91T 1Mr4Hx0Zd7aEuNUC3Q02eQ== 0000950129-99-003013.txt : 19990708 0000950129-99-003013.hdr.sgml : 19990708 ACCESSION NUMBER: 0000950129-99-003013 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990706 ITEM INFORMATION: FILED AS OF DATE: 19990707 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SONAT INC CENTRAL INDEX KEY: 0000092236 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 630647939 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-07179 FILM NUMBER: 99659769 BUSINESS ADDRESS: STREET 1: 1900 FIFTH AVENUE NORTH STREET 2: AMSOUTH SONAT TOWER CITY: BIRMINGHAM STATE: AL ZIP: 35203 BUSINESS PHONE: 2053253800 MAIL ADDRESS: STREET 1: PO BOX 2563 CITY: BIRMINGHAM STATE: AL ZIP: 35202 FORMER COMPANY: FORMER CONFORMED NAME: SOUTHERN NATURAL RESOURCES INC DATE OF NAME CHANGE: 19820305 8-K 1 SONAT, INC. - DATED 07/06/99 1 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 (Date of earliest event reported): July 6, 1999 SONAT INC. (Exact name of registrant as specified in its charter) Delaware 1-7179 63-0647939 (State or other jurisdiction (Commission File Number) (IRS Employer Identification No.) of incorporation) AmSouth-Sonat Tower, Birmingham, Alabama 35203 (Address of principal executive offices) (Zip Code)
(205) 325-3800 (Registrant's telephone number, including area code) 2 Item 5. Other Events. As previously reported, Sonat Inc. ("Sonat") and El Paso Energy Corporation ("El Paso Energy") have entered into the Second Amended and Restated Agreement and Plan of Merger (the "Merger Agreement"), which provides for the merger of Sonat into El Paso Energy (the "Merger"). Sonat is filing this report to incorporate into its Registration Statements under the Securities Act of 1933 that incorporate this Form 8-K certain information concerning El Paso Energy and the Merger. Accordingly, set forth on the following pages are (i) certain pro forma financial information concerning the Merger and (ii) El Paso Energy's Annual Report on Form 10-K for 1998 and Quarterly Report on Form 10-Q for the quarter ended March 31, 1999. 2 3 Pro forma financial information FINANCIAL INFORMATION On June 10, 1999, El Paso Energy stockholders and Sonat stockholders approved the Merger Agreement. Presented below are unaudited pro forma condensed combined financial statements reflecting the merger using the pooling of interests method of accounting in accordance with United States generally accepted accounting principles. Under this accounting method, El Paso Energy's and Sonat's balance sheets and income statements are treated as if they had always been combined for accounting and financial reporting purposes. This information is included to give you a better understanding of what the combined results of operations and financial position of El Paso Energy and Sonat may have looked like had the merger occurred on an earlier date. The pro forma information reflecting the merger assumes (1) each share of Sonat common stock will be converted into one share of El Paso Energy common stock and (2) El Paso Energy will issue a total of approximately 110 million shares in the merger. The unaudited pro forma condensed combined balance sheet as of March 31, 1999, assumes the merger had been completed on March 31, 1999. The unaudited pro forma condensed combined income statements for the three months ended March 31, 1999, and three years ended December 31, 1998, assume the merger had been completed on January 1, 1996, the beginning of the earliest period presented. Accounting policy differences and intercompany balances between El Paso Energy and Sonat have been determined to be immaterial and, accordingly, the pro forma condensed combined financial statements have not been adjusted for these differences. The unaudited pro forma condensed combined financial statements are presented for illustrative purposes only and are not necessarily indicative of the operating results or financial position that would have been achieved had the merger of El Paso Energy and Sonat been consummated as of the beginning of the periods presented, nor are they necessarily indicative of the future operating results or financial position of El Paso Energy. The unaudited pro forma condensed combined financial statements do not give effect to any operating efficiencies or cost savings that may result from the integration of El Paso Energy's and Sonat's operations. These unaudited pro forma condensed combined financial statements should be read in conjunction with the historical financial statements and related notes of El Paso Energy and Sonat included in their respective Annual Reports on Form 10-K for the year ended December 31, 1998, and Quarterly Reports on Form 10-Q for the three months ended March 31, 1999. The historical financial information presented for Sonat includes certain reclassifications to conform to El Paso Energy's presentation. These reclassifications have no impact on results of operations or total stockholders' equity. 3 4 UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET AS OF MARCH 31, 1999 (IN MILLIONS) ASSETS
EL PASO SONAT COMBINED HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA ---------- ---------- ----------- --------- Total current assets............................... $ 1,223 $ 639 $ -- $ 1,862 Property, plant and equipment, net................. 7,191 2,464 -- 9,655 Other.............................................. 2,052 863 -- 2,915 ------- ------ ----- ------- Total assets............................. $10,466 $3,966 $ -- $14,432 ======= ====== ===== ======= LIABILITIES & STOCKHOLDERS' EQUITY Total current liabilities.......................... $ 1,935 $1,510 $ 133(a) $ 3,527 (51)(c) ------- ------ ----- ------- Long-term debt, less current maturities............ 3,082 1,098 -- 4,180 ------- ------ ----- ------- Deferred income taxes.............................. 1,589 90 (22)(c) 1,657 ------- ------ ----- ------- Other.............................................. 1,008 170 -- 1,178 ------- ------ ----- ------- Company-obligated mandatorily redeemable convertible preferred securities of El Paso Energy Capital Trust I........................... 325 -- -- 325 ------- ------ ----- ------- Minority interest.................................. 365 11 -- 376 ------- ------ ----- ------- Stockholders' equity Common stock..................................... 377 111 219(b) 707 Additional paid-in capital....................... 1,465 75 (279)(b) 1,261 Retained earnings................................ 494 968 (192)(a) 1,343 73(c) Other............................................ (174) (67) 60(b) (122) 59(a) ------- ------ ----- ------- Total stockholders' equity............... 2,162 1,087 (60) 3,189 ------- ------ ----- ------- Total liabilities and stockholders' equity................................. $10,466 $3,966 $ -- $14,432 ======= ====== ===== =======
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Balance Sheet. 4 5 NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET (a) Reflects estimated costs of $192 million associated with the merger of El Paso Energy and Sonat. These costs consist of (1) $142 million of costs for compensation related programs under which certain benefits of El Paso Energy and Sonat personnel accelerate and vest as a result of the change in control associated with the merger and (2) $50 million of transaction costs, which include legal, accounting, and financial advisory services. (b) Reflects the exchange of one share of El Paso Energy common stock for each share of outstanding Sonat common stock, as provided in the merger agreement and the cancellation of $60 million of Sonat treasury stock. (c) Reflects the income tax consequences of the $192 million of costs associated with the merger assuming an effective income tax rate of 38%. 5 6 UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME FOR THE THREE MONTHS ENDED MARCH 31, 1999 (IN MILLIONS, EXCEPT PER COMMON SHARE DATA)
EL PASO SONAT COMBINED HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA ---------- ---------- ----------- --------- Operating revenues................................. $1,494 $ 774 $-- $2,268 ------ ------ --- ------ Operating expenses Cost of gas and other products................... 1,068 564 -- 1,632 Operation and maintenance........................ 183 77 -- 260 Depreciation, depletion and amortization......... 71 75 -- 146 Ceiling test charges............................. -- 352 -- 352 Other............................................ 27 12 -- 39 ------ ------ --- ------ 1,349 1,080 -- 2,429 ------ ------ --- ------ Operating income (loss)............................ 145 (306) -- (161) Interest and debt expense.......................... 73 35 -- 108 Other income, net.................................. (45) (15) -- (60) ------ ------ --- ------ Income (loss) before income taxes, minority interest, and cumulative effect of accounting change........................................... 117 (326) -- (209) Income tax expense (benefit)....................... 40 (115) -- (75) Minority interest.................................. 6 1 -- 7 ------ ------ --- ------ Income (loss) before cumulative effect of accounting change................................ 71 (212) -- (141) Cumulative effect of accounting change, net of income tax....................................... (13) -- -- (13) ------ ------ --- ------ Net income (loss).................................. $ 58 $ (212) $-- $ (154) ====== ====== === ====== Basic earnings per common share Income (loss) before cumulative effect of accounting change.............................. $ 0.62 $(0.62) Cumulative effect of accounting change, net of income tax..................................... (0.12) (0.06) ------ ------ Net income (loss)................................ $ 0.50 $(0.68) ====== ====== Diluted earnings per common share Income (loss) before cumulative effect of accounting change.............................. $ 0.58 $(0.62)(a) Cumulative effect of accounting change, net of income tax..................................... (0.10) (0.06)(a) ------ ------ Net income (loss)................................ $ 0.48 $(0.68)(a) ====== ====== Basic average common shares outstanding............ 116 110(b) 226 ====== === ====== Diluted average common shares outstanding.......... 128 111(b) 239 ====== === ======
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Statements of Income. 6 7 UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1998 (IN MILLIONS, EXCEPT PER COMMON SHARE DATA)
EL PASO SONAT COMBINED HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA ---------- ---------- ----------- --------- Operating revenues................................. $5,782 $3,710 $-- $9,492 ------ ------ --- ------ Operating expenses Cost of gas and other products................... 4,212 2,745 -- 6,957 Operation and maintenance........................ 707 281 -- 988 Depreciation, depletion and amortization......... 269 349 -- 618 Ceiling test charges............................. -- 1,035 -- 1,035 Other............................................ 88 63 -- 151 ------ ------ --- ------ 5,276 4,473 -- 9,749 ------ ------ --- ------ Operating income (loss)............................ 506 (763) -- (257) Interest and debt expense.......................... 267 137 -- 404 Other income, net.................................. (138) (67) -- (205) ------ ------ --- ------ Income (loss) before income taxes and minority interest......................................... 377 (833) -- (456) Income tax expense (benefit)....................... 127 (299) -- (172) ------ ------ --- ------ Income (loss) before minority interest............. 250 (534) -- (284) Minority interest.................................. 25 (3) -- 22 ------ ------ --- ------ Net income (loss).................................. $ 225 $ (531) $-- $ (306) ====== ====== === ====== Basic earnings (loss) per common share............ $ 1.94 $(1.35) ====== ====== Diluted earnings (loss) per common share.......... $ 1.85 $(1.35)(a) ====== ====== Basic average common shares outstanding............ 116 110(b) 226 ====== === ====== Diluted average common shares outstanding.......... 126 111(b) 237 ====== === ======
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Statements of Income. 7 8 UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1997 (IN MILLIONS, EXCEPT PER COMMON SHARE DATA)
EL PASO SONAT COMBINED HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA ---------- ---------- ----------- --------- Operating revenues................................. $5,638 $4,372 $-- $10,010 ------ ------ --- ------- Operating expenses Cost of gas and other products................... 4,125 3,174 -- 7,299 Operation and maintenance........................ 664 385 -- 1,049 Depreciation, depletion and amortization......... 236 398 -- 634 Other............................................ 92 43 -- 135 ------ ------ --- ------- 5,117 4,000 -- 9,117 ------ ------ --- ------- Operating income................................... 521 372 -- 893 Interest and debt expense.......................... 238 110 -- 348 Other income, net.................................. (57) (66) -- (123) ------ ------ --- ------- Income before income taxes and minority interest... 340 328 -- 668 Income tax expense................................. 129 107 -- 236 ------ ------ --- ------- Income before minority interest.................... 211 221 -- 432 Minority interest.................................. 25 3 -- 28 ------ ------ --- ------- Net income......................................... $ 186 $ 218 $-- $ 404 ====== ====== === ======= Basic earnings per common share.................... $ 1.64 $ 1.80 ====== ======= Diluted earnings per common share.................. $ 1.59 $ 1.76 ====== ======= Basic average common shares outstanding............ 114 110(b) 224 ====== === ======= Diluted average common shares outstanding.......... 117 112(b) 229 ====== === =======
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Statements of Income. 8 9 UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1996 (IN MILLIONS, EXCEPT PER COMMON SHARE DATA)
EL PASO SONAT COMBINED HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA ---------- ---------- ----------- --------- Operating revenues................................. $3,012 $3,204 $-- $6,216 ------ ------ --- ------ Operating expenses Cost of gas and other products................... 2,277 2,039 -- 4,316 Operation and maintenance........................ 322 301 -- 623 Depreciation, depletion and amortization......... 101 384 -- 485 Employee separation and asset impairment charge........................................ 99 -- -- 99 Other............................................ 43 48 -- 91 ------ ------ --- ------ 2,842 2,772 -- 5,614 ------ ------ --- ------ Operating income................................... 170 432 -- 602 Interest and debt expense.......................... 110 101 -- 211 Other income, net.................................. (5) (53) -- (58) ------ ------ --- ------ Income before income taxes and minority interest... 65 384 -- 449 Income tax expense................................. 25 125 -- 150 ------ ------ --- ------ Income before minority interest.................... 40 259 -- 299 Minority interest.................................. 2 3 -- 5 ------ ------ --- ------ Net income......................................... $ 38 $ 256 $-- $ 294 ====== ====== === ====== Basic earnings per common share.................... $ 0.53 $ 1.62 ====== ====== Diluted earnings per common share.................. $ 0.52 $ 1.59 ====== ====== Basic average common shares outstanding............ 72 110(b) 182 ====== === ====== Diluted average common shares outstanding.......... 73 112(b) 185 ====== === ======
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Statements of Income. 9 10 NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENTS OF INCOME (a) As required by the accounting rules, we have excluded additional dilutive securities such as options in determining diluted earnings (loss) per common share. If we had included those securities, we would have shown less of a loss per common share. (b) The basic and diluted common shares adjustments reflect the exchange of one share of El Paso Energy common stock for each share of Sonat common stock contemplated by the merger agreement. 10 11 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------- FORM 10-K (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO . COMMISSION FILE NUMBER 1-14365 EL PASO ENERGY CORPORATION (Exact Name of Registrant as Specified in Its Charter) DELAWARE 76-0568816 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) EL PASO ENERGY BUILDING 1001 LOUISIANA STREET HOUSTON, TEXAS 77002 (Address of Principal Executive Offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 420-2131 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- Common Stock, par value $3 per New York Stock Exchange share............................... Preferred Stock Purchase Rights....... New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT. Aggregate market value of the voting stock (which consists solely of shares of common stock) held by non-affiliates of the registrant as of March 5, 1999, computed by reference to the closing sale price of the registrant's common stock on the New York Stock Exchange on such date: $4,340,497,918 INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE. Common Stock, par value $3 per share. Shares outstanding on March 5, 1999: 120,989,489 DOCUMENTS INCORPORATED BY REFERENCE List hereunder the following documents if incorporated by reference and the part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: Portions of El Paso Energy Corporation's definitive Proxy Statement for the 1999 Annual Meeting of Stockholders, to be filed not later than 120 days after the end of the fiscal year covered by this report, are incorporated by reference into Part III. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 12 EL PASO ENERGY CORPORATION TABLE OF CONTENTS
CAPTION PAGE ------- ---- Glossary.............................................................. ii PART I Item 1. Business.................................................... 1 Item 2. Properties.................................................. 13 Item 3. Legal Proceedings........................................... 13 Item 4. Submission of Matters to a Vote of Security Holders......... 13 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................................... 14 Item 6. Selected Financial Data..................................... 15 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 16 Risk Factors -- Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995... 36 Item 7A. Quantitative and Qualitative Disclosures About Market Risk...................................................... 39 Item 8. Financial Statements and Supplementary Data................. 42 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................. 78 PART III Item 10. Directors and Executive Officers of the Registrant.......... 78 Item 11. Executive Compensation...................................... 78 Item 12. Security Ownership of a Certain Beneficial Owner and Management................................................ 78 Item 13. Certain Relationships and Related Transactions.............. 78 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K....................................................... 78 Signatures.................................................. 82
i 13 GLOSSARY The following abbreviations, acronyms, or defined terms used in this Form 10-K are defined below: ALJ............................... Administrative Law Judge BBtu(/d).......................... Billion British thermal units (per day) Bcf(/d)........................... Billion cubic feet (per day) Board............................. Board of directors of El Paso Energy Corporation CAPSA............................. Companias Asociadas Petroleras SA, a privately held integrated energy company in Argentina Company........................... El Paso Energy Corporation and its subsidiaries which, on August 1, 1998, became the successor company to El Paso Natural Gas Company Court of Appeals.................. United States Court of Appeals for the District of Columbia Circuit DeepTech.......................... DeepTech International Inc., a wholly owned subsidiary of El Paso Energy Corporation Distributions..................... Various intercompany transfers and distributions which restructured, divided and separated the business, assets and liabilities of Old Tenneco and its subsidiaries so that all the assets, liabilities and operations related to the automotive parts, packaging and administrative services businesses and the shipbuilding business were spun-off to Old Tenneco's then existing common stockholders Dynegy............................ Dynegy Inc., formerly known as NGC Corporation EBIT.............................. Earnings before interest expense and income taxes, excluding affiliated interest income East Tennessee.................... East Tennessee Natural Gas Company, a wholly owned subsidiary of El Paso Tennessee Pipeline Co. Edison............................ Southern California Edison Company EPA............................... United States Environmental Protection Agency EPEC.............................. El Paso Energy Corporation, unless the context otherwise requires EPEI.............................. El Paso Energy International Company, a wholly owned subsidiary of El Paso Tennessee Pipeline Co. EPEM.............................. El Paso Energy Marketing Company, a wholly owned indirect subsidiary of El Paso Tennessee Pipeline Co. EPFS.............................. El Paso Field Services Company, a wholly owned subsidiary of El Paso Tennessee Pipeline Co. EPNG.............................. El Paso Natural Gas Company, a wholly owned subsidiary of El Paso Energy Corporation subsequent to August 1, 1998 EPTPC............................. El Paso Tennessee Pipeline Co. (formerly Tenneco Inc.), a direct subsidiary of El Paso Energy Corporation FERC.............................. Federal Energy Regulatory Commission GSR............................... Gas supply realignment IRS............................... Internal Revenue Service Leviathan......................... Leviathan Gas Pipeline Partners, L.P., a publicly held Delaware limited partnership MBbls............................. Thousand barrels Merger............................ The acquisition of El Paso Tennessee Pipeline Co. by El Paso Natural Gas Company in December 1996 Mgal/d............................ Thousand gallons per day Midwestern........................ Midwestern Gas Transmission Company, a wholly owned subsidiary of El Paso Tennessee Pipeline Co.
ii 14 MMcf/d............................ Million cubic feet per day Mdth/d............................ Thousand decatherms per day MPC............................... Mojave Pipeline Company, a wholly owned indirect partnership of El Paso Natural Gas Company MW(s)............................. Megawatt(s) New Tenneco....................... Tenneco Inc., subsequent to the Merger and Distributions, consisting of the automotive parts, packaging and administrative services businesses Old Tenneco....................... Tenneco Inc. (renamed El Paso Tennessee Pipeline Co.), prior to its acquisition by the Company PCB(s)............................ Polychlorinated biphenyl(s) PG&E.............................. Pacific Gas & Electric Company PLN............................... Perusahaan Listrik Negara, the Indonesian government owned electric utility Program........................... Continuous Odd-Lot Stock Sales Program PRP(s)............................ Potentially Responsible Party(ies) SFAS.............................. Statement of Financial Accounting Standards SoCal............................. Southern California Gas Company TGP............................... Tennessee Gas Pipeline Company, a wholly owned subsidiary of El Paso Tennessee Pipeline Co.
iii 15 PART I ITEM 1. BUSINESS GENERAL On August 1, 1998, EPEC succeeded EPNG as the publicly traded parent corporation in a holding company reorganization. In the reorganization, EPNG, a Delaware corporation formed in 1928, and its subsidiaries became direct and indirect subsidiaries of the Company. EPEC, also a Delaware corporation, was incorporated in 1998. The New York Stock Exchange ticker symbol used by EPEC following the reorganization remains unchanged as "EPG." The Company's principal operations include the interstate and intrastate transportation, gathering and processing of natural gas; the marketing of natural gas, power, and other commodities; and the development and operation of energy infrastructure facilities worldwide. The Company owns or has interests in over 28,000 miles of interstate and intrastate pipeline connecting the nation's principal natural gas supply regions to the four largest consuming regions in the United States, namely the Gulf Coast, California, the Northeast and the Midwest. The Company's natural gas transmission operations include one of the nation's largest mainline natural gas transmission systems which is comprised of five interstate pipeline systems: the El Paso Natural Gas pipeline, the Tennessee Gas pipeline, the Midwestern Gas Transmission pipeline, the East Tennessee Natural Gas pipeline, and the Mojave Pipeline. In addition to its interstate transmission services, the Company provides related services, including natural gas gathering, products extraction, dehydration, purification, compression, and intrastate transmission. These services include gathering of natural gas from more than 10,000 natural gas wells with approximately 11,000 miles of gathering lines, and 23 natural gas processing and treating facilities located in some of the most prolific and active production areas of the United States, including the San Juan and Permian Basins and in east Texas, south Texas, Louisiana, and the Gulf of Mexico. The Company conducts intrastate transmission operations through its interests in four Texas intrastate systems, which include the Oasis Pipeline running from west Texas to Katy, Texas, the Channel Pipeline extending from south Texas to the Houston Ship Channel, and the Shoreline and Tomcat gathering systems which gather gas from offshore Texas. The Company's marketing activities include the marketing and trading of natural gas, power, and petroleum products, as well as providing integrated price risk management services associated with these commodities. The Company also participates in the development and ownership of domestic power generation facilities, and other power-related assets and joint ventures. The Company's international activities focus on the development and operation of international energy infrastructure projects and include ownership interests in three major operating natural gas transmission systems in Australia and natural gas transmission systems and power generation facilities currently in operation or under construction in Argentina, Bolivia, Brazil, Chile, the Czech Republic, Hungary, Indonesia, Mexico, Pakistan, Peru, the United Kingdom, Bangladesh, the Philippines and China. The Company also has an interest in three operating domestic power generation plants. In August 1998, the Company completed the acquisition of DeepTech by merging DeepTech with a subsidiary of the Company. As a result of the acquisition, the Company owns 100 percent of the general partner of Leviathan, and a 27.3 percent effective ownership interest in Leviathan, with the remaining interest held publicly. The acquisition was accounted for as a purchase with a total purchase price of approximately $422 million, net of cash acquired. Leviathan is the largest independent gatherer of natural gas in the Gulf of Mexico and owns interests in pipeline systems which transported an average of approximately 3.1 Bcf/d in 1998. These pipeline systems serve a large portion of the outer continental shelf and provide access to the prolific deepwater trend of the Gulf of Mexico. Leviathan has ownership interests in the High Island Offshore system, the U-T Offshore system, the Stingray Pipeline system, the Nautilus/Manta Ray Offshore system, the Viosca Knoll Gathering system and the Poseidon Oil Pipeline system. 1 16 In December 1996, the Company completed its $4 billion acquisition of EPTPC in a transaction accounted for as a purchase. In the Merger, Old Tenneco changed its name to EPTPC. Prior to the Merger, Old Tenneco and its subsidiaries effected various intercompany transfers and restructurings so that in the Distributions all the assets, liabilities and operations related to their automotive parts, packaging, and administrative services businesses (collectively, the "Industrial Business") and their shipbuilding business (the "Shipbuilding Business") were spun-off to Old Tenneco's then existing common stockholders. Following the Distributions, EPTPC's business consisted principally of the regulated energy operations, including the interstate transportation of natural gas, as well as non-regulated energy operations such as gas marketing, intrastate pipelines, international pipelines and power generation, and domestic power generation. This acquisition created the nation's first coast-to-coast natural gas pipeline system and furthered the Company's efforts to expand its presence in non-regulated portions of the energy industry. EPEC owns 100 percent of the common equity and greater than 80 percent of the combined equity value of EPTPC. The remaining combined equity of EPTPC consists of $300 million of preferred stock issued in a public offering by Old Tenneco in November 1996, which remains outstanding. For a further discussion of these acquisitions, see Item 8, Financial Statements and Supplementary Data, Note 2. SEGMENTS Beginning in 1998, the Company segregated its business activities into five segments: Tennessee Gas Pipeline segment, El Paso Natural Gas segment, El Paso Field Services segment, El Paso Energy Marketing segment, and El Paso Energy International segment. These segments are strategic business units that offer a variety of different energy products and services. They are managed separately, as each business unit requires different technology and marketing strategies. For information relating to operating revenues, operating income, EBIT, and identifiable assets attributable to each segment, see Item 8, Financial Statements and Supplementary Data, Note 13. Set forth below is a description of the principal business activities conducted by each of the Company's segments:
Tennessee Gas Pipeline Provides interstate natural gas pipeline transportation to the northeast, midwest and mid-Atlantic sections of the U.S., including the states of Tennessee and Virginia as well as the New York City, Chicago and Boston metropolitan areas. Such transportation is conducted through the interstate pipeline systems of TGP, Midwestern and East Tennessee. El Paso Natural Gas Provides interstate natural gas pipeline transportation primarily to the California market. Such transportation is conducted by the EPNG and MPC interstate pipeline systems. El Paso Field Services Provides natural gas gathering, products extraction, dehydration, purification, compression and intrastate natural gas transmission services. El Paso Energy Marketing Markets and trades natural gas, power and petroleum products and provides integrated risk management services. El Paso Energy International Develops and operates energy infrastructure facilities worldwide.
In addition, the Company participates in the development and ownership of domestic power generation projects. 2 17 TENNESSEE GAS PIPELINE The TGP system. The TGP system consists of approximately 14,700 miles of pipeline with a design capacity of 5,512 MMcf/d. During 1998, TGP transported natural gas volumes averaging approximately 80 percent of its capacity. The TGP system serves the northeast section of the U.S., including the New York City and Boston metropolitan areas. The multiple-line system begins in the gas-producing regions of south Texas and Louisiana, including the Gulf of Mexico. The Midwestern system. The Midwestern system consists of approximately 400 miles of pipeline with a design capacity of 785 MMcf/d. During 1998, Midwestern transported natural gas volumes averaging approximately 35 percent of its capacity. The Midwestern system extends from a connection with the TGP system at Portland, Tennessee, to Chicago and principally serves the Chicago metropolitan area. The East Tennessee system. The East Tennessee system consists of approximately 1,100 miles of pipeline with a design capacity of 675 MMcf/d. During 1998, East Tennessee transported natural gas volumes averaging approximately 45 percent of its capacity. The East Tennessee system serves the states of Tennessee, Virginia and Georgia and connects with the TGP system in Springfield and Lobelville, Tennessee. Other. The Company increased its ownership interest in the Portland Natural Gas Transmission ("Portland") system from 17.8 percent to approximately 19 percent in April 1998. Portland is a 292-mile interstate natural gas pipeline with initial capacity of 178 MMcf/d extending from the Canadian border near Pittsburg, New Hampshire to Dracut, Massachusetts. In April 1998, Portland secured $256 million in non-recourse project financing. Construction started in June 1998, with an estimated total cost of $423 million. Portland commenced commercial operations in March of 1999. From time to time, the Company holds open seasons in an effort to capitalize on pipeline expansion opportunities. Currently, TGP has completed an open season for the Eastern Express Project 2000 to provide gas transportation for the growing markets in the northeast. As a result, TGP will be filing an application before FERC for the expansion in the first quarter of 1999 to begin service in 2000. TGP has also filed an application with FERC to construct an international border crossing at Reynosa, Tamaulipas, Mexico, and interconnect with Pemex Gas y Petroquimica Basica, a Mexican state-owned company ("Pemex") to provide the import of gas from Mexico. The border crossing service is expected to begin in 1999. EL PASO NATURAL GAS The EPNG system. The EPNG system consists of approximately 9,800 miles of pipeline with a design capacity of 4,744 MMcf/d. During 1998, EPNG transported natural gas volumes averaging approximately 77 percent of its capacity. The EPNG system serves California, which is its single largest market, and also serves markets in Nevada, Arizona, New Mexico, Texas, Oklahoma, and northern Mexico. The EPNG system delivers natural gas from the San Juan Basin of northern New Mexico and southern Colorado, and also accesses natural gas supplies in the Permian and Anadarko Basins of West Texas. The MPC system. The MPC system consists of approximately 400 miles of pipeline with a design capacity of approximately 400 MMcf/d. During 1998, MPC transported natural gas volumes averaging approximately 81 percent of its capacity. The MPC system is connected with the EPNG transmission system at Topock, Arizona and Kern River Gas Transmission Company in California and extends to customers in the vicinity of Bakersfield, California. REGULATORY ENVIRONMENT The interstate systems are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Industry Restructuring. In the mid-1980s, FERC initiated a series of actions which ultimately had the effect of substantially removing interstate pipelines from the gas purchase and resale business and confining their role to transportation of gas owned by others. In Order No. 436, issued in 1985, FERC began this transition by requiring interstate pipelines to provide non-discriminatory access to their facilities for all 3 18 transporters of natural gas. This requirement enabled consumers to purchase their own gas and have it transported on the interstate pipeline system, rather than purchase gas from the pipelines. The transition was completed with Order No. 636, issued in 1992, in which FERC required all interstate pipelines to "unbundle" their sales and transportation services so that the transportation services they provided to third parties would be "comparable" to the transportation services provided to gas owned by the pipeline. FERC's stated purpose was to ensure that the pipelines' monopoly over the transportation of natural gas did not distort the competition in the gas producer sales market, which had, by then, been essentially deregulated. One of the obstacles to this transition was the existence of long-term gas purchase contracts between pipelines and producers which required the pipelines to take or pay for a significant percentage of the gas the producer was capable of delivering. While FERC did not deal with this issue initially, it eventually adopted rate recovery procedures which facilitated negotiations between pipelines and producers to address take-or-pay issues. Such procedures were established in Order Nos. 500, 528 and 636, in the last of which FERC provided that pipelines could recover 100 percent of the costs prudently incurred to terminate their gas purchase obligations. In July 1996, the Court of Appeals issued its decision upholding, in large part, Order No. 636. TGP. In December 1994, TGP filed for a general rate increase with FERC and in October 1996, FERC approved the settlement resolving that proceeding. The settlement included a structural rate design change that resulted in a larger portion of TGP's transportation revenues being dependent upon throughput. One party, a competitor of TGP, filed a petition for review of the FERC orders with the Court of Appeals. The Court of Appeals remanded the case to FERC to respond to the competitor's argument that TGP's cost allocation methodology deterred the development of market centers (centralized locations where buyers and sellers can physically exchange gas) and, at FERC's request, comments were filed in January 1999. EPNG. In June 1995, EPNG filed with FERC for approval of new system rates for mainline transportation to be effective January 1, 1996. In March 1996, EPNG filed a comprehensive offer of settlement to resolve that proceeding as well as issues surrounding certain contract reductions and expirations that were to occur from January 1, 1996 through December 31, 1997. In April 1997, FERC approved EPNG's settlement as filed and determined that only the contesting party, Edison, should be severed for separate determination of the rates it directly pays EPNG. In July 1997, FERC issued an order denying requests for rehearing of the April 1997 order, and the settlement was implemented effective July 1, 1997. Hearings to determine Edison's rates were completed in May 1998, and an initial decision was issued by the presiding ALJ in July 1998. EPNG and Edison have filed exceptions to the decision with FERC. If the ALJ's decision is affirmed by FERC, EPNG believes that the resulting rates to Edison would be such that no significant, if any, refunds in excess of the amounts reserved would be required. Pending the final outcome, Edison continues to pay the filed rates, subject to refund, and EPNG continues to provide a reserve for such potential refunds. Edison filed with the Court of Appeals a petition for review of FERC's April 1997 and July 1997 orders, in which it challenged the propriety of FERC's approving the settlement over Edison's objections to the settlement in its capacity as a customer of SoCal. In December 1998, the Court of Appeals issued its decision vacating and remanding FERC's order. EPNG will file a motion with FERC proposing procedures for FERC to address deficiencies which the Court of Appeals found in FERC's earlier orders. EPNG cannot predict the outcome with certainty but it believes that FERC will ultimately approve the settlement. For a further discussion of regulatory matters related to TGP and EPNG, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. MARKETS AND COMPETITION The Interstate Systems face varying degrees of competition from alternative energy sources, such as electricity, hydroelectric power, coal, and fuel oil. The potential consequences of proposed and ongoing restructuring and deregulation of the electric power industry are currently unclear. It may benefit the natural gas industry by creating more demand for natural gas turbine generated electric power, or it may hamper demand by allowing more effective use of surplus electric capacity through increased wheeling as a result of open access. At this time, the Company is not projecting a significant change in natural gas demand as a result of such restructuring. 4 19 The TGP System. Customers of TGP include natural gas producers, marketers and end-users, as well as other gas transmission and distribution companies, none of which individually represents more than 10 percent of the revenues on TGP's system. Substantially all of the revenues of TGP are generated under long-term natural gas transmission contracts. Contracts representing approximately 70 percent of TGP's firm transportation capacity will be expiring over the next two years, principally in November 2000. Although TGP cannot predict how much capacity will be resubscribed, a majority of the expiring contracts cover service to northeastern markets, where there is currently little excess capacity. Several projects, however, have been proposed to deliver incremental volumes to these markets. Although TGP is actively pursuing the renegotiation, extension and/or replacement of these contracts, TGP cannot give any assurance that it will be able to extend or replace these contracts (or a substantial portion thereof) or that the terms of any renegotiated contracts will be as favorable to TGP as the existing contracts. In a number of key markets, TGP faces competitive pressure from other major pipeline systems, enabling local distribution companies and end-users to choose a supplier or switch suppliers based on the short-term price of natural gas and the cost of transportation. Competition among pipelines is particularly intense in TGP's supply areas, Louisiana and Texas. In some instances, TGP has had to discount its transportation rates in order to maintain market share. The renegotiation of TGP's expiring contracts may be adversely affected by the foregoing competitive factors. The EPNG System. EPNG faces significant competition from three other companies -- Transwestern Pipeline Company, Kern River Gas Transmission Company, and PG&E -- all of which transport natural gas to the California market. The combined capacity of these three companies and EPNG to the California market is approximately 6.9 Bcf/d. In 1998, the demand for interstate pipeline capacity to California averaged 5.1 Bcf/d. Competition generally occurs on the basis of the delivered cost of natural gas, including transportation costs, into the SoCal and PG&E distribution systems. In addition to being the principal transporter to certain markets east of California, EPNG maintains a significant competitive position in the California market because its pipeline is currently the lowest-cost transporter of, and the principal means of moving, natural gas from the San Juan Basin to the California border. EPNG's current capacity to deliver natural gas to California is approximately 3.3 Bcf/d, equivalent to approximately 48 percent of the total interstate pipeline capacity serving that state. Natural gas shipped to California across the EPNG System represented approximately 33 percent of the natural gas consumed in the state in 1998. The significant customers served by EPNG in California during 1998 include SoCal, with capacity of 1,150 MMcf/d under contract until August 2006, and Dynegy, with capacity of 1,311 MMcf/d under contract until December 1999. Interstate pipeline capacity utilization to California is currently approximately 74 percent and is not expected to reach 100 percent until sometime in the next decade, assuming no new interstate pipeline construction. Currently, EPNG has firm transportation contracts covering all of its available capacity to California. As a part of its effort to remarket capacity relinquished by PG&E at the end of 1997, EPNG entered into three contracts with Dynegy for the sale of all of its then available firm capacity for a two-year period beginning January 1, 1998 at rates negotiated pursuant to EPNG's tariff provisions and FERC policies. For a further discussion of capacity relinquishments, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. EL PASO FIELD SERVICES EPFS was formed for the purpose of owning, operating, acquiring and constructing natural gas gathering, processing and other related facilities. Effective January 1, 1996, EPNG transferred its non-regulated assets to EPFS. These assets included major natural gas gathering systems in the San Juan and Permian Basins. From this initial asset base, EPFS began to implement plans to increase natural gas gathering and processing volumes through a strategy of project development, acquisitions, and joint ventures. EPFS provides its customers with wellhead-to-mainline field services, including natural gas gathering and transportation, products extraction, dehydration, purification and compression. EPFS also provides intrastate natural gas transmission services. EPFS, together with EPEM, provides fully bundled natural gas services with a broad range of pricing options as well as financial risk management products. EPFS also provides well-ties 5 20 and offers real-time information services, including electronic wellhead gas flow measurement. EPFS services are provided under a variety of fee structures including fixed fee per decatherm, floating fee per decatherm indexed to the applicable local area price of gas, or percentage of products sold. In August 1998, the Company completed the acquisition of DeepTech by merging it with a subsidiary of EPEC. DeepTech's assets included a combined 27.3 percent ownership interest in Leviathan, a publicly traded master limited partnership. The acquisition, valued at approximately $422 million, net of cash acquired, was accounted for as a purchase. The Leviathan assets include interests in eight natural gas pipeline systems with 1,167 miles of pipeline capable of moving 6.5 Bcf/d, 316 miles of crude oil pipelines, five multi-purpose platforms with processing capabilities, and four producing oil and gas properties. Additionally, in August 1998, the Company completed the expansion of the Coyote Gulch Treating Plant which increased capacity from 120 MMcf/d to 240 MMcf/d, providing an additional outlet for coal seam gas production in southwestern Colorado. In September 1998, the Company completed the Global Compression project, a $45 million capital investment that consists of 40,000 horsepower of compression, gas dehydration facilities, and 54 miles of pipeline looping. The project lowered wellhead pressures and increased production rates for 70 percent of the wells from which EPFS gathers in the San Juan Basin. In September 1998, EPFS sold its natural gas gathering, treating, and processing assets in the Anadarko Basin to Midcoast Energy Resources, Inc. for $35 million. The following table provides information as of December 31, 1998, concerning the natural gas gathering and transportation facilities, as well as natural gas gathered/transported for the three years ended December 31:
AVERAGE THROUGHPUT MILES THROUGHPUT (BBTU/D) OF CAPACITY --------------------- GATHERING & TREATING PIPELINE(1) (MMCF/D)(2) 1998 1997 1996 -------------------- ----------- ----------- ----- ----- ----- Western Division...................... 5,555 1,200 1,191 1,167 1,139 Eastern Division...................... 955 910 282 252 149 Central Division...................... 1,266 933 427 408 373 Offshore Division..................... 410 2,040 780 314 -- Joint Owned Division.................. 750 900 564 6 --
The following table provides information concerning the processing facilities for the three years ended December 31:
AVG INLET VOLUME AVERAGE NGLS SALES (BBTU/D) (MGAL/D) INLET ------------------ ------------------ PROCESSING PLANTS CAPACITY(2) 1998 1997 1996 1998 1997 1996 ----------------- ----------- ---- ---- ---- ---- ---- ---- Western Division..................... 600 586 551 557 370 505 352 Eastern Division..................... 207 109 126 75 275 229 115 Central Division..................... 278 269 58 19 208 94 39 Joint Owned Division................. 199 51 102 -- 74 167 --
6 21 The following table provides information concerning natural gas gathering and transportation facilities in which EPFS owns a minority interest and accounts for under the equity method:
AVERAGE AVERAGE THROUGHPUT THROUGHPUT THROUGHPUT PERCENT OF MILES THROUGHPUT (BBTU/D) CAPACITY MBBLS OWNERSHIP OF CAPACITY ------------------- MBBLS OIL OIL/D INTEREST PIPELINE(1) (MMCF/D)(2) 1998(3) 1997(4) PER DAY(2) 1998(3) ---------- ----------- ----------- -------- -------- ---------- ---------- Leviathan............ 27.3 1,358 1,198 593 -- 58 17 Oasis................ 35.0 608 350 289 338 -- -- Coyote Gulch......... 50.0 -- 120 69 42 -- -- Viosca Knoll......... 50.0 125 500 287 205 -- --
- ------------ (1) Mileage amounts are approximate for the total systems and have not been reduced to reflect EPFS's net ownership. (2) All capacity information reflects EPFS's net interest and is subject to increases or decreases depending on operating pressures and point of delivery into or out of the system. (3) Throughput for Leviathan is averaged since its acquisition on August 14, 1998. (4) Throughput for Oasis was in El Paso Energy Marketing segment in 1997. In January 1999, the Company and Leviathan entered into an agreement where the Company will sell, for approximately $85 million, all of its interest in Viosca Knoll Gathering Company to Leviathan except for a 1 percent interest in profits and capital. The transaction was approved by Leviathan's board of directors in January 1999, and at a special meeting held March 5, 1999, the Leviathan unitholders approved an increase in the authorized number of common units required to complete the acquisition. The transaction is expected to close in the second quarter of 1999. As a result of this transaction, the Company's combined ownership interest in Leviathan will increase to approximately 35 percent. Competition EPFS operates in a highly competitive environment that includes independent natural gas gathering and processing companies, intrastate pipeline companies, natural gas marketers, and oil and gas producers. EPFS competes for throughput primarily based on price, efficiency of facilities, gathering system line pressures, availability of facilities near drilling activity, service, and access to favorable downstream markets. EL PASO ENERGY MARKETING EPEM, the Company's merchant services and trading business, utilizes its extensive knowledge of the marketplace, natural gas pipeline and power transmission infrastructure, supply aggregation, transportation management and valuation, storage and integrated price risk management to provide customers with flexible solutions to meet their energy supply and financial risk management requirements. EPEM markets and trades natural gas, power, and petroleum products in the United States, Canada and Mexico. EPEM has emerged as one of North America's largest energy marketing and trading companies. EPEM contracts to purchase specific natural gas volumes from suppliers at various times and points of receipt, arranges for the aggregation and transportation of such natural gas, and negotiates the sale of these volumes to utilities (including local distribution companies and power plants), municipalities, and a variety of industrial and commercial end users. EPEM seeks to maintain a balanced portfolio of supply and demand contracts and a diverse natural gas supplier and customer base. During 1998, it served over 400 producers/suppliers and approximately 2,000 sales customers in 26 states and shipped natural gas supplies on 65 pipelines. EPEM utilizes a broad range of risk management instruments to manage its fixed-price purchase and sales commitments and reduce its exposure to market price volatility. EPEM trades futures contracts and options on the New York Mercantile Exchange and trades swaps and options in over-the-counter financial markets with other major energy merchants. Market risks are managed on a portfolio basis, subject to parameters established by a risk control committee that operates independently from commercial operations 7 22 and reports directly to the Board. Market risk in EPEM's commodity derivative portfolio is measured on a daily basis utilizing a Value-at-Risk (VAR) model to determine the maximum potential one-day unfavorable impact on its earnings. For additional information regarding the use of financial instruments, see Item 7A, Quantitative and Qualitative Disclosures About Market Risk and Item 8, Financial Statements and Supplementary Data, Note 5. Set forth below are the marketed gas, power and petroleum volumes for the years ended December 31:
1998 1997 1996(1) ------ ------ ------- Natural gas volumes marketed (Bbtu/d)(2)................... 11,540 6,969 4,568 Power volumes marketed (Thousand MW hours)................. 44,677 12,969 3,878 Petroleum volumes marketed (MBbls per year)(2)............. 21,717 80,641 54,913
- --------------- (1) Average daily volumes for the gas marketing activities of EPTPC, acquired in December 1996, are reflected from the date of acquisition in 1996 and for the full year of 1997 and 1998. (2) Includes financial trades. Competition EPEM operates in a highly competitive environment. Its primary competitors include: (i) marketing affiliates of major oil and gas producers; (ii) marketing affiliates of large local distribution companies; (iii) marketing affiliates of other interstate and intrastate pipelines; and (iv) independent energy marketers with varying scopes of operations and financial resources. EPEM competes on the basis of price, access to production, understanding of pipeline and transmission networks, imbalance management, and experience in the marketplace. EL PASO ENERGY INTERNATIONAL EPEI was formed for the purpose of investing in integrated energy projects with an emphasis on developing infrastructure to gather, transport and use natural gas in northern Mexico and certain Latin American countries. With the combination of EPTPC's international activities, the focus of international project pursuit has expanded to include power generation and to include investments located in Australia, Asia, Europe and other Latin American countries. Set forth below are brief descriptions, by region, of the projects that are either operational or in various stages of development. Acquisitions and greenfield development projects are subject to a higher level of commercial and financial risk in foreign countries. Accordingly, EPEI has adopted a risk mitigation strategy to reduce risks to more acceptable and manageable levels. EPEI's practice is to select experienced partners with a history of success in commercial operations. Individual partners are generally chosen based on the complementary competencies which they offer to the various joint ventures formed or to be formed. EPEI designs and implements a formal due diligence plan on every project it pursues, and contracts are negotiated to secure fuel supply, manage operating and maintenance costs and, when possible, index revenues and denominate transactions in U.S. dollars. EPEI also obtains political risk insurance when deemed appropriate, through the Overseas Private Investment Corporation, the Multilateral Investment Guarantee Agency, or a private insurer. Latin America and Mexico Samalayuca Power Project -- The Company owns a 30 percent interest in a 700 MW combined cycle gas fired power plant in Samalayuca, Mexico. The first, second, and third units commenced commercial operations in May, September, and December 1998, respectively. Comision Federal de Electricidad, the Mexican government-owned electric utility ("CFE") operates the plant under a 20-year lease. Upon expiration of the lease term, ownership of the plant will be transferred to CFE. Samalayuca Pipeline -- This 45-mile 212 MMcf/d pipeline system commenced gas deliveries in December 1997. The pipeline delivers natural gas to the Samalayuca Power Project from EPNG's existing pipeline system in West Texas and Pemex's pipeline system in northern Mexico. This system consists of 8 23 22 miles of pipeline in the U.S. (currently owned by EPNG) and 23 miles of pipeline in Mexico (currently 50 percent owned by the Company). Aguaytia Project -- The Company owns a 24 percent interest in an integrated natural gas and power generation project near Pucallpa, located in central Peru. The project consists of a 302 Bcf natural gas field, a natural gas processing facility, a 71-mile natural gas liquids pipeline to a fractionation facility, a 126-mile natural gas pipeline to a 155 MW simple cycle power plant, and a 250-mile 220 KV power transmission line interconnecting with the Peruvian grid at Paramonga. The project began operations in July 1998. CAPSA -- The Company has an effective 45 percent interest in CAPSA, a privately held integrated energy company in Argentina. CAPSA was incorporated in 1977 for the purpose of producing, selling and exploring for liquid hydrocarbons. CAPSA's assets include a 100 percent ownership interest in the Diadema Oil Field and a 55 percent ownership interest in CAPEX, a publicly traded company on the Argentine and Luxembourg stock exchanges that owns the 382 MW (currently being expanded to 650 MW) Agua del Cajon gas fired power plant in western Argentina. This plant has been fully operational since 1995 and buys natural gas from CAPEX's Agua del Cajon gas field. CAPEX also owns a 24 percent interest in the 76 MW Energia del Sur gas fired power plant in southern Argentina. Triunion Energy Company -- In January 1998, the Company, CAPEX and InterEnergy formed a new development company named Triunion Energy Company ("Triunion Energy") to identify and develop new energy related projects in Latin America. Triunion Energy currently owns a 20 percent interest in an exploration and production project in Charagua, Bolivia, as well as a 22 percent interest in an approved project to build a $380 million, 325 mile, natural gas pipeline that will cross the Andes Mountains connecting natural gas production in Argentina's Neuquen Basin to customers in Concepcion, Chile. Construction of the pipeline commenced in early 1998 and is expected to be completed in late 1999. Manaus Power Project -- The Company owns 100 percent of a 250 MW power plant in Manaus, the capital city of the state of Amazonas in northern Brazil. Power from the plant is currently sold under a four-year contract to Electronorte, the local electric company. The first phase of the project commenced operations in February 1998. The second phase commenced operations in March 1998 and the third phase commenced operations in June 1998. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the Manaus power project. Bolivia to Brazil Pipeline -- The Company is part of a consortium that is constructing a 2,000 mile pipeline from Santa Cruz, Bolivia to Sao Paulo, Brazil, with a southern lateral to Porto Alegre, Brazil. The pipeline will transport natural gas to the largest unserved market in the western hemisphere (approximately 100 million people). The pipeline is expected to be in service in early 1999. The Company's interest in the project is approximately 8 percent. Parana Power Project -- The Company has an approximate 30 percent interest in a consortium to build a 480 MW natural gas fired power plant in the state of Parana, in southern Brazil. The power plant will be located in Araucaria, Brazil. The electricity will be purchased by Companhia Paranaense de Energia, an integrated electric utility providing generation, transmission, and distribution of electricity to all regions of the state of Parana. The plant will be fueled by natural gas provided from the Bolivia to Brazil pipeline. Final negotiation and signing of a power purchase agreement will take place in early 1999 with financial close expected in the fourth quarter of 1999. Commercial operations are expected to commence in late 2000. Costanera -- In July 1998, the Company acquired 100 percent of KLT Power, Inc., the international business unit of Kansas City Power and Light Company. KLT Power, was established in 1993, to develop, finance, own, and operate independent power projects in selected markets worldwide. KLT Power owns a 12 percent interest in Central Costanera, the largest thermal-power plant in Argentina consisting of 2,167 MW of power generation and a 7.8 percent interest in Central Termoelectrica Buenos Aires, S.A., a 328 MW combined cycle power plant in Buenos Aires. 9 24 Europe EMA Power -- The Company owns a 50 percent controlling interest in a 70 MW power plant located in Dunaujvaros, Hungary. The electricity generated at the plant is consumed by Dunaferr Kft., the largest steel mill in Hungary. Approval has been given to expand the capacity of the electric generating plant to 140 MW and construction is scheduled to commence in late 1999. Kladno Power -- In May 1997, the Company acquired a 31 percent interest in a 338 MW natural gas and coal fired expansion and upgrade of an existing 25 MW cogeneration facility located approximately 19 miles northwest of Prague, in the Czech Republic. The Company sold a 13 percent interest in the project to one of the original partners under a buy back option granted by the Company in June 1997. The Company expects to purchase a similar amount in 1999 from another partner under a similar option agreement. Non-recourse project financing was finalized in June 1997, and commercial operations are expected to commence in the fourth quarter of 1999. Fife Power -- In September 1998, the Company acquired a 50 percent interest in the first Scottish independent power project located in Fife. The existing plant consists of a simple cycle natural gas fired turbine generating 75 MW, which commenced operations in the fourth quarter of 1998. Under Phase II, a steam turbine will be added to produce a total combined-cycle generating capacity of 115 MW. Financial close for Phase II is expected to occur in early 1999, and commercial operation is expected to commence in early 2001. Enfield -- In December 1998, the Company acquired a 25 percent interest in Enfield Energy Center Limited. The 396 MW combined cycle natural gas turbine power plant is under construction near London, England and is expected to be operational by October 1999. Asia Pacific Australian Pipelines -- The Company owns a 30 percent interest in the Moomba to Adelaide pipeline system, a 488-mile natural gas pipeline in southern Australia and the Ballera to Wallumbilla pipeline system, a 470-mile natural gas pipeline in southwestern Queensland. In March 1998, the Company, through its 33.3 percent interest in Epic Energy (WA) Pipeline Trust venture, purchased the 925-mile Dampier-to-Bunbury natural gas pipeline in western Australia. This 550 MMcf/d pipeline system serves a number of western Australian markets, including industrial end-users. An expansion of the Dampier-to-Bunbury pipeline is currently underway to supply additional natural gas to Alcoa, Worsley and Wesfarmers. The expansion, scheduled for completion in fourth quarter of 1999, will expand the pipeline capacity to 635 MMcf/d. Sengkang Project -- The Company has a 50 percent interest in a producing natural gas field with proven reserves of 533 Bcf and a 47.5 percent interest in a 135 MW power plant in Sengkang, South Sulawesi, Indonesia. The electricity produced by the power plant is sold to PLN, the national electric utility, under a long-term power purchase agreement. The power plant began simple cycle commercial operation in September 1997, making it one of the first independent power plants to operate in Indonesia. Combined cycle completion was in September 1998. For a discussion related to the effects on the project of the devaluation of the Indonesian rupiah, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Kabirwala Power -- The Company owns a 42 percent interest in a 151 MW natural gas fired power plant currently under construction in Kabirwala, Pakistan. Commercial operation is expected to commence in the second quarter of 1999. The power plant will sell electricity to the State Water and Power Development Authority. Haripur -- The Company owns a 50 percent interest in a consortium formed to construct a 115 MW oil and gas-fired power generation facility in Haripur, Bangladesh. The plant will sell power to the Bangladesh Power Development Board under a 15-year power purchase agreement. The plant is expected to be in service by the end of May 1999. 10 25 East Asia Power -- In 1998, the Company executed agreements to acquire a 46 percent interest in East Asia Power Resources Corporation ("EAPRC"), a publicly traded company in the Philippines. EAPRC owns and operates three power generation facilities in the Philippines and owns an interest in one power generation facility in China, with a total generating capacity of 289 MW. EAPRC also has options to acquire two additional power generation facilities in the Philippines with an aggregate generating capacity of 123 MW. Electric power generated by the facilities is supplied to a diversified base of customers including NPC, the state-owned utility, private distribution companies and industrial users. This acquisition was completed in February 1999. Other Projects The Company owns interests in three operating domestic power generation plants consisting of a 17.5 percent interest in a 240 MW power plant in Springfield, Massachusetts and a 50 percent interest in two additional cogeneration projects in Florida with a combined generating capacity of 220 MW. CORPORATE AND OTHER OPERATIONS In February 1998, El Paso Power Services ("EPPS") was formed to manage, acquire, and develop power-related assets and joint ventures. EPPS participates in the development, construction, and operation of domestic power generation projects as well as provides restructuring services to electric utilities, non-utility and merchant generators, fuel suppliers, and large industrial concerns to achieve lower costs in the transition to a more competitive business environment. EPPS has a 56 percent interest in a 270 MW natural gas-fired combined cycle power generation facility under construction in Agawam, Massachusetts ("Berkshire") which is expected to commence commercial operation in December 1999. Berkshire has entered into a fuel management agreement to purchase all natural gas and fuel oil used to operate the facility at market rates from EPEM through December 2019. In addition, Berkshire has entered into a power marketing agreement to sell all power produced by the facility to EPPS at market rates through December 2019. In December 1998, EPPS purchased a 100 percent interest in a 150 MW natural gas-fired combined cycle electric generation facility in Brush, Colorado ("Brush I"). Brush I consists of two natural gas turbines, which currently operate alternately, and a steam turbine. The gas and steam turbines together generate electricity and provide radiant heating for a greenhouse complex. During 1998, EPPS activities were included with Corporate operations. As EPPS operations increase, they may be reported as a separate business segment or combined with El Paso Energy Marketing segment. As a result of the Merger, the Company holds certain limited assets and is responsible for certain liabilities of EPTPC's existing and discontinued operations and businesses. In addition, the Company, through its corporate and other segment, performs management, legal, financial, tax, consultative, administrative and other services for the operating business segments of the Company. ENVIRONMENTAL A description of the Company's environmental activities is included in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and is incorporated by reference herein. EMPLOYEES The Company had approximately 3,600 full-time employees on December 31, 1998. The Company has no collective bargaining arrangements and no significant changes in the workforce have occurred since December 31, 1998. During 1997, the Company reduced its workforce by approximately 800 employees as a result of a program to streamline operations and reduce operating costs in connection with the acquisition of EPTPC. 11 26 EXECUTIVE OFFICERS OF THE REGISTRANT The executive officers of EPEC as of March 10, 1999, are set forth below. For dates prior to August 1, 1998 (the date of the holding company reorganization), references to positions held with EPEC refer instead to positions held with EPNG.
OFFICER NAME OFFICE SINCE AGE ---- ------ ------- --- William A. Wise.............. Chairman of the Board, President, and Chief 1983 53 Executive Officer of EPEC H. Brent Austin.............. Executive Vice President and Chief Financial 1992 44 Officer of EPEC Joel Richards III............ Executive Vice President of EPEC 1990 52 Britton White, Jr............ Executive Vice President and General Counsel 1991 55 of EPEC Mark A. Searles.............. Senior Vice President of EPEC 1995 42 Richard Owen Baish........... President of EPNG 1987 52 John D. Hushon............... President of EPEI 1996 53 Greg G. Jenkins.............. President of EPEM 1996 41 Robert G. Phillips........... President of EPFS 1995 44 John W. Somerhalder II....... President of TGP 1990 43
Mr. Wise has been Chairman of the Board since January 1994 and Chief Executive Officer since January 1990. In July 1998, Mr. Wise also became the President of the Company. He was President of EPEC from April 1989 to April 1996. From March 1987 until April 1989, Mr. Wise was an Executive Vice President of EPEC. From January 1984 to February 1987, he was a Senior Vice President of EPEC. Mr. Wise is a member of the Board of Directors of Battle Mountain Gold Company and is the Chairman of the Board of EPNG, EPTPC, and Leviathan Gas Pipeline Company, the general partner of Leviathan. Mr. Austin has been Executive Vice President of EPEC since May 1995. He has been Chief Financial Officer of EPEC since April 1992. He was Senior Vice President of EPEC from April 1992 to April 1995. He was Vice President, Planning and Treasurer of Burlington Resources Inc. ("BR") from November 1990 to March 1992 and Assistant Vice President, Planning of BR from January 1989 to October 1990. Mr. Richards has been Executive Vice President of EPEC since December 1996. From January 1991 until December 1996, he was Senior Vice President of EPEC. He was Vice President from June 1990 to December 1990. He was Senior Vice President, Finance and Human Resources of Meridian Minerals Company, a wholly owned subsidiary of BR, from October 1988 to June 1990. Mr. White has been Executive Vice President of EPEC since December 1996 and General Counsel of EPEC since March 1991. He was Senior Vice President and General Counsel of EPEC from March 1991 until December 1996. From March 1991 to April 1992, he was also Corporate Secretary of EPEC. For more than five years prior to that time, Mr. White was a partner in the law firm of Holland & Hart. Mr. Searles has been Senior Vice President of EPEC since April 1998. He was Executive Vice President of EPEM from June 1997 to June 1998. He was President of EPFS from December 1996 to June 1997 and was President of EPEM from September 1995 to December 1996. From March 1994 to September 1995, Mr. Searles was President and Chief Operating Officer of Eastex Energy, Inc. For more than five years prior to that he held various management positions with Enron Corp. Mr. Baish has been President of EPNG since April 1996. From September 1994 until April 1996, he was Executive Vice President of EPNG and was Senior Vice President from November 1990 to August 1994. He was General Counsel and Corporate Secretary from November 1990 to December 1990 and Vice President and Associate General Counsel from March 1987 to October 1990. 12 27 Mr. Hushon has been President of EPEI since April 1996. He was Senior Vice President of EPEI from September 1995 to April 1996. For more than five years prior to that time, Mr. Hushon was a senior partner in the law firm of Arent Fox Kintner Plotkin & Kahn. Mr. Jenkins has been President of EPEM since December 1996. He was Senior Vice President and General Manager of Entergy Corp. from May 1996 to December 1996 and President and Chief Executive Officer of Hadson Gas Services Company from December 1993 to January 1996. For more than five years prior to that time, Mr. Jenkins was in various managerial positions with Santa Fe Energy Resources, Inc. Mr. Phillips has been President of EPFS since June 1997. He was President of El Paso Energy Resources Company from December 1996 to June 1997, President of EPFS from April 1996 to December 1996 and was a Senior Vice President of EPEC from September 1995 to April 1996. For more than five years prior to that time, Mr. Phillips was Chief Executive Officer of Eastex Energy, Inc. Mr. Somerhalder has been President of TGP since December 1996. He was President of El Paso Energy Resources Company from April 1996 to December 1996 and Senior Vice President of EPEC from August 1992 to April 1996. From January 1990 to July 1992, he was Vice President of EPEC. Executive officers hold offices until their successors are elected and qualified, subject to their earlier removal. ITEM 2. PROPERTIES A description of the Company's properties is included in Item 1, Business and is incorporated by reference herein. The Company is of the opinion that it has generally satisfactory title to the properties owned and used in its businesses, subject to the liens for current taxes, liens incident to minor encumbrances, and easements and restrictions that do not materially detract from the value of such property or the interests therein or the use of such properties in its businesses. The Company believes that its physical properties are adequate and suitable for the conduct of its business in the future. ITEM 3. LEGAL PROCEEDINGS See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies, Legal Proceedings which is incorporated herein by reference. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None 13 28 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS EPEC's common stock is traded on the New York Stock Exchange. As of March 5, 1999, the number of holders of record of common stock was approximately 72,000. This does not include individual participants on whose behalf a clearing agency, or its nominee, holds EPEC's common stock. The following table reflects the high and low sales prices for EPEC's common stock for the periods indicated based on the daily composite listing of stock transactions for the New York Stock Exchange and cash dividends declared during those periods.
HIGH LOW DIVIDENDS -------- -------- --------- (PER SHARE) 1998 First Quarter....................................... $35.6250 $31.1250 $0.19125 Second Quarter...................................... 38.9375 35.4375 0.19125 Third Quarter....................................... 38.6250 24.6875 0.19125 Fourth Quarter...................................... 36.8125 30.1250 0.19125 1997 First Quarter....................................... $28.5000 $24.4375 $0.18250 Second Quarter...................................... 30.3125 27.1250 0.18250 Third Quarter....................................... 30.3436 26.5000 0.18250 Fourth Quarter...................................... 33.7500 28.8750 0.18250
In January 1999, the Board declared a quarterly dividend of $0.20 per share on EPEC's common stock, payable on April 1, 1999, to stockholders of record on March 5, 1999. The declaration of future dividends will be dependent upon business conditions, earnings, the cash requirements of EPEC, and other relevant factors. In January 1998, the Board declared a two-for-one stock split in the form of a 100 percent stock dividend (on a per share basis). In March 1998, the stockholders approved an increase in the Company's authorized common stock, which was necessary to effect the stock split. The stock dividend was paid on April 1, 1998 to stockholders of record on March 13, 1998. All presentations herein are made on a post-split basis. Separately, the Board also approved a new 10 million common stock repurchase authority that replaced the repurchase authority approved by the Board in November 1994. The timing and amount of additional share repurchases, if any, will depend upon the availability and alternate uses of capital, market conditions and other factors. EPEC has made available a continuous odd-lot stock sales program (the "Program"), in which stockholders of EPEC owning beneficially fewer than 100 shares of EPEC's common stock ("Odd-Lot-Holders") are offered a convenient method of disposing of all their shares without incurring any brokerage costs associated with the sale of an odd-lot. Only Odd-Lot Holders are eligible to participate in the Program. The Program is strictly voluntary, and no Odd-Lot Holder is obligated to sell pursuant to the Program. A brochure and related materials describing the Program were sent to Odd-Lot Holders in February 1994. The Program currently does not have a termination date, but EPEC may suspend the Program at any time. Inquiries regarding the Program should be directed to Boston EquiServe. EPEC has made available a dividend reinvestment and common stock purchase plan (the "Plan"), which provides all stockholders of record a convenient and economical means of increasing their holdings in EPEC's common stock. A stockholder who owns shares of common stock in street name or broker name and who wishes to participate in the Plan will need to have his or her broker or nominee transfer the shares into the stockholder's name. The Plan is strictly voluntary, and no stockholder of record is obligated to participate in the Plan. The Plan currently does not have a termination date, but EPEC may suspend the Plan at any time. Inquiries regarding the Plan should be directed to Boston EquiServe. 14 29 ITEM 6. SELECTED FINANCIAL DATA
YEAR ENDED DECEMBER 31, ------------------------------------------------- 1998 1997 1996 1995 1994 -------- ------- ------- -------- ------- (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) Operating Results Data(a): Operating revenues.................................. $5,782 $5,638 $3,012 $1,038 $ 870 Employee separation and asset impairment charge(b)........................................ -- -- 99 -- -- Net income.......................................... 225 186 38 85 90 Basic earnings per common share(b).................. 1.94 1.64 .53 1.24 1.23 Diluted earnings per common share................... 1.85 1.59 .52 1.24 1.23 Cash dividends declared per common share............ .76 .73 .70 .66 .61 Basic average common shares outstanding............. 116 114 72 69 73 Diluted average common shares outstanding........... 126 117 73 69 73
DECEMBER 31, ------------------------------------------- 1998 1997 1996 1995 1994 ------- ------ ------ ------ ------ (IN MILLIONS) Financial Position Data(a): Total assets....................................... $10,069 $9,532 $8,843 $2,535 $2,332 Long-term debt..................................... 2,552 2,119 2,215 772 779 Preferred stock of subsidiary...................... 300 300 296 -- -- Other minority interest............................ 65 65 39 -- -- Stockholders' equity............................... 2,108 1,959 1,638 712 710
- --------------- (a) Reflects the acquisition in September 1995 of Eastex Energy, Inc., in December 1995 of Premier Gas Company, in June 1996 of Cornerstone Natural Gas, Inc., in December 1996 of EPTPC, and in August 1998 of DeepTech. All acquisitions were accounted for as purchases and therefore operating results are included prospectively from the date of acquisition. (b) Reflects a charge in 1996 of $99 million pre-tax ($60 million after tax) to reflect costs associated with the implementation of a workforce reduction plan and the impairment of certain long-lived assets. Basic earnings per common share for the year ended December 31, 1996 before giving effect to this charge and an $8 million pre-tax ($5 million after tax) charge taken in the fourth quarter for relocating the corporate headquarters from El Paso, Texas to Houston, Texas in connection with the acquisition of EPTPC, would have been $1.43 (compared to $0.53). 15 30 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL For the past four years, the Company has engaged in numerous activities and transactions designed to significantly improve its ability to compete effectively in the rapidly evolving world energy industry. In late 1995, the Company acquired two energy marketing businesses, Eastex Energy Inc. and Premier Gas Company. During the first quarter of 1996, the Company completed its organizational review and workforce reduction program, reducing the total workforce from 2,400 to about 1,600. During May 1996, the Company completed and placed in service the Chaco Plant, the largest facility of its kind in the continental U.S. In June 1996, the Company acquired Cornerstone Natural Gas, Inc., expanding its gathering and processing operations into Louisiana and East Texas. The Company completed its $4 billion acquisition of EPTPC in December 1996, expanding its natural gas pipeline systems from coast to coast and continuing the expansion of the non-regulated business operations. In connection with the EPTPC acquisition, the Company completed a workforce reduction program in the first quarter of 1997, reducing the workforce of the combined companies by approximately 800 from about 4,300 following the acquisition of EPTPC to about 3,500. In late 1997, the Company acquired additional natural gas gathering and processing assets by completing the purchases of Gulf States Gas Pipeline Company and certain Texas Gulf Coast subsidiaries of PacifiCorp ("TPC"). In August 1998, the Company acquired DeepTech. Additionally, throughout 1996, 1997 and 1998, the Company's international operations were expanding into Latin and South America, the Asia Pacific region, Australia, and Europe. These changes in the make-up of the Company significantly increased the Company's operating results, its ability to generate operating cash flows and its needs for cash for investment opportunities. Consequently, the Company's credit facilities were substantially expanded during this period to meet those needs. The Company adopted the provisions of SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, effective January 1, 1998. Accordingly, the Company has segregated its business activities into five segments: Tennessee Gas Pipeline segment, El Paso Natural Gas segment, El Paso Field Services segment, El Paso Energy Marketing segment, and El Paso Energy International segment. These segments are strategic business units that offer a variety of different energy products and services. They are managed separately as each business segment requires different technology and marketing strategies. Certain business segments' earnings are largely derived from the earnings of equity investments. Accordingly, the Company evaluates segment performance based on EBIT. HOLDING COMPANY REORGANIZATION AND TAX-FREE INTERNAL REORGANIZATION Effective August 1, 1998, the Company reorganized into a holding company organizational structure, whereby EPEC, a Delaware corporation, became the parent holding company. See Item 8, Financial Statements and Supplementary Data, Note 1, for further discussion of the holding company reorganization. On December 31, 1998, the Company completed a tax-free internal reorganization of its assets and operations and those of its subsidiaries in accordance with a private letter ruling received from the IRS. In the reorganization, a substantial number of subsidiaries were transferred to or from the Company and/or other entities owned by the Company. Neither the creation of the holding company structure nor the tax-free internal reorganization had any impact on the presentation herein. RESULTS OF OPERATIONS Consolidated EBIT for the year ended December 31, 1998, increased 11 percent to $644 million compared to $578 million in the year ago period. Consolidated EBIT for the year ended December 31, 1997, was $403 million higher than for the same period of 1996. Variances are discussed in the segment results below. 16 31 SEGMENT RESULTS To the extent practicable, results of operations for 1997 and 1996 have been reclassified to conform to the current business segment presentation, although such results are not necessarily indicative of the results which would have been achieved had the revised business segment structure been in effect during those periods. Operating revenues and expenses by segment include intersegment sales and expenses which are eliminated in consolidation. Because of energy commodity price volatility, the Company believes that gross margin (revenue less cost of sales), rather than operating revenue, provides a more accurate indicator for the El Paso Field Services and the El Paso Energy Marketing segments. For a further discussion of the individual segments, see Item 8, Financial Statements and Supplementary Data, Note 13.
YEAR ENDED DECEMBER 31, --------------------------- 1998 1997 1996 ----- ----- ----- (IN MILLIONS) EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES Tennessee Gas Pipeline...................................... $ 358 $ 318 $ 16 El Paso Natural Gas......................................... 217 260 223 ----- ----- ----- Regulated segments........................................ 575 578 239 ----- ----- ----- El Paso Field Services...................................... 75 74 35 El Paso Energy Marketing.................................... 9 (28) 24 El Paso Energy International................................ 25 2 (4) ----- ----- ----- Non-regulated segments.................................... 109 48 55 ----- ----- ----- Corporate expenses, net..................................... (40) (48) (119) ----- ----- ----- Consolidated EBIT......................................... $ 644 $ 578 $ 175 ===== ===== =====
TENNESSEE GAS PIPELINE
YEAR ENDED DECEMBER 31, --------------------------- 1998 1997 1996 ----- ----- ----- (IN MILLIONS) Operating revenues.......................................... $ 766 $ 798 $ 48 Operating expenses.......................................... (434) (494) (34) Other -- net................................................ 26 14 2 ----- ----- ----- EBIT...................................................... $ 358 $ 318 $ 16 ===== ===== =====
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 Operating revenues for the year ended December 31, 1998, were $32 million lower than for the same period of 1997 primarily because of lower throughput resulting from warmer average temperatures in the northeastern and midwestern markets and a downward revision in the amount of recoverable interest on GSR costs. Operating expenses for the year ended December 31, 1998, were $60 million lower than for the same period of 1997 primarily due to lower system fuel usage associated with operating efficiencies attained during the period of lower throughput, reduced operation and maintenance expenses largely due to lower payroll costs, and lower franchise taxes. Other -- net for the year ended December 31, 1998, was $12 million higher than for the same period of 1997 due to interest income on a favorable sales and use tax settlement and gains on the sale of assets. YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996 The results of operations for 1996 represents EPEC's ownership of this segment for 20 days after the EPTPC Merger in December 1996. Operating revenues for the year ended December 31, 1997, were $750 million higher than for the same period of 1996 due to the acquisition of EPTPC in December 1996. 17 32 Operating expenses for the year ended December 31, 1997, were $460 million higher than for the same period of 1996 due to the acquisition of EPTPC in December 1996. Other -- net for the year ended December 31, 1997, was $12 million higher than for the same period of 1996 due to the acquisition of EPTPC in December 1996. EL PASO NATURAL GAS
YEAR ENDED DECEMBER 31, --------------------------- 1998 1997 1996 ----- ----- ----- (IN MILLIONS) Operating revenues.......................................... $ 475 $ 520 $ 511 Operating expenses.......................................... (260) (265) (302) Other -- net................................................ 2 5 14 ----- ----- ----- EBIT...................................................... $ 217 $ 260 $ 223 ===== ===== =====
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 Operating revenues for the year ended December 31, 1998, were $45 million lower than for the same period of 1997 primarily due to lower net revenues resulting from the PG&E contract expiration which was effective December 31, 1997. The decrease in revenues from the loss of the PG&E contract was significantly offset by risk sharing revenue, other non-traditional revenues including revenue from the sale of capacity to Dynegy, and the favorable resolution of a contested rate matter. (See Commitments and Contingencies, Rates and Regulatory Matters, below for a discussion of the Dynegy contracts.) Operating expenses for the year ended December 31, 1998, were $5 million lower than for the same period of 1997 primarily due to lower fuel costs and recovery of a receivable previously deemed uncollectible. Partially offsetting the decrease were higher operating and depreciation expenses. YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996 Operating revenues for the year ended December 31, 1997, were $9 million higher than for the same period of 1996 primarily due to higher accruals for take-or-pay issues in 1996 and an increase in non-traditional revenues associated with a system expansion. This increase was partially offset by lower revenues resulting from contract expirations occurring in late 1996 and early 1997. Operating expenses for the year ended December 31, 1997, were $37 million lower than for the same period of 1996 primarily due to lower labor, benefits, and payroll tax expenses in 1997 which resulted from a reduction in staffing levels during 1996. Other -- net for the year ended December 31, 1997, was $9 million lower than for the same period of 1996 due to gains on the disposition of assets in 1996. EL PASO FIELD SERVICES
YEAR ENDED DECEMBER 31, --------------------------- 1998 1997 1996 ----- ----- ----- (IN MILLIONS) Gathering and treating margin............................... $ 150 $ 119 $ 87 Processing margin........................................... 48 55 46 Other margin................................................ 3 6 1 ----- ----- ----- Total gross margin................................ 201 180 134 Operating expenses.......................................... (141) (114) (99) Other -- net................................................ 15 8 -- ----- ----- ----- EBIT...................................................... $ 75 $ 74 $ 35 ===== ===== =====
18 33 YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 Total gross margin for the year ended December 31, 1998, was $21 million higher than for the same period of 1997. The increase in the gathering and treating margin primarily resulted from higher gathering rates compared to 1997, an increase in gathering and treating volumes largely attributable to the acquisition of TPC in December 1997, and the inclusion of the results of operations of Channel Pipeline ("Channel"), in El Paso Field Services segment beginning January 1998 versus El Paso Energy Marketing segment. The decrease in the processing margin was largely attributable to lower liquids prices during 1998 compared to the same period of 1997. Liquids prices directly impact EPFS's processing revenues. During 1998, liquids prices were at their lowest level since 1990, and the Company expects this trend to continue through 1999. The Company attempts to mitigate the impact of lower liquids prices by utilizing hedging strategies where possible. Operating expenses for the year ended December 31, 1998, were $27 million higher than for the same period of 1997 primarily as a result of additional expenses associated with the addition of TPC and Channel as well as higher general and administrative expenses. Other -- net for the year ended December 31, 1998, was $7 million higher than for the same period of 1997 reflecting higher earnings from equity investments and higher capitalized interest. YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996 Total gross margin for the year ended December 31, 1997, was $46 million higher than for the same period of 1996. The increase in the gathering and treating margin and the processing margin was primarily the result of higher natural gas prices in the San Juan Basin and an increase in gathering and treating volumes due to the acquisitions of EPTPC in December 1996 and Cornerstone Natural Gas, Inc. in June 1996. Operating expenses for the year ended December 31, 1997, were $15 million higher than for the same period of 1996 primarily due to the acquisition of EPTPC and Cornerstone Natural Gas, Inc. Other -- net for the year ended December 31, 1997, was $8 million higher than for the same period of 1996 primarily due to the acquisition of EPTPC. EL PASO ENERGY MARKETING
YEAR ENDED DECEMBER 31, ----------------------- 1998 1997 1996 ----- ----- ----- (IN MILLIONS) Natural gas margin.......................................... $ 26 $ 25 $ 46 Power margin................................................ 16 -- (3) Petroleum products margin................................... 1 (3) 3 ---- ---- ---- Total gross margin................................ 43 22 46 Operating expenses.......................................... (38) (53) (23) Other -- net................................................ 4 3 1 ---- ---- ---- EBIT...................................................... $ 9 $(28) $ 24 ==== ==== ====
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 Total gross margin for the year ended December 31, 1998, was $21 million higher than for the same period of 1997. Increases in total gross margin in 1998 reflect a fundamental shift in focus initiated by the energy marketing business segment from a short-term positional trading operation to a long-term, asset-based origination, trading, and risk management operation. In 1998, such energy activities emphasized long-term power and gas contract management and related energy services for power and natural gas customers, including independent power producers, utilities and end users. Trading activities, while substantially increasing in volume in 1998, are primarily used to manage risk in long-term contract positions. Partially offsetting the increase in gross margin was the impact of reporting the operations of Channel in El Paso Field Services segment versus El Paso Energy Marketing segment beginning in January 1998. 19 34 Operating expenses for the year ended December 31, 1998, were $15 million lower than for the same period of 1997. The decrease was attributable to the 1997 restructuring of the marketing organization following the EPTPC acquisition and the transfer of Channel operations as mentioned above. YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996 Total gross margin for the year ended December 31, 1997, was $24 million lower than for the same period of 1996. The decrease resulted from generally lower industry-wide gas marketing margins in the second quarter of 1997, as well as extreme market volatility which negatively impacted the Company's natural gas marketing activities and trading positions during the first quarter of 1997. Operating expenses for the year ended December 31, 1997, were $30 million higher than for the same period of 1996 primarily due to the costs associated with the marketing activities of EPTPC which were acquired in December 1996. EL PASO ENERGY INTERNATIONAL
YEAR ENDED DECEMBER 31, ----------------------- 1998 1997 1996 ----- ----- ----- (IN MILLIONS) Operating revenues.......................................... $ 58 $ 13 $-- Operating expenses.......................................... (86) (37) (3) Other -- net................................................ 53 26 (1) ---- ---- --- EBIT...................................................... $ 25 $ 2 $(4) ==== ==== ===
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 Operating revenues for the year ended December 31, 1998, were $45 million higher than for the same period of 1997 due to the consolidation for financial reporting purposes of the Manaus Power project in May 1998 after acquiring an additional ownership interest and an increase in revenue attributable to the EMA Power project which the Company began reporting on a consolidated basis in July 1997. Operating expenses for the year ended December 31, 1998, were $49 million higher than for the same period of 1997 primarily due to costs related to the consolidation of the EMA Power and Manaus Power projects and increased general and administrative expenses largely due to higher project development costs reflecting an increase in project-related activities in 1998. Other -- net for the year ended December 31, 1998, was $27 million higher than for the same period of 1997 primarily due to increased equity earnings, a gain on the sale of surplus power equipment, and the recognition of certain net gains from project-related activities. As EPEI's projects move from the development stage to the operational stage, it is common to recognize one-time gains and fees, which may include management fees, development fees, financing fees, and gains on the sell-down of ownership interests. The Company anticipates additional one-time events may result in the recognition of income or expense in the future. YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996 EBIT for the year ended December 31, 1997, was $6 million higher than for the same period of 1996. During 1997, EPEI completed its first full year of operations following the EPTPC acquisition, which represented a significant increase in international project development activities. Because of this increase in development activities, operating results likewise increased substantially over 1996. 20 35 CORPORATE EXPENSES, NET YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 Net corporate expenses for the year ended December 31, 1998, were $8 million lower than for the same period of 1997. The decrease results from lower benefits costs and non-recurring gains, partially offset by administrative costs associated with the formation and startup of EPPS, a power services group established in the first quarter of 1998, and costs associated with the Company's Year 2000 project. YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996 Net corporate expenses for the year ended December 31, 1997, were $71 million lower than for the same period of 1996 primarily as a result of a $99 million employee separation and asset impairment charge recorded in the first quarter of 1996 and an $8 million charge in the fourth quarter of 1996 for relocating the Company's headquarters from El Paso, Texas to Houston, Texas in connection with the acquisition of EPTPC. The decrease was partially offset by additional costs related to the discontinued operations assumed as part of the EPTPC acquisition. INTEREST AND DEBT EXPENSE YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 Interest and debt expense for the year ended December 31, 1998, was $29 million higher than for the same period of 1997 primarily because of increased borrowings to fund capital expenditures, acquisitions, and other investing expenditures and a higher average effective interest rate during 1998 generally resulting from the higher rates associated with the March 1997 issuance of TGP long-term debt of approximately $883 million. These increases were partially offset by higher interest expense in 1997 incurred on rate refunds paid to EPNG's customers in 1998. YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996 Interest and debt expense for the year ended December 31, 1997, was $128 million higher than for the same period of 1996 due primarily to the level of debt assumed in connection with the acquisition of EPTPC and the Company's debt and capital realignment efforts. INCOME TAX EXPENSE The effective tax rate for 1998 was 34 percent compared to 38 percent in 1997 and 1996. The lower rate in 1998 is due to an increase in the level of foreign income in 1998, which is subject to foreign tax rates that differ from U.S. tax rates, increases in permanently reinvested equity income from unconsolidated foreign affiliates for which no provision for U.S. income tax is required, and lower state income taxes. LIQUIDITY AND CAPITAL RESOURCES CASH FROM OPERATING ACTIVITIES Net cash provided by operating activities was $61 million lower for the year ended December 31, 1998, compared to the same period of 1997. The decrease was primarily attributable to working capital changes, a take-or-pay refund paid to EPNG's customers in February 1998, lower GSR collections in 1998, and prepayments of risk sharing revenues in 1997. The decrease was partially offset by higher net tax refunds in 1998 and rate refunds paid to TGP's customers in March 1997 and EPNG's customers in August 1997. CASH FROM INVESTING ACTIVITIES Net cash used in investing activities was approximately $1 billion for the year ended December 31, 1998. Investment activities included the August 1998 acquisition of DeepTech (see Item 8, Financial Statements and Supplementary Data, Note 2), as well as expenditures for joint ventures, equity investments, and 21 36 expansion and construction projects. Expenditures related to joint ventures and equity investments were primarily attributable to the EPEI segment. Internally generated funds, supplemented by other financing activities, were used to fund these expenditures. The Company's planned capital and investment expenditures for 1999 of approximately $900 million are primarily for expansion of international operations and domestic unregulated operations, pipeline systems activities and other facilities, and computer and communication system enhancements. Funding for capital expenditures, acquisitions, and other investing expenditures is expected to be provided by internally generated funds, commercial paper issuances, available capacity under existing credit facilities, and/or the issuance of other long-term debt, trust securities, or equity. CASH FROM FINANCING ACTIVITIES Net cash provided by financing activities was $463 million for the year ended December 31, 1998. In March 1998, Trust Convertible Preferred Securities were issued (see Item 8, Financial Statements and Supplementary Data, Note 3) for net proceeds of $317 million. In October 1998, TGP issued debentures due 2028 for net proceeds of $391 million. These proceeds, supplemented by internally generated funds, were used to retire long-term debt, pay dividends, acquire treasury stock, fund capital and equity investments, and for other corporate purposes. Since November 1994, the Company has been authorized by the Board to repurchase shares of its common stock. Shares repurchased are held in EPEC's treasury and are expected to be used in conjunction with EPEC stock compensation plans and for other corporate purposes. Pursuant to the November 1994 authorization, the Company had repurchased 9.4 million shares as of December 31, 1997. In January 1998, the Board approved a new 10 million common stock repurchase authority that replaced the November 1994 repurchase authority. The 10 million share repurchase authority reflects the two-for-one stock split as discussed in Item 5, Market for Registrant's Common Equity and Related Stockholder Matters. In 1998, the Company repurchased 995,600 common shares at a weighted average cost of $35.77 per share. The timing and amount of future share repurchases, if any, will depend upon the availability and alternate uses of capital, market conditions and other factors. Future funding for long-term debt retirements, dividends, and other financing expenditures is expected to be provided by internally generated funds, commercial paper issuances, available capacity under existing credit facilities, and/or the issuance of other long-term debt, trust securities, or equity. LIQUIDITY The Company relies on cash generated from internal operations as its primary source of liquidity, supplemented by its available credit facilities and commercial paper program. In October 1997, EPNG established a new $750 million five-year revolving credit and competitive advance facility and a new $750 million 364-day renewable revolving credit and competitive advance facility (collectively, the "Revolving Credit Facility"). In connection with the establishment of the Revolving Credit Facility, EPTPC's revolving credit facility was also terminated, and the outstanding balance of $417 million was financed under the five-year portion of the new Revolving Credit Facility with TGP designated as the borrower. The availability under the Revolving Credit Facility is expected to be used for general corporate purposes including, but not limited to, backstopping EPNG's and TGP's $1 billion commercial paper programs. In August 1998, EPEC became a guarantor of EPNG's Revolving Credit Facility. In October 1998, the $750 million 364-day portion of the Revolving Credit Facility was amended to extend the termination date to October 27, 1999. In addition, in October 1998, the Revolving Credit Facility was amended to permit TGP to issue commercial paper, provided that the total amount of commercial paper outstanding at EPNG and TGP is equal to or less than the unused capacity under the Revolving Credit Facility. In December 1998, EPEC became a borrower under the Revolving Credit Facility. The interest rate on the Revolving Credit Facility is 40 basis points above LIBOR, with the spread varying based on EPEC's long-term debt credit rating. The availability of borrowings under the Company's credit agreements is subject to specified conditions, which management believes the Company currently meets. These conditions include compliance with the 22 37 financial covenants and ratios required by such agreements, absence of default under such agreements, and continued accuracy of the representations and warranties contained in such agreements (including the absence of any material adverse changes since the specified dates). All of the Company's senior debt issues have been given investment grade ratings by Standard & Poors and Moody's. The Company must comply with various restrictive covenants contained in its debt agreements which include, among others, maintaining a consolidated debt and guarantees to capitalization ratio no greater than 70 percent. In addition, the Company's subsidiaries on a consolidated basis (as defined in the agreements) may not incur debt obligations which would exceed $300 million in the aggregate, excluding acquisition debt, project financing, and certain refinancings. As of December 31, 1998, EPEC's consolidated debt and guarantees to capitalization ratio (as defined in the agreements) was 55 percent and debt obligations of EPEC subsidiaries in excess of permitted debt did not exceed $300 million on a consolidated basis. In March 1997, TGP issued $300 million aggregate principal amount of 7 1/2% debentures due 2017, $300 million aggregate principal amount of 7% debentures due 2027, and $300 million aggregate principal amount of 7 5/8% debentures due 2037. Proceeds of approximately $883 million, net of issuance costs, were used to repay a portion of EPTPC's credit facility and for general corporate purposes. In December 1997, EPEC filed a shelf registration statement pursuant to which EPEC may offer up to $900 million (including $250 million transferred from prior shelf registrations) of common or preferred equities, various forms of debt securities (including convertible debt securities), and various types of trust securities from time to time as determined by market conditions. In March 1998, the El Paso Energy Capital Trust I, a Delaware business trust sponsored by the Company, issued 6.5 million 4 3/4% Trust Convertible Preferred Securities. The sole assets of the trust are approximately $335 million principal amount of 4 3/4% convertible subordinated debentures due 2028 of the Company. As a result of such offering, EPEC has approximately $565 million of capacity remaining under its existing shelf registration to issue public securities registered thereunder. In September 1998, TGP filed a shelf registration permitting TGP to offer up to $600 million (including $100 million carried forward from a prior shelf registration) of debt securities. In October 1998, TGP issued $400 million aggregate principal amount of 7% debentures due 2028. Proceeds to TGP were approximately $391 million, net of issuance cost. Approximately $300 million of the proceeds were used to repay TGP's short-term indebtedness under the Revolving Credit Facility and the remainder were used by TGP for general corporate purposes. After this issuance, TGP has $200 million of capacity remaining under its shelf registration. In March 1998, EPNG retired its outstanding 8 5/8% debentures in the amount of $17 million and in August 1998, EPTPC retired its outstanding 10% debentures in the amount of $38 million. In February 1999, DeepTech retired its 11% senior subordinated promissory note due 2000 in the amount of $16 million. COMMITMENTS AND CONTINGENCIES Indonesia The Company owns a 47.5 percent interest in a power generating plant in Sengkang, South Sulawesi, Indonesia. Under the terms of the project's power purchase agreement, PLN purchases power from the Company in Indonesian rupiah indexed to the U.S. dollar at the date of payment. Due to the devaluation of the rupiah, the cost of power to PLN has significantly increased. PLN is currently unable to pass this increase in cost on to its customers without creating further political instability. PLN has requested financial aid from the Minister of Finance to help ease the effects of the devaluation. PLN has been paying the Company in rupiah indexed to the U.S. dollar at the rate in effect prior to the rupiah devaluation, with a commitment to pay the balance when financial aid is received. The difference between the current and prior exchange rate has resulted in an outstanding balance due from PLN of $9.4 million at December 31, 1998. The Company continues to meet with PLN on a regular basis to resolve the payment in arrears issue but has been unsuccessful to date. Recently, the Company has met and discussed its situation and concerns with the World 23 38 Bank, the International Monetary Fund, the Overseas Private Investment Corporation, and the U.S. Treasury Department in an attempt to achieve a resolution through the Indonesian Minister of Finance. The Company will meet with PLN in April 1999 to discuss payments in arrear and the terms of a contract rationalization process proposed by PLN. The Company has informed PLN that all payments in arrear must first be received as a prerequisite to any further discussions on contract rationalization. The Company cannot predict with certainty the outcome of such discussions. The Company's total investment in the Sengkang project was approximately $25 million at December 31, 1998. Additionally, the Company has provided specific recourse guarantees of up to $6 million for loans from the project lenders. All other project debt is non-recourse. The Company has political risk insurance on the Sengkang project. The Company believes the current economic difficulties in Indonesia will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. Brazil The Company owns 100 percent of a 250 MW power plant in Manaus, Brazil. Power from the plant is currently sold under a four-year contract to Electronorte, denominated in Brazilian real. Due to the devaluation of the real in January 1999, Manaus suffered an $831,000 exchange loss on the December invoice. There is no provision in the contract to recover the effects of the devaluation on this invoice. However, future invoices are covered under a provision in the contract entitling the Company to recover a substantial portion of any future devaluation. The Company believes the current economic difficulties in Brazil will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. The contract for the Manaus power project provides for delay damages to be paid to Electronorte if the specified construction schedule was not met. Completion of the project was delayed beyond the originally scheduled completion dates provided in the contract and such delays have resulted in a claim by Electronorte for delay damages. The Company is in discussions with Electronorte regarding such claim. In any event, the Company has the right under its construction contract to assert claims against the construction contractor for such delay damages and believes that any such damages will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. Capital Commitments At December 31, 1998, the Company had capital and investment commitments of $245 million, which are expected to be funded through internally generated funds and/or incremental borrowings. The Company's other planned capital and investment projects are discretionary in nature, with no substantial capital commitments made in advance of the actual expenditures. Purchase Obligations In connection with the financing commitments of certain joint ventures, TGP has entered into unconditional purchase obligations for products and services totaling $77 million at December 31, 1998. TGP's annual obligations under these agreements are $21 million for the years 1999 and 2000, $11 million for the year 2001, $4 million for the years 2002 and 2003, and $16 million in total thereafter. Excluded from these amounts is TGP's obligation to purchase 30 percent of the output of the Great Plains coal gasification project's original design capacity through July 2009. In January 1997, TGP executed a settlement of this contract as part of its GSR negotiations, recorded the related liability, and, in the third quarter of 1997, purchased an annuity for $42 million to fund the expected remaining monthly demand requirements of the contract which, under the settlement, continue through January 2004. Operating Leases The Company leases certain property, facilities and equipment under various operating leases. In addition, in 1995, El Paso New Chaco Company ("EPNC") entered into an unconditional lease for the Chaco Plant. The lease term expires in 2002, at which time EPNC has an option, and an obligation upon the occurrence of certain events, to purchase the plant for a price sufficient to pay the amount of the $77 million 24 39 construction financing, plus interest and certain expenses. If EPNC does not purchase the plant at the end of the lease term, it has an obligation to pay a residual guaranty amount equal to approximately 87 percent of the amount financed, plus interest. The Company unconditionally guaranteed all obligations of EPNC under the lease. Minimum annual rental commitments at December 31, 1998, were as follows:
YEAR ENDING DECEMBER 31, OPERATING LEASES - ------------------------------------------------------------ ---------------- (IN MILLIONS) 1999..................................................... $ 18 2000..................................................... 18 2001..................................................... 18 2002..................................................... 17 2003..................................................... 13 Thereafter............................................... 56 ---- Total............................................. $140 ====
Aggregate minimum commitments have not been reduced by minimum sublease rentals of approximately $15 million due in the future under noncancelable subleases. Rental expense for operating leases for the years ended December 31, 1998, 1997, and 1996 was $27 million, $23 million, and $14 million, respectively. Guarantees At December 31, 1998, the Company had parental guarantees of up to $486 million in connection with its international development activities, as well as $181 million related to various other projects. The Company also had letters of credit of approximately $80 million outstanding at December 31, 1998. Rates and Regulatory Matters In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which it seeks comments on a wide range of initiatives to change the manner in which short-term (less than one year) transportation markets are regulated. Among other things, the NOPR proposes the following: (i) removing the price cap for the short-term capacity market; (ii) establishing procedures to make pipeline and shipper-owned capacity comparable; (iii) auctioning all available short-term pipeline capacity on a daily basis with the pipeline unable to set a reserve price above variable costs; (iv) changing policies or pipeline penalties, nomination procedures and services; (v) increasing pipeline reporting requirements; (vi) permitting the negotiation of terms and conditions of service; and (vii) potentially modifying the procedures for certificating new pipeline construction. Also in July 1998, FERC issued a Notice of Inquiry ("NOI") seeking comments on FERC's policy for pricing long-term capacity. Comments on the NOPR and NOI are due in April 1999, and it is unclear when and what action, if any, FERC will take in connection with the NOPR and NOI and the comments received in response to them. TGP -- In February 1997, TGP filed a settlement with FERC of all issues related to the recovery of its GSR and other transition costs and related proceedings (the "GSR Stipulation and Agreement"). In April 1997, FERC approved the settlement. Under the terms of the GSR Stipulation and Agreement, TGP is entitled to collect up to $770 million from its customers, $693 million through a demand surcharge and $77 million through an interruptible transportation surcharge. As of December 31, 1998, the demand portion had been fully collected and $41 million of the interruptible transportation portion had been collected. There is no time limit for collection of the interruptible transportation surcharge portion. The terms of the GSR Stipulation and Agreement also provide for a rate case moratorium through November 2000 (subject to certain limited exceptions) and an escalating rate cap, indexed to inflation, through October 2005, for certain 25 40 of TGP's customers. Under the terms of the GSR Stipulation and Agreement, TGP is required to refund to customers amounts collected in excess of each customer's share of transition costs. In December 1994, TGP filed for a general rate increase with FERC and in October 1996, FERC approved a settlement resolving that proceeding. The settlement included a structural rate design change that results in a larger portion of TGP's transportation revenues being dependent upon throughput. Under the stipulation, TGP's refund obligation was approximately $185 million, inclusive of interest, of which $161 million was refunded to customers in March 1997 and June 1997 with the remaining $24 million refund obligation offset against GSR recoveries in accordance with particular customer elections. TGP provided a reserve for these rate refunds as revenues were collected. One party, a competitor of TGP, filed a Petition for Review of the FERC orders with the Court of Appeals. The Court of Appeals remanded the case to FERC to respond to the competitor's argument that TGP's cost allocation methodology deterred the development of market centers (centralized locations where buyers and sellers can physically exchange gas). At FERC's request, comments were filed in January 1999. All cost of service issues related to TGP's 1991 general rate proceeding were resolved pursuant to a settlement agreement approved by FERC in an order which now has become final. However, cost allocation and rate design issues remained unresolved. In July 1996, following an ALJ's decision on these cost and design issues, FERC ruled on certain issues but remanded to the ALJ the issue of the proper allocation of TGP's New England lateral costs. In July 1997, FERC issued an order denying rehearing of its July 1996 order but clarifying that, among other things, although the ultimate resolution as to the proper allocation of costs would be applied retroactively to July 1, 1995, the cost of service settlement does not allow TGP to recover from other customers any amounts that TGP may ultimately be required to refund. In February 1999, petitions for review of the July 1996 and July 1997 FERC orders were denied by the Court of Appeals. In the remand proceeding, the ALJ issued his decision on the proper allocation of the New England lateral costs in December 1997. That decision adopts a methodology that, economically, approximates the one currently used by TGP. In October 1998, FERC issued an order affirming the ALJ's decision. Certain parties have requested rehearing of that order, and the matter is currently pending before FERC. TGP has filed cash out reports for the period September 1993 through August 1998. TGP's filings showed a cumulative loss through August of 1998 of $3 million. TGP has reached a settlement in principle with its customers to resolve outstanding FERC proceedings related to these filed cash out reports. The reports, as well as the accounting for customer imbalances, had been challenged by TGP's customers. Upon FERC's approval, the settlement will provide for a new mechanism for accounting for TGP's cash out program. Substantially all of the revenues of TGP are generated under long-term gas transmission contracts. Contracts representing approximately 70 percent of TGP's firm transportation capacity will be expiring over the next two years, principally in November 2000. Although TGP cannot predict how much capacity will be resubscribed, a majority of the expiring contracts cover service to northeastern markets, where there is currently little excess capacity. Several projects, however, have been proposed to deliver incremental volumes to these markets. Although TGP is actively pursuing the renegotiation, extension and/or replacement of these contracts, there can be no assurance as to whether TGP will be able to extend or replace these contracts (or a substantial portion thereof) or that the terms of any renegotiated contracts will be as favorable to TGP as the existing contracts. EPNG -- In June 1995, EPNG filed with FERC for approval of new system rates for mainline transportation to be effective January 1, 1996. In March 1996, EPNG filed a comprehensive offer of settlement to resolve that proceeding as well as issues surrounding certain contract reductions and expirations that were to occur from January 1, 1996, through December 31, 1997. In April 1997, FERC approved EPNG's settlement as filed and determined that only the contesting party, Edison, should be severed for separate determination of the rates it ultimately pays EPNG. In July 1997, FERC issued an order denying the requests for rehearing of the April 1997 order and the settlement was implemented effective July 1, 1997. Hearings to determine Edison's rates were completed in May 1998, and an initial decision was issued by the presiding ALJ in July 1998. EPNG and Edison have filed exceptions to the decision with FERC. If the ALJ's decision is affirmed by FERC, EPNG believes that the resulting rates to Edison would be such that no 26 41 significant, if any, refunds in excess of the amounts reserved would be required. Pending the final outcome, Edison continues to pay the originally filed rates, subject to refund, and EPNG continues to provide a reserve for such potential refunds. Edison filed with the Court of Appeals a petition for review of FERC's April 1997 and July 1997 orders, in which it challenged the propriety of FERC's approving the settlement over Edison's objections to the settlement as a customer of SoCal. In December 1998, the Court of Appeals issued its decision vacating and remanding FERC's order. EPNG will file a motion with FERC proposing procedures to address deficiencies which the Court of Appeals found in FERC's earlier orders. EPNG cannot predict the outcome with certainty, but it believes that FERC will ultimately approve the settlement. The rate settlement establishes, among other things, base rates through December 31, 2005. Such rates escalate annually beginning in 1998. In addition, the settlement provides for settling customers to (i) pay $295 million (including interest) as a risk sharing obligation, which approximates 35 percent of anticipated revenue shortfalls over an 8 year period, resulting from the contract reductions and expirations referred to above, (ii) receive 35 percent of additional revenues received by EPNG, above a threshold, for the same eight-year period, and (iii) have the base rates increase or decrease if certain changes in laws or regulations result in increased or decreased costs in excess of $10 million a year. In accordance with the terms of the rate settlement, EPNG's refund obligation (including interest) was approximately $194 million. EPNG refunded $61 million to customers in August 1997 and, in accordance with certain customers' elections, the remaining $133 million of refund obligation was applied towards their $295 million risk sharing obligation. Through December 31, 1998, an additional $94 million of the risk sharing obligation was paid and the remaining $68 million balance, including interest, will be collected by the end of 2003. From 1996 through December 31, 1998, $69 million of the risk sharing obligation had been recognized as revenue. The remaining unearned risk sharing amounts, totaling $226 million, excluding interest, will be recognized ratably through the year 2003. In addition to other arrangements to offset the effects of the reduction in firm capacity commitments referred to above, EPNG entered into three contracts with Dynegy for the sale of substantially all of its turned back firm capacity available to California as of January 1, 1998, (approximately 1.3 Bcf) for a two-year period beginning January 1, 1998, at rates negotiated pursuant to EPNG's tariff provisions and FERC policies. EPNG realized $29 million in revenue in 1998 and anticipates realizing at least $41 million in revenues in 1999 (which are and will be subject to the revenue sharing provisions of the rate settlement) for this capacity. The contracts have a transport-or-pay provision requiring Dynegy to pay a minimum charge equal to the reservation component of the contractual charge on at least 50 percent of the contracted volumes in each month in 1998 and on at least 72 percent of the contracted volumes each month in 1999. In the third quarter of 1999, EPNG intends to remarket this capacity pursuant to EPNG's tariff provisions and FERC regulations, subject to Dynegy's right of first refusal. In December 1997, EPNG filed to implement several negotiated rate contracts, including those with Dynegy. In a protest to this filing, three shippers (producers/marketers) requested that FERC require EPNG to eliminate certain provisions from the Dynegy contracts, to publicly disclose and repost the contracts for competitive bidding, and to suspend their effectiveness. In an order issued in January 1998, FERC rejected several of the arguments made in the protest and allowed the contracts to become effective as of January 1, 1998, subject to refund, and to the outcome of a technical conference, which was held in March 1998. In June 1998, FERC issued an order rejecting the protests to the Dynegy contracts, but required EPNG to file modifications with FERC to the contracts clarifying the credits under the reservation reduction mechanism and the recall rights of certain capacity. In addition, EPNG agreed to separately post capacity covered by the Dynegy contracts which becomes available in the future. Several parties have protested EPNG's compliance filing and/or requested rehearing of FERC's June 1998 order. In June 1998, EPNG filed a letter agreement in compliance with the June 1998 FERC order. In September 1998, FERC issued an order accepting the letter agreement subject to EPNG making additional modifications. The additional modifications to the letter agreement required further clarification of credits available to Dynegy under the reservation reduction mechanism and the recall rights of certain capacity. In October 1998, EPNG filed a revised letter agreement with FERC and requested rehearing of the September 1998 order. 27 42 Under the revenue sharing provisions of its rate case settlement, EPNG is obligated to return approximately $12 million of non-traditional revenues to certain customers. Approximately $5 million had been credited to such customers' transportation invoices at December 31, 1998, and the balance of the $7 million has been or will be credited ratably over January, February, and March 1999. At December 31, 1998, EPNG had a reserve for the $7 million. Under FERC procedures, take-or-pay cost recovery filings may be challenged by pipeline customers on prudence and certain other grounds. Certain parties sought review in the Court of Appeals of FERC's determination in an October 1992 order that certain buy-down/buy-out costs were eligible for recovery. In January 1996, the Court of Appeals remanded the order to FERC with direction to clarify the basis for its decision that the take-or-pay buy-down/buy-out costs were eligible for recovery. In March 1997, following a technical conference and the submission of statements of position and replies, FERC issued an order determining that the costs related to all but one of EPNG's disputed contracts were eligible for recovery. The costs ruled ineligible for recovery totaled approximately $3 million, including interest, and were refunded to customers in the second quarter of 1997. In October 1997, FERC issued an order denying the challenging parties' request for rehearing of the March 1997 order in most respects, but determined that the costs incurred pursuant to two additional EPNG contracts were ineligible for recovery. These costs, including interest, totaled approximately $9 million and were refunded to customers in February 1998. The challenging parties, which claim that EPNG should be required to refund up to an additional $31 million filed a petition for review of the FERC order in the Court of Appeals. In February 1999, the Court of Appeals affirmed FERC's October 1997 order. In November 1996, GPM Corporation filed a complaint, as amended, with FERC alleging that EPNG's South Carlsbad compression facilities were gathering facilities and were improperly functionalized by EPNG as transmission facilities. In accordance with the FERC orders, the South Carlsbad compressor facilities were transferred to EPFS in April 1998. In a November 1997 order, FERC reversed its previous decision and found that EPNG's Chaco Station should be functionalized as gathering, not transmission, facility and should be transferred to EPFS. FERC has denied all requests for rehearing. EPNG and two other parties filed petitions for review with the Court of Appeals. The matter has been briefed and will be argued in September 1999. In accordance with the FERC orders, the Chaco Station was transferred to EPFS in April 1998. FERC Compliance Audits TGP and EPNG, as interstate pipelines, are subject to FERC audits of their books and records. EPNG currently has an open audit covering the years 1990 through 1995. FERC is expected to issue its audit report in 1999. Both EPNG's and TGP's property retirements are currently under review by the FERC audit staff. Management believes the ultimate resolution of the aforementioned rate and regulatory matters, which are in various stages of finalization, will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. Legal Proceedings In November 1993, TransAmerican filed a complaint in a Texas state court, TransAmerican Natural Gas Corporation v. El Paso Natural Gas Company, et al., alleging fraud, tortious interference with contractual relationships, negligent misrepresentation, economic duress, civil conspiracy, and violation of state antitrust laws arising from a settlement agreement entered into by EPNG, TransAmerican Natural Gas Corporation ("TransAmerican"), and others in 1990 to settle litigation then pending and other potential claims. The complaint, as amended, seeks actual damages of $1.5 billion and exemplary damages of $6 billion. EPNG is defending the matter in the State District Court of Dallas County, Texas. In April 1996, a former employee of TransAmerican filed a related case in Harris County, Texas, Vickroy E. Stone v. Godwin & Carlton, P.C., et al. (including EPNG), seeking indemnification and other damages in unspecified amounts relating to litigation consulting work allegedly performed for various entities, including EPNG, in cases involving TransAmerican. EPNG filed a motion for summary judgment in the TransAmerican case arguing that 28 43 plaintiff's claims are barred by a prior release executed by TransAmerican, by statutes of limitations, and by the final court judgment ending the original litigation in 1990. Following a hearing in January 1998, the court granted summary judgment in EPNG's favor on TransAmerican's claims based on economic duress and negligent misrepresentation, but denied the motion as to the remaining claims. In February 1998, EPNG filed a motion for summary judgment in the Stone litigation arguing that all claims are baseless, barred by statutes of limitations, subject to executed releases, or have been assigned to TransAmerican. In June 1998, the court granted EPNG's motion in its entirety and dismissed all the remaining claims in the Stone litigation. In August 1998, the court denied Stone's motion for a new trial seeking reconsideration of that ruling. Stone has appealed the court's ruling to the Texas Court of Appeals in Houston, Texas. The TransAmerican trial is set to commence in September 1999. Based on information available at this time, management believes that the claims asserted against it in both cases have no factual or legal basis and that the ultimate resolution of these matters will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. In February 1998, the United States and the State of Texas filed in a United States District Court a Comprehensive Environmental Response, Compensation and Liability Act cost recovery action, United States v. Atlantic Richfield Co., et al., against fourteen companies including the following affiliates of EPEC: TGP, EPTPC, EPEC Corporation, EPEC Polymers, Inc. and the dissolved Petro-Tex Chemical Corporation, relating to the Sikes Disposal Pits Superfund Site ("Sikes") located in Harris County, Texas. Sikes was an unpermitted waste disposal site during the 1960s that accepted waste hauled from numerous Houston Ship Channel industries. The suit alleges that the former Tenneco Chemicals, Inc. and Petro-Tex Chemical Corporation arranged for disposal of hazardous substances at Sikes. TGP, EPTPC, EPEC Corporation and EPEC Polymers, Inc. are alleged to be derivatively liable as successors or as parent corporations. The suit claims that the United States and the State of Texas have expended over $125 million in remediating the site, and seeks to recover that amount plus interest. Other companies named as defendants include Atlantic Richfield Company, Crown Central Petroleum Corporation, Occidental Chemical Corporation, Exxon Corporation, Goodyear Tire & Rubber Company, Rohm & Haas Company, Shell Oil Company and Vacuum Tanks, Inc. These defendants have filed their answers and third-party complaints seeking contribution from twelve other entities believed to be PRPs at Sikes. Although factual investigation relating to Sikes is in very preliminary stages, the Company believes that the amount of material, if any, disposed at Sikes from the Tenneco Chemicals, Inc. or Petro-Tex Chemical Corporation facilities was small, possibly de minimis. However, the government plaintiffs have alleged that the defendants are each jointly and severally liable for the entire remediation costs and have also sought a declaration of liability for future response costs such as groundwater monitoring. While the outcome of this matter cannot be predicted with certainty, management does not expect this matter to have a material adverse effect on the Company's financial position, results of operations, or cash flows. TGP is a party in proceedings involving federal and state authorities regarding the past use by TGP of a lubricant containing PCBs in its starting air systems. TGP has executed a consent order with the EPA governing the remediation of certain of its compressor stations and is working with the relevant states regarding those remediation activities. TGP is also working with the Pennsylvania and New York environmental agencies to specify the remediation requirements at the Pennsylvania and New York stations. Remediation activities in Pennsylvania are complete with the exception of some long-term groundwater monitoring requirements. Remediation and characterization work at the compressor stations under its consent order with the EPA and the jurisdiction of the New York Department of Environmental Conservation is ongoing. Management believes that the ultimate resolution of these matters will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. In November 1988, the Kentucky environmental agency filed a complaint in a Kentucky state court, Commonwealth of Kentucky, Natural Resources and Environmental Protection Cabinet v. Tennessee Gas Pipeline Company, alleging that TGP discharged pollutants into the waters of the state without a permit and disposed of PCBs without a permit. The agency sought an injunction against future discharges, sought an order to remediate or remove PCBs, and sought a civil penalty. TGP has entered into agreed orders with the agency to resolve many of the issues raised in the original allegations, has received water discharge permits for 29 44 its Kentucky compressor stations from the agency, and continues to work to resolve the remaining issues. The relevant Kentucky compressor stations are scheduled to be characterized and remediated under the consent order with the EPA. Management believes that the resolution of this issue will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. A number of subsidiaries of EPEC, both wholly owned and partially owned, as well as Leviathan, have been named defendants in United States ex rel Grynberg v. El Paso Natural Gas Company, et al. Generally, the complaint in this motion alleges an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Indian lands, thereby depriving the U.S. government of royalties. The complaint remains sealed. The Company believes the complaint to be without merit. The Company is a named defendant in numerous lawsuits and a named party in numerous governmental proceedings arising in the ordinary course of business. While the outcome of such lawsuits or other proceedings against the Company cannot be predicted with certainty, management currently does not expect these matters to have a material adverse effect on the Company's financial position, results of operations, or cash flows. ENVIRONMENTAL The Company is subject to extensive federal, state, and local laws and regulations governing environmental quality and pollution control. These laws and regulations require the Company to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 1998, the Company had a reserve of approximately $255 million for expected remediation costs and associated onsite, offsite and groundwater technical studies of approximately $239 million; and other costs of approximately $16 million which the Company anticipates incurring through 2027. In addition, the Company estimates that its subsidiaries will make capital expenditures for environmental matters of approximately $6 million in 1999. Capital expenditures will range from approximately $60 million to $85 million in the aggregate for the years 2000 through 2007. These expenditures primarily relate to compliance with air regulations and, to a lesser extent, control of water discharges. Since 1988, TGP has been engaged in an internal project to identify and deal with the presence of PCBs and other substances of concern, including substances on the EPA List of Hazardous Substances, at compressor stations and other facilities operated by both its interstate and intrastate natural gas pipeline systems. While conducting this project, TGP has been in frequent contact with federal and state regulatory agencies, both through informal negotiation and formal entry of consent orders, to assure that its efforts meet regulatory requirements. In May 1995, following negotiations with its customers, TGP filed with FERC a separate Stipulation and Agreement (the "Environmental Stipulation") that establishes a mechanism for recovering a substantial portion of the environmental costs identified in the internal project. In November 1995, FERC issued an order approving the Environmental Stipulation. Although one shipper filed for rehearing, FERC denied rehearing of its order in February 1996. The Environmental Stipulation was effective July 1, 1995. As of December 31, 1998, a balance of $2 million remains to be collected under the stipulation. The Company and certain of its subsidiaries have been designated, have received notice that they could be designated, or have been asked for information to determine whether they could be designated as a PRP with respect to 30 sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund) or state equivalents. The Company has sought to resolve its liability as a PRP with respect to these Superfund sites through indemnification by third parties and/or settlements which provide for payment of the Company's allocable share of remediation costs. As of December 31, 1998, the Company has estimated its share of the remediation costs at these sites to be between $62 million and $75 million and has provided reserves that it believes are adequate for such costs. Since the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases the Company has asserted a defense to any liability, the Company's estimate of its 30 45 share of remediation costs could change. Moreover, liability under the federal Superfund statute is joint and several, meaning that the Company could be required to pay in excess of its pro rata share of remediation costs. The Company's understanding of the financial strength of other PRPs has been considered, where appropriate, in its determination of its estimated liability as described herein. The Company presently believes that the costs associated with the current status of such entities as PRPs at the Superfund sites referenced above will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. The Company has initiated proceedings against its historic liability insurers seeking payment or reimbursement of costs and liabilities associated with environmental matters. In these proceedings, the Company contends that certain environmental costs and liabilities associated with various entities or sites, including costs associated with former operating sites, must be paid or reimbursed by certain of its historic insurers. The proceedings are in the discovery stage, and it is not yet possible to predict the outcome. It is possible that new information or future developments could require the Company to reassess its potential exposure related to environmental matters. The Company may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from current or discontinued operations, could result in substantial costs and liabilities in the future. As such information becomes available, or developments occur, related accrual amounts will be adjusted accordingly. While there are still uncertainties relating to the ultimate costs which may be incurred, based upon the Company's evaluation and experience to date, the Company believes the recorded reserve is adequate. For a further discussion of specific environmental matters, see Legal Proceedings above. OTHER Acquisition of CE Generation LLC In March 1999, EPPS purchased a 50 percent ownership interest in CE Generation LLC. The equity investment in CE Generation LLC of approximately $260 million, subject to certain adjustments, will be accounted for under the equity method. CE Generation LLC owns 12 power generation projects, which are qualifying facilities under the Public Utility Regulatory Policy Act, and two additional generating facilities currently under construction in southern California. Collectively, the 14 power projects have a combined electric generating capacity of approximately 896 MW and include ten geothermal projects near the Imperial Valley in southern California and four natural gas-fired cogeneration projects in New York, Pennsylvania, Texas and Arizona. PPN Power Project In March 1999, the Company signed a sale and purchase agreement to acquire a 26 percent interest in a $295 million power plant in Tamil Nadu, India. The project consists of a 346 MW combined cycle power plant which will serve as a base load facility and sell power to the state-owned Tamil Nadu Electricity Board under a thirty-year power purchase agreement. Construction began in January 1999, and operations are expected to commence in early 2001. Transfer of the funds to complete the acquisition is expected to be finalized by the end of March 1999. Acquisition of DeepTech In August 1998, the Company completed its acquisition of DeepTech by merging DeepTech with a subsidiary of EPEC. DeepTech's assets included a combined 27.3 percent ownership interest in Leviathan. The acquisition was accounted for as a purchase with a total purchase price, net of cash received, of approximately $422 million. The Company recorded $214 million of goodwill in connection with the acquisition which will be amortized using the straight-line method over a period of 40 years. The amount allocated to goodwill is based on the excess of the total purchase price over the estimated fair value of assets 31 46 and liabilities at the acquisition date. The amounts may be adjusted in the final purchase price allocation. Management does not expect the ultimate resolution of the purchase price allocation to materially impact the Company's financial position, results of operations, or cash flows. The operating results of DeepTech are included in the Company's Consolidated Statements of Income beginning on August 15, 1998. Year 2000 The Company has established an executive steering committee and a project team to coordinate the phases of its Year 2000 project to assure that the Company's key automated systems and related processes will remain functional through the year 2000. Those phases are: (i) awareness; (ii) assessment; (iii) remediation; (iv) testing; (v) implementation of the necessary modifications and (vi) contingency planning (which was previously included as a component of the Company's implementation phase). In recognition of the importance of Year 2000 issues and their potential impact to the Company, the initial phase of the Year 2000 project involved the establishment of a company-wide awareness program. The awareness program is directed by the executive steering committee and project team and includes participation of senior management in each core business area. The awareness phase is substantially completed, although the Company will continually update awareness efforts for the duration of the Year 2000 project. The Company's assessment phase consists of conducting a company-wide inventory of its key automated systems and related processes, analyzing and assigning levels of criticality to those systems and processes, identifying and prioritizing resource requirements, developing validation strategies and testing plans, and evaluating business partner relationships. The portion of the assessment phase related to internally developed computer applications, hardware and equipment, and embedded chips is substantially complete. The Company estimates that it has finished more than three-fourths of the portion of the assessment to determine the nature and impact of the Year 2000 date change for third-party-developed software. The assessment phase of the project, among other things, involves efforts to obtain representations and assurances from third parties, including third party vendors, that their hardware and equipment products, embedded chip systems, and software products being used by or impacting the Company are or will be modified to be Year 2000 compliant. To date, the responses from such third parties, although generally encouraging, are inconclusive. As a result, the Company cannot predict the potential consequences if these or other third parties or their products are not Year 2000 compliant. The Company is currently evaluating the exposure associated with such business partner relationships. The remediation phase involves converting, modifying, replacing or eliminating key automated systems identified in the assessment phase. The testing phase involves the validation of the identified key automated systems. The Company is utilizing test tools and written test procedures to document and validate, as necessary, its unit, system, integration, and acceptance testing. The Company estimates that approximately one-half of the work of these phases remains, and expects each to be substantially completed by mid-1999. The implementation phase involves placing the converted or replaced key automated systems into operation. In some cases, this phase will also involve the implementation of contingency plans needed to support business functions and processes that may be interrupted by Year 2000 failures that are outside of the Company's control. The Company has completed more than one-fourth of the implementation phase, which is expected to be substantially completed by mid-1999. The contingency planning phase consists of developing a risk profile of the Company's critical business processes and then providing for actions the Company will pursue to keep such processes operational in the event of Year 2000 disruptions. The focus of such contingency planning is on prompt response to any Year 2000 events, and a plan for subsequent resumption of normal operations. The plan is expected to assess the risk of a significant failure to critical processes performed by the Company, and to address the mitigation of those risks. The plan will also consider any significant failures related to the most reasonably likely worst case scenario, discussed below, as they may occur. In addition, the plan is expected to factor in the severity and duration of the impact of a significant failure. The Company plans to have its contingency plan completed by 32 47 mid-1999. The Year 2000 contingency plan will continue to be modified and adjusted throughout the year as additional information becomes available. The goal of the Year 2000 project is to ensure that all of the critical systems and processes which are under the Company's direct control remain functional. Certain systems and processes may be interrelated with or dependent upon systems outside the Company's control, however, and systems within the Company's control may have unpredicted problems. Accordingly, there can be no assurance that significant disruptions will be avoided. The Company's present analysis of its most reasonably likely worst case scenario for Year 2000 disruptions includes Year 2000 failures in the telecommunications and electricity industries, as well as interruptions from suppliers that might cause disruptions in the Company's operations, thus causing temporary financial losses and an inability to deliver products and services to customers. Virtually all of the natural gas transported through the Company's interstate pipelines is owned by third parties. Accordingly, failures of natural gas producers to be ready for the Year 2000 could significantly disrupt the flow of product to the Company's customers. In many cases, the producers have no direct contractual relationship with the Company, and the Company relies on its customers to verify the Year 2000 readiness of the producers from whom they purchase natural gas. Since most of the Company's revenues from the delivery of natural gas are based upon fees paid by its customers for the reservation of capacity, and not based upon the volume of actual deliveries, short term disruptions in deliveries caused by factors beyond the Company's control should not have a significant financial impact on the Company, although it could cause operational problems for the Company's customers. Longer-term disruptions, however, could materially impact the Company's results of operations, financial condition, and cash flows. While the Company owns or controls most of its domestic facilities and projects, nearly all of the Company's international investments have been made in conjunction with unrelated third parties. In many cases, the operators of such international facilities are not under the sole or direct control of the Company. As a consequence, the Year 2000 programs instituted at some of the international facilities may be different from the Year 2000 program implemented by the Company domestically, and the party responsible for the results of such program may not be under the direct or indirect control of the Company. In addition, the "non-controlled" programs may not provide the same degree of communication, documentation and coordination as the Company achieves in its domestic Year 2000 program. Moreover, the regulatory and legal environment in which such international facilities operate makes analysis of possible disruption and associated financial impact difficult. Many foreign countries appear to be substantially behind the United States in addressing potential Year 2000 disruption of critical infrastructure and in developing a framework governing the reporting requirements and relative liabilities of business entities. Accordingly, the Year 2000 risks posed by international operations as a whole are different than those presented domestically. As part of its Year 2000 effort, the Company is assessing the differences between the non-controlled programs and its domestic Year 2000 project, and has formulated and instituted a program for identifying such risks and preparing a response to such risks. While the Company believes that most of the international facilities in which it has significant investments are addressing Year 2000 issues in an adequate manner, it is possible that some of them may experience significant Year 2000 disruption, and that the aggregate effect of problems experienced at multiple international locations may be material and adverse. The Company intends to incorporate this possibility into the relevant contingency plans. While the total cost of the Company's Year 2000 project is still being evaluated, the Company estimates that the costs to be incurred in 1999 and 2000 associated with assessing, remediating and testing internally developed computer applications, hardware and equipment, embedded chip systems, and third-party-developed software will be between $14 million and $26 million. Of these estimated costs, the Company expects between $6 million and $14 million to be capitalized and the remainder to be expensed. As of December 31, 1998, the Company has incurred expenses of approximately $6 million. The Company has previously only traced incremental expenses related to its Year 2000 project. This means that the costs of the Year 2000 project related to salaried employees of the Company, including their direct salaries and benefits, are not available, and have not been included in the estimated costs of the project. Since the earlier phases of the project mostly involved work performed by such salaried employees, the costs expended to date do not reflect the percentage completion of the project. The Company anticipates that it will expend most of the costs 33 48 reported above in the remediation, implementation and contingency planning phases of the project. It is possible the Company may need to reassess its estimate of Year 2000 costs in the event the Company completes an acquisition of, or makes a material investment in, substantial facilities or another business entity. Although the Company does not expect the costs of its Year 2000 project to have a material adverse effect on its financial position, results of operations, or cash flows, based on information available at this time the Company cannot conclude that disruption caused by internal or external Year 2000 related failures will not have such an effect. Specific factors which might affect the success of the Company's Year 2000 efforts and the occurrence of Year 2000 disruption or expense include the failure of the Company of its outside consultants to properly identify deficient systems, the failure of the selected remedial action to adequately address the deficiencies, the failure of the Company's outside consultants to complete the remediation in a timely manner (due to shortages of qualified labor or other factors), unforeseen expenses related to the remediation of existing systems or the transition to replacement systems, the failure of third parties to become Year 2000 compliant or to adequately notify the Company of potential noncompliance and the effects of any significant disruption at international facilities in which the Company has significant investments. The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the intention to comply fully with the Year 2000 Information and Readiness Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat, 2386, signed into law October 19, 1998. All statements made herein shall be construed within the confines of that Act. To the extent that any reader of the above Year 2000 Readiness Disclosure is other than an investor or potential investor in the Company's -- or an affiliate's -- equity or debt securities, this disclosure is made for the SOLE PURPOSE of communicating or disclosing information aimed at correcting, helping to correct and/or avoid Year 2000 failures. Employee Separation and Asset Impairment Charge During the first quarter of 1996, the Company adopted a program to reduce operating costs through work force reductions and improved work processes and adopted SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. As a result of the workforce reduction program and the adoption of SFAS No. 121, the Company recorded a special charge of $99 million ($47 million for employee separation costs and $52 million for asset impairments) in the first quarter of 1996. For a further discussion, see Item 8, Financial Statements and Supplementary Data, Note 11. Management is not aware of other commitments or contingent liabilities which would have a materially adverse effect on the Company's financial condition, results of operations, or cash flows. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED Accounting for the Costs of Computer Software Developed or Obtained for Internal Use In March 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. This statement provides guidance on accounting for such costs, and also defines internal-use computer software. The statement is effective for fiscal years beginning after December 15, 1998. The application of this pronouncement will not have a material impact on the Company's financial position, results of operations, or cash flows. Reporting on the Costs of Start-Up Activities In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5, Reporting on the Costs of Start-Up Activities. The statement defines start-up activities and requires start-up and organization costs to be expensed as incurred. In addition, it requires that any such cost that exists on the balance sheet be expensed upon adoption of this pronouncement. The statement is effective for fiscal years beginning after December 15, 1998. The Company will adopt this pronouncement effective January 1, 1999, and expects to report a charge in the range of $7 million to $12 million, net of income taxes, in the first quarter of 1999 as a cumulative effect of a change in accounting principle. 34 49 Accounting for Derivative Instruments and Hedging Activities In June 1998, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, was issued by the Financial Accounting Standards Board to establish accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity classify all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (i) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (ii) a hedge of the exposure to variable cash flows of a forecasted transaction, or (iii) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. The accounting for the changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. The standard is effective for all quarters in fiscal years beginning after June 15, 1999. The Company is currently evaluating the effects of this pronouncement. Disclosure relating to Euro Conversion In July 1998, the Securities and Exchange Commission issued Staff Legal Bulletin No. 6 to provide guidance for disclosure related to the Euro Conversion. The guidance primarily focuses on disclosure in the Management's Discussion and Analysis of Financial Condition and Results of Operations, as well as Description of Business. The Company currently has no investments in the countries affected by the Euro Conversion. Accounting for Contracts Involved in Energy Trading and Risk Management Activities In November 1998, the Emerging Issues Task Force reached a consensus on EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in fair value included in earnings. EITF 98-10 is effective for fiscal years beginning after December 15, 1998. The Company adopted the provisions of EITF 98-10 in January 1999. The application of this pronouncement did not have a material impact on the Company's financial position, results of operations, or cash flows. 35 50 RISK FACTORS -- CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 This report contains or incorporates by reference forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while such assumptions or bases are believed to be reasonable and are made in good faith, assumed facts or bases almost always vary from the actual results, and the differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, we or our management express an expectation or belief as to future results, such expectation or belief is expressed in good faith and is believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. The words "believe," "expect," "estimate," "anticipate" and similar expressions may identify forward-looking statements. With this in mind, you should consider the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf: OUR INDUSTRY IS HIGHLY COMPETITIVE The hydrocarbons that we transport, gather, process and store are owned by third parties. As a result, the volume of hydrocarbons involved in such activities is dependent upon the actions of those third parties, and are beyond our control. Further, our ability to maintain or increase current transmission, gathering, processing, and sales volumes or to remarket unsubscribed capacity, is subject to the impact of the following: - future weather conditions, including those that favor hydroelectric generation or other alternative energy sources; - price competition; - drilling activity and supply availability; - expiration of the Dynegy contracts at the end of 1999; and - service competition, especially due to current excess pipeline capacity into California. Our future profitability may be affected by our ability to compete with the services offered by other energy enterprises which may be larger, offer more services, and possess greater resources. Seventy percent of TGP's contracts are expiring over the next two years, principally in November 2000. Our ability to negotiate new contracts and to renegotiate existing contracts could be adversely affected by factors we cannot control, including: - the proposed construction by other companies of additional pipeline capacity in the markets served by TGP; - reduced demand due to higher gas prices; - the availability of alternative energy sources; and - the viability of our expansion projects. For a further discussion see Item 1, Business, Natural Gas Transmission, Markets and Competition. FLUCTUATIONS IN NATURAL GAS AND NATURAL GAS LIQUIDS PRICES COULD ADVERSELY AFFECT OUR BUSINESS Our ability to compete with other transporters is impacted by natural gas prices in the supply basins connected to our pipeline systems as compared to prices in other gas producing regions, especially Canada. Revenues generated by our gathering and processing contracts are dependent upon volumes and rates, both of which can be affected by the prices of natural gas and natural gas liquids. The success of our expanding gathering and processing operations in the offshore Gulf of Mexico is subject to continued development of 36 51 additional oil and gas reserves in the vicinity of our facilities and our ability to access such additional reserves to offset the natural decline from existing wells connected to our systems. A decline in energy prices could precipitate a decrease in such development activities and could cause a decrease in the volume of reserves available for gathering and processing through our offshore facilities. Fluctuations in energy prices, which may impact gathering rates and investments by third parties in the development of new oil and gas reserves connected to our gathering and processing facilities, are caused by a number of factors, including: - regional, domestic and international supply and demand; - availability and adequacy of transportation facilities; - energy legislation; - federal or state taxes, if any, on the sale or transportation of natural gas and natural gas liquids and the price; and - abundance of supplies of alternative energy sources. If there are reductions in the average volume of the natural gas we transport, gather and process for a prolonged period, our results of operations and financial position could be materially adversely affected. THE USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES Some of our non-regulated subsidiaries are engaged in the gathering, processing and marketing of natural gas and other energy commodities and utilize futures and option contracts traded on the New York Mercantile Exchange and over-the-counter options and price and basis swaps with other gas merchants and financial institutions. These instruments are intended to reduce our exposure to short-term volatility in changes in commodities prices. We could, however, incur financial losses in the future as a result of volatility in the market values of the underlying commodities or if one of our counterparties fails to perform under a contract. For additional information concerning our derivative financial instruments, see item 7A, Quantitative and Qualitative Disclosures About Market Risks and Item 8, Financial Statements and Supplementary Data, Note 5. ATTRACTIVE ACQUISITION AND INVESTMENT OPPORTUNITIES MAY NOT BE AVAILABLE Our ability to grow will depend, in part, upon our ability to identify and complete attractive acquisition and investment opportunities. Opportunities for growth through acquisitions and investments in joint ventures, and the future operating results and success of such acquisitions and joint ventures within and outside the U.S. may be subject to the effects of, and changes in the following: - U.S. and foreign trade and monetary policies; - laws and regulations; - political and economic developments; - inflation rates; - taxes; and - operating conditions. OUR FOREIGN INVESTMENTS INVOLVE SPECIAL RISKS Our activities in areas outside the U.S. are subject to the risks inherent in foreign operations, including: - loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, wars, insurrection and other political risks, and - the effects of currency fluctuations and exchange controls (such as the recent devaluation of the Indonesian and Brazilian currencies and other economic problems). 37 52 Such legal and regulatory events and other unforeseeable obstacles may be beyond our control or ability to manage. WE COULD INCUR SUBSTANTIAL ENVIRONMENTAL LIABILITIES We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from current or discontinued operations, could result in substantial costs and liabilities in the future. For additional information concerning the Company's environmental matters, see the section of this item entitled "Environmental." OUR ACTIVITIES INVOLVE OPERATING HAZARDS AND UNINSURED RISKS While we maintain insurance against certain of the risks normally associated with the transportation, gathering and processing of natural gas, including explosions, pollution and fires, the occurrence of a significant event that is not fully insured against could have a material adverse effect on our business. THERE REMAIN POTENTIAL LIABILITIES RELATED TO THE ACQUISITION OF EPTPC The amount of the actual and contingent liabilities of EPTPC, which remained the liabilities of EPNG after it acquired EPTPC, could vary materially from the amount we estimated, which was based upon assumptions which could prove to be inaccurate. If New Tenneco or Newport News Shipbuilding Inc. were unable or unwilling to pay their respective liabilities, a court could require us, under certain legal theories which may or may not be applicable to the situation, to assume responsibility for such obligations. If we were required to assume these obligations, it could have a material adverse effect on our financial condition, results of operations or cash flows. THERE REMAIN POTENTIAL FEDERAL INCOME TAX LIABILITIES RELATED TO THE ACQUISITION OF EPTPC In connection with the acquisition of EPTPC and the Distributions made by EPTPC prior to that acquisition, the IRS issued a private letter ruling to Old Tenneco, in which it ruled that for U.S. federal income tax purposes the Distributions would be tax-free to Old Tenneco and, except to the extent cash was received in lieu of fractional shares, to its then existing stockholders; the Merger would constitute a tax-free reorganization; and that certain other transactions effected in connection with the Merger and Distribution would be tax-free. If the Distributions were not to qualify as tax-free distributions, then a corporate level federal income tax would be assessed to the consolidated group of which Old Tenneco was the common parent. This corporate level federal income tax would be payable by EPTPC. Under certain limited circumstances, however, New Tenneco and Newport News Shipbuilding Inc. have agreed to indemnify EPTPC for a defined portion of such tax liabilities. WE ARE SUBJECT TO FINANCING AND INTEREST RATE EXPOSURE RISKS Our business and operating results can be adversely affected by factors such as the availability or cost of capital, changes in interest rates, changes in the tax rates due to new tax laws, market perceptions of the natural gas industry or EPEC, or credit ratings. WE ARE SUBJECT TO RISKS ASSOCIATED WITH YEAR 2000 ISSUES We are taking steps to mitigate any adverse effects of the Year 2000 date change on our customers and business operations including the assessment, remediation, testing of our applications, hardware and software, and the implementation of necessary change. Nevertheless, our failure, or the failure of third-parties with whom we deal, to achieve Year 2000 compliance may adversely affect our business. For additional information on our Year 2000 strategy and specific factors that may affect our ability to achieve Year 2000 compliance, see the section of this item entitled "Other -- Year 2000." 38 53 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company utilizes derivative financial instruments to manage market risks associated with certain energy commodities and interest and foreign currency exchange rates. The Company's primary market risk exposure is to changing commodity prices. Market risks are monitored by a corporate risk management committee that operates independently from the business segments that create or actively manage these risk exposures to ensure compliance with the Company's stated risk management policies as approved by the Board. These policies are set forth in Item 8, Financial Statements and Supplementary Data, Note 1. TRADING COMMODITY PRICE RISK EPEM is exposed to certain market risks inherent in its financial instruments entered into for trading purposes associated with natural gas, power and petroleum products. EPEM marks to market all energy trading activities, including transportation capacity and storage. EPEM's policy is to manage commodity price risks through a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, swap contracts which require payment to (or receipts from) counterparties based on the differential between a fixed and variable price for the commodity, exchange-traded options, over-the-counter options and other contractual arrangements. EPEM manages its markets risk on a portfolio basis, subject to parameters established by the risk management committee. Comprehensive risk management processes, policies, and procedures have been established to monitor and control its market risk. The Company's risk management committee also continually reviews these policies to ensure they are responsive to changing business conditions. EPEM measures the risk in its commodity and energy related contract portfolio on a daily basis utilizing a Value-at-Risk ("VAR") model to determine the maximum potential one-day unfavorable impact on its earnings from its existing portfolio due to normal market movements and monitors its risk in comparison to established thresholds. The VAR computations are based on historical simulation, which utilizes price movements over a specified period to simulate forward price curves in the energy markets, and several key assumptions, including the selection of a confidence level for expected losses and the holding period for liquidation. EPEM also utilizes other measures outside the VAR methodology to monitor the risk in its commodity and energy related contract portfolio on a monthly basis, including stress testing, position limit control and credit, liquidity and event risk management. EPEM previously utilized sensitivity analysis to report market risk based on a ten percent change in commodity prices. The uncertainty of the market place, increased trading of derivative instruments, and the complexity of these instruments created the demand for a more comprehensive portfolio level quantitative measure of market risk. Accordingly, EPEM converted from utilizing sensitivity analysis to the VAR model during 1998. Assuming a confidence level of 95 percent and a one-day holding period, EPEM's estimated potential one-day unfavorable impact on income before income taxes and minority interest, as measured by VAR, related to its commodity and energy related contracts held for trading purposes was approximately $3 million and $2 million at December 31, 1998, and 1997, respectively. VAR was implemented on April 1, 1998, therefore volatilities and correlations applicable on April 1, 1998, were used to provide comparative data for December 31, 1997. Actual losses could exceed those measured by VAR. NON-TRADING COMMODITY PRICE RISK The estimated potential one-day unfavorable impact on income before income taxes and minority interest, as measured by VAR, related to EPEM's non-trading commodity activities was immaterial at December 31, 1998, and 1997. INTEREST RATE RISK The Company's debt financial instruments are sensitive to market fluctuations in interest rates. The table below presents principal cash flows and related weighted average interest rates by expected maturity dates. As of December 31, 1998, and 1997, the carrying amounts of short-term borrowings are representative of fair 39 54 values because of the short-term maturity of these instruments. The fair value of the long-term debt has been estimated based on quoted market prices for the same or similar issues. The Company's non-trading derivative financial instruments, including interest rate and equity swaps are also sensitive to market fluctuations in interest rates. The interest rate swap agreements entered into by MPC effectively convert $114 million of floating-rate debt to fixed-rate debt (see Item 8, Financial Statements and Supplementary Data, Note 4). MPC makes payments to counterparties at fixed rates and in return receives payments at floating rates. The two swap agreements were entered into in March 1992 and have remaining terms of approximately 1 year and 3 years, respectively. This transaction is recorded using accrual accounting. In addition, in March 1997, the Company purchased a 10.5 percent interest in CAPSA for approximately $57 million. In connection with this acquisition, the Company entered into an equity swap transaction associated with an additional 18.5 percent of CAPSA's then outstanding stock. Under the equity swap, the Company pays interest to the counterparty, on a quarterly basis, on a notional amount of $100 million at a rate of LIBOR plus 0.85 percent. In exchange, the Company receives dividends on the CAPSA stock to the extent of the counterparty's equity interest of 18.5 percent. In February 1999, the Company extended the term of the swap for two and a half years. For the interest rate and equity swaps, the table below presents notional amounts and weighted average interest rates by expected or contractual maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contact. The fair value of the derivative financial instruments is the estimated amount at which management believes they could be liquidated over a reasonable period of time, based on quoted market prices, current market conditions, or other estimates obtained from third-party dealers. The tabular presentation related to activities other than commodity trading, as of December 31, 1998, and 1997, is illustrated below:
DECEMBER 31, 1998 -------------------------------------------------------------------- EXPECTED FISCAL YEAR OF MATURITY -------------------------------------------------------------------- 1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE ---- ----- ---- ---- ---- ---------- ------ ---------- (DOLLARS IN MILLIONS) LIABILITIES: Short-term debt -- variable rate.............................. $750 $ 750 $ 750 - ------------------------------------ Average interest rate........ 5.8% Long-term debt, including ----------------------------- current portion -- fixed rate......................... $ 62 $ 125 $ 52 $240 $215 $1,920 $2,614 $2,795 ---------------------------------- Average interest rate........ 8.0% 10.5% 7.3% 7.8% 7.8% 7.8% INTEREST RATE DERIVATIVES: Interest rate swap -------------------- Variable to fixed rate -- notional amounts..... $ 29 $ 85 $ 114 $ (9) Average interest rate........ 8.3% 8.4% 8.4% 8.4% Average received rate(a)..... 4.9% 5.0% 5.1% 5.1% Net cash flow effect......... $ (4) $ (3) $ (3) $ (3) Equity swap -------------- Interest to dividend -- notional amount....................... $100 $ 100 $ 3 Average interest rate(a)..... 6.5% Received dollars(b).......... -- Net cash flow effect......... (7)
40 55
DECEMBER 31, 1997 ---------------------- TOTAL FAIR VALUE ------ ---------- (DOLLARS IN MILLIONS) LIABILITIES: Short-term debt -- variable rate.......................... $ 813 $ 813 Average interest rate paid in 1998..................... 5.8% Long-term debt, including current portion -- fixed rate... $2,191 $2,334 Average interest rate paid in 1998................... 7.8% INTEREST RATE DERIVATIVES: Interest rate swap Variable to fixed rate -- notional amounts............. $ 114 $ (9) Average interest rate paid in 1998................... 8.3% Average received rate in 1998(a)..................... 5.8% Net cash flow effect for 1998........................ $ (3) Equity swap Interest to dividend -- notional amount................ $ 100 $ 8 Average interest rate paid in 1998(a)................ 6.6% Received dollars in 1998(b).......................... -- Net cash flow effect for 1998........................ $ (7)
- --------------- (a) The variable rates presented are the average forward rates for the remaining term of each contract. (b) The Company receives dividends, to the extent paid, on the CAPSA stock to the extent of the counterparty's equity interest of 18.5 percent. No dividends were received in 1998 and no dividends are expected for 1999. 41 56 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA EL PASO ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, -------------------------- 1998 1997 1996 ------ ------ ------ Operating revenues Transportation............................................ $1,194 $1,200 $ 534 Natural gas, liquids and power............................ 4,370 4,110 2,359 Gathering and processing.................................. 141 204 85 Other..................................................... 77 124 34 ------ ------ ------ 5,782 5,638 3,012 ------ ------ ------ Operating expenses Cost of gas and other products............................ 4,212 4,125 2,277 Operation and maintenance................................. 707 664 322 Depreciation, depletion, and amortization................. 269 236 101 Employee separation and asset impairment charge........... -- -- 99 Taxes, other than income taxes............................ 88 92 43 ------ ------ ------ 5,276 5,117 2,842 ------ ------ ------ Operating income............................................ 506 521 170 ------ ------ ------ Other (income) and expense Interest and debt expense................................. 267 238 110 Other, net................................................ (138) (57) (5) ------ ------ ------ 129 181 105 ------ ------ ------ Income before income taxes and minority interest............ 377 340 65 Income tax expense.......................................... 127 129 25 ------ ------ ------ Income before minority interest............................. 250 211 40 Minority interest Preferred stock dividend of subsidiary.................... 25 25 2 ------ ------ ------ Net income.................................................. $ 225 $ 186 $ 38 ====== ====== ====== Basic earnings per common share............................. $ 1.94 $ 1.64 $ 0.53 ====== ====== ====== Diluted earnings per common share........................... $ 1.85 $ 1.59 $ 0.52 ====== ====== ====== Basic average common shares outstanding..................... 116 114 72 ====== ====== ====== Diluted average common shares outstanding................... 126 117 73 ====== ====== ======
The accompanying Notes are an integral part of these Consolidated Financial Statements. 42 57 EL PASO ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT COMMON SHARE AMOUNTS) ASSETS
DECEMBER 31, --------------------------- 1998 1997 ------------ ------------ Current assets Cash and temporary investments............................ $ 90 $ 116 Accounts and notes receivable, net Customer................................................ 557 737 Other................................................... 176 252 Inventories............................................... 49 68 Deferred income taxes..................................... 81 168 Assets from price risk management activities.............. 181 96 Regulatory assets......................................... 9 116 Prepaid expenses.......................................... 40 28 Other..................................................... 26 48 ------- ------ Total current assets............................... 1,209 1,629 ------- ------ Property, plant, and equipment, net......................... 7,341 7,116 Investments in unconsolidated affiliates.................... 600 373 Intangibles, net............................................ 537 117 Other....................................................... 382 297 ------- ------ Total assets....................................... $10,069 $9,532 ======= ====== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable Trade................................................... $ 547 $ 787 Other................................................... 177 99 Short-term borrowings (including current maturities of long-term debt)......................................... 812 885 Accrual for regulatory issues............................. 37 22 Liabilities from price risk management activities......... 127 73 Other..................................................... 462 598 ------- ------ Total current liabilities.......................... 2,162 2,464 ------- ------ Long-term debt, less current maturities..................... 2,552 2,119 ------- ------ Deferred income taxes....................................... 1,564 1,550 ------- ------ Postretirement benefits..................................... 248 285 ------- ------ Other....................................................... 745 790 ------- ------ Commitments and contingencies (See Note 6) Company-obligated mandatorily redeemable convertible preferred securities of El Paso Energy Capital Trust I.... 325 -- ------- ------ Minority interest Preferred stock of subsidiary............................. 300 300 ------- ------ Other minority interest................................... 65 65 ------- ------ Stockholders' equity Common stock, par value $3 per share; authorized 275,000,000 shares; issued 124,434,110 and 122,581,816 shares, respectively.................................... 373 368 Additional paid-in capital................................ 1,436 1,389 Retained earnings......................................... 460 327 Accumulated comprehensive income.......................... (14) (7) Treasury stock (at cost) 4,149,099 and 2,946,832 shares, respectively............................................ (90) (47) Deferred compensation..................................... (57) (71) ------- ------ Total stockholders' equity......................... 2,108 1,959 ------- ------ Total liabilities and stockholders' equity......... $10,069 $9,532 ======= ======
The accompanying Notes are an integral part of these Consolidated Financial Statements. 43 58 EL PASO ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS)
YEAR ENDED DECEMBER 31, --------------------------- 1998 1997 1996 ----- ------- ------- Cash flows from operating activities Net income................................................ $ 225 $ 186 $ 38 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion, and amortization.............. 269 236 101 Deferred income taxes (benefit)........................ 128 195 (5) Gain on disposition of property........................ (20) (2) -- Undistributed earnings in equity investees............. (28) (3) 16 Amortization of deferred compensation.................. 24 19 5 Risk-sharing revenue................................... (31) -- -- Net employee separation and asset impairment charge.... -- -- 76 Working capital changes, net of non-cash transactions Accounts and notes receivable........................ 250 342 (168) Inventories.......................................... 19 16 (5) Net price risk management activities................. (32) 16 (39) Regulatory asset..................................... 124 19 -- Other current assets................................. 11 47 77 Accrual for regulatory issues........................ 16 (266) 135 Accounts payable..................................... (178) (249) 65 Other current liabilities............................ (143) 11 (8) Other..................................................... (124) 4 3 ----- ------- ------- Net cash provided by operating activities......... 510 571 291 ----- ------- ------- Cash flows from investing activities Capital expenditures...................................... (406) (293) (119) Investment in joint ventures and equity investees......... (447) (239) (24) Net cash flow impact of acquisitions...................... (373) (213) (35) Proceeds from disposal of property and investments........ 74 14 190 Proceeds from equity investment project financing......... 153 53 -- Other..................................................... -- (28) (17) ----- ------- ------- Net cash used in investing activities............. (999) (706) (5) ----- ------- ------- Cash flows from financing activities Net commercial paper borrowings (repayments).............. 14 326 (203) Revolving credit borrowings............................... 610 70 400 Revolving credit repayments............................... (687) (1,200) (1,022) Long-term debt retirements................................ (72) (124) (24) Long-term debt issuance, net.............................. 391 883 396 Proceeds from issuance of El Paso Energy Capital Trust I preferred securities, net of issuance costs............ 317 -- -- Acquisition of treasury stock............................. (36) -- -- Dividends paid............................................ (91) (77) (53) Proceeds from stock issuance, net of issuance costs....... -- 152 -- Proceeds from project financing........................... -- -- 310 Other..................................................... 17 21 71 ----- ------- ------- Net cash provided by (used in) financing activities...................................... 463 51 (125) ----- ------- ------- Increase (decrease) in cash and temporary investments....... (26) (84) 161 Cash and temporary investments Beginning of period....................................... 116 200 39 ----- ------- ------- End of period............................................. $ 90 $ 116 $ 200 ===== ======= =======
The accompanying Notes are an integral part of these Consolidated Financial Statements. 44 59 EL PASO ENERGY CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
COMMON STOCK ADDITIONAL ACCUMULATED TREASURY STOCK --------------- PAID-IN RETAINED COMPREHENSIVE --------------- DEFERRED SHARES AMOUNT CAPITAL EARNINGS INCOME SHARES AMOUNT COMPENSATION ------ ------ ---------- -------- ------------- ------ ------ ------------ January 1, 1996............. 75 $224 $ 343 $240 $ -- (6) $(95) $ -- Net income................ 38 Common stock dividend ($0.695 per share)...... (50) Issuance of common stock for acquisition of EPTPC................... 37 113 800 Restricted stock issuances............... 23 2 41 (74) Amortization of deferred compensation............ 5 Options exercised......... 1 3 18 (1) 1 9 Other..................... 1 --- ---- ------ ---- ---- -- ---- ---- December 31, 1996........... 113 340 1,185 227 -- (3) (45) (69) Net income................ 186 Common stock dividend ($0.730 per share)...... (86) Issuance of common stock, net of related costs.... 7 20 152 Restricted stock issuances............... 1 4 20 -- 1 (23) Restricted stock forfeitures............. -- (3) 2 Amortization of deferred compensation............ 19 Options exercised......... 2 4 21 Income tax benefit of stock-based compensation plans................... 11 Comprehensive income...... (7) --- ---- ------ ---- ---- -- ---- ---- December 31, 1997........... 123 368 1,389 327 (7) (3) (47) (71) Net income................ 225 Common stock dividend ($0.765 per share)...... (92) Issuance of common stock for acquisition of DeepTech................ -- -- 2 Restricted stock issuances............... -- 2 23 (14) Restricted stock forfeitures............. -- (4) 4 Restricted stock used for tax withholdings........ -- (1) Amortization of deferred compensation............ 24 Options exercised......... 1 3 13 -- (2) Income tax benefit of stock-based compensation plans................... 9 Open market stock repurchases............. (1) (36) Comprehensive income...... (7) --- ---- ------ ---- ---- -- ---- ---- December 31, 1998........... 124 $373 $1,436 $460 $(14) (4) $(90) $(57) === ==== ====== ==== ==== == ==== ==== TOTAL STOCKHOLDERS' EQUITY ------------- January 1, 1996............. $ 712 Net income................ 38 Common stock dividend ($0.695 per share)...... (50) Issuance of common stock for acquisition of EPTPC................... 913 Restricted stock issuances............... (10) Amortization of deferred compensation............ 5 Options exercised......... 29 Other..................... 1 ------ December 31, 1996........... 1,638 Net income................ 186 Common stock dividend ($0.730 per share)...... (86) Issuance of common stock, net of related costs.... 172 Restricted stock issuances............... 2 Restricted stock forfeitures............. (1) Amortization of deferred compensation............ 19 Options exercised......... 25 Income tax benefit of stock-based compensation plans................... 11 Comprehensive income...... (7) ------ December 31, 1997........... 1,959 Net income................ 225 Common stock dividend ($0.765 per share)...... (92) Issuance of common stock for acquisition of DeepTech................ 2 Restricted stock issuances............... 11 Restricted stock forfeitures............. -- Restricted stock used for tax withholdings........ (1) Amortization of deferred compensation............ 24 Options exercised......... 14 Income tax benefit of stock-based compensation plans................... 9 Open market stock repurchases............. (36) Comprehensive income...... (7) ------ December 31, 1998........... $2,108 ======
The accompanying Notes are an integral part of these Consolidated Financial Statements. 45 60 EL PASO ENERGY CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (IN MILLIONS)
YEAR ENDED DECEMBER 31, ------------------------- 1998 1997 1996 ----- ----- ----- Net income.................................................. $225 $186 $38 Foreign currency translation adjustments.................... (7) (7) -- ---- ---- --- Comprehensive income........................................ $218 $179 $38 ==== ==== ===
The accompanying Notes are an integral part of these Consolidated Financial Statements. 46 61 EL PASO ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation and Principles of Consolidation The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries of the Company after the elimination of all significant intercompany accounts and transactions. Investments in companies where the Company has the ability to exert significant influence over, but not control operating and financial policies are accounted for using the equity method. The financial statements for previous periods include certain reclassifications that were made to conform to the current year presentation. Such reclassifications have no impact on reported net income or stockholders' equity. Holding Company Reorganization Effective August 1, 1998, the Company reorganized into a holding company organizational structure, whereby EPEC, a Delaware corporation, became the holding company. The holding company organizational structure was effected by a merger conducted pursuant to Section 251(g) of the Delaware General Corporation Law, which provides for the formation of a holding company structure without a vote of the stockholders of EPNG. In the merger, El Paso Energy Merger Company, a Delaware corporation and wholly owned subsidiary of EPEC, merged with and into EPNG, with EPNG as the surviving corporation. By virtue of the reorganization, EPNG became a direct, wholly owned subsidiary of EPEC, and all of EPNG's outstanding capital stock was converted, on a share for share basis, into capital stock of EPEC. As a result of such restructuring, each outstanding share of $3.00 par value common stock of EPNG was converted into one share of $3.00 par value common stock of EPEC, and each one-half outstanding preferred stock purchase right of EPNG was converted into one preferred stock purchase right of EPEC common stock, with such right representing the right to purchase one two-hundredth (subject to adjustment) of a share of Series A Junior Participating Preferred Stock of EPEC. Because the reorganization was with companies under common control, the stockholders' equity and components thereof of EPNG became the basis for EPEC stockholders' equity. In addition to the holding company formation, EPEC assumed ownership of the Trust (as defined in Note 3) as well as EPNG's obligations related to the Trust. See Note 3, Trust Preferred Securities for a further discussion. Finally, EPEC became the successor to EPNG's previous shelf registration in the amount of $565 million. The New York Stock Exchange ticker symbol used by EPEC following the reorganization remains unchanged as "EPG." Tax-free Internal Reorganization On December 31, 1998, the Company effected a tax-free internal reorganization of its assets and operations and those of a majority of its subsidiaries in accordance with a private letter ruling received from the IRS. In the internal reorganization, a substantial number of subsidiaries were transferred to or from the Company and/or other entities owned by the Company. The tax-free internal reorganization had no impact on the presentation herein. Stock Split On January 21, 1998, the Board approved a two-for-one stock split of EPNG's common stock (the "Stock Split"), subject to stockholder approval of an amendment to EPNG's Restated Certificate of Incorporation to increase the number of authorized shares of EPNG's common stock to 275,000,000 shares (the "Amendment"). EPNG's stockholders approved the Amendment on March 2, 1998. In connection with the Amendment, the Board increased the number of authorized shares of EPNG's preferred stock designated as Series A Junior Participating Preferred Stock to 1,375,000 shares. Prior to the holding company reorganization, the designated number of Series A Junior Participating Preferred Stock was increased to 2,750,000. The Stock Split was effected in the form of a stock dividend of an aggregate of 60,944,417 shares of 47 62 EPNG's common stock, which was paid on April 1,1998, to stockholders of record on March 13, 1998. All common shares and per common share amounts have been adjusted to give effect to the Stock Split. After giving effect to the Stock Split in accordance with the adjustment provisions of the Amended and Restated Shareholder Rights Agreement, dated as of July 23, 1997, between the Company and BankBoston, N.A. as Rights Agent, the number of rights to purchase one one-hundredth of a share of the Series A Junior Participating Preferred Stock associated with each share of common stock was adjusted to become one-half of such right (see Holding Company Reorganization above, for the impact of the holding company reorganization). Use of Estimates 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, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Actual results are likely to differ from those estimates. Accounting for Regulated Operations The Company's businesses that are subject to the regulations and accounting requirements of FERC have followed the accounting requirements of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, which may differ from the accounting requirements of the Company's non-regulated entities. Transactions that have been recorded differently as a result of regulatory accounting requirements include: GSR costs to be recovered under a demand and interruptible surcharge, environmental costs to be recovered under a demand surcharge, and certain benefits and other costs and taxes included in or expected to be included in future rates, including costs to refinance debt. When the accounting method followed is prescribed by or allowed by the regulatory authority for rate-making purposes, such method conforms to the generally accepted accounting principle of matching costs with the revenues to which they apply. Cash and Temporary Investments Short-term investments purchased with an original maturity of three months or less are considered cash equivalents. Allowance for Doubtful Accounts and Notes Receivable The Company has established a provision for losses on accounts and notes receivable, as well as for gas imbalances due from shippers and operators, which may become uncollectible. Collectibility is reviewed regularly, and the allowance is adjusted as necessary primarily under the specific identification method. The balances of this provision at December 31, 1998 and 1997, were $15 million and $17 million, respectively. Gas Imbalances The Company values gas imbalances due to or due from shippers and operators at the appropriate index price. Natural gas imbalances are settled in cash or made up in-kind. Inventories Inventories, consisting of materials and supplies and natural gas in storage, are valued at the lower of cost or market with cost determined using the average cost method. Property, Plant, and Equipment Included in the Company's property, plant, and equipment is construction work in progress of approximately $392 million and $276 million at December 31, 1998, and 1997, respectively. An allowance for both debt and equity funds used during construction of regulated projects is included in the cost of the Company's property, plant, and equipment. 48 63 Accounting for a substantial portion of property, plant, and equipment is subject to regulation by the FERC. The objectives of this regulation are to ensure the proper recovery of capital investments in rates. Such recovery is generally accomplished by allowing a return of the investment through inclusion of depreciation expense in the cost of service. Rates also allow for a return on the net unrecovered rate base. Specific procedures are prescribed by FERC to control capitalized costs, depreciation, and the disposal of assets. SFAS No. 71 specifically acknowledges the obligation of regulated companies to comply with regulated accounting procedures, even when they conflict with other generally accepted accounting principle pronouncements. Regulated property, plant, and equipment is recorded at original cost of construction or, on acquisition, the cost of first party committing the asset to utility services. Construction cost includes direct labor and materials, as well as indirect charges such as overheads and allowance for funds used during construction. Replacements or betterments of major units of property are capitalized. Replacements or additions of minor units of property are expensed. Depreciation for regulated property, plant, and equipment is calculated using the composite method. Assets with similar economic characteristics are grouped. The depreciation rate prescribed in the rate settlement is applied to the gross investment for the group until net book value of the group is equal to the salvage value. Currently, depreciation rates vary from 1 percent to 33 percent. This results in remaining economic lives of groups ranging from 2 to 36 years. Depreciation rates are reevaluated in conjunction with the rate making process. When regulated property, plant, and equipment is retired, due to abandonment or replacement, the original cost, plus the cost of retirement, less salvage, is charged to accumulated depreciation and amortization. No gain or loss is recognized unless an entire operating unit, as defined by FERC, has been retired. Gains or losses on dispositions of operating units are included in income. Additional acquisition cost assigned to utility plant primarily represents the excess of allocated purchase costs over historical costs that resulted from the December 1996 acquisition of EPTPC. These costs are being amortized on a straight-line basis using FERC approved rates. Depreciation of the Company's non-regulated properties is provided using the straight line or composite method which, in the opinion of management, is adequate to allocate the cost of properties over their estimated useful lives. Non-regulated properties have expected lives of 5 to 40 years. The Company evaluates impairment of its property, plant, and equipment in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. Intangible Assets Intangible assets are amortized using the straight-line method over periods ranging from 5 years to 40 years. Accumulated amortization of intangible assets was $24 million and $21 million for 1998 and 1997, respectively. The Company evaluates impairment of goodwill in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. Environmental Costs Expenditures for ongoing compliance with environmental regulations that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of the liability are based upon currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. All available evidence is considered including prior experience in remediation of contaminated sites, other companies' clean-up experience and data released by the EPA or other organizations. These estimated liabilities are subject to 49 64 revision in future periods based on actual costs or new circumstances. These liabilities are included in the balance sheets at their undiscounted amounts. Recoveries are evaluated separately from the liability and, when recovery is assured, are recorded and reported separately from the associated liability in the consolidated financial statements as an asset. Price Risk Management Activities The Company utilizes derivative financial instruments to manage market risks associated with certain energy commodities, and interest rates. In its commodity price risk management activities, the Company engages in both trading and non-trading activities. Activities for trading purposes consist of services provided to the energy sector, and all energy trading activities, including transportation capacity and storage, are accounted for using the mark-to-market method of accounting. Such trading activities are conducted through a variety of financial instruments, including forward contracts involving cash settlement or physical delivery of an energy commodity, swap contracts which require payments to (or receipts from) counterparties based on the differential between a fixed and variable price for the commodity, exchange-trade options, over-the-counter options, and other contractual arrangements. Under mark-to-market accounting, commodity and energy related contracts are reflected at estimated market value with resulting gains and losses recorded in operating income in the Consolidated Statements of Income. The net gains or losses recognized in the current period result primarily from transactions originating within the period and the impact of price movements on transactions originating in previous periods. The assets and liabilities resulting from mark-to-market accounting are presented as assets and liabilities from price risk management activities in the Consolidated Balance Sheets. Terms regarding cash settlement of the contracts vary with respect to the actual timing of cash receipts and payments. Receivables and payables resulting from these timing differences are presented in accounts receivable, and accounts payable in the Consolidated Balance Sheets. Cash inflows and outflows associated with these price risk management activities are recognized in operating cash flow as the settlements of transactions occur. The market value of these commodity and energy related contracts reflects 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 the Company's position in an orderly manner over a reasonable period of time under present market conditions. Derivative and other financial instruments are also utilized in connection with non-trading activities. The Company enters into forwards, swaps, and other contracts to hedge the impact of market fluctuations on assets, liabilities, or other contractual commitments. Derivatives held for non-trading price risk management activities are not recorded on the balance sheet. Net periodic settlements are recorded as a gain or loss in operating income in the consolidated statements of income, and cash inflows and outflows are recognized in operating cash flow as the settlements of the transactions occur. See Note 5 for a further discussion of the Company's price risk management activities. In late 1998, the Emerging Issues Task Force reached a consensus which supported the Company's accounting policy as described above. Income Taxes Income taxes are based on income reported for tax return purposes along with a provision for deferred income taxes. Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax bases of assets and liabilities at each year end. Tax credits are accounted for under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. Deferred tax assets are reduced by a valuation allowance when, based upon management's estimates, it is more likely than not that a portion of the deferred tax assets will not be realized 50 65 in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision in future periods based on new facts or circumstances. In connection with the Merger, EPTPC entered into a tax sharing agreement with Newport News Shipbuilding Inc., New Tenneco and the Company, as successor to EPNG. This tax sharing agreement provides, among other things, for the allocation among the parties of tax assets and liabilities arising prior to, as a result of, and subsequent to the Distributions. Generally, EPTPC will be liable for taxes imposed on itself. With respect to periods prior to the consummation of the Distributions, in the case of federal income taxes imposed on the combined activities of Old Tenneco and other members of its consolidated group prior to giving effect to the Distributions, New Tenneco and Newport News Shipbuilding Inc. will be liable to EPTPC for federal income taxes attributable to their activities, and each will be allocated an agreed-upon share of estimated tax payments made by EPTPC for Old Tenneco. Pursuant to the tax sharing agreement, EPTPC paid New Tenneco in 1997 for the tax benefits realized from the deduction of 1996 taxable losses generated by a debt realignment in accordance with the Merger. Treasury Stock Treasury stock is accounted for using the cost method and is shown as a reduction to stockholders' equity in the consolidated balance sheets. Treasury stock sold or issued is valued on a first-in, first-out basis. Included in treasury stock at December 31, 1998, and 1997, were 1,360,000 shares of common stock that were reserved for use under certain of the Company's benefit plans. Stock-Based Compensation As allowed under SFAS No. 123, the Company has elected to continue to apply the provisions of Accounting Principles Board Opinion No. 25 and related interpretations in accounting for its stock compensation plans. The Company uses fixed and variable plan accounting for fixed and variable compensation plans, respectively. Accordingly, compensation expense is not recognized for stock options unless the options were granted at an exercise price lower than market on the grant date. New Accounting Pronouncements Not Yet Adopted See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, New Accounting Pronouncements Not Yet Adopted, which is incorporated herein by reference. 51 66 2. ACQUISITIONS DeepTech In August 1998, the Company completed its acquisition of DeepTech by merging DeepTech with a subsidiary of EPEC. DeepTech's assets include a 27.3 percent ownership interest in Leviathan. The acquisition was accounted for as a purchase with a total purchase price of approximately $422 million, net of cash acquired. The Company recorded $214 million of goodwill in connection with the acquisition which will be amortized using the straight-line method over a period of 40 years. The amount allocated to goodwill is based on an estimate of the excess of the total purchase price over the fair value of assets and liabilities at the acquisition date. The amounts may be adjusted in the final purchase price allocation. Management does not expect the ultimate resolution of the purchase price allocation to materially impact the Company's financial position, results of operations, or cash flows. The operating results of DeepTech are included in the Company's Consolidated Statements of Income beginning on August 15, 1998. The components of the purchase price are as follows:
(IN MILLIONS) Fair value of assets acquired............................... $ 338 Goodwill.................................................... 214 Fair value of liabilities assumed........................... (101) Cash acquired............................................... (29) ----- Purchase price, net of cash acquired.............. 422 Affiliated receivable extinguished.......................... (77) Issuance of common stock.................................... (2) ----- Net cash consideration paid....................... $ 343 =====
In accordance with the DeepTech merger agreement, the Company has executed a guarantee with regard to DeepTech's 12% senior notes due 2000. The following table contains summarized financial information of DeepTech. Information as of and for the twelve months ended June 30, 1998, 1997, and 1996 are for pre-merger periods. The information for December 31, 1998, is for the post-merger period and the information for the six months ended December 31, 1998, is part post-merger and part pre-merger.
FOR THE SIX FOR THE TWELVE MONTHS MONTHS ENDED ENDED JUNE 30, DECEMBER 31, --------------------- 1998(a) 1998 1997 1996 ------------ ------- ---- ---- (IN MILLIONS) Operating results data: Operating revenue......................................... $ 15 $ 69 $120 $ 55 Operating expenses........................................ $ 25 $ 74 $132 $ 50 Net income (loss)......................................... $ 11 $ (2) $(20) $ 4
JUNE 30, DECEMBER 31, --------------------- 1998(b) 1998 1997 1996 ------------ ------- ---- ---- (IN MILLIONS) Financial position data: Total assets.............................................. $551 $181 $228 $156 Short term debt (including current maturities of long-term debt).................................................. $ 17 $ 12 $ 25 $ 46 Long term debt............................................ $ 90 $ 96 $165 $ 98 Stockholder's equity...................................... $444 $ 47 $ 6 $ 12
- --------------- (a) Unaudited (b) Reflects the allocation of the purchase price to the assets acquired and liabilities assumed in connection with the Company's acquisition of DeepTech in August 1998. 52 67 TPC In December 1997, the Company completed its purchase of gathering facilities consisting of 360 miles of natural gas pipeline and a natural gas cryogenic processing plant through the acquisition of 100 percent of the stock of TPC at a cash price of approximately $195 million. This transaction was accounted for as a purchase. Gulf States In October 1997, the Company completed the acquisition of Gulf States Gas Pipeline Company. The assets purchased include a 175-mile natural gas gathering and intrastate transmission system in Northwest Louisiana with a capacity of 250 MMcf/d. The purchase price was approximately $39 million, which included the issuance of $21 million of common stock of the Company. This transaction was accounted for as a purchase. EPTPC On December 12, 1996, the Company completed the acquisition of EPTPC in a transaction accounted for as a purchase. The purchase price was assigned to the assets and liabilities acquired based upon the estimated fair value of those assets and liabilities as of the acquisition date. Substantially all of the excess of the total purchase price over historical carrying amounts of the net assets acquired was allocated to property, plant and equipment of EPTPC's interstate pipeline systems. Such allocation was confirmed by an independent appraisal of the property acquired. In the Merger, Old Tenneco changed its name to EPTPC. Prior to the Merger, Old Tenneco and its subsidiaries completed various intercompany transfers and distributions which restructured, divided and separated their businesses, assets and liabilities so that all the assets, liabilities and operations related to the Industrial Business and the Shipbuilding Business were spun-off to Old Tenneco's then existing common stockholders. The Distributions were effected on December 11, 1996 pursuant to the Distribution Agreement dated as of November 1, 1996. Following the Distributions, the remaining operations of Old Tenneco consisted primarily of activities related to the transmission and marketing of natural gas. Results of operations of EPTPC were included in the Company's Consolidated Statements of Income for the last 20 days of 1996. On October 30, 1996, the IRS issued a private letter ruling to Old Tenneco, in which it ruled that for U.S. federal income tax purposes the Distributions would be tax-free to Old Tenneco and, except to the extent cash is received in lieu of fractional shares, to its then existing stockholders; the Merger would constitute a tax-free reorganization; and certain other transactions effected in connection with the Merger and Distributions would be tax-free. If the Distributions were not to qualify as tax-free distributions, then a corporate level federal income tax would be assessed to the consolidated group of which Old Tenneco was the common parent. This corporate level federal income tax would be payable by EPTPC. Under certain limited circumstances, however, New Tenneco and Newport News Shipbuilding Inc. have agreed to indemnify EPTPC for a defined portion of such tax liabilities. The consideration paid by the Company in the Merger consisted of: - the retention after the Merger of approximately $2.6 billion of debt and preferred stock obligations of Old Tenneco, subject to certain adjustments (which consisted, in part, of (i) approximately $200 million of public debt of Old Tenneco outstanding at the effective time of the Merger, (ii) $2.1 billion of debt of Old Tenneco outstanding at the effective time of the Merger under a $3 billion Revolving Credit and Competitive Advance Facility Agreement, dated as of November 4, 1996 (the "Credit Facility"), among Old Tenneco, certain banks and other financial institutions and The Chase Manhattan Bank, as agent), and (iii) $300 million of Old Tenneco preferred stock); - the issuance of 37.6 million shares of common stock of the Company valued at approximately $913 million, based on a closing price per share of common stock on the New York Stock Exchange of $24.3125 on December 9, 1996, to Old Tenneco's then existing common and preferred stockholders; and 53 68 - the retention of approximately $600 million of estimated liabilities related to certain discontinued businesses of Old Tenneco. The number of shares of the Company's common stock issued in the Merger to stockholders of Old Tenneco was determined pursuant to formulas set forth in the Merger Agreement. In the Merger, (i) a holder of Old Tenneco's common stock received 0.186 of a share of the Company's common stock for each share of Tenneco common stock, (ii) a holder of Old Tenneco's $7.40 Cumulative Preferred Stock received 4.73 shares of the Company's common stock for each such share of $7.40 Cumulative Preferred Stock, and (iii) a holder of Old Tenneco's $4.50 Cumulative Preferred Stock received 4.73 shares of the Company's common stock for each such share of $4.50 Cumulative Preferred Stock. At December 31, 1998, the Company owns 100 percent of the common equity and more than 80 percent of the combined equity value of EPTPC. The remaining combined equity of EPTPC consists of $300 million of preferred stock issued in a public offering by Old Tenneco on November 18, 1996, which remains outstanding. Assets acquired, liabilities assumed, and consideration received are as follows:
(IN MILLIONS) Fair value of assets acquired............................... $ 6,649 Cash acquired............................................... (75) Fair value of liabilities assumed........................... (5,724) Issuance of common stock.................................... (913) ------- Net cash consideration received................... $ (63) =======
The following unaudited pro forma information presents a summary of what the consolidated results of operations would have been on a pro forma basis for the year ended December 31, 1996, assuming the EPTPC acquisition had been in effect throughout 1996:
1996 -------------------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Operating revenue........................................... $5,281 Net income.................................................. $ 183 Basic earnings per common share............................. $ 1.61
In December 1996, subsequent to the Merger, TGP sold 70 percent of its interests in two natural gas pipeline systems in Australia to CNGI Australia Pty. Limited, a wholly owned indirect subsidiary of Consolidated Natural Gas Company, and four Australian investors for approximately $400 million, inclusive of related debt financing, and completed the sale of its oil and gas exploration, production and financing unit, formerly known as Tenneco Ventures, for approximately $105 million. After consideration of the purchase price allocation adjustments, there was no gain or loss recognized on these transactions. Effective June 1996, the Company acquired Cornerstone Natural Gas, Inc. in a transaction accounted for as a purchase. The purchase price of approximately $94 million, exclusive of acquisition costs, was financed through internally generated funds and short-term borrowings. Acquisition costs of approximately $5 million were capitalized. The cost of the acquisition was allocated on the basis of the estimated fair value of the assets acquired and the liabilities assumed, resulting in goodwill of approximately $59 million which is being amortized over 40 years using the straight-line method. Results of operations of Cornerstone Natural Gas, Inc. are included in the Company's Consolidated Statements of Income beginning in June 1996. 3. TRUST PREFERRED SECURITIES In March 1998, El Paso Energy Capital Trust I (the "Trust") issued 6.5 million of 4 3/4% trust convertible preferred securities (the "Trust Preferred Securities") for $325 million ($317 million, net of issuance costs). 54 69 In addition, the Trust issued trust convertible common securities of approximately $10 million to EPNG. The net proceeds were used by EPNG to pay down commercial paper. The Trust exists for the sole purpose of issuing Trust Preferred Securities and investing the proceeds in 4 3/4% convertible subordinated debentures due 2028 (the "Trust Debentures") of EPNG, the Trust's sole asset. EPNG executed a guarantee with regard to the Trust Preferred Securities. The guarantee, when taken together with EPNG's obligations under the Trust Debentures, the indenture pursuant to which the Trust Debentures were issued, and the applicable trust document, provides a full and unconditional guarantee of the Trust's obligations under the Trust Preferred Securities. As a result of the holding company reorganization discussed in Note 1, EPEC assumed ownership of the Trust, as well as the obligations of the Trust Debentures, and the guarantee of the Trust's obligations under the Trust Preferred Securities. The results of the Trust are consolidated with those of the Company and, therefore, the Trust Debentures are eliminated and the Trust Preferred Securities are reflected as company-obligated mandatorily redeemable convertible preferred securities of El Paso Energy Capital Trust I in the Consolidated Balance Sheets. Distributions on the Trust Preferred Securities are included in interest and debt expense in the Consolidated Statements of Income. The Trust Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4 3/4% commencing on June 30, 1998, carry a liquidation value of $50 per security plus accrued and unpaid distributions and are convertible into the Company's common shares at any time prior to the close of business on March 31, 2028, at the option of the holder at a rate of 1.2022 common shares for each Trust Preferred Security (equivalent to a conversion price of $41.59 per common share), subject to adjustment in certain circumstances. 4. FINANCING TRANSACTIONS The average interest rate of short-term borrowings was 5.8% and 5.9% at December 31, 1998, and 1997, respectively. The Company had short-term borrowings, including current maturities of long-term debt, at December 31, 1998 and December 31, 1997, as follows:
1998 1997 ------ ------ (IN MILLIONS) EPNG Revolving Credit Facility.............................. $ -- $ 45 EPNG Revolving Credit Facility with TGP designated as borrower.................................................. -- 417 EPNG Revolving Credit Facility with EPEC designated as borrower.................................................. 350 -- Commercial paper............................................ 340 326 Other credit facilities..................................... 60 25 Current maturities of other long-term debt.................. 62 72 ------ ------ $ 812 $ 885 ====== ======
55 70 Long-term debt outstanding at December 31, 1998 and 1997, consisted of the following:
1998 1997 ------ ------ (IN MILLIONS) Long-term debt TGP Debentures due 2011, average effective interest rates of 7.5% in 1998 and 7.9% in 1997, net of unamortized discount of $10.6 in 1998 ($11.1 in 1997)............. $ 75 $ 75 Debentures due 2017, average effective interest rates of 7.7% in 1998 and 7.8% in 1997, net of unamortized discount of $4.7 in 1998 ($5.0 in 1997)............... 295 295 Debentures due 2027, average effective interest rates of 7.1% in 1998 and 7.2% in 1997, net of unamortized discount of $3.6 in 1998 ($3.7 in 1997)............... 296 296 Debentures due 2028, average effective interest rate of 7.2% in 1998, net of unamortized discount of $8.9 in 1998.................................................. 391 -- Debentures due 2037, average effective interest rates of 7.8% in 1998 and 7.9% in 1997, net of unamortized discount of $6.3 in 1998 ($6.5 in 1997)............... 294 293 EPNG Debentures due 2012 through 2026, average effective interest rates of 8.4% in 1998 and 8.3% in 1997, net of unamortized discount of $1.3 in 1998 ($1.4 in 1997)................................................. 459 475 Notes due 1999 through 2003, average effective interest rates of 7.7% in 1998 and 7.6% in 1997, net of unamortized discount of $0.5 in 1998 ($0.7 in 1997)... 462 462 EPTPC Debentures due 2008 through 2025, average effective interest rates of 7.3% in 1998 and 7.2% in 1997, net of unamortized premium of $3.5 in 1998 ($4.0 in 1997)................................................. 54 55 Notes due 1998 through 2005, average effective interest rates of 6.5% in 1998 and 6.4% in 1997, net of unamortized premium of $2.3 in 1998 ($4.1 in 1997).... 48 87 EPEC Corporation, successor to El Paso Energy Credit Corporation Senior notes due 2001, average effective interest rates of 6.6% in 1998 and 6.0% in 1997, net of unamortized premium of $0.9 in 1998 ($1.2 in 1997)................ 14 15 Subordinated notes due 1998, average effective interest rate of 6.5% in 1997, net of unamortized premium of $0.2 in 1997.......................................... -- 7 MPC Project financing loan, due 1998 through March 2007, average effective interest rates of 9.7% in 1998 and 9.4% in 1997.......................................... 117 126 DeepTech Senior notes due 2000, average effective interest rate of 11% from merger date to December 31, 1998, net of unamortized premium of $6.7........................... 89 -- Senior subordinated promissory note due 2000, average effective interest rate of 10.3% from merger date to December 31, 1998, net of unamortized premium of $.8................................................... 16 --
56 71
1998 1997 ------ ------ (IN MILLIONS) Other Notes due 2000 through 2014, average effective interest rates of 7.5% in 1998 and 8.7% in 1997................ 4 5 ------ ------ 2,614 2,191 Less current maturities................................... 62 72 ------ ------ Long-term debt, less current maturities........... $2,552 $2,119 ====== ======
The following are aggregate maturities of long-term debt for the next 5 years and in total thereafter:
(IN MILLIONS) ------------- 1999........................................................ $ 62 2000........................................................ 125 2001........................................................ 52 2002........................................................ 240 2003........................................................ 215 Thereafter.................................................. 1,920 ------ Total long-term debt, including current maturities....................................... $2,614 ======
Other Financing Arrangements In October 1997, EPNG established a new $750 million five-year revolving credit and competitive advance facility and a new $750 million 364-day renewable revolving credit and competitive advance facility. In connection with the establishment of the Revolving Credit Facility, EPTPC's revolving credit facility was also terminated, and the outstanding balance of $417 million was financed under the five-year portion of the new Revolving Credit Facility with TGP designated as the borrower. The availability under the Revolving Credit Facility is expected to be used for general corporate purposes including, but not limited to, backstopping EPNG's and TGP's $1 billion commercial paper programs. In August 1998, EPEC became a guarantor of the Revolving Credit Facility. In October 1998, the $750 million 364-day portion of the Revolving Credit Facility was amended to extend the termination date to October 27, 1999. In addition, in October 1998, the Revolving Credit Facility was amended to permit TGP to issue commercial paper, provided that the total amount of commercial paper outstanding at EPNG and TGP is equal to or less than the unused capacity under the Revolving Credit Facility. In December 1998, EPEC became a borrower under the Revolving Credit Facility. The interest rate is 40 basis points above LIBOR, with the spread varying based on EPEC's long-term debt credit rating. The availability of borrowings under the Company's credit agreements is subject to specified conditions, which management believes the Company currently meets. These conditions include compliance with the financial covenants and ratios required by such agreements, absence of default under such agreements, and continued accuracy of the representations and warranties contained in such agreements (including the absence of any material adverse changes since the specified dates). All of the Company's senior debt issues have been given investment grade ratings by Standard & Poors and Moody's. The Company must comply with various restrictive covenants contained in its debt agreements which include, among others, maintaining a consolidated debt and guarantees to capitalization ratio no greater than 70 percent. In addition, the Company's subsidiaries on a consolidated basis (as defined in the agreements) may not incur debt obligations which would exceed $300 million in the aggregate, excluding acquisition debt, project financing, and certain refinancings. As of December 31, 1998, EPEC's consolidated debt and guarantees to capitalization ratio (as defined in the agreements) was 55 percent and debt obligations of EPEC subsidiaries in excess of permitted debt did not exceed $300 million on a consolidated basis. 57 72 In March 1997, TGP issued $300 million aggregate principal amount of 7 1/2% debentures due 2017, $300 million aggregate principal amount of 7% debentures due 2027, and $300 million aggregate principal amount of 7 5/8% debentures due 2037. Proceeds of approximately $883 million, net of issuance costs, were used to repay a portion of EPTPC's credit facility and for general corporate purposes. In December 1997, EPEC filed a shelf registration statement pursuant to which EPEC may offer up to $900 million (including $250 million transferred from prior shelf registrations) of common or preferred equities, various forms of debt securities (including convertible debt securities), and various types of trust securities from time to time as determined by market conditions. In March 1998, the El Paso Energy Capital Trust I, a Delaware business trust sponsored by the Company, issued 6.5 million 4 3/4% Trust Convertible Preferred Securities. The sole assets of the trust are approximately $335 million principal amount of 4 3/4% convertible subordinated debentures due 2028 of the Company. As a result of such offering, EPEC has approximately $565 million of capacity remaining under its existing shelf registration to issue public securities registered thereunder. In September 1998, TGP filed a shelf registration permitting TGP to offer up to $600 million (including $100 million carried forward from a prior shelf registration) of debt securities. In October 1998, TGP issued $400 million aggregate principal amount of 7% debentures due 2028. Proceeds to TGP were approximately $391 million, net of issuance cost. Approximately $300 million of the proceeds were used to repay TGP's short-term indebtedness under the Revolving Credit Facility and the remainder were used by TGP for general corporate purposes. After this issuance, TGP has $200 million of capacity remaining under its shelf registration. In March 1998, EPNG retired its outstanding 8 5/8% debentures in the amount of $17 million and in August 1998, EPTPC retired its outstanding 10% debentures in the amount of $38 million. In February 1999, DeepTech retired its 11% senior subordinated promissory note due 2000 in the amount of $16 million. 5. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES Fair Value of Financial Instruments The following disclosure of the estimated fair value of financial instruments is presented in accordance with the requirements of SFAS No. 107. The estimated fair value amounts have been determined by the Company using available market information and valuation methodologies. As of December 31, 1998, and 1997, the carrying amounts of certain financial instruments held by the Company, including cash, cash equivalents, short-term borrowings and investments, and trade receivables and payables are representative of fair value because of the short-term maturity of these instruments. The fair value of long-term debt with variable interest rates is the carrying value because of the variable nature of the respective debt's interest rate, and the fair value of debt with fixed interest rates has been estimated based on quoted market prices for the same or similar issues. The project financing debt is at market interest rates and therefore, the fair value of the project financing debt is representative of the carrying amount. The fair value of all derivative financial instruments is the estimated amount at which management believes the instruments could be liquidated over a reasonable period of time, based on quoted market prices, current market conditions, or other estimates obtained from third-party brokers or dealers. 58 73 The following table reflects the carrying amount and estimated fair value of the Company's financial instruments at December 31:
1998 1997 --------------------- --------------------- CARRYING CARRYING AMOUNT FAIR VALUE AMOUNT FAIR VALUE -------- ---------- -------- ---------- (IN MILLIONS) Balance sheet financial instruments: Long-term debt, excluding project financing.......... $2,497 $2,678 $2,065 $2,208 Project financing debt............................... 117 117 126 126 Other financial instruments: Trading Futures contracts................................. (4) (4) (3) (3) Option contracts.................................. 77 77 3 3 Swap and forward contracts........................ (28) (28) 23 23 Non-Trading Interest rate swap agreements..................... -- (9) -- (9) Equity swap....................................... 3 3 6 8 Commodity option contracts........................ -- 1 -- 1 Commodity swap and forward contracts.............. -- (14) -- 4
Trading Commodity Activities The Company, through its merchant services business, offers integrated price risk management services to the energy sector. These services primarily relate to energy related commodities including natural gas, power, and petroleum products. The Company provides these services through a variety of contracts entered into for trading purposes including forward contracts involving cash settlements or physical delivery of an energy commodity, swap contracts, 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. The Company recognized gross margin of $40 million and $17 million during 1998 and 1997, respectively, arising from its trading activities. The fair value of commodity and energy related contracts entered into for trading purposes as of December 31, 1998, and 1997, and the average fair value of those instruments held during the years ended December 31, 1998, and 1997 are set forth below. At December 31, 1998, $92 million of assets from price risk management activities are included in other assets and $42 million of liabilities from price risk management activities are included in other liabilities in the Consolidated Balance Sheets.
AVERAGE FAIR VALUE FOR THE YEAR ENDED ASSETS LIABILITIES DECEMBER 31,(A) ------ ----------- --------------- (IN MILLIONS) 1998 Futures contracts................................. $ 2 $ (6) $ (5) Option contracts.................................. 153 (17) 30 Swap and forward contracts........................ 118 (146) (31) 1997 Futures contracts................................. $ 4 $ (7) $ -- Option contracts.................................. 15 (12) 2 Swap and forward contracts........................ 77 (54) 13
- --------------- (a) computed using the net asset balance at each month end. 59 74 Notional Amounts and Terms The notional amounts and terms of these financial instruments at December 31, 1998, and 1997 are set forth below (natural gas volumes in trillions of British thermal units, power volumes in millions of megawatt hours, petroleum products volumes in millions of British thermal units):
FIXED PRICE FIXED PRICE MAXIMUM PAYOR RECEIVER TERMS IN YEARS ----------- ----------- -------------- 1998 Energy Commodities: Natural gas.................................. 9,605 8,866 20 Power........................................ 22 28 20 Petroleum products........................... 67 72 2 1997 Energy Commodities: Natural gas.................................. 4,079 3,584 20 Power........................................ 12 13 1 Petroleum products........................... 197 195 2
Notional amounts reflect the volume of transactions but do not represent the amounts exchanged by the parties. Accordingly, notional amounts are an incomplete measure of the Company'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 or cashed-out in the markets at any time based on the Company's risk management needs and liquidity in the commodity markets. The weighted average maturity of the Company's entire portfolio of price risk management activities was approximately two years as of December 31, 1998 and 1997, respectively. Market and Credit Risks The Company serves a diverse customer group that includes independent power producers, industrial companies, gas and electric utilities, oil and gas producers, financial institutions and other energy marketers. This broad customer mix generates a need for a variety of financial structures, products and terms. This diversity requires the Company to manage, on a portfolio basis, the resulting market risks inherent in these transactions subject to parameters established by the Company's risk management committee. Market risks are monitored by a risk control committee operating independently from the units that create or actively manage these risk exposures to ensure compliance with the Company's stated risk management policies. The Company measures and adjusts the risk in its portfolio in accordance with mark-to-market and other risk management methodologies which utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure. 60 75 Credit risk relates to the risk of loss that the Company would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. The Company maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances (including cash in advance, letters of credit, and parental guarantees), 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 the Company's assets from price risk management activities as of December 31, 1998, and 1997 are summarized as follows:
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF DECEMBER 31, 1998 --------------------------------------------------- BELOW INVESTMENT GRADE(a) INVESTMENT GRADE TOTAL(b) ------------------- ---------------- -------- (IN MILLIONS) Energy marketers.......................... $ 71 $ 5 $ 76 Financial institutions.................... 21 -- 21 Oil and gas producers..................... 37 5 42 Gas and electric utilities................ 104 6 110 Industrials............................... 18 -- 18 Other..................................... 4 2 6 ---- --- ---- Total assets from price risk management activities......... $255 $18 $273 ==== === ====
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF DECEMBER 31, 1997 --------------------------------------------------- BELOW INVESTMENT GRADE(a) INVESTMENT GRADE TOTAL(b) ------------------- ---------------- -------- (IN MILLIONS) Energy marketers.......................... $21 $ 3 $24 Financial institutions.................... 20 20 Oil and gas producers..................... 14 4 18 Gas and electric utilities................ 16 2 18 Industrials............................... 6 1 7 Other..................................... 8 1 9 --- --- --- Total assets from price risk management activities......... $85 $11 $96 === === ===
- --------------- (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 interest, 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, or minimum implied (through internal credit analysis) Standard & Poor's equivalent rating of BBB-. (b) Two customers' exposure at December 31, 1998, and 1997 comprise greater than 5 percent of assets from price risk management activities. These customers have Investment Grade ratings. This concentration of counterparties may impact the Company'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 the Company's policies, risk exposure, and reserves, the Company does not anticipate a material adverse effect on its financial position, or results of operations, or cash flows as a result of counterparty nonperformance. 61 76 Non-Trading Price Risk Management Activities MPC has entered into interest rate swap agreements which effectively convert $114 million of floating-rate debt to fixed-rate debt (see Note 4). MPC makes payments to counterparties at fixed rates and in return receives payments at floating rates. The two swap agreements were entered into in March 1992 and have remaining terms of approximately 1 year and 3 years, respectively. This transaction is recorded using accrual accounting. Interest expense and cash requirements were $3 million higher in 1998, 1997, and 1996, respectively, as a result of these swaps. In March 1997, the Company purchased a 10.5 percent interest in CAPSA, a privately held Argentine company engaged in power generation and oil and gas production for approximately $57 million. In connection with this acquisition, the Company entered into an equity swap transaction associated with an additional 18.5 percent of CAPSA's then outstanding stock. Under the swap, the Company pays interest to the counterparty, on a quarterly basis, on a notional amount of $100 million at a rate of LIBOR plus 0.85 percent. In exchange, the Company receives dividends on the CAPSA stock to the extent of the counterparty's equity interest of 18.5 percent. The Company also fully participates in the market appreciation or depreciation of the underlying investment whereby the Company will realize appreciation or fund any depreciation attributable to the actual sale of the stock upon termination or expiration of the swap transaction. The initial term of the swap was two years, and in February 1999, was extended for an additional two and one-half years. Upon maturity or termination of the swap, the Company has a right of first refusal to purchase the counterparty's 18.5 percent investment in CAPSA common stock at the fair value of the stock at that date or at a later date at a price offered by a good faith buyer. This transaction is recorded using mark-to-market accounting. 6. COMMITMENTS AND CONTINGENCIES See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies and Environmental, which are incorporated herein by reference. 7. INCOME TAXES The following table reflects the components of income tax expense for the years ended December 31:
1998 1997 1996 ---- ---- ---- (IN MILLIONS) Current Federal................................................... $ 6 $(45) $23 State..................................................... (12) (21) 7 Foreign................................................... 5 -- -- ---- ---- --- (1) (66) 30 ---- ---- --- Deferred Federal................................................... 116 164 (4) State..................................................... 14 31 (1) Foreign................................................... (2) -- -- ---- ---- --- 128 195 (5) ---- ---- --- Total tax expense................................. $127 $129 $25 ==== ==== ===
62 77 Tax expense of the Company differs from the amount computed by applying the statutory federal income tax rate (35 percent) to income before taxes. The following table outlines the reasons for the differences for the periods ended December 31:
1998 1997 1996 ---- ---- ---- (IN MILLIONS) Tax expense at the statutory federal rate of 35%............ $132 $119 $22 Increase (decrease) State income tax, net of federal income tax benefit....... 1 7 4 Other..................................................... (6) 3 (1) ---- ---- --- Income tax expense.......................................... $127 $129 $25 ==== ==== === Effective tax rate.......................................... 34% 38% 38% ==== ==== ===
The following table reflects the components of the net deferred tax liability at December 31:
1998 1997 ------ ------ (IN MILLIONS) Deferred tax liabilities Property, plant, and equipment............................ $2,012 $1,982 Regulatory and other assets............................... 474 393 ------ ------ Total deferred tax liability...................... 2,486 2,375 ------ ------ Deferred tax assets U.S. net operating loss and tax credit carryovers......... 85 113 Accrual for regulatory issues............................. 266 226 Postretirement benefits................................... 116 123 Other liabilities......................................... 542 539 Valuation allowance....................................... (5) (8) ------ ------ Total deferred tax asset.......................... 1,004 993 ------ ------ Net deferred tax liability(a)............................... $1,482 $1,382 ====== ======
- --------------- (a) As of December 31, 1998, $1 million of non-current foreign deferred income taxes are included in other assets in the Consolidated Balance Sheets. The cumulative undistributed earnings of certain foreign subsidiaries and foreign corporate joint ventures were approximately $35 million as of December 31, 1998. Since the earnings have been or are intended to be indefinitely reinvested in foreign operations, no provision has been made for any U.S. taxes or foreign withholding taxes that may be applicable upon actual or deemed repatriation. If a distribution of such earnings were to be made, the Company may be subject to both foreign withholding taxes and U.S. income taxes, net of any allowable foreign tax credits or deductions. However, an estimate of such taxes is not practicable. For the same reasons, the Company has not provided for any U.S. taxes on the foreign currency translation adjustments recognized in comprehensive income. The tax benefit associated with the exercise of non-qualified stock options and restricted stock as well as restricted stock dividends, reduced taxes payable by $9 million in 1998 and $11 million in 1997. Such benefits are included in additional paid-in capital in the Consolidated Balance Sheets. As of December 31, 1998, approximately $45 million of alternative minimum tax credits were available to offset future regular tax liabilities. These alternative minimum tax credit carryovers have no expiration date. Additionally, at December 31, 1998, approximately $1 million of general business credit, $102 million of net operating loss, and $9 million of capital loss carryovers were available to offset future tax liabilities. The general business credit carryovers expire in the years 1999 and 2000. Approximately $57 million of the net operating loss carryovers expire in 2012 and the remaining $45 million expire in the years 2004 through 2011. Usage of these carryovers is subject to the limitations provided for under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations. 63 78 The Company has recorded a valuation allowance to reflect the estimated amount of deferred tax assets which may not be realized due to the expiration of net operating loss and tax credit carryovers. As of December 31, 1998, and 1997, approximately $4 million and $8 million, respectively, of the valuation allowance relates to the net operating loss carryovers of an acquired company. The remainder of the valuation allowance relates to the general business credit carryovers of an acquired company. Any tax benefits subsequently recognized from reversal of this valuation allowance will be allocated to goodwill. Prior to 1999, EPTPC and its subsidiaries filed a consolidated federal income tax return and EPEC and its other subsidiaries filed a separate consolidated federal income tax return. As a result of the tax-free reorganization described in Note 1, starting in 1999, EPEC and its subsidiaries, including EPTPC and its subsidiaries, will file one consolidated federal income tax return. Deferred taxes corresponding to the allocation of the purchase price to the assets and liabilities acquired of EPTPC, have been reflected in the Consolidated Balance Sheets as of December 31, 1998, and 1997. 8. CAPITAL STOCK Common Stock In October 1997, approximately .8 million shares of Company common stock were issued in connection with the acquisition of Gulf States Gas Pipeline Company. Such shares were valued at approximately $21 million. In February 1997, approximately 6 million shares of Company common stock were issued in a public offering registered under the Securities Act of 1933, as amended. Proceeds of $152 million, net of issuance costs, were received and used to repay borrowings under the Revolving Credit Facility. In December 1996, 37.6 million shares of Company common stock were issued in connection with the acquisition of EPTPC. Such shares were valued at approximately $913 million. Treasury Stock From time to time, the Board has authorized the repurchase of EPEC's outstanding shares of common stock to be used in connection with EPEC employee stock-based compensation plans and for other corporate purposes. During 1998, the Company repurchased 995,600 common shares at a weighted average cost of $35.77 per share. As of December 31, 1998, and 1997, EPEC held 4,149,099 and 2,946,832 shares of treasury stock, respectively. Included in the balance at December 31, 1998, were 1,360,000 shares of treasury stock used to secure benefits under certain of the Company's benefit plans which are subject to certain restrictions. Stock Dividend In January 1998, the Board declared a two-for-one stock split in the form of a 100 percent stock dividend (on a per share basis). In March 1998, the stockholders approved an increase in the Company's authorized common stock. The stock dividend of an aggregate of 60,944,417 shares of common stock was paid on April 1, 1998 to stockholders of record on March 13, 1998. All presentations herein are made on a post-split basis. Other EPEC has 25,000,000 shares of authorized preferred stock, par value $0.01 per share, none of which have been issued, but of which 2,750,000 shares have been designated as Series A Junior Participating Preferred Stock and reserved for issuance pursuant to the Company's preferred stock purchase rights plan. 64 79 9. STOCK-BASED COMPENSATION During 1998, 1997, and 1996 the Company granted stock options under various stock option plans (the "Plans"). The Company applies Accounting Principles Board Opinion No. 25 and related Interpretations in accounting for these Plans. In 1995, the Financial Accounting Standards Board issued SFAS No. 123, Accounting for Stock-Based Compensation which, if fully adopted, changes the methods companies apply in determining expense related to their stock option plans. Adoption of the expense recognition provisions of SFAS No. 123 was optional and the Company elected not to apply provisions of SFAS No. 123. However, pro forma disclosures as if the Company adopted the expense recognition provisions of SFAS No. 123 are presented below. Under the Company's existing stock option plans, the Company is authorized to issue shares of Common Stock to employees and non-employee directors pursuant to awards granted as incentive stock options (intended to qualify under Section 422 of the Internal Revenue Code, non-qualified stock options, restricted stock, stock appreciation rights ("SARs"), and performance units. Non-qualified Stock Options The Company granted non-qualified stock options in 1998, 1997, and 1996 under its stock option plans. The stock options granted during these periods have contractual terms of 10 years and generally vest after completion of one to five years of continuous employment from the grant date. Options are also granted to non-employee members of the Board at fair market value on the date of grant and are exercisable immediately. Under the terms of certain plans, EPEC may grant SARs to certain holders of stock options. SARs are subject to the same terms and conditions as the related stock options. As of December 31, 1998, 50,538 SARs were outstanding which have been included in stock options as part of tandem awards. The stock option holder who has been granted tandem SARs can elect to exercise either an option or a SAR. SARs entitle an option holder to receive a payment equal to the difference between the option price and the fair market value of the common stock of EPEC at the date of exercise of the SAR. To the extent a SAR is exercised, the related option is canceled, and to the extent an option is exercised, the related SAR is canceled. Currently, the SARs are being accounted for as compensation expense under Accounting Principles Board Opinion No. 25 and are not considered for purposes of computing fair value of outstanding options using the Black-Scholes option pricing model as described below. A summary of the status of the Company's stock options as of December 31, 1998, 1997, and 1996 is presented below:
STOCK OPTIONS ------------------------------------------------------------------------ 1998 1997 1996 ---------------------- ---------------------- ---------------------- WEIGHTED WEIGHTED WEIGHTED # SHARES OF AVERAGE # SHARES OF AVERAGE # SHARES OF AVERAGE UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE OPTIONS PRICES OPTIONS PRICES OPTIONS PRICES ----------- -------- ----------- -------- ----------- -------- Outstanding at beginning of the year.............................. 8,782,214 $17.90 8,847,190 $15.83 5,207,910 $14.41 Granted........................... 2,328,450 $33.40 1,775,200 $26.23 4,933,646 $16.55 Exercised......................... 1,072,351 $17.40 1,643,376 $15.28 1,240,596 $12.79 Forfeited......................... 187,070 $21.48 196,800 $21.77 53,770 $14.44 --------- --------- --------- Outstanding at end of year.......... 9,851,243 $21.55 8,782,214 $17.90 8,847,190 $15.83 ========= ========= ========= Exercisable at end of year.......... 5,042,572 $16.94 4,006,508 $15.43 3,960,190 $14.82 ========= ========= =========
65 80 The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
ASSUMPTION: 1998 1997 1996 ----------- ----- ----- ----- Expected Term in Years...................................... 5 3 3 Expected Volatility......................................... 20.3% 17.3% 20.3% Expected Dividends.......................................... 3.0% 3.0% 3.0% Risk-Free Interest Rate..................................... 4.6% 6.3% 5.5%
The Black-Scholes weighted average fair value of options granted during 1998, 1997 and 1996 was as follows:
1998 1997 1996 ------ ------ ------ Weighted-average fair value of options granted at a discount............................................... $ 9.71 $ 5.96 $10.26 Weighted-average fair value of options granted at market................................................. $ 7.00 $ 3.86 $ 2.58
Options outstanding as of December 31, 1998 are summarized below:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------------------------- ----------------------------- NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED RANGE OF OUTSTANDING REMAINING AVERAGE EXERCISABLE AVERAGE EXERCISE PRICES AT 12/31/98 CONTRACTUAL LIFE EXERCISE PRICE AT 12/31/98 EXERCISE PRICE --------------- ----------- ---------------- -------------- ----------- -------------- $ 7.50 to $15.37 1,361,776 4.3 $12.66 1,361,776 $12.66 $15.38 to $19.28 4,541,225 6.5 $16.43 2,957,865 $16.56 $19.29 to $31.99 2,169,092 8.3 $26.77 603,531 $25.15 $32.00 to $38.56 1,779,150 9.4 $35.07 119,400 $33.42 --------- --------- $ 7.50 to $38.56 9,851,243 7.1 $21.55 5,042,572 $16.94 ========= =========
Restricted Stock Under the Company's various stock-based compensation plans, a limited number of shares of restricted Company common stock may be granted at no cost to certain key officers and employees. These shares carry voting and dividend rights; however, sale or transfer of the shares is restricted in accordance with the vesting procedures. These restricted stock awards vest over a specific period of time and/or if the Company achieves certain performance targets. Restricted stock awards representing .5 million, .7 million, and 3.2 million shares were granted during 1998, 1997, and 1996, respectively, with a weighted average grant date fair value of $32.29, $28.53, and $18.82 per share, respectively. At December 31, 1998, 4.5 million shares of restricted stock were outstanding. The value of these shares is determined based on the fair market value on the measurement dates and is charged to compensation expense ratably over the restriction period based on the number of shares earned over the vesting period. For 1998, 1997, and 1996, these charges totaled $27 million, $19 million, and $5 million, respectively. The unamortized balance is recorded as a reduction of stockholders' equity in the Consolidated Balance Sheets. Performance Units Certain employees and officers of the Company are awarded performance units that are payable in cash or stock at the end of the vesting period. The final value of the performance units may vary according to the plan under which they are granted, but is usually based on the Company's common stock price at the end of the vesting period. The value of the performance units is charged ratably to compensation expense over the vesting period with periodic adjustments to account for the fluctuation in the market price of the Company's stock. Amounts charged to compensation expense in 1998, 1997, and 1996 were $13 million, $5 million, and $5 million, respectively. 66 81 Pro Forma Net Income and Net Income Per Common Share Had the compensation expense for the Company's stock-based compensation plans been determined applying the provisions of SFAS No. 123, the Company's net income and net income per common share for 1998, 1997, and 1996 would approximate the pro forma amounts below:
DECEMBER 31, 1998 DECEMBER 31, 1997 DECEMBER 31, 1996 ----------------------- ----------------------- ----------------------- AS REPORTED PRO FORMA AS REPORTED PRO FORMA AS REPORTED PRO FORMA ----------- --------- ----------- --------- ----------- --------- SFAS No. 123 charge, pretax..... $ -- $ 61 $ -- $ 30 $ -- $ 17 APB No. 25 charge, pretax....... $ 49 $ -- $ 24 $ -- $ 13 $ -- Net income...................... $ 225 $ 217 $ 186 $ 183 $ 38 $ 36 Basic earnings per common share......................... $1.94 $1.87 $1.64 $1.61 $0.53 $0.50 Diluted earnings per common share......................... $1.85 $1.79 $1.59 $1.56 $0.52 $0.49
The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts. SFAS No. 123 does not apply to awards granted prior to the 1995 fiscal year. At December 31, 1998, 21.1 million shares of common stock were reserved for issuance pursuant to existing and future stock awards, of which approximately 5.4 million shares remain reserved. 10. RETIREMENT BENEFITS Pension Benefits Prior to January 1, 1997, the Company maintained a defined benefit pension plan covering substantially all employees of EPNG and EPFS. Pension benefits were based on years of credited service and final 5-year average compensation, subject to maximum limitations as defined in the pension plan. During 1996, the Company recognized a $21 million charge to pension expense related to an early retirement window and workforce reductions. Effective January 1, 1997, the plan was amended to provide benefits determined by a cash balance formula and to include employees added as a result of the Merger and other acquisitions prior to 1997. Employees who were participants on December 31, 1996, receive the greater of cash balance benefits or prior plan benefits accrued through December 31, 2001. During 1997, the Company offered special termination benefits to employees added as a result of the Merger who were at least 55 years old and who were eligible to retire under the Tenneco Inc. Retirement Plan on December 31, 1996. Eligible employees accepting this offer and retiring by July 1, 1997, received a cash balance credit based on an enhanced formula not to exceed one year's base salary. The cost associated with the special termination benefits was accrued at December 31, 1996, as part of the liabilities assumed in the Merger. In 1997, the Company funded $11 million for these special termination benefits. Other Postretirement Benefits EPNG provides postretirement medical benefits for a closed group of employees who retired on or before March 1, 1986, and limited postretirement life insurance for employees who retired after January 1, 1985. As such, EPNG's obligation to accrue for other postretirement employee benefits ("OPEB") is primarily limited to the fixed population of retirees who retired on or before March 1, 1986. The medical plan is pre-funded to the extent employer contributions are recoverable through rates. To the extent actual OPEB costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. As a result of the Merger, EPTPC retained responsibility for certain postretirement medical and life insurance benefits for former employees of operations previously disposed of by Old Tenneco, and for employees, including TGP employees, added as a result of the Merger who were eligible to retire on December 31, 1996, and did so on or before July 1, 1997. Medical benefits for this closed group of retirees may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of 67 82 employer costs. EPTPC has reserved the right to change these benefits. Employees who retired on or after July 1, 1997 will continue to receive limited postretirement life insurance benefits. TGP's postretirement benefit plan costs are pre-funded to the extent such costs are recoverable through rates. Effective February 1, 1992, TGP began recovering through its rates the OPEB costs included in the June 2, 1993 rate case settlement agreement. To the extent actual OPEB costs differ from the amounts funded, a regulatory asset or liability is recorded. Several plan amendments were made effective January 1, 1998, including increases in deductibles, increases in out-of-pocket limits, and changes to the prescription drug provisions. These changes resulted in a $25 million decrease in the postretirement benefits obligation. The following table sets forth the change in benefit obligation, change in plan assets, funded status, and components of net periodic benefit cost for pension benefits and other postretirement benefits. In 1998, the Company changed the measurement date for measuring its pension and OPEB obligations from December 31 to September 30. Traditionally, timing of the receipt of this information has limited the Company's ability to maximize planning and budgeting opportunities with respect to projected costs of its various plans. The Company changed its benefit reporting date to facilitate the planning process and gather necessary financial reporting information in a more timely manner. Management believes the date change is preferable to the method previously employed. This change in measurement date has been accounted for as a change in accounting principle and had no material cumulative effect on retirement benefit expense for the current or prior periods.
POSTRETIREMENT PENSION BENEFITS BENEFITS ---------------- -------------- 1998 1997 1998 1997 ------ ------ ----- ----- (IN MILLIONS) Change in benefit obligation Actuarial present value of benefit obligation at January 1,..................................................... $535 $505 $ 417 $ 427 Service cost.............................................. 11 13 -- -- Interest cost............................................. 36 37 27 30 Participant contributions................................. -- -- 4 5 Amendments................................................ -- -- (25) -- Special termination benefits.............................. -- 11 -- -- Actuarial (gain) or loss.................................. (8) 28 29 15 Benefits paid............................................. (38) (59) (45) (60) ---- ---- ----- ----- Actuarial present value of benefit obligation for 1998 at September 30 and for 1997 at December 31............... $536 $535 $ 407 $ 417 ==== ==== ===== ===== Change in plan assets Fair value of plan assets at January 1,................... $547 $497 $ 55 $ 42 Actual return on plan assets.............................. 7 79 3 9 Employer contributions.................................... 4 30 46 59 Participant contributions................................. -- -- 4 5 Benefits paid............................................. (38) (59) (45) (60) ---- ---- ----- ----- Fair value of plan assets for 1998 at September 30 and for 1997 at December 31.................................... $520 $547 $ 63 $ 55 ==== ==== ===== ===== Reconciliation of fund status Funded status............................................. $(16) $ 12 $(344) $(362) Fourth quarter contributions.............................. 5 -- 15 -- Unrecognized net actuarial (gain) or loss................. 29 (4) -- (26) Unrecognized net transition obligation.................... 6 8 54 70 Unrecognized prior service cost........................... (34) (37) (12) -- ---- ---- ----- ----- Net accrued benefit cost at December 31,.................. $(10) $(21) $(287) $(318) ==== ==== ===== =====
68 83 As of December 31, 1998, and 1997, the current liability portion of the postretirement benefits was $39 million and $33 million, respectively. Benefit obligations are based upon certain actuarial estimates as described below.
POSTRETIREMENT PENSION BENEFITS BENEFITS ------------------ ------------------ YEAR ENDED DECEMBER 31, --------------------------------------- 1998 1997 1996 1998 1997 1996 ---- ---- ---- ---- ---- ---- (IN MILLIONS) Benefit cost for the plans includes the following components Service cost........................................ $ 11 $ 13 $ 7 $-- $-- $-- Interest cost....................................... 36 37 41 27 30 6 Expected return on plan assets...................... (47) (43) (41) (3) (3) (2) Amortization of net actuarial gain.................. -- -- -- -- (4) (2) Amortization of transition obligation............... 2 2 2 7 9 9 Amortization of prior service cost.................. (3) (3) -- (1) -- -- Curtailment and special termination benefits expense.......................................... -- -- 21 -- -- -- ---- ---- ---- --- --- --- Net benefit cost.................................... $ (1) $ 6 $ 30 $30 $32 $11 ==== ==== ==== === === ===
POSTRETIREMENT PENSION BENEFITS BENEFITS ----------------------------- ---------------------------- SEPTEMBER 30, DECEMBER 31, SEPTEMBER 30, DECEMBER 31, 1998 1997 1998 1997 ------------- ------------- ------------- ------------ Weighted average assumptions Discount rate........................... 6.75% 7.00% 6.75% 7.00% Expected return on plan assets.......... 9.50% 9.25% 7.50% 8.50% Rate of compensation increase........... 4.50% 4.50% -- --
Actuarial estimates for the Company's postretirement benefits plans assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 10 percent through 2000, gradually decreasing to 6 percent by the year 2008. Assumed health care cost trends have a significant effect on the amounts reported for other postretirement benefit plans. A one-percentage point change in assumed health care cost trends would have the following effects:
1998 1997 ----- ----- (IN MILLIONS) One Percentage Point Increase Aggregate of Service Cost and Interest Cost for 1998 at September 30 and for 1997 at December 31............... $ 0.7 $ 0.6 Accumulated Postretirement Benefit Obligation for 1998 at September 30 and for 1997 at December 31............... $ 9.9 $ 9.1 One Percentage Point Decrease Aggregate of Service Cost and Interest Cost for 1998 at September 30 and for 1997 at December 31............... $(0.6) $(0.6) Accumulated Postretirement Benefit Obligation for 1998 at September 30 and for 1997 at December 31............... $(9.1) $(8.2)
Retirement Savings Plan The Company maintains a defined contribution plan covering all employees of the Company. During the first six months of 1996, the Company made matching contributions equal to a participant's basic contributions of up to 6 percent where the participant had fewer than 10 years of employment with the Company, or up to 8 percent where the participant had 10 or more years of employment with the Company. In February 1996, the Company changed its matching contribution to 75 percent of a participant's basic contributions of up to 6 percent, with the matching contribution being made in Company stock. Amounts 69 84 expensed under the plan were approximately $9 million, $9 million and $4 million for the years ended December 31, 1998, 1997, and 1996, respectively. 11. EMPLOYEE SEPARATION AND ASSET IMPAIRMENT CHARGE During the first quarter of 1996, the Company adopted a program to reduce operating costs through work force reductions and improved work processes and adopted SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. As a result of the workforce reduction program and the adoption of SFAS No. 121, the Company recorded a special charge of $99 million ($47 million for employee separation costs and $52 million for asset impairments) in the first quarter of 1996. The employee separation charge included approximately $26 million for expected severance-related costs and $21 million for pension costs related to special termination benefits and work force reductions. The special charge for pension-related costs will have no cash impact outside of the normal funding of the Company's pension plan. In accordance with SFAS No. 121, the Company determined the fair value of certain assets based on discounted future cash flows. The resultant non-cash charge for asset impairments included approximately $44 million for the impairment of certain natural gas gathering, processing, and production facilities and $8 million for the write-off of a regulatory asset established upon the adoption of SFAS No. 112, Employers' Accounting for Postemployment Benefits, but not recoverable through the Company's rate settlement filed with FERC in March 1996. 12. PREFERRED STOCK OF SUBSIDIARY In November 1996, EPTPC issued 6 million shares of 8 1/4% cumulative preferred stock with a par value of $50 per share for $296 million (net of issuance costs). The preferred stock is redeemable, at the option of EPTPC, after December 31, 2001, at a redemption price equal to $50 per share, plus dividends accrued and unpaid up to the date of redemption. During 1998, 1997, and 1996, dividends of approximately $25 million, $25 million, and $3 million, respectively, were paid on the cumulative preferred stock. Approximately $2 million is reflected in 1996 as minority interest for the 20 days EPTPC was included in the Consolidated Statements of Income. 13. SEGMENT INFORMATION The Company adopted the provisions of SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, effective January 1, 1998. Accordingly, the Company has segregated its business activities into five segments: Tennessee Gas Pipeline segment, El Paso Natural Gas segment, El Paso Field Services segment, El Paso Energy Marketing segment, and El Paso Energy International segment. These segments are strategic business units that offer a variety of different energy products and services. They are managed separately as each business requires different technology and marketing strategies. The Tennessee Gas Pipeline segment, which includes the interstate pipeline systems of TGP, Midwestern, and East Tennessee, transports natural gas to the northeast, midwest, and mid-Atlantic sections of the U.S. including the states of Tennessee, Virginia and Georgia as well as the New York City, Chicago, and Boston metropolitan areas. The El Paso Natural Gas segment, which includes the interstate pipeline systems of EPNG and MPC, transports natural gas primarily to the California market. The El Paso Field Services segment provides natural gas gathering, products extraction, dehydration, purification, compression and intrastate transmission services. The El Paso Energy Marketing segment markets and trades natural gas, power, and petroleum products and participates in the development and ownership of domestic power generation projects. The El Paso Energy International segment develops and operates energy infrastructure facilities worldwide. 70 85 The accounting policies of the individual segments are the same as those of the Company, as a whole, as described in Note 1. Certain business segments' earnings are largely derived from the earnings on equity investments which are reported in Other, net in the Consolidated Statements of Income. Accordingly, the Company evaluates segment performance, based on EBIT. To the extent practicable, results of operations for the years ended December 31, 1997, and 1996 have been reclassified to conform to the current business segment presentation, although such results are not necessarily indicative of the results which would have been achieved had the revised business segment structure been in effect during that period.
SEGMENTS AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998 ------------------------------------------------------------------- TENNESSEE EL PASO EL PASO EL PASO EL PASO GAS NATURAL FIELD ENERGY ENERGY PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL --------- ------- -------- --------- ------------- ------ (IN MILLIONS) Revenue from external customers Domestic......................... $ 728 $ 473 $ 194 $4,000 $ -- $5,395 Foreign.......................... -- -- -- 323 58 381 Intersegment revenue............... 38 2 59 17 -- 116 Depreciation and amortization...... 143 61 47 3 9 263 Operating income................... 332 215 60 5 (28) 584 Other, net......................... 26 2 15 4 53 100 Earnings before interest and taxes............................ 358 217 75 9 25 684 Assets Domestic......................... 4,995 1,742 1,426 762 281 9,206 Foreign.......................... -- -- -- 73 581 654 Capital expenditures............... 138 31 107 2 119 397 Equity investments................. 74 -- 87 -- 436 597
SEGMENTS AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1997 ------------------------------------------------------------------- TENNESSEE EL PASO EL PASO EL PASO EL PASO GAS NATURAL FIELD ENERGY ENERGY PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL --------- ------- -------- --------- ------------- ------ (IN MILLIONS) Revenue from external customers Domestic......................... $ 765 $ 518 $360 $3,757 $ -- $5,400 Foreign.......................... -- -- -- 218 13 231 Intersegment revenue............... 33 2 20 20 -- 75 Depreciation and amortization...... 137 56 33 4 1 231 Operating income................... 304 255 66 (31) (24) 570 Other, net......................... 14 5 8 3 26 56 Earnings before interest and taxes............................ 318 260 74 (28) 2 626 Assets Domestic......................... 5,179 1,838 852 859 180 8,908 Foreign.......................... -- -- -- 16 238 254 Capital expenditures............... 111 84 62 8 21 286 Equity investments................. 64 -- 24 44 241 373
71 86
SEGMENTS FOR THE YEAR ENDED OF DECEMBER 31, 1996 ------------------------------------------------------------------- TENNESSEE EL PASO EL PASO EL PASO EL PASO GAS NATURAL FIELD ENERGY ENERGY PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL --------- ------- -------- --------- ------------- ------ (IN MILLIONS) Revenue from external customers Domestic......................... $47 $510 $276 $2,177 $-- $3,010 Intersegment revenue............... 1 1 15 6 -- 23 Depreciation and amortization...... 12 58 27 4 -- 101 Operating income................... 14 209 35 23 (3) 278 Other, net......................... 2 14 -- 1 (1) 16 Earnings before interest and taxes............................ 16 223 35 24 (4) 294
The reconciliations of revenues for reportable segments to total consolidated revenues are presented below.
FOR THE YEAR ENDED DECEMBER 31, ------------------------ 1998 1997 1996 ------ ------ ------ (IN MILLIONS) Total revenues for segments................................. $5,892 $5,706 $3,033 Other revenues.............................................. 6 7 2 Elimination of intersegment revenue......................... (116) (75) (23) ------ ------ ------ Total consolidated revenues....................... $5,782 $5,638 $3,012 ====== ====== ======
The reconciliations of other, net for reportable segments to total consolidated other, net are presented below.
FOR THE YEAR ENDED DECEMBER 31, ------------------ 1998 1997 1996 ---- ---- ---- Total other, net for segments............................... $100 $ 56 $ 16 Corporate other, net........................................ 38 1 (11) ---- ---- ---- Total consolidated other, net..................... $138 $ 57 5 ==== ==== ====
The reconciliations of EBIT to income before income taxes and minority interest are presented below.
FOR THE YEAR ENDED DECEMBER 31, ------------------- 1998 1997 1996 ---- ----- ---- (IN MILLIONS) Total EBIT for segments..................................... $684 $ 626 $294 Corporate expenses, net..................................... 40 48 119 Interest and debt expense................................... 267 238 110 ---- ----- ---- Income before income taxes and minority interest........................................ $377 $ 340 $ 65 ==== ===== ====
The reconciliations of assets for reportable segments to total consolidated assets are presented below.
AS OF DECEMBER 31, ------------------ 1998 1997 -------- ------- (IN MILLIONS) Total assets for segments................................... $ 9,860 $9,162 Corporate and other assets.................................. 209 370 ------- ------ Total consolidated assets......................... $10,069 $9,532 ======= ======
72 87 The Company did not have gross revenue from any customer equal to, or in excess of, ten percent of consolidated operating revenue for the years ended December 31, 1998, 1997, and 1996. 14. INVENTORIES Inventories consisted of the following at December 31:
1998 1997 ----- ----- (IN MILLIONS) Materials and supplies...................................... $45 $42 Gas in storage.............................................. 4 26 --- --- Total............................................. $49 $68 === ===
15. PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment consisted of the following at December 31:
1998 1997 ------ ------ (IN MILLIONS) Property, plant, and equipment, at cost Tennessee Gas Pipeline.................................... $2,438 $2,289 El Paso Natural Gas....................................... 2,417 2,454 El Paso Field Services.................................... 1,118 1,022 El Paso Energy Marketing.................................. 47 78 El Paso Energy International.............................. 283 79 Corporate and Other....................................... 103 82 ------ ------ 6,406 6,004 Less accumulated depreciation and depletion................. 1,546 1,395 ------ ------ 4,860 4,609 Additional acquisition cost assigned to utility plant, net of accumulated amortization............................... 2,481 2,507 ------ ------ Total property, plant, and equipment, net................... $7,341 $7,116 ====== ======
16. EARNINGS PER SHARE In March 1997, the Financial Accounting Standards Board issued SFAS No. 128, Earnings Per Share, which establishes new guidelines for calculating earnings per share. The pronouncement is effective for reporting periods ending after December 15, 1997. SFAS No. 128 requires companies to present both a basic and diluted earnings per share amount on the face of the statement of income and to restate prior period earnings per share amounts to comply with this standard. Basic and diluted earnings per share amounts calculated in accordance with SFAS No. 128 are presented below for the years ended December 31.
1998 1997 ------------------------------------ ------------------------ AVERAGE AVERAGE SHARES EARNINGS SHARES NET INCOME OUTSTANDING PER SHARE NET INCOME OUTSTANDING ---------- ----------- --------- ---------- ----------- (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) Basic.................. $225 115.8 $1.94 $186 114.0 ===== Effect of dilutive securities Stock options........ -- 2.5 -- 2.1 Trust preferred securities......... 8 6.2 -- -- Restricted stock..... -- 1.4 -- 1.3 ---- ----- ---- ----- Diluted................ $233 125.9 $1.85 $186 117.4 ==== ===== ===== ==== ===== 1997 1996 --------- ------------------------------------ AVERAGE EARNINGS SHARES EARNINGS PER SHARE NET INCOME OUTSTANDING PER SHARE --------- ---------- ----------- --------- (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) Basic.................. $1.63 $38 72.3 $0.53 ===== ===== Effect of dilutive securities Stock options........ -- 1.0 Trust preferred securities......... -- -- Restricted stock..... -- -- --- ---- Diluted................ $1.59 $38 73.3 $0.52 ===== === ==== =====
73 88 17. SUPPLEMENTAL CASH FLOW INFORMATION The following table contains supplemental cash flow information for the years ended December 31:
1998 1997 1996 ---- ---- ---- (IN MILLIONS) Interest.................................................. $266 $249 $ 85 Income tax payments (refunds)............................. (93) (34) 49
See Note 2, for a discussion of the non-cash investing transactions related to certain acquisitions. 18. INVESTMENT IN AFFILIATED COMPANIES (UNAUDITED) The Company holds investments in various affiliates which are accounted for on the equity method of accounting. The principal equity method investments are the Company's investments in international pipelines, interstate pipelines, power generation plants, gathering systems and natural gas storage facilities. Summarized financial information of the Company's proportionate share of 50 percent or less owned companies and majority owned unconsolidated subsidiaries accounted for by the equity method of accounting is as follows:
YEAR ENDED DECEMBER 31, ----------------------- COMPANIES OWNED 50% OR LESS 1998 1997 1996 - --------------------------- ----- ----- ----- (IN MILLIONS) Operating results data: Revenues and other income................................. $202 $130 $98 Costs and expenses........................................ 156 103 68 Net income................................................ 46 26 30
DECEMBER 31, --------------- 1998 1997 ------ ------ Financial position data: Current assets............................................ $ 182 $ 78 Non-current assets........................................ 1,941 1,033 Short-term debt........................................... 175 25 Other current liabilities................................. 75 50 Long-term debt............................................ 1,028 640 Other non-current liabilities............................. 171 67 Equity in net assets...................................... 674 329
74 89 19. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Financial information by quarter is summarized below. In the opinion of management, all adjustments necessary for a fair presentation have been made.
QUARTERS ENDED ----------------------------------------------- DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31 ----------- ------------ ------- -------- (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) 1998 Operating revenues............................... $1,252 $1,615 $1,296 $1,619 Operating income................................. 140 112 113 141 Net income....................................... 60 52 55 58 Basic earnings per common share.................. 0.52 0.45 0.47 0.50 Diluted earnings per share....................... 0.49 0.43 0.45 0.48 1997 Operating revenues............................... $1,577 $1,251 $ 979 $1,831 Operating income................................. 137 120 125 139 Net income....................................... 52 44 43 47 Basic earnings per common share.................. 0.45 0.38 0.38 0.43 Diluted earnings per share....................... 0.44 0.37 0.37 0.42
75 90 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of El Paso Energy Corporation: In our opinion, the consolidated financial statements listed in the index appearing under Item 14.(a) 1. present fairly, in all material respects, the consolidated financial position of El Paso Energy Corporation as of December 31, 1998 and 1997, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14.(a) 2. presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinions expressed above. PricewaterhouseCoopers LLP Houston, Texas March 9, 1999 76 91 SCHEDULE II EL PASO ENERGY CORPORATION VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996 (IN MILLIONS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E -------- ---------- ------------------- ---------- --------- CHARGED BALANCE AT TO COSTS CHARGED BALANCE BEGINNING AND TO OTHER AT END DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD ----------- ---------- -------- -------- ---------- --------- 1998 Allowance for doubtful accounts.......... $ 56 $ 7 $ 4 $(29)(a) $ 38 Valuation allowance on deferred tax assets................................ 8 -- 4 (7) 5 1997 Allowance for doubtful accounts.......... $ 64 $ 53 $ -- $(61)(a) $ 56 Valuation allowance on deferred tax assets................................ -- -- 8(b) -- 8 1996 Allowance for doubtful accounts.......... $ 11 $ 6 $ 51(c) $ (4)(a) $ 64
- --------------- (a) Primarily accounts written off. (b) Due to acquisition of Gulf States Gas Pipeline Company. (c) Primarily due to acquisition of EPTPC. 77 92 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information appearing under the captions "Proposal No. 1 -- Election of Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in EPEC's proxy statement for the 1999 Annual Meeting of Stockholders is incorporated herein by reference. Information regarding executive officers of EPEC is presented in Item 1, Business, of this Form 10-K under the caption "Executive Officers of the Registrant." ITEM 11. EXECUTIVE COMPENSATION Information appearing under the caption "Executive Compensation" in EPEC's proxy statement for the 1999 Annual Meeting of Stockholders is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information appearing under the caption "Security Ownership of a Certain Beneficial Owner and Management" in EPEC's proxy statement for the 1999 Annual Meeting of Stockholders is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT: 1. Financial statements. The following consolidated financial statements of the Company are included in Part II, Item 8 of this report:
PAGE ---- Consolidated Statements of Income...................... 42 Consolidated Balance Sheets............................ 43 Consolidated Statements of Cash Flows.................. 44 Consolidated Statements of Stockholders' Equity........ 45 Consolidated Statements of Comprehensive Income........ 46 Notes to Consolidated Financial Statements............. 47 Report of independent accountants...................... 76 2. Financial statement schedules and supplementary information required to be submitted. Schedule II -- Valuation and qualifying accounts....... 77 Schedules other than that listed above are omitted because they are not applicable 3. Exhibit list............................................. 79
(B) REPORTS ON FORM 8-K: None. 78 93 EL PASO ENERGY CORPORATION EXHIBIT LIST DECEMBER 31, 1998 Each exhibit identified below is filed as a part of this report. Exhibits not incorporated by reference to a prior filing are designated by an asterisk; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with a "+" constitute a management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
EXHIBIT NUMBER DESCRIPTION ------- ----------- 2 -- Agreement and Plan of Merger, dated July 16, 1998, by and among EPEC, EPNG, and El Paso Energy Merger Company (Exhibit 2.1 to EPEC's Form 8-K, filed August 3, 1998, File No. 1-14365). 3.A -- Restated Certificate of Incorporation of EPEC, dated July 16, 1998; Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock of EPEC, dated July 16, 1998, as amended (Exhibit 3.1 to EPEC's Form 8-K, filed August 3, 1998, File No. 1-14365). 3.B -- By-laws of EPEC, as amended dated October 21, 1998 (Exhibit 3.B to EPEC's Form 10-Q, filed November 12, 1998, File No. 1-14365 (the "EPEC 1998 Third Quarter 10-Q")). 4.A -- Amended and Restated Shareholder Rights Agreement, between EPEC and BankBoston, N.A., dated January 20, 1999 (Exhibit 1 to EPEC's Registration Statement on Form 8-A/A Amendment No. 1, filed January 29, 1999, File No. 1-14365). 4.B -- Amended and Restated Declaration of Trust of El Paso Energy Capital Trust I dated March 16, 1998 (Exhibit 4.4 to EPNG's Form 8-K, filed March 17, 1998, File No. 1-2700); First Amendment to the Amended and Restated Declaration of Trust of El Paso Energy Capital Trust I, dated August 1, 1998 (Exhibit 4.3 of EPEC's Form 8-K, filed August 3, 1998, File No. 1-14365). 4.C -- Subordinated Debt Securities Indenture dated March 1, 1998, between EPNG and The Chase Manhattan Bank as Trustee (Exhibit 4.1 to EPNG's Form 8-K, filed March 17, 1998, File No. 1-2700); First Supplemental Indenture dated March 17, 1998, between EPNG and The Chase Manhattan Bank, as Trustee (Exhibit 4.2 to EPNG's Form 8-K, filed March 17, 1998, File No. 1-2700); Second Supplemental Indenture, dated August 1, 1998 between EPEC and The Chase Manhattan Bank, as Trustee (Exhibit 4.2 to EPEC's Form 8-K, filed August 3, 1998, File No. 1-14365). 4.D -- 4 3/4% Convertible Subordinated Debenture due 2028 (Exhibit 4.6 to EPNG's Form 8-K, filed March 17, 1998, File No. 1-2700). 4.E -- Certificate of Trust Preferred Security (Exhibit 4.5 to EPNG's Form 8-K, filed March 17, 1998, File No. 1-2700). 4.F -- Trust Preferred Securities Guarantee Agreement issued by EPNG dated March 17, 1998 (Exhibit 4.7 to EPNG's Form 8-K, filed March 17, 1998, File No. 1-2700); First Amendment to Trust Preferred Securities Guarantee Agreement issued by EPEC dated August 1, 1998, (Exhibit 4.4 to EPEC's Form 8-K, filed August 3, 1998, File No. 1-14365).
79 94
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.A -- $750 million 364-Day Revolving Credit and Competitive Advance Facility Agreement dated as of October 29, 1997, by and among EPNG, TGP, The Chase Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust Company of New York and certain other banks (Exhibit 10.A to the EPEC 1998 Third Quarter 10-Q); First Amendment to the $750 million 364-Day Revolving Credit and Competitive Advance Facility dated as of October 9, 1998, among EPNG, TGP, The Chase Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust Company of New York, and certain other banks (Exhibit 10.B to the EPEC 1998 Third Quarter 10-Q); Guarantee, dated as of August 28, 1998, made by EPEC in favor of The Chase Manhattan Bank, as Administrative Agent for several banks and other financial institutions from time to time parties to the $750 million 364-Day Revolving Credit and Competitive Advance Facility dated as of October 29, 1997, by and among EPNG, TGP, The Chase Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust Company of New York, and certain other banks (Exhibit 10.C to the EPEC 1998 Third Quarter 10-Q). *10.A.1 -- Joinder Agreement dated December 7, 1998, made by EPEC to the $750 million 364-Day Revolving Credit and CAF Advance Facility Agreement, by and among EPNG, TGP, The Chase Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust Company of New York. 10.B -- $750 million 5-Year Revolving Credit and Competitive Advance Facility Agreement dated as of October 29, 1997, by and among EPNG, TGP, The Chase Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust Company of New York, and certain other banks (Exhibit 10.D to the EPEC 1998 Third Quarter 10-Q); First Amendment to the $750 million 5-Year Revolving Credit and Competitive Advance Facility dated as of October 9, 1998, among EPNG, TGP, The Chase Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust Company of New York, and certain other banks (Exhibit 10.E to the EPEC 1998 Third Quarter 10-Q); Guarantee, dated as of August 28, 1998, made by EPEC in favor of The Chase Manhattan Bank, as Administrative Agent for several banks and other financial institutions from time to time parties to the $750 million 5-Year Revolving Credit and Competitive Advance Facility dated as of October 29, 1997, by and among EPNG, TGP, The Chase Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust Company of New York, and certain other banks (Exhibit 10.F to the EPEC 1998 Third Quarter 10-Q). *10.B.1 -- Joinder Agreement dated December 7, 1998, made by EPEC to the $750 million 5-Year Revolving Credit and CAF Advance Facility Agreement, by and among EPNG, TGP, The Chase Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust Company of New York. *+10.C -- Omnibus Compensation Plan dated January 1, 1992; Amendment No. 1 effective as of April 1, 1998; Amendment No. 2 effective as of August 1, 1998; Amendment No. 3 effective as of December 3, 1998; and Amendment No. 4 effective as of January 20, 1999. *+10.D -- 1995 Incentive Compensation Plan, Amended and Restated effective as of December 3, 1998. +10.E -- 1995 Compensation Plan for Non-Employee Directors, Amended and Restated effective as of August 1, 1998 (Exhibit 10.H to the EPEC 1998 Third Quarter 10-Q). *+10.F -- Stock Option Plan for Non-Employee Directors, Amended and Restated effective as of January 20, 1999.
80 95
EXHIBIT NUMBER DESCRIPTION ------- ----------- +10.G -- 1995 Omnibus Compensation Plan, Amended and Restated effective as of August 1, 1998 (Exhibit 10.J to the EPEC 1998 Third Quarter 10-Q). *+10.G.1 -- Amendment No. 1 to the 1995 Omnibus Compensation Plan effective as of December 3, 1998; Amendment No. 2 to the 1995 Omnibus Compensation Plan effective as of January 20, 1999. *+10.H -- Supplemental Benefits Plan, Amended and Restated effective as of December 3, 1998. +10.I -- Senior Executive Survivor Benefit Plan, Amended and Restated effective as of August 1, 1998 (Exhibit 10.M to the EPEC 1998 Third Quarter 10-Q). *+10.J -- Deferred Compensation Plan, Amended and Restated effective as of December 3, 1998. +10.K -- Key Executive Severance Protection Plan, Amended and Restated effective as of August 1, 1998 (Exhibit 10.O to the EPEC 1998 Third Quarter 10-Q). +10.L -- Director Charitable Award Plan, Amended and Restated effective as of August 1, 1998 (Exhibit 10.P to the EPEC 1998 Third Quarter 10-Q). +10.M -- Strategic Stock Plan, Amended and Restated effective as of August 1, 1998 (Exhibit 10.Q to the EPEC 1998 Third Quarter 10-Q). *+10.M.1 -- Amendment No. 1 to the Strategic Stock Plan, effective as of December 3, 1998; Amendment No. 2 to the Strategic Stock Plan, effective as of January 20, 1999. +10.N -- Domestic Relocation Policy, effective November 1, 1996 (Exhibit 10.Q to EPNG's Form 10-K for 1997, File No. 1-2700). +10.O -- Employment Agreement dated July 31, 1992 between EPNG and William A. Wise (Exhibit 10.R to the EPEC 1998 Third Quarter 10-Q); Amendment to Employment Agreement dated January 29, 1996, between EPNG and William A. Wise (Exhibit 10.U.1 to EPNG's Form 10-K for 1995, File No. 1-2700). *+10.P -- Letter Agreement dated January 13, 1995 between EPNG and William A. Wise. +10.Q -- Promissory Note dated May 30, 1997, made by William A. Wise to EPEC (Exhibit 10.R to EPNG's Form 10-Q, filed May 15, 1998, File No. 1-2700; Amendment to Promissory Note dated November 20, 1997 (Exhibit 10.R to EPNG's Form 10-Q, filed May 15, 1998, File No. 1-2700). +10.S -- Letter Agreement dated February 22, 1991, between EPNG and Britton White Jr. (Exhibit 10.V to the EPEC 1998 Third Quarter 10-Q). *18 -- Letter regarding Change in Accounting Principles. *21 -- Subsidiaries of EPEC. *23 -- Consent of Independent Accountants. *27 -- Financial Data Schedule.
81 96 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, El Paso Energy Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 9th day of March 1999. EL PASO ENERGY CORPORATION Registrant By /s/ WILLIAM A. WISE ------------------------------------ William A. Wise Chairman of the Board, President, and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of El Paso Energy Corporation and in the capacities and on the dates indicated:
SIGNATURE TITLE DATE --------- ----- ---- /s/ WILLIAM A. WISE Chairman of the Board, March 9, 1999 - ----------------------------------------------------- President, Chief Executive (William A. Wise) Officer and Director /s/ H. BRENT AUSTIN Executive Vice President and March 9, 1999 - ----------------------------------------------------- Chief Financial Officer (H. Brent Austin) /s/ JEFFREY I. BEASON Vice President and Controller March 9, 1999 - ----------------------------------------------------- (Chief Accounting Officer) (Jeffrey I. Beason) /s/ BYRON ALLUMBAUGH Director March 9, 1999 - ----------------------------------------------------- (Byron Allumbaugh) /s/ JUAN CARLOS BRANIFF Director March 9, 1999 - ----------------------------------------------------- (Juan Carlos Braniff) /s/ PETER T. FLAWN Director March 9, 1999 - ----------------------------------------------------- (Peter T. Flawn) /s/ JAMES F. GIBBONS Director March 9, 1999 - ----------------------------------------------------- (James F. Gibbons) /s/ BEN F. LOVE Director March 9, 1999 - ----------------------------------------------------- (Ben F. Love) /s/ KENNETH L. SMALLEY Director March 9, 1999 - ----------------------------------------------------- (Kenneth L. Smalley) /s/ MALCOLM WALLOP Director March 9, 1999 - ----------------------------------------------------- (Malcolm Wallop)
82 97 REPORT OF MANAGEMENT To the Board of Directors and Stockholders El Paso Energy Corporation The management of El Paso Energy Corporation is responsible for the preparation, integrity, and fairness of the accompanying financial statements as well as other information presented in this Annual Report. Such responsibility includes judgments, estimates, the selection of appropriate generally accepted accounting principles, the consistent application of such principles, and devising and maintaining adequate systems of internal controls. In the opinion of management, the financial statements are fairly stated and have been prepared in conformity with generally accepted accounting principles, and, to that end, the Company and its subsidiaries maintain a system of internal control which: provides reasonable assurance that transactions are recorded properly for the preparation of financial statements; safeguards assets against unauthorized acquisition, use or disposition; maintains accountability for assets; requires proper authorization and accountability for all transactions; provides for a comparison of the recorded and existing assets at reasonable intervals and requires appropriate action with respect to any difference; and promotes compliance with applicable laws and regulations. The financial statements have been audited by the independent accounting firm, PricewaterhouseCoopers LLP, which was given unrestricted access to all financial records and related data. Their audit was conducted in accordance with generally accepted auditing standards and included a review of internal control to the extent deemed necessary for the purpose of their audit. Management is responsible for the effectiveness of its system of internal control. This is accomplished through established codes of conduct, accounting and other control systems, policies and procedures, employee selection and training, appropriate delegation of authority, and segregation of responsibilities. To further ensure compliance with established standards and related control procedures, the Company conducts an ongoing, substantial corporate audit program. Corporate auditors monitor the operation of the Company's internal control system and report findings and recommendations to management, including corrective action taken to address control deficiencies and opportunities for improving the system. Even an effective internal control system has inherent limitations, including the possibility of circumvention or overriding of controls, and therefore can provide only reasonable assurance with respect to financial statement preparation. The Audit Committee of the Board of Directors, composed entirely of Directors who are not employees of El Paso Energy Corporation, has met privately and separately with PricewaterhouseCoopers LLP, corporate auditors, and management of the Company to review accounting, auditing, internal control, and financial reporting matters. March 9, 1999 /s/ H. BRENT AUSTIN H. Brent Austin Executive Vice President and Chief Financial Officer /s/ JEFFREY I. BEASON Jeffrey I. Beason Vice President, Controller and Chief Accounting Officer 98 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------- FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 1-14365 --------------------- EL PASO ENERGY CORPORATION (Exact Name of Registrant as Specified in its Charter) DELAWARE 76-0568816 (State or Other Jurisdiction (I.R.S. Employer of Incorporation or Organization) Identification No.) EL PASO ENERGY BUILDING 1001 LOUISIANA STREET 77002 HOUSTON, TEXAS (Zip Code) (Address of Principal Executive Offices)
Registrant's Telephone Number, Including Area Code: (713) 420-2131 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock, par value $3.00 per share. Shares outstanding on May 10, 1999: 121,491,576 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 99 GLOSSARY The following abbreviations, acronyms, or defined terms used in this Form 10-Q are defined below:
DEFINITIONS ----------- ALJ................... Administrative Law Judge Company............... El Paso Energy Corporation and its subsidiaries Court of Appeals...... United States Court of Appeals for the District of Columbia Circuit EBIT.................. Earnings before interest expense and income taxes, excluding affiliated interest income Edison................ Southern California Edison Company EPA................... United States Environmental Protection Agency EPEC.................. El Paso Energy Corporation, unless the context otherwise requires EPFS.................. El Paso Field Services Company, a wholly owned subsidiary of El Paso Tennessee Pipeline Co. EPNG.................. El Paso Natural Gas Company, a wholly owned subsidiary of El Paso Energy Corporation EPTPC................. El Paso Tennessee Pipeline Co., a direct subsidiary of El Paso Energy Corporation FERC.................. Federal Energy Regulatory Commission GSR................... Gas supply realignment PCB(s)................ Polychlorinated biphenyl(s) PLN................... Perusahaan Listrik Negara, the Indonesian government-owned electric utility PRP(s)................ Potentially responsible party(ies) TGP................... Tennessee Gas Pipeline Company, a wholly owned subsidiary of El Paso Tennessee Pipeline Co. TransAmerican......... TransAmerican Natural Gas Corporation
i 100 PART I -- FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS EL PASO ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) (UNAUDITED)
FIRST QUARTER ENDED MARCH 31, ------------------- 1999 1998 ------- ------- Operating revenues.......................................... $ 1,494 $ 1,619 ------- ------- Operating expenses Cost of gas and other products............................ 1,068 1,209 Operation and maintenance................................. 183 180 Depreciation, depletion, and amortization................. 71 65 Taxes, other than income taxes............................ 27 24 ------- ------- 1,349 1,478 ------- ------- Operating income............................................ 145 141 ------- ------- Other (income) and expense Interest and debt expense................................. 73 64 Other -- net.............................................. (45) (22) ------- ------- 28 42 ------- ------- Income before income taxes, minority interest, and cumulative effect of accounting change.................... 117 99 Income tax expense.......................................... 40 35 Minority interest Preferred stock dividend requirement of subsidiary........ 6 6 ------- ------- Income before cumulative effect of accounting change........ 71 58 Cumulative effect of accounting change, net of income tax... (13) -- ------- ------- Net income.................................................. $ 58 $ 58 ======= ======= Comprehensive income........................................ $ 49 $ 57 ======= ======= Basic earnings per common share Income before cumulative effect of accounting change...... $ 0.62 $ 0.50 Cumulative effect of accounting change, net of income tax.................................................... (0.12) -- ------- ------- Net income................................................ $ 0.50 $ 0.50 ======= ======= Diluted earnings per common share Income before cumulative effect of accounting change...... $ 0.58 $ 0.48 Cumulative effect of accounting change, net of income tax.................................................... (0.10) -- ------- ------- Net income................................................ $ 0.48 $ 0.48 ======= ======= Basic average common shares outstanding..................... 116.0 115.9 ======= ======= Diluted average common shares outstanding................... 127.8 121.7 ======= ======= Dividends declared per common share......................... $ 0.20 $ 0.19 ======= =======
The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements. 1 101 EL PASO ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE AMOUNTS) ASSETS
MARCH 31, DECEMBER 31, 1999 1998 ----------- ------------ (UNAUDITED) Current assets Cash and temporary investments............................ $ 90 $ 90 Accounts and notes receivable, net........................ 780 733 Materials and supplies.................................... 48 49 Other..................................................... 305 337 ------- ------- Total current assets.............................. 1,223 1,209 Property, plant, and equipment, net......................... 7,191 7,220 Investments in unconsolidated affiliates.................... 973 600 Other....................................................... 1,079 1,009 ------- ------- Total assets...................................... $10,466 $10,038 ======= ======= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable.......................................... $ 599 $ 724 Short-term borrowings (including current maturities of long-term debt)........................................ 736 812 Other..................................................... 600 595 ------- ------- Total current liabilities......................... 1,935 2,131 ------- ------- Long-term debt, less current maturities..................... 3,082 2,552 ------- ------- Deferred income taxes....................................... 1,589 1,564 ------- ------- Other....................................................... 1,008 993 ------- ------- Commitments and contingencies (See Note 4) Company-obligated mandatorily redeemable convertible preferred securities of El Paso Energy Capital Trust I.... 325 325 ------- ------- Minority interest Preferred stock of subsidiary............................. 300 300 ------- ------- Other minority interest................................... 65 65 ------- ------- Stockholders' equity Common stock, par value $3 per share; authorized 275,000,000 shares; issued 125,529,432 and 124,434,110 shares, respectively................................... 377 373 Additional paid-in capital................................ 1,465 1,436 Retained earnings......................................... 494 460 Accumulated comprehensive income.......................... (23) (14) Treasury stock (at cost) 4,233,028 and 4,149,099 shares, respectively.................................... (92) (90) Deferred compensation..................................... (59) (57) ------- ------- Total stockholders' equity........................ 2,162 2,108 ------- ------- Total liabilities and stockholders' equity........ $10,466 $10,038 ======= =======
The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements. 2 102 EL PASO ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS) (UNAUDITED)
FIRST QUARTER ENDED MARCH 31, -------------- 1999 1998 ----- ----- Cash flows from operating activities Net income................................................ $ 58 $ 58 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion, and amortization.............. 71 65 Deferred income taxes.................................. 23 24 Undistributed earnings in equity investees............. (11) (4) Cumulative effect of accounting change, net of income tax................................................... 13 -- Other.................................................. -- (2) Working capital changes, net of the effect of acquisitions........................................... 30 (54) Other..................................................... (53) 23 ----- ----- Net cash provided by operating activities......... 131 110 ----- ----- Cash flows from investing activities Capital expenditures...................................... (39) (47) Investment in joint ventures and equity investees......... (443) (278) Acquisition of EnCap Investments L.C...................... (36) -- Restricted cash deposited in escrow related to equity investee............................................... (53) -- Other..................................................... 4 7 ----- ----- Net cash used in investing activities............. (567) (318) ----- ----- Cash flows from financing activities Net commercial paper borrowings (repayments).............. 354 (72) Revolving credit borrowings............................... 220 -- Revolving credit repayments............................... (150) (45) Long-term debt retirements................................ (21) (21) Net proceeds from preferred securities of El Paso Energy Capital Trust I issuance................... -- 317 Net proceeds from long-term note payable.................. 53 -- Dividends paid on common stock............................ (23) (22) Other..................................................... 3 8 ----- ----- Net cash provided by financing activities......... 436 165 ----- ----- Decrease in cash and temporary investments.................. -- (43) Cash and temporary investments Beginning of period............................... 90 116 ----- ----- End of period..................................... $ 90 $ 73 ===== =====
The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements. 3 103 EL PASO ENERGY CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. BASIS OF PRESENTATION The 1998 Annual Report on Form 10-K for the Company includes a summary of significant accounting policies and other disclosures and should be read in conjunction with this Quarterly Report on Form 10-Q. The condensed consolidated financial statements at March 31, 1999, and for the quarters ended March 31, 1999, and 1998, are unaudited. The condensed balance sheet at December 31, 1998, is derived from audited financial statements. These financial statements do not include all disclosures required by generally accepted accounting principles. In the opinion of management, all material adjustments necessary to present fairly the results of operations for such periods have been included. All such adjustments are of a normal recurring nature. Results of operations for any interim period are not necessarily indicative of the results of operations for the entire year due to the seasonal nature of the Company's businesses. Financial statements for the previous periods include certain reclassifications which were made to conform to current presentation. Such reclassifications have no effect on reported net income or stockholders' equity. Cumulative Effect of Accounting Change In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5, Reporting on the Costs of Start-Up Activities. The statement defines start-up activities and requires start-up and organization costs be expensed as incurred. In addition, it requires that any such cost that exists on the balance sheet be expensed upon adoption of this pronouncement. The Company adopted this pronouncement effective January 1, 1999, and reported a charge of $13 million, net of income taxes, in the first quarter of 1999 as a cumulative effect of a change in accounting principle. 2. MERGER WITH SONAT INC. In March 1999, the Company entered into a merger agreement with Sonat Inc. See Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments for a further discussion. 3. ACQUISITIONS In February 1999, the Company acquired a 51 percent ownership interest in East Asia Power Resources Corporation ("EAPRC"), a publicly traded company in the Philippines, for approximately $70 million. Since the Company's majority ownership is expected to be temporary, the investment is accounted for under the equity method of accounting. EAPRC owns and operates three power generation facilities in the Philippines and owns an interest in one power generation facility in China, with a total generating capacity of 289 megawatts. Electric power generated by the facilities is supplied to a diversified base of customers including National Power Corporation, the state-owned utility, private distribution companies and industrial users. In March 1999, El Paso Power Holding Company purchased a 50 percent ownership interest in CE Generation LLC. The investment of approximately $254 million is accounted for under the equity method of accounting. CE Generation LLC owns four natural gas-fired cogeneration projects in New York, Pennsylvania, Texas and Arizona and eight geothermal facilities near the Imperial Valley in southern California, which are qualifying facilities under the Public Utility Regulatory Policy Act. In addition, two additional geothermal facilities are currently under construction in southern California. Collectively, the 14 power projects will have a combined electric generating capacity of approximately 900 megawatts. In March 1999, EPFS acquired EnCap Investments L.C. ("EnCap"), a Texas limited liability company, for $52 million, net of cash acquired. The purchase price included $17 million in Company common stock, of which $7 million is issuable upon the occurrence of certain events. The acquisition was accounted for as a purchase. EnCap is an institutional funds management firm specializing in financing independent oil and gas 4 104 producers. EnCap manages three separate institutional oil and gas investment funds in the U.S., and serves as investment advisor to Energy Capital Investment Company PLC, a publicly traded investment company in the United Kingdom. In March 1999, the Company increased its ownership interest from 30 percent to 40 percent in the Samalayuca Power project for approximately $22 million. In addition, the Company made a $48 million equity contribution replacing equity financing which was established in the second quarter of 1996. 4. COMMITMENTS AND CONTINGENCIES Indonesia The Company owns a 47.5 percent ownership interest in a power generating plant in Sengkang, South Sulawesi, Indonesia. Under the terms of the project's power purchase agreement, PLN purchases power from the Company in Indonesian rupiah indexed to the U.S. dollar at the date of payment. Due to the devaluation of the rupiah, the cost of power to PLN has significantly increased. PLN is currently unable to pass this increase in cost on to its customers without creating further political instability. PLN has requested financial aid from the Minister of Finance to help ease the effects of the devaluation. PLN has been paying the Company in rupiah indexed to the U.S. dollar at the rate in effect prior to the rupiah devaluation, with a commitment to pay the balance when financial aid is received. The difference between the current and prior exchange rate has resulted in an outstanding balance due from PLN of $12 million at March 31, 1999. Recently, the Company met and discussed its situation and concerns with the World Bank, the International Monetary Fund, the Overseas Private Investment Corporation, and the U.S. Treasury Department in an attempt to achieve a resolution through the Indonesian Minister of Finance. The Company met with PLN in April 1999 to discuss payments in arrears and the terms of a contract rationalization process proposed by PLN. The Company informed PLN that all payments in arrears must first be received as a prerequisite to any further discussions on contract rationalization. The Company continues to meet with PLN on a regular basis to resolve the payment in arrears issue but has been unsuccessful to date. The Company cannot predict with certainty the outcome of such discussions. The total investment in the Sengkang project was approximately $26 million at March 31, 1999. Additionally, the Company has provided specific recourse guarantees of up to $6 million for loans from the project lenders. All other project debt is non-recourse. The Company has political risk insurance on the Sengkang project. The Company believes the current economic difficulties in Indonesia will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. Brazil The Company owns 100 percent of a 250 megawatt power generating plant in Manaus, Brazil. Power from the plant is currently sold under a four-year contract to a subsidiary of Centrais Electricas do Norte do Brasil, S.A., ("Electronorte"), denominated in Brazilian real. In January 1999, the real was devalued. Under a provision in the contract, the Company is entitled to recover a substantial portion of any devaluation. In April 1999, the contract with Electronorte was amended to extend the term from four to six years. The Company believes the current economic difficulties in Brazil will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. The contract for the Manaus power project provides for delay damages to be paid to Electronorte if the specified construction schedule is not met. Completion of the project was delayed beyond the originally scheduled completion dates provided in the contract, and such delays have resulted in claims by Electronorte for delay damages. The Company believes that any delay damages for which it may ultimately be responsible will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. Rates and Regulatory Matters In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which it sought comments on a wide range of initiatives to change the manner in which short-term (less than one year) transportation markets are regulated. Among other things, the NOPR proposes the following: (i) removing the price cap for the short-term capacity market; (ii) establishing procedures to make pipeline and shipper-owned capacity 5 105 comparable; (iii) auctioning all available short-term pipeline capacity on a daily basis with the pipeline unable to set a reserve price above variable costs; (iv) changing policies or pipeline penalties, nomination procedures and services; (v) increasing pipeline reporting requirements; (vi) permitting the negotiation of terms and conditions of service; and (vii) potentially modifying the procedures for certificating new pipeline construction. Also in July 1998, FERC issued a Notice of Inquiry ("NOI") seeking comments on FERC's policy for pricing long-term capacity. The Company provided comments on the NOPR and NOI in April 1999. It is not known when FERC will act on the NOPR and NOI. TGP -- In February 1997, TGP filed a settlement with FERC of all issues related to the recovery of its GSR and other transition costs and related proceedings (the "GSR Stipulation and Agreement"). In April 1997, FERC approved the settlement. Under the terms of the GSR Stipulation and Agreement, TGP is entitled to collect up to $770 million from its customers, $693 million through a demand surcharge and $77 million through an interruptible transportation surcharge. As of March 31, 1999, the demand portion had been fully collected and $43 million of the interruptible transportation portion had been collected. There is no time limit for collection of the interruptible transportation surcharge portion. The terms of the GSR Stipulation and Agreement also provide for a rate case moratorium through November 2000 (subject to certain limited exceptions) and an escalating rate cap, indexed to inflation, through October 2005, for certain of TGP's customers. In accordance with the terms of the GSR Stipulation and Agreement, TGP filed a GSR Reconciliation Report with FERC on March 31, 1999. Upon approval of this report, TGP will refund approximately $14 million to its firm customers, which represents the amount collected in excess of the $693 million recovered through the demand surcharge. TGP will also be required to refund to firm customers amounts collected in excess of each firm customer's share of the final transition costs based on the final GSR Reconciliation Report which will be filed on March 31, 2001. Any future refund is not expected to have a material adverse effect on the Company's financial position, results of operations, or cash flows. In December 1994, TGP filed for a general rate increase with FERC and in October 1996, FERC approved a settlement resolving that proceeding. The settlement included a structural rate design change that results in a larger portion of TGP's transportation revenues being dependent upon throughput. One party, a competitor of TGP, filed a Petition for Review of the FERC orders with the Court of Appeals. The Court of Appeals remanded the case to FERC to respond to the competitor's argument that TGP's cost allocation methodology deterred the development of market centers (centralized locations where buyers and sellers can physically exchange gas). At FERC's request, comments were filed in January 1999. All cost of service issues related to TGP's 1991 general rate proceeding were resolved pursuant to a settlement agreement approved by FERC in an order which now has become final. However, cost allocation and rate design issues remained unresolved. In July 1996, following an ALJ's decision on these cost and design issues, FERC ruled on certain issues but remanded to the ALJ the issue of the proper allocation of TGP's New England lateral costs. In July 1997, FERC issued an order denying rehearing of its July 1996 order but clarifying that, among other things, although the ultimate resolution as to the proper allocation of costs would be applied retroactively to July 1, 1995, the cost of service settlement does not allow TGP to recover from other customers any amounts that TGP may ultimately be required to refund. In February 1999, petitions for review of the July 1996 and July 1997 FERC orders were denied by the Court of Appeals. In the remand proceeding, the ALJ issued his decision on the proper allocation of the New England lateral costs in December 1997. That decision adopts a methodology that economically approximates the one currently used by TGP. In October 1998, FERC issued an order affirming the ALJ's decision and, in April 1999, FERC denied requests for rehearing of the October 1998 order. TGP has filed cash out reports for the period September 1993 through August 1998. TGP's filings showed a cumulative loss through August of 1998 of $3 million. The reports, as well as the accounting for customer imbalances, were previously challenged by TGP's customers. In April 1999, FERC approved a settlement that resolved outstanding FERC proceedings relating to the filed cashout reports, subject to rehearing. The settlement provides a new mechanism for accounting for TGP's cash out program. Substantially all of the revenues of TGP are generated under long-term gas transmission contracts. Contracts representing approximately 70 percent of TGP's firm transportation capacity will expire by 6 106 November 2000. Although TGP cannot predict how much capacity will be resubscribed, a majority of the expiring contracts cover service to northeastern markets, where there is currently little excess capacity. Several projects, however, have been proposed to deliver incremental volumes to these markets. Although TGP is actively pursuing the renegotiation, extension and/or replacement of these contracts, there can be no assurance as to whether TGP will be able to extend or replace these contracts (or a substantial portion thereof) or that the terms of any renegotiated contracts will be as favorable to TGP as the existing contracts. EPNG -- In June 1995, EPNG filed with FERC for approval of new system rates for mainline transportation to be effective January 1, 1996. In March 1996, EPNG filed a comprehensive offer of settlement to resolve that proceeding as well as issues surrounding certain contract reductions and expirations that were to occur from January 1, 1996, through December 31, 1997. In April 1997, FERC approved EPNG's settlement as filed and determined that only the contesting party, Edison, should be severed for separate determination of the rates it ultimately pays EPNG. In July 1997, FERC issued an order denying the requests for rehearing of the April 1997 order and the settlement was implemented effective July 1, 1997. Hearings to determine Edison's rates were completed in May 1998, and an initial decision was issued by the presiding ALJ in July 1998. EPNG and Edison have filed exceptions to the decision with FERC. If the ALJ's decision is affirmed by FERC, EPNG believes that the resulting rates to Edison would be such that no significant, if any, refunds in excess of the amounts reserved would be required. Pending the final outcome, Edison continues to pay the originally filed rates, subject to refund, and EPNG continues to provide a reserve for such potential refunds. Edison filed with the Court of Appeals a petition for review of FERC's April 1997 and July 1997 orders, in which it challenged the propriety of FERC's approving the settlement over Edison's objections to the settlement as a customer of Southern California Gas Company. In December 1998, the Court of Appeals issued its decision vacating and remanding FERC's order. In April 1999, FERC issued an order requiring the parties to submit briefs setting forth their positions as to whether FERC can approve the settlement over Edison's continuing objections. EPNG cannot predict the outcome with certainty, but it believes that FERC will ultimately approve the settlement. The rate settlement establishes, among other things, base rates through December 31, 2005. Such rates escalate annually beginning in 1998. In addition, the settlement provides for settling customers to (i) pay $295 million (including interest) as a risk sharing obligation, which approximates 35 percent of anticipated revenue shortfalls over an 8 year period, resulting from certain contract reductions and expirations identified in the settlement, (ii) receive 35 percent of additional revenues received by EPNG, above a threshold, for the same eight-year period, and (iii) have the base rates increase or decrease if certain changes in laws or regulations result in increased or decreased costs in excess of $10 million a year. Through March 31, 1999, approximately $231 million of the risk sharing obligation had been paid, and the remaining balance of $64 million will be collected by the end of 2003. At March 31, 1999, the balance of the unearned risk sharing revenue was $215 million. This amount will be recognized ratably through the year 2003. In addition to other arrangements to offset the effects of the reduction in firm capacity commitments referred to above, EPNG entered into three contracts with Dynegy Inc. ("Dynegy") for the sale of substantially all of its turned back firm capacity available to California as of January 1, 1998, (approximately 1.3 billion cubic feet) for a two-year period beginning January 1, 1998, at rates negotiated pursuant to EPNG's tariff provisions and FERC policies. EPNG realized $11 million in revenue in the first quarter of 1999 and anticipates realizing at least $32 million in revenues during the remainder of 1999. Such revenue is subject to the revenue sharing provisions of the rate settlement. The contracts have a transport-or-pay provision requiring Dynegy to pay a minimum charge equal to the reservation component of the contractual charge on at least 72 percent of the contracted volumes each month in 1999. In the third quarter of 1999, EPNG intends to remarket this capacity pursuant to EPNG's tariff provisions and FERC regulations, subject to Dynegy's right of first refusal. In December 1997, EPNG filed to implement several negotiated rate contracts, including those with Dynegy. In a protest to this filing, three shippers (producers/marketers) requested that FERC require EPNG to eliminate certain provisions from the Dynegy contracts, to publicly disclose and repost the contracts for 7 107 competitive bidding, and to suspend their effectiveness. In an order issued in January 1998, FERC rejected several of the arguments made in the protest and allowed the contracts to become effective as of January 1, 1998, subject to refund, and subject to the outcome of a technical conference, which was held in March 1998. In June 1998, FERC issued an order rejecting the protests to the Dynegy contracts, but required EPNG to file modifications with FERC to the contracts clarifying the credits under the reservation reduction mechanism and the recall rights of certain capacity. In addition, EPNG agreed to separately post capacity covered by the Dynegy contracts which becomes available in the future. Several parties have protested EPNG's compliance filing and/or requested rehearing of FERC's June 1998 order. In June 1998, EPNG filed a letter agreement in compliance with the June 1998 FERC order. In September 1998, FERC issued an order accepting the letter agreement subject to EPNG making additional modifications. The additional modifications to the letter agreement required further clarification of credits available to Dynegy under the reservation reduction mechanism and the recall rights of certain capacity. In October 1998, EPNG filed a revised letter agreement with FERC and requested rehearing of the September 1998 order. The issue is pending before FERC. Under the revenue sharing provisions of its rate case settlement, EPNG was obligated to return approximately $12 million of non-traditional fixed cost revenues earned in 1998 to certain customers. This amount was credited to those customers' transportation invoices between October 1998 and March 1999. EPNG continues to reserve for the revenue sharing provisions. At March 31, 1999, EPNG had a reserve of $4 million for additional amounts, which are expected to be credited to customer accounts during the period September 1999 through March 2000. In a November 1997 order, FERC reversed its previous decision and found that EPNG's Chaco Station should be functionalized as a gathering, not transmission, facility and should be transferred to EPFS. In accordance with the FERC orders, the Chaco Station was transferred to EPFS in April 1998. EPNG and two other parties filed petitions for review with the Court of Appeals. EPNG and others contested FERC's functionalization ruling and other parties contested FERC's determination of the impact of the functionalization ruling on the treatment of the Chaco Station costs in the rate settlement. The matter has been briefed and will be argued in September 1999. TGP and EPNG, as interstate pipelines, are subject to FERC audits of their books and records. EPNG currently has an open audit covering the years 1990 through 1995. FERC is expected to issue its final audit report in 1999. As part of an industry-wide initiative, both EPNG's and TGP's property retirements are currently under review by the FERC audit staff. As the aforementioned rate and regulatory matters are fully and unconditionally resolved, the Company may either recognize an additional refund obligation or a non-cash benefit to finalize previously estimated liabilities. Management believes the ultimate resolution of these matters, which are in various stages of finalization, will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. Legal Proceedings In November 1993, TransAmerican filed a complaint in a Texas state court, TransAmerican Natural Gas Corporation v. El Paso Natural Gas Company, et al., alleging fraud, tortious interference with contractual relationships, negligent misrepresentation, economic duress, civil conspiracy, and violation of state antitrust laws arising from a settlement agreement entered into by EPNG, TransAmerican Natural Gas Corporation ("TransAmerican"), and others in 1990 to settle litigation then pending and other potential claims. The complaint, as amended, seeks actual damages of $1.5 billion and exemplary damages of $6 billion. EPNG is defending the matter in the State District Court of Dallas County, Texas. In April 1996, a former employee of TransAmerican filed a related case in Harris County, Texas, Vickroy E. Stone v. Godwin & Carlton, P.C., et al. (including EPNG), seeking indemnification and other damages in unspecified amounts relating to litigation consulting work allegedly performed for various entities, including EPNG, in cases involving TransAmerican. EPNG filed a motion for summary judgment in the TransAmerican case arguing that plaintiff's claims are barred by a prior release executed by TransAmerican, by statues of limitations, and by the final court judgment ending the original litigation in 1990. Following a hearing in January 1998, the court 8 108 granted summary judgment in EPNG's favor on TransAmerican's claims based on economic duress and negligent misrepresentation, but denied the motion as to the remaining claims. In March 1999, the Court ruled in EPNG's favor, denying TransAmerican's summary judgment motion which sought to dismiss EPNG's counterclaims. In April 1999, EPNG filed a motion for partial summary judgment as to TransAmerican's claims of fraud, tortious interference and civil conspiracy. That motion is currently set for hearing in June 1999. The TransAmerican trial is set to commence in September 1999. In February 1998, EPNG filed a motion for summary judgment in the Stone litigation arguing that all claims are baseless, barred by statutes of limitations, subject to executed releases, or have been assigned to TransAmerican. In June 1998, the court granted EPNG's motion in its entirety and dismissed all the remaining claims in the Stone litigation. In August 1998, the court denied Stone's motion for a new trial seeking reconsideration of that ruling. Stone has appealed the court's ruling to the Texas Court of Appeals in Houston, Texas. Based on information available at this time, management believes that the claims asserted against it in both cases have no factual or legal basis and that the ultimate resolution of these matters will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. In February 1998, the United States and the State of Texas filed in a United States District Court a Comprehensive Environmental Response, Compensation and Liability Act cost recovery action, United States v. Atlantic Richfield Co., et al., against fourteen companies including the following affiliates of EPEC: TGP, EPTPC, EPEC Corporation, EPEC Polymers, Inc. and the dissolved Petro-Tex Chemical Corporation, relating to the Sikes Disposal Pits Superfund Site ("Sikes") located in Harris County, Texas. Sikes was an unpermitted waste disposal site during the 1960s that accepted waste hauled from numerous Houston Ship Channel industries. The suit alleges that the former Tenneco Chemicals, Inc. and Petro-Tex Chemical Corporation arranged for disposal of hazardous substances at Sikes. TGP, EPTPC, EPEC Corporation and EPEC Polymers, Inc. are alleged to be derivatively liable as successors or as parent corporations. The suit claims that the United States and the State of Texas have expended over $125 million in remediating the site, and seeks to recover that amount plus interest. Other companies named as defendants include Atlantic Richfield Company, Crown Central Petroleum Corporation, Occidental Chemical Corporation, Exxon Corporation, Goodyear Tire & Rubber Company, Rohm & Haas Company, Shell Oil Company and Vacuum Tanks, Inc. These defendants have filed their answers and third-party complaints seeking contribution from twelve other entities believed to be PRPs at Sikes. Although factual investigation relating to Sikes is in very preliminary stages, the Company believes that the amount of material, if any, disposed at Sikes from the Tenneco Chemicals, Inc. or Petro-Tex Chemical Corporation facilities was small, possibly de minimis. However, the government plaintiffs have alleged that the defendants are each jointly and severally liable for the entire remediation costs and have also sought a declaration of liability for future response costs such as groundwater monitoring. While the outcome of this matter cannot be predicted with certainty, management does not expect this matter to have a material adverse effect on the Company's financial position, results of operations, or cash flows. TGP is a party in proceedings involving federal and state authorities regarding the past use by TGP of a lubricant containing PCBs in its starting air systems. TGP has executed a consent order with the EPA governing the remediation of certain of its compressor stations and is working with the relevant states regarding those remediation activities. TGP is also working with the Pennsylvania and New York environmental agencies to specify the remediation requirements at the Pennsylvania and New York stations. Remediation activities in Pennsylvania are complete with the exception of some long-term groundwater monitoring requirements. Remediation and characterization work at the compressor stations under its consent order with the EPA and the jurisdiction of the New York Department of Environmental Conservation is ongoing. Management believes that the ultimate resolution of these matters will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. In November 1988, the Kentucky environmental agency filed a complaint in a Kentucky state court, Commonwealth of Kentucky, Natural Resources and Environmental Protection Cabinet v. Tennessee Gas Pipeline Company, alleging that TGP discharged pollutants into the waters of the state without a permit and disposed of PCBs without a permit. The agency sought an injunction against future discharges, sought an order to remediate or remove PCBs, and sought a civil penalty. TGP has entered into agreed orders with the 9 109 agency to resolve many of the issues raised in the original allegations, has received water discharge permits for its Kentucky compressor stations from the agency, and continues to work to resolve the remaining issues. The relevant Kentucky compressor stations are scheduled to be characterized and remediated under the consent order with the EPA. Management believes that the resolution of this issue will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. A number of subsidiaries of EPEC, both wholly and partially owned, have been named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the false claims act. Generally, the complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Indian lands, thereby depriving the U.S. Government of royalties. In April 1999, the U.S. Government filed a notice that it does not intend to intervene in these actions. The Company believes the complaint to be without merit. The Company is a named defendant in numerous lawsuits and a named party in numerous governmental proceedings arising in the ordinary course of business. While the outcome of such lawsuits or other proceedings against the Company cannot be predicted with certainty, management currently does not expect these matters to have a material adverse effect on the Company's financial position, results of operations, or cash flows. Environmental The Company is subject to extensive federal, state, and local laws and regulations governing environmental quality and pollution control. These laws and regulations require the Company to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of March 31, 1999, the Company had reserves of approximately $252 million for expected environmental costs. In addition, the Company estimates that its subsidiaries will make capital expenditures for environmental matters of approximately $6 million for the remainder of 1999. Capital expenditures are expected to range from approximately $84 million to $109 million in the aggregate for the years 2000 through 2007. These expenditures primarily relate to compliance with air regulations and, to a lesser extent, control of water discharges. Since 1988, TGP has been engaged in an internal project to identify and deal with the presence of PCBs and other substances of concern, including substances on the EPA List of Hazardous Substances, at compressor stations and other facilities operated by both its interstate and intrastate natural gas pipeline systems. While conducting this project, TGP has been in frequent contact with federal and state regulatory agencies, both through informal negotiation and formal entry of consent orders, to assure that its efforts meet regulatory requirements. In May 1995, following negotiations with its customers, TGP filed with FERC a Stipulation and Agreement (the "Environmental Stipulation") that establishes a mechanism for recovering a substantial portion of the environmental costs identified in the internal project. The Environmental Stipulation was effective July 1, 1995. As of March 31, 1999, all amounts have been collected under the Environmental Stipulation. Refunds may be required to the extent actual eligible expenditures are less than estimated eligible expenditures used to determine amounts to be collected under the Environmental Stipulation. The Company and certain of its subsidiaries have been designated, have received notice that they could be designated, or have been asked for information to determine whether they could be designated as a PRP with respect to 32 sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund) or state equivalents. The Company has sought to resolve its liability as a PRP with respect to these Superfund sites through indemnification by third parties and/or settlements which provide for payment of the Company's allocable share of remediation costs. Since the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases the Company has asserted a defense to any liability, the Company's estimate of its share of remediation costs could change. Moreover, liability under the federal Superfund statute is joint and 10 110 several, meaning that the Company could be required to pay in excess of its pro rata share of remediation costs. The Company's understanding of the financial strength of other PRPs has been considered, where appropriate, in its determination of its estimated liability as described herein. The Company presently believes that the costs associated with the current status of such other entities as PRPs at the Superfund sites referenced above will not have a material adverse effect on the Company's financial position, results of operations, or cash flows. The Company has initiated proceedings against its historic liability insurers seeking payment or reimbursement of costs and liabilities associated with environmental matters. In these proceedings, the Company contends that certain environmental costs and liabilities associated with various entities or sites, including costs associated with former operating sites, must be paid or reimbursed by certain of its historic insurers. The proceedings are in the discovery stage, and it is not yet possible to predict the outcome. It is possible that new information or future developments could require the Company to reassess its potential exposure related to environmental matters. The Company may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from current or discontinued operations, could result in substantial costs and liabilities in the future. As such information becomes available, or other relevant developments occur, related accrual amounts will be adjusted accordingly. While there are still uncertainties relating to the ultimate costs which may be incurred, based upon the Company's evaluation and experience to date, the Company believes the recorded reserve is adequate. For a further discussion of other environmental matters, see Legal Proceedings above. Other than the items discussed above, management is not aware of any other commitments or contingent liabilities which would have a material adverse effect on the Company's financial condition, results of operations, or cash flows. 5. SEGMENT INFORMATION
SEGMENTS FOR THE QUARTER ENDED MARCH 31, 1999 -------------------------------------------------------------------- TENNESSEE EL PASO EL PASO EL PASO EL PASO GAS NATURAL FIELD ENERGY ENERGY PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL --------- ------- -------- --------- ------------- ------- (IN MILLIONS) Revenues from external customers....... $ 201 $ 118 $ 74 $1,084 $ 17 $ 1,494 Intersegment revenues.................. 7 -- 17 2 -- 26 Operating income (loss)................ 103 56 10 5 (16) 158 EBIT................................... 113 56 16 8 3 196 Segment assets......................... 4,887 1,728 1,459 968 1,029 10,071
SEGMENTS FOR THE QUARTER ENDED MARCH 31, 1998 ------------------------------------------------------------------- TENNESSEE EL PASO EL PASO EL PASO EL PASO GAS NATURAL FIELD ENERGY ENERGY PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL --------- ------- -------- --------- ------------- ------ (IN MILLIONS) Revenues from external customers........ $ 203 $ 114 $ 59 $1,227 $ 12 $1,615 Intersegment revenues................... 9 1 9 4 -- 23 Operating income (loss)................. 94 52 20 -- (7) 159 EBIT.................................... 98 52 24 -- 2 176 Segment assets.......................... 5,137 1,757 916 536 653 8,999
11 111 The reconciliations of EBIT to income before income taxes, minority interest, and cumulative effect of accounting change are presented below for the quarters ended March 31:
1999 1998 ----- ----- (IN MILLIONS) Total EBIT for reportable segments.......................... $196 $176 Corporate expenses, net..................................... (6) (13) Interest and debt expense................................... (73) (64) ---- ---- Income before income taxes, minority interest, and cumulative effect of accounting change.................... $117 $ 99 ==== ====
6. FINANCING TRANSACTIONS In February 1999, DeepTech International, Inc. retired its 11% senior promissory notes due 2000 in the amount of $16 million. The average interest rate of short-term borrowings was 5.1% and 5.8% at March 31, 1999 and December 31, 1998, respectively. The Company had short-term borrowings, including current maturities of long-term debt, at March 31, 1999, and December 31, 1998, as follows:
1999 1998 ----- ---- (IN MILLIONS) EPEC revolving credit facility.............................. $ 350 $350 Commercial paper............................................ 694 340 Other credit facilities..................................... 130 60 Current maturities of long-term debt........................ 62 62 Less amount reclassified as long-term debt.................. (500) -- ----- ---- $ 736 $812 ===== ====
In May 1999, EPEC issued $500 million aggregate principal amount of 6.75% Senior Notes due 2009. Proceeds of approximately $496 million, net of issuance costs, were used to repay approximately $350 million of outstanding debt under EPEC's revolving credit facility and the remainder was used to repay commercial paper. As a result of this transaction, $500 million of short-term borrowings has been reclassified and reflected as long-term debt at March 31, 1999. 7. PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment at March 31, 1999, and December 31, 1998, consisted of the following:
1999 1998 ------ ------ (IN MILLIONS) Property, plant, and equipment, at cost..................... $6,336 $6,285 Less accumulated depreciation and depletion................. 1,619 1,546 ------ ------ 4,717 4,739 Additional acquisition cost assigned to utility plant, net of accumulated amortization............................... 2,474 2,481 ------ ------ Total property, plant, and equipment, net................... $7,191 $7,220 ====== ======
Current FERC policy does not permit the Company to recover amounts in excess of original cost allocated in purchase accounting to its regulated operations through rates. 12 112 8. EARNINGS PER SHARE The computation of basic and diluted earnings per common share amounts are presented below for the quarters ended March 31.
1999 1998 --------------------- --------------------- BASIC DILUTED BASIC DILUTED -------- --------- ------- --------- (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) Income before cumulative effect of accounting change... $ 71 $ 71 $ 58 $ 58 Interest on trust preferred securities............... -- 3 -- -- ------ ------ ----- ----- Adjusted income before cumulative effect of accounting change................................. 71 74 58 58 Cumulative effect of accounting change, net of income tax............................................... (13) (13) -- -- ------ ------ ----- ----- Net income............................................. $ 58 $ 61 $ 58 $ 58 ====== ====== ===== ===== Average common shares outstanding...................... 116 116 116 116 Effect of diluted securities Restricted stock..................................... -- 2 -- 2 Stock options........................................ -- 2 -- 3 Trust preferred securities........................... -- 8 -- 1 ------ ------ ----- ----- Adjusted average common shares outstanding............. 116 128 116 122 ====== ====== ===== ===== Earnings per common share Adjusted income before cumulative effect of accounting change................................. $ 0.62 $ 0.58 $0.50 $0.48 Cumulative effect of accounting change, net of income tax............................................... (0.12) (0.10) -- -- ------ ------ ----- ----- Net income........................................... $ 0.50 $ 0.48 $0.50 $0.48 ====== ====== ===== =====
9. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED Accounting for Derivative Instruments and Hedging Activities In June 1998, Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, was issued by the Financial Accounting Standards Board to establish accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This pronouncement requires that an entity classify all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (i) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (ii) a hedge of the exposure to variable cash flows of a forecasted transaction, or (iii) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security or a foreign-currency-denominated forecasted transaction. The accounting for the changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. The standard is effective for all quarters in fiscal years beginning after June 15, 1999. The Company is currently evaluating the effects of this pronouncement. 13 113 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information contained in Item 2 updates, and should be read in conjunction with, information set forth in Part II, Items 7, 7A, and 8, in the Company's Annual Report on Form 10-K for the year ended December 31, 1998, in addition to the interim condensed consolidated financial statements and accompanying notes presented in Item 1 of this Quarterly Report on Form 10-Q. RECENT DEVELOPMENTS MERGER WITH SONAT INC. In March 1999, the Company announced it had entered into a definitive agreement to acquire Sonat Inc. ("Sonat"). The Company entered into the second amended and restated agreement and plan of merger effective as of March 13, 1999, (the "Merger Agreement") with Sonat pursuant to which Sonat will merge into the Company, and the Company will issue to Sonat stockholders one share of Company common stock for each share of Sonat common stock owned by them, and the Company's restated certificate of incorporation will be amended to authorize the issuance of up to 750 million shares of common stock and 50 million shares of preferred stock. The Company and Sonat are separately holding a special meeting of their stockholders on June 10, 1999, to consider and vote on a proposal to approve and adopt the Merger Agreement. If the Company's stockholders approve the Merger Agreement, the Company intends to account for the merger as a pooling of interests. If the Company's stockholders do not approve the Merger Agreement and Sonat's stockholders do, Sonat will instead merge with a subsidiary of the Company, and the Company will issue a fraction of a share of Company common stock and a fraction of a depositary share representing a fractional interest in a new series of senior voting preferred stock of the Company for each share of Sonat common stock. The Company and Sonat will complete the merger only if a number of conditions are satisfied or waived, including: - Sonat stockholders adopt the Merger Agreement; - no law or court order prohibits the transaction; - all waiting periods under federal antitrust laws applicable to the merger expire or terminate; - all other regulatory approvals are received without conditions that would have a material adverse effect on the financial condition, results of operations, or cash flows of the Company's and Sonat's combined businesses; and - attorneys for the Company and Sonat issue opinions that the merger is expected to be tax-free. However, we cannot assure you that the Company and Sonat will complete the merger even if all those conditions are satisfied. Sonat is a diversified energy holding company. It is engaged through its subsidiaries and joint ventures in domestic oil and natural gas exploration and production, transmission and storage of natural gas, and natural gas and power marketing. Sonat owns interests in approximately 14,000 miles of natural gas pipelines extending across the southeastern U.S. from Texas to South Carolina and Florida. Also, Sonat has interests in oil and gas producing properties in Louisiana, Texas, Oklahoma, Arkansas, Alabama, New Mexico and the Gulf of Mexico. Sonat owns approximately 1.6 trillion cubic feet equivalent of proved natural gas and oil reserves based on estimates as of December 31, 1998. RESULTS OF OPERATIONS Consolidated EBIT for the quarter ended March 31, 1999, increased 17 percent to $190 million from $163 million in the first quarter of 1998. Variances are discussed in the segment results below. 14 114 SEGMENT RESULTS
FIRST QUARTER ENDED MARCH 31, -------------- 1999 1998 ----- ----- (IN MILLIONS) EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES Tennessee Gas Pipeline...................................... $ 113 $ 98 El Paso Natural Gas......................................... 56 52 ----- ----- Regulated segments........................................ 169 150 El Paso Field Services...................................... 16 24 El Paso Energy Marketing.................................... 8 -- El Paso Energy International................................ 3 2 ----- ----- Non-regulated segments.................................... 27 26 Corporate expenses, net..................................... (6) (13) ----- ----- Total EBIT................................................ $ 190 $ 163 ===== =====
Tennessee Gas Pipeline
FIRST QUARTER ENDED MARCH 31, -------------- 1999 1998 ----- ----- (IN MILLIONS) Operating revenues.......................................... $ 208 $ 212 Operating expenses.......................................... (105) (118) Other -- net................................................ 10 4 ----- ----- EBIT...................................................... $ 113 $ 98 ===== =====
Operating revenues for the quarter ended March 31, 1999, were $4 million lower than for the same period of 1998 primarily due to lower GSR revenue in 1999, a favorable customer settlement in the first quarter of 1998, and lower miscellaneous operating revenue. The decrease was partially offset by the favorable resolution of a regulatory issue. Operating expenses for the quarter ended March 31, 1999, were $13 million lower than for the same period of 1998 primarily due to lower system fuel costs associated with operating efficiencies related to lower throughput levels, the favorable resolution of certain regulatory issues and lower operating expenses. Other -- net for the quarter ended March 31, 1999, was $6 million higher than for the same period of 1998 primarily due to the favorable resolution of regulatory and contractual issues and higher earnings from equity investments. 15 115 El Paso Natural Gas
FIRST QUARTER ENDED MARCH 31, ------------- 1999 1998 ---- ---- (IN MILLIONS) Operating revenues.......................................... $118 $115 Operating expenses.......................................... (62) (63) ---- ---- EBIT...................................................... $ 56 $ 52 ==== ====
Operating revenues for the quarter ended March 31, 1999, were $3 million higher than for the same period of 1998 primarily due to an increase in non-traditional revenues including revenues from the sale of capacity to Dynegy. El Paso Field Services
FIRST QUARTER ENDED MARCH 31, ------------- 1999 1998 ---- ---- (IN MILLIONS) Gathering and treating margin............................... $ 40 $ 39 Processing margin........................................... 9 14 Other margin................................................ -- 2 ---- ---- Total gross margin................................ 49 55 Operating expenses.......................................... (39) (35) Other -- net................................................ 6 4 ---- ---- EBIT...................................................... $ 16 $ 24 ==== ====
Total gross margin for the quarter ended March 31, 1999, was $6 million lower than for the same period of 1998 primarily due to a decrease in the processing margin. The decrease resulted from lower liquids prices during the first quarter of 1999 compared to the same period of 1998. The slight increase in the gathering and treating margin primarily resulted from higher volumes attributable to the global compression project which was completed in September 1998. This increase was offset by lower volumes attributable to the sale of the natural gas gathering and treating assets in the Anadarko Basin in September 1998. Operating expenses for the quarter ended in March 31, 1999, were $4 million higher than for the same period of 1998 primarily due to an increase in amortization expense attributable to the acquisition of DeepTech International Inc. Other -- net for the quarter ended March 31, 1999, was $2 million higher than for the same period of 1998 due to additional earnings from equity investments primarily attributable to the acquisition of DeepTech International Inc. 16 116 El Paso Energy Marketing
FIRST QUARTER ENDED MARCH 31, ------------- 1999 1998 ---- ---- (IN MILLIONS) Natural gas margin.......................................... $ 17 $ 6 Power margin................................................ 2 7 ---- ---- Total gross margin................................ 19 13 Operating expenses.......................................... (14) (13) Other -- net................................................ 3 -- ---- ---- EBIT...................................................... $ 8 $ -- ==== ====
Total gross margin for the quarter ended March 31, 1999, was $6 million higher than for the same period of 1998. The increase in the natural gas margin was primarily due to the income recognition from long-term natural gas transactions closed during the quarter. The decrease in the power margin was largely due to the first quarter 1998 income recognition from electric power transactions, partially offset by the contribution from power generation facilities acquired in December 1998. Operating expenses for the quarter ended March 31, 1999, were $1 million higher than for the same period of 1998 primarily due to expenses associated with acquired power generation facilities. Other -- net for the quarter ended March 31, 1999, was $3 million higher than for the same period of 1998 primarily due to additional earnings from the acquisition of a 50 percent ownership interest in CE Generation LLC in March 1999. El Paso Energy International
FIRST QUARTER ENDED MARCH 31, ---------------- 1999 1998 ----- ----- (IN MILLIONS) Operating revenues.......................................... $ 17 $ 12 Operating expenses.......................................... (33) (19) Other -- net................................................ 19 9 ---- ---- EBIT...................................................... $ 3 $ 2 ==== ====
Operating revenues for the quarter ended March 31, 1999, were $5 million higher than for the same period of 1998 primarily due to the consolidation for financial reporting purposes of the Manaus Power project in May 1998. Operating expenses for the quarter ended March 31, 1999, were $14 million higher than for the same period of 1998 due to the consolidation of the Manaus Power project and an increase in general and administrative expenses primarily attributable to higher project development costs reflecting increased project-related activities. Other -- net for the quarter ended March 31, 1999, was $10 million higher than for the same period of 1998 primarily due to higher earnings from equity investments. Corporate expenses, net Net corporate expenses for the quarter ended March 31, 1999, were $7 million lower than for the same period of 1998 primarily due to lower costs related to the Company's employee incentive plans and lower benefits costs. 17 117 INTEREST AND DEBT EXPENSE Interest and debt expense for the quarter ended March 31, 1999, was $9 million higher than for the same period of 1998 primarily due to increased borrowings used to fund acquisitions, capital expenditures, and other investing expenditures. INCOME TAX EXPENSE The effective tax rate for the quarter ended March 31, 1999, was lower than the rate for the same period of 1998 primarily as a result of increased consolidated foreign income subject to foreign tax rates different than U.S. tax rates and increased equity income from unconsolidated foreign affiliates recorded net of foreign income taxes for which no provision for U.S. income tax is required. LIQUIDITY AND CAPITAL RESOURCES CASH FROM OPERATING ACTIVITIES Net cash provided by operating activities was $21 million higher for the quarter ended March 31, 1999, compared to the same period of 1998. The increase was primarily attributable to a take-or-pay refund to EPNG customers in February 1998 and other working capital changes. The increase was partially offset by net income tax refunds received in 1998 and non-working capital changes including lower GSR collections in 1999. CASH FROM INVESTING ACTIVITIES Net cash used in investing activities was $567 million for the quarter ended March 31, 1999. Expenditures related to joint ventures and equity investments were primarily for the acquisition of the 50 percent ownership interest in CE Generation LLC, as well as the acquisition of a 51 percent ownership interest in the East Asia Power project. Other investment activity included the acquisition of EnCap. Internally generated funds, supplemented by other financing activities, were used to fund these expenditures. Future funding for capital expenditures, acquisitions, and other investing expenditures is expected to be provided by internally generated funds, commercial paper issuances, available capacity under existing credit facilities, and/or the issuance of other long-term debt, trust securities, or equity. CASH FROM FINANCING ACTIVITIES Net cash provided by financing activities was $436 million for the quarter ended March 31, 1999. Short-term borrowings, supplemented by internally generated funds, were used to fund capital and equity investments, retire long-term debt, pay dividends, and for other corporate purposes. The following table reflects quarterly dividends declared and paid on EPEC's common stock:
AMOUNT PER DECLARATION DATE COMMON SHARE PAYMENT DATE TOTAL AMOUNT ---------------- ------------ ------------ ------------- (IN MILLIONS) October 22, 1998....................... $0.19125 January 4, 1999 $22 January 21, 1999....................... $0.20000 April 1, 1999 $23
In April 1999, the board of directors of EPEC declared a quarterly dividend of $0.20 per share on EPEC's common stock, payable on July 1, 1999, to stockholders of record on June 4, 1999. Also during the first quarter of 1999, quarterly dividends of $6 million were paid on the 8 1/4% cumulative preferred stock, series A of EPTPC. Future funding for long-term debt retirements, dividends, and other financing expenditures is expected to be provided by internally generated funds, commercial paper issuances, available capacity under existing credit facilities, and/or the issuance of other long-term debt, trust securities, or equity. 18 118 At March 31, 1999, the Company had approximately $450 million available under its revolving credit facilities. The availability of borrowings under the Company's credit agreements is subject to certain specified conditions, which management believes it currently meets. In May 1999, EPEC issued $500 million aggregate principal amount of 6.75% Senior Notes due 2009. Proceeds of approximately $496 million, net of issuance costs, were used to repay approximately $350 million of outstanding debt under EPEC's revolving credit facility and the remainder was used to repay commercial paper. As a result of this transaction, $500 million of short-term debt has been reclassified and reflected as long-term debt at March 31, 1999. COMMITMENTS AND CONTINGENCIES See Note 4, which is incorporated herein by reference. OTHER PPN POWER PROJECT In March 1999, the Company signed a sale and purchase agreement, subject to the project lenders' consent, to acquire a 26 percent interest in a $295 million power plant in Tamil Nadu, India. The project consists of a 346 megawatt combined cycle power plant which will serve as a base load facility and sell power to the state-owned Tamil Nadu Electricity Board under a thirty-year power purchase agreement. Construction began in January 1999, and operations are expected to commence in early 2001. The transaction is expected to close before the end of the second quarter of 1999. YEAR 2000 The Company has established an executive steering committee and a project team to coordinate the phases of its Year 2000 project to assure that the Company's key automated systems, equipment, and related processes will remain functional through the year 2000. Those phases are: (i) awareness; (ii) assessment; (iii) remediation; (iv) testing; (v) implementation of the necessary modifications and (vi) contingency planning. In recognition of the importance of Year 2000 issues and their potential impact to the Company, the initial phase of the Year 2000 project involved the establishment of a company-wide awareness program. The awareness program is directed by the executive steering committee and project team and includes participation of senior management in each core business area. The awareness phase is substantially completed, although the Company will continually update awareness efforts for the duration of the Year 2000 project. The Company's assessment phase consists of conducting a company-wide inventory of its key automated systems and related processes, analyzing and assigning levels of criticality to those systems and processes, identifying and prioritizing resource requirements, developing validation strategies and testing plans, and evaluating business partner relationships. The portion of the assessment phase related to internally developed computer applications, hardware and equipment, third-party-developed software, and embedded chips is substantially complete. The assessment phase of the project, among other things, involves efforts to obtain representations and assurances from third parties, including third party vendors, that their hardware and equipment products, embedded chip systems, and software products being used by or impacting the Company are or will be modified to be Year 2000 compliant. To date, the responses from such third parties, although generally encouraging, are inconclusive. As a result, the Company cannot predict the potential consequences if these or other third parties or their products are not Year 2000 compliant. The Company continues to evaluate the exposure associated with such business partner relationships. The remediation phase involves converting, modifying, replacing or eliminating key automated systems identified in the assessment phase. The testing phase involves the validation of the identified key automated systems. The Company is utilizing test tools and written test procedures to document and validate, as 19 119 necessary, its unit, system, integration and acceptance testing. The Company estimates that approximately one-fourth of the work of these phases remains, and expects each to be substantially completed by mid-1999. The implementation phase involves placing the converted or replaced key automated systems into operation. In some cases, this phase will also involve the implementation of contingency plans needed to support business functions and processes that may be interrupted by Year 2000 failures that are outside of the Company's control. The Company has completed more than three-fourths of the implementation phase, which is expected to be substantially completed by mid-1999. The contingency planning phase consists of developing a risk profile of the Company's critical business processes and then providing for actions the Company will pursue to keep such processes operational in the event of Year 2000 disruptions. The focus of such contingency planning is on prompt response to any Year 2000 events, and a plan for subsequent resumption of normal operations. The plan is expected to assess the risk of a significant failure to critical processes performed by the Company, and to address the mitigation of those risks. The plan will also consider any significant failures related to the most reasonably likely worst case scenario, discussed below, as they may occur. In addition, the plan is expected to factor in the severity and duration of the impact of a significant failure. The Company plans to have its contingency plan completed by mid-1999. The Year 2000 contingency plan will continue to be modified and adjusted throughout the year as additional information becomes available. The goal of the Year 2000 project is to ensure that all of the critical systems and processes which are under the Company's direct control remain functional. Certain systems and processes may be interrelated with or dependent upon systems outside the Company's control. However, systems within the Company's control may also have unpredicted problems. Accordingly, there can be no assurance that significant disruptions will be avoided. The Company's present analysis of its most reasonably likely worst case scenario for Year 2000 disruptions includes Year 2000 failures in the telecommunications and electricity industries, as well as interruptions from suppliers that might cause disruptions in the Company's operations, thus causing temporary financial losses and an inability to deliver products and services to customers. Virtually all of the natural gas transported through the Company's interstate pipelines is owned by third parties. Accordingly, failures of natural gas producers to be ready for the Year 2000 could significantly disrupt the flow of product to the Company's customers. In many cases, the producers have no direct contractual relationship with the Company, and the Company relies on its customers to verify the Year 2000 readiness of the producers from whom they purchase natural gas. Since most of the Company's revenues from the delivery of natural gas are based upon fees paid by its customers for the reservation of capacity, and not based upon the volume of actual deliveries, short term disruptions in deliveries caused by factors beyond the Company's control should not have a significant financial impact on the Company, although it could cause operational problems for the Company's customers. Longer-term disruptions, however, could materially impact the Company's results of operations, financial condition, and cash flows. While the Company owns or controls most of its domestic facilities and projects, nearly all of the Company's international investments have been made in conjunction with unrelated third parties. In many cases, the operators of such international facilities are not under the sole or direct control of the Company. As a consequence, the Year 2000 programs instituted at some of the international facilities may be different from the Year 2000 program implemented by the Company domestically, and the party responsible for the results of such program may not be under the direct or indirect control of the Company. In addition, the "non-controlled" programs may not provide the same degree of communication, documentation and coordination as the Company achieves in its domestic Year 2000 program. Moreover, the regulatory and legal environment in which such international facilities operate makes analysis of possible disruption and associated financial impact difficult. Many foreign countries appear to be substantially behind the United States in addressing potential Year 2000 disruption of critical infrastructure and in developing a framework governing the reporting requirements and relative liabilities of business entities. Accordingly, the Year 2000 risks posed by international operations as a whole are different than those presented domestically. As part of its Year 2000 effort, the Company is assessing the differences between the non-controlled programs and its domestic Year 2000 project, and has formulated and instituted a program for identifying such risks and preparing a response to such risks. While the Company believes that most of the international facilities in which it has significant 20 120 investments are addressing Year 2000 issues in an adequate manner, it is possible that some of them may experience significant Year 2000 disruption, and that the aggregate effect of problems experienced at multiple international locations may be material and adverse. The Company is incorporating this possibility into the relevant contingency plans. While the total cost of the Company's Year 2000 project continues to be evaluated, the Company estimates that the costs remaining to be incurred in 1999 and 2000 associated with assessing, remediating and testing internally developed computer applications, hardware and equipment, embedded chip systems, and third-party-developed software will be between $12 million and $19 million. Of these estimated costs, the Company expects between $5 million and $9 million to be capitalized and the remainder to be expensed. As of March 31, 1999, the Company has incurred expenses of approximately $8 million and has capitalized costs of approximately $2 million. The Company has previously only traced incremental expenses related to its Year 2000 project. This means that the costs of the Year 2000 project related to salaried employees of the Company, including their direct salaries and benefits, are not available, and have not been included in the estimated costs of the project. Since the earlier phases of the project mostly involved work performed by such salaried employees, the costs expended to date do not reflect the percentage completion of the project. The Company anticipates that it will expend most of the costs reported above in the remediation, implementation and contingency planning phases of the project. As described herein, the Company and Sonat have entered into an agreement which, if approved, will result in the merger of the Company and Sonat. If the merger is consummated, Sonat's Year 2000 risks, liabilities and expenses will be assumed by the Company. Based on its due diligence investigation in connection with the merger, the Company is not aware of any material Year 2000 risks, liabilities, or expenses that are not disclosed in Sonat's filings with the U.S. Securities and Exchange Commission. It is possible the Company may need to reassess its estimate of Year 2000 costs in the event the Company completes an acquisition of, or makes a material investment in, substantial facilities or another business entity. Although the Company does not expect the costs of its Year 2000 project to have a material adverse effect on its financial position, results of operations, or cash flows, based on information available at this time the Company cannot conclude that disruption caused by internal or external Year 2000 related failures will not have such an effect. Specific factors which might affect the success of the Company's Year 2000 efforts and the frequency or severity of a Year 2000 disruption or the amount of expense include the failure of the Company or its outside consultants to properly identify deficient systems, the failure of the selected remedial action to adequately address the deficiencies, the failure of the Company or its outside consultants to complete the remediation in a timely manner (due to shortages of qualified labor or other factors), the failure of other parties to joint ventures in which the Company is involved to meet their obligations, both financial and operational, under the relevant joint venture agreements to remediate assets used by the joint venture, unforeseen expenses related to the remediation of existing systems or the transition to replacement systems, the failure of third parties to become Year 2000 compliant or to adequately notify the Company of potential noncompliance and the effects of any significant disruption at international facilities in which the Company has significant investments. The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the intention to comply fully with the Year 2000 Information and Readiness Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat, 2386, signed into law October 19, 1998. All statements made herein shall be construed within the confines of that Act. To the extent that any reader of the above Year 2000 Readiness Disclosure is other than an investor or potential investor in the Company's -- or an affiliate's -- equity or debt securities, this disclosure is made for the SOLE PURPOSE of communicating or disclosing information aimed at correcting, helping to correct and/or avoiding Year 2000 failures. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED See Note 9, which is incorporated herein by reference. 21 121 CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995. This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, the Company cautions that, while such assumptions or bases are believed to be reasonable and are made in good faith, assumed facts or bases almost always vary from the actual results, and the differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, the Company or its management expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and is believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. The words "believe," "expect," "estimate," "anticipate" and similar expressions may identify forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include increasing competition within the Company's industry, the timing and extent of changes in commodity prices for natural gas and power, uncertainties associated with acquisitions and joint ventures, potential environmental liabilities, potential contingent liabilities and tax liabilities related to the Company's acquisitions, political and economic risks associated with current and future operations in foreign countries, conditions of the equity and other capital markets during the periods covered by the forward-looking statements, and other risks, uncertainties and factors, including the effect of the Year 2000 date change, discussed more completely in the Company's other filings with the U.S. Securities and Exchange Commission, including its Annual Report on Form 10-K for the year ended December 31, 1998. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in the Company's Annual Report on Form 10-K for the year ended December 31, 1998, in addition to the interim consolidated financial statements, accompanying notes, and Management's Discussion and Analysis of Financial Condition and Results of Operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There are no material changes in market risks faced by the Company from those reported in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. 22 122 PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS See Part I, Financial Information, Note 4, which is incorporated herein by reference. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS None. ITEM 5. OTHER INFORMATION None. ITEM. 6. EXHIBITS AND REPORTS ON FORM 8-K a. Exhibits Each exhibit identified below is filed as part of this report. Exhibits designated with a "+" constitute a management contract or compensatory plan or arrangement required to be filed as an exhibit to this report.
EXHIBIT NUMBER DESCRIPTION ------- ----------- +10.E.1 -- Amendment No. 1, effective March 9, 1999, to the 1995 Compensation Plan for Non-Employee Directors, Amended and Restated effective as of August 1, 1998. 27 -- Financial Data Schedule.
Undertaking The undersigned hereby undertakes, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the U.S. Securities and Exchange Commission, upon request, all constituent instruments defining the rights of holders of long-term debt of EPEC and its consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of the total consolidated assets of EPEC and its consolidated subsidiaries. b. Reports on Form 8-K EPEC filed a report under Item 5 and Item 7 on Form 8-K, dated March 15, 1999, with respect to the Sonat Merger Agreement. In addition, EPEC filed a report under Item 5 and Item 7 on Form 8-K and Form 8-K/A dated April 23, 1999 and April 30, 1999, respectively, disclosing preliminary unaudited pro forma financial information of EPEC and Sonat giving effect to the proposed merger. EPEC filed a report under Item 5 and Item 7 on Form 8-K, dated May 10, 1999 with respect to the issuance of $500 million aggregate principal amount of 6.75% Senior Notes due 2009. 23 123 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 thereunto duly authorized. EL PASO ENERGY CORPORATION Date: May 12, 1999 /s/ H. BRENT AUSTIN ------------------------------------ H. Brent Austin Executive Vice President and Chief Financial Officer Date: May 12, 1999 /s/ JEFFREY I. BEASON ------------------------------------ Jeffrey I. Beason Vice President and Controller (Chief Accounting Officer) 24 124 Item 7. Financial Statements and Exhibits. Exhibit No. Description - ----------- ----------- 23 Consent of PricewaterhouseCoopers LLP SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, Sonat Inc. has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. SONAT INC. By /s/ William A. Smith ------------------------------- William A. Smith Executive Vice President and General Counsel July 6, 1999 125 EXHIBIT INDEX Exhibit No. Description - ---------- ----------- 23 Consent of PricewaterhouseCoopers LLP EX-23 2 CONSENT OF PRICEWATERHOUSECOOPERS LLP 1 EXHIBIT 23 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the registration statement of Sonat Inc. (the "Company") on Form S-3 (File No. 333-62383) and the registration statements of the Company on Form S-8 (File Nos. 33-64367 and 33-50142) of our report dated March 9, 1999 relating to El Paso Energy Corporation's consolidated financial statements as of December 31, 1998 and 1997, and for each of the three years in the period ended December 31, 1998, which appears in the Company's Current Report on Form 8-K dated July 6, 1999. PricewaterhouseCoopers LLP Houston, Texas July 6, 1999 -----END PRIVACY-ENHANCED MESSAGE-----