-----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, DsmNNuY/WC28LNZZE30yrwf37xO/f3Qtz1//2Zgf0Gdl59iRHyUga6AnRoMat2KT Ky0Q8GGgx/zFLlGFVA2TSA== 0000950129-03-002803.txt : 20030515 0000950129-03-002803.hdr.sgml : 20030515 20030515152302 ACCESSION NUMBER: 0000950129-03-002803 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20030331 FILED AS OF DATE: 20030515 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EL PASO CGP CO CENTRAL INDEX KEY: 0000021267 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 741734212 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-07176 FILM NUMBER: 03704525 BUSINESS ADDRESS: STREET 1: EL PASO BUILDING STREET 2: 1001 LOUISIANA STREET CITY: HOUSTON STATE: TX ZIP: 77095 BUSINESS PHONE: 7134202131 MAIL ADDRESS: STREET 1: 1001 LOUISIANA STREET CITY: HOUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: COASTAL CORP DATE OF NAME CHANGE: 19920703 FORMER COMPANY: FORMER CONFORMED NAME: COASTAL STATES GAS CORP DATE OF NAME CHANGE: 19800113 10-Q 1 h04921e10vq.txt EL PASO CGP COMPANY - MARCH 31, 2003 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 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, 2003 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 1-7176 --------------------- EL PASO CGP COMPANY (Exact Name of Registrant as Specified in its Charter) DELAWARE 74-1734212 (State or Other Jurisdiction (I.R.S. Employer of Incorporation or Organization) Identification No.) EL PASO BUILDING 1001 LOUISIANA STREET HOUSTON, TEXAS 77002 (Address of Principal Executive Offices) (Zip Code)

Telephone Number: (713) 420-2600 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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [ ] No [X] 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 $1 per share. Shares outstanding on May 15, 2003: 1,000 EL PASO CGP COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- EL PASO CGP COMPANY TABLE OF CONTENTS
CAPTION PAGE ------- ---- PART I -- Financial Information Item 1. Financial Statements........................................ 1 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 22 Cautionary Statement Regarding Forward-Looking Statements... 31 Item 3. Quantitative and Qualitative Disclosures About Market Risk...................................................... 31 Item 4. Controls and Procedures..................................... 31 PART II -- Other Information Item 1. Legal Proceedings........................................... 33 Item 2. Changes in Securities and Use of Proceeds................... 33 Item 3. Defaults Upon Senior Securities............................. 33 Item 4. Submission of Matters to a Vote of Security Holders......... 33 Item 5. Other Information........................................... 33 Item 6. Exhibits and Reports on Form 8-K............................ 33 Signatures.................................................. 34 Certifications.............................................. 35
- --------------- Below is a list of terms that are common to our industry and used throughout this document: /d = per day Bbl = barrels BBtu = billion British thermal units MBbls = thousand barrels Mcf = thousand cubic feet MMBtu = million British thermal units MMcf = million cubic feet

When we refer to natural gas and oil in "equivalents," we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch. When we refer to "us", "we", "our", "ours", or "El Paso CGP", we are describing El Paso CGP Company and/or our subsidiaries. i PART I -- FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS EL PASO CGP COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME (IN MILLIONS) (UNAUDITED)
QUARTERS ENDED MARCH 31, ---------------- 2003 2002 ------ ------ Operating revenues.......................................... $2,918 $2,555 ------ ------ Operating expenses Cost of products and services............................. 2,105 1,276 Operation and maintenance................................. 320 328 Depreciation, depletion and amortization.................. 150 197 Ceiling test charges...................................... -- 10 (Gain) loss on long-lived assets.......................... 304 (11) Taxes, other than income taxes............................ 33 35 ------ ------ 2,912 1,835 ------ ------ Operating income............................................ 6 720 Earnings from unconsolidated affiliates..................... 42 51 Minority interest in consolidated subsidiaries.............. 2 (50) Other income................................................ 14 18 Other expenses.............................................. (6) (4) Interest and debt expense................................... (99) (107) Affiliated interest expense, net............................ (7) (3) Return on preferred interests of consolidated subsidiaries.............................................. (7) (10) ------ ------ Income (loss) before income taxes........................... (55) 615 Income taxes................................................ (18) 202 ------ ------ Income (loss) from continuing operations.................... (37) 413 Discontinued operations, net of income taxes................ 3 (19) Cumulative effect of accounting changes, net of income taxes..................................................... (21) -- ------ ------ Net income (loss)........................................... $ (55) $ 394 ====== ======
See accompanying notes. 1 EL PASO CGP COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE AMOUNTS) (UNAUDITED)
MARCH 31, DECEMBER 31, 2003 2002 --------- ------------ ASSETS Current assets Cash and cash equivalents................................. $ 191 $ 128 Accounts and notes receivable Customers, net of allowance of $39 in 2003 and $37 in 2002.................................................. 771 1,537 Affiliates............................................. 618 545 Other.................................................. 217 200 Inventory................................................. 715 697 Assets from price risk management activities.............. 103 122 Other..................................................... 281 432 ------- ------- Total current assets.............................. 2,896 3,661 ------- ------- Property, plant and equipment, at cost Natural gas and oil properties, at full cost.............. 7,669 7,479 Pipelines................................................. 6,362 6,522 Refining, crude oil and chemical facilities............... 2,263 2,557 Power facilities.......................................... 458 460 Gathering and processing systems.......................... 272 279 Other..................................................... 93 92 ------- ------- 17,117 17,389 Less accumulated depreciation, depletion and amortization........................................... 7,629 7,259 ------- ------- Total property, plant and equipment, net.......... 9,488 10,130 ------- ------- Other assets Investments in unconsolidated affiliates.................. 1,551 1,544 Assets from price risk management activities.............. 915 956 Goodwill and other intangible assets, net................. 492 498 Other..................................................... 597 444 ------- ------- 3,555 3,442 ------- ------- Total assets...................................... $15,939 $17,233 ======= =======
See accompanying notes. 2 EL PASO CGP COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS -- (CONTINUED) (IN MILLIONS, EXCEPT SHARE AMOUNTS) (UNAUDITED)
MARCH 31, DECEMBER 31, 2003 2002 --------- ------------ LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities Accounts payable Trade.................................................. $ 392 $ 1,326 Affiliates............................................. 140 87 Other.................................................. 240 296 Short-term borrowings, including current maturities....... 371 369 Notes payable to affiliates............................... 2,033 2,374 Liabilities from price risk management activities......... 232 248 Other..................................................... 409 461 ------- ------- Total current liabilities......................... 3,817 5,161 ------- ------- Long-term debt.............................................. 4,991 4,985 ------- ------- Other Liabilities from price risk management activities......... 5 26 Deferred income taxes..................................... 1,732 1,753 Other..................................................... 435 355 ------- ------- 2,172 2,134 ------- ------- Commitments and contingencies Securities of subsidiaries Preferred interests of consolidated subsidiaries.......... 400 400 Minority interests of consolidated subsidiaries........... 114 253 ------- ------- 514 653 ------- ------- Stockholder's equity Common stock, par value $1 per share; authorized and issued 1,000 shares.................................... -- -- Additional paid-in capital................................ 1,502 1,339 Retained earnings......................................... 3,047 3,102 Accumulated other comprehensive loss...................... (104) (141) ------- ------- Total stockholder's equity........................ 4,445 4,300 ------- ------- Total liabilities and stockholder's equity........ $15,939 $17,233 ======= =======
See accompanying notes. 3 EL PASO CGP COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS) (UNAUDITED)
QUARTERS ENDED MARCH 31, -------------- 2003 2002 ----- ----- Cash flows from operating activities Net income (loss)......................................... $ (55) $ 394 Less income (loss) from discontinued operations, net of income taxes.......................................... 3 (19) ----- ----- Net income (loss) from continuing operations.............. (58) 413 Adjustments to reconcile net income (loss) to net cash from operating activities Non-cash gains from trading and power activities....... (22) (394) Depreciation, depletion and amortization............... 150 197 Ceiling test charges................................... -- 10 (Gain) loss on long-lived assets....................... 304 (11) Undistributed earnings of unconsolidated affiliates.... (19) (12) Deferred income tax benefit............................ (7) (58) Cumulative effect of accounting changes................ 21 -- Other non-cash income items............................ 30 22 Working capital changes................................ (90) 335 Non-working capital changes and other.................. (21) (114) ----- ----- Cash provided by continuing operations................. 288 388 Cash provided by discontinued operations............... 2 6 ----- ----- Net cash provided by operating activities......... 290 394 ----- ----- Cash flows from investing activities Additions to property, plant and equipment................ (375) (300) Purchases of interests in equity investments.............. (2) (76) Net proceeds from the sale of assets...................... 601 524 Net proceeds from the sale of investments................. 25 2 Net change in restricted cash............................. (43) 17 Net change in notes receivable from unconsolidated affiliates............................................. (115) 54 Other..................................................... (3) 30 ----- ----- Cash provided by continuing operations................. 88 251 Cash used in investing activities by discontinued operations............................................ (2) (4) ----- ----- Net cash provided by investing activities......... 86 247 ----- ----- Cash flows from financing activities Net repayments under commercial paper and short-term credit facilities...................................... -- (30) Net proceeds from the issuance of long-term debt.......... 288 -- Payments to retire long-term debt......................... (290) (431) Repayments of notes payable............................... -- (7) Net change in affiliated advances payable................. (316) (108) Other..................................................... 3 -- Contributions from discontinued operations................ 2 3 ----- ----- Net cash used in financing activities............. (313) (573) ----- ----- Increase in cash and cash equivalents....................... 63 68 Less increase in cash and cash equivalents related to discontinued operations................................ -- 2 ----- ----- Increase in cash and cash equivalents from continuing operations............................................. 63 66 Cash and cash equivalents Beginning of period....................................... 128 141 ----- ----- End of period............................................. $ 191 $ 207 ===== =====
See accompanying notes. 4 EL PASO CGP COMPANY CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (IN MILLIONS) (UNAUDITED)
QUARTERS ENDED MARCH 31, -------------- 2003 2002 ---- ----- Net income (loss)........................................... $(55) $ 394 ---- ----- Foreign currency translation adjustments.................... 40 -- Unrealized net gains (losses) from cash flow hedging activity Unrealized mark-to-market losses arising during period (net of income tax of $24 in 2003 and $70 in 2002)..... (44) (118) Reclassification adjustments for changes in initial value to settlement date (net of income tax of $22 in 2003 and $47 in 2002)....................................... 41 (84) ---- ----- Other comprehensive income (loss).................... 37 (202) ---- ----- Comprehensive income (loss)................................. $(18) $ 192 ==== =====
See accompanying notes. 5 EL PASO CGP COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. BASIS OF PRESENTATION We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles. You should read it along with our 2002 Form 10-K which includes a summary of our significant accounting policies and other disclosures. The financial statements as of March 31, 2003, and for the quarters ended March 31, 2003 and 2002, are unaudited. We derived the balance sheet as of December 31, 2002, from the audited balance sheet filed in our 2002 Form 10-K. In our opinion, we have made all adjustments, all of which are of a normal, recurring nature (except for the items discussed below and in Notes 2 through 5), to fairly present our interim period results. Due to the seasonal nature of our businesses, information for interim periods may not indicate the results of operations for the entire year. In addition, prior period information presented in these financial statements includes reclassifications which were made to conform to the current period presentation. These reclassifications have no effect on our previously reported net income or stockholder's equity. Significant Accounting Policies Update Our accounting policies are consistent with those discussed in our 2002 Form 10-K, except as follows: Accounting for Asset Retirement Obligations. On January 1, 2003, we adopted Statement of Financial Accounting Standard (SFAS) No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires that we record a liability for retirement and removal costs of long-lived assets used in our business. This liability is recorded at its estimated fair value, with a corresponding increase to property, plant and equipment. This asset is depreciated over the remaining useful life of the long-lived asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion and amortization expense in our income statement. In the first quarter of 2003, we recorded a charge as a cumulative effect of accounting change of approximately $21 million, net of income taxes related to our adoption of SFAS No. 143. We also recorded property, plant and equipment of $106 million and non-current retirement obligations of $156 million as of January 1, 2003. Our asset retirement obligations are associated with our natural gas and oil wells and related infrastructure in our Production segment and our natural gas storage wells in our Pipelines segment. We have obligations to plug wells when production on those wells is exhausted, and we abandon the wells. We currently forecast that these obligations will be met at various times over the next twenty-four years, based on the expected natural gas and oil contained in the wells and the estimated timing of plugging and abandoning the wells. The net asset retirement liability as of January 1, 2003 and March 31, 2003, reported in other non-current liabilities in our balance sheet, and the changes in the net liability for the quarter ended March 31, 2003, were as follows (in millions): Liability at January 1, 2003................................ $156 Liability settled in 2003................................... (25) Accretion expense in 2003................................... 3 Other....................................................... (1) ---- Net liability at March 31, 2003........................... $133 ====

Had we adopted SFAS No. 143 as of January 1, 2002, our non-current retirement liabilities would have been approximately $140 million as of January 1, 2002, and our income from continuing operations and net income for the quarter ended March 31, 2002, would have been lower by $2 million. Accounting for Costs Associated with Exit or Disposal Activities. On January 1, 2003, we adopted SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 requires that 6 we recognize costs associated with exit or disposal activities when they are incurred rather than when we commit to an exit or disposal plan. We recognized $7 million of employee severance costs, less income taxes of $2 million, in the first quarter of 2003, all of which had been paid as of March 31, 2003. We recorded these costs as operation and maintenance expenses in our income statement and impacted the results in our Merchant Energy segment. As we continue to evaluate our business activities and seek additional cost savings, we expect to incur additional charges that will be evaluated under this accounting standard. Accounting for Guarantees. On January 1, 2003, we adopted Financial Accounting Standards Board Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN No. 45 requires that we record a liability for all guarantees, including financial performance and fair value guarantees, issued after December 31, 2002, at their fair value when they are issued. There was no initial financial statement impact of adopting this standard. Accounting for Regulated Operations Our natural gas pipelines are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978. We discontinued the application of regulatory accounting principles under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation in 1996. SFAS No. 71 provides that rate regulated enterprises account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if those rates are designed to recover the costs of providing the regulated service and if it is reasonable to assume that those rates can be charged and collected. While our rates are designed to recover our costs, our ability to extend or re-market expiring contracts is highly dependent on competitive alternatives at the time these contracts are extended or expire. Currently, a substantial portion of our revenues are under contracts that are discounted at rates below the maximum rates. We will continue to evaluate the application of regulatory accounting principles based on on- going changes in the regulatory and economic environment and further actions in current and future rate cases or settlements. 2. DIVESTITURES During 2003, we completed or announced the sale of a number of assets as part of El Paso Corporation's (El Paso) 2003 Operational and Financial Plan. These sales transactions occurred in each of our business segments as follows:
PRE-TAX SEGMENT PROCEEDS GAIN (LOSS)(1) SIGNIFICANT ASSET AND INVESTMENT DIVESTITURES - ------- -------- -------------- --------------------------------------------- (IN MILLIONS) COMPLETED IN THE FIRST QUARTER Pipelines $ 43 $(1) - Panhandle gathering system located in Texas - 2.1 percent interest in Alliance pipeline and related assets Production 168 --(2) - Natural gas and oil properties located in western Canada, New Mexico, Oklahoma and the Gulf of Mexico Field Services 35 -- - Gathering systems located in Wyoming Merchant Energy 455 56 - Corpus Christi refinery - Florida petroleum terminals and tug and barge operations Other 59 -- - Coal reserves and properties in West Virginia, Virginia and Kentucky ---- --- $760 $55 ==== === ANNOUNCED TO DATE(3) Pipelines $ 10 $ 2 - Helium processing operations in Oklahoma Field Services 60 21 - Midstream assets in the Mid-Continent region
7
PRE-TAX SEGMENT PROCEEDS GAIN (LOSS)(1) SIGNIFICANT ASSET AND INVESTMENT DIVESTITURES - ------- -------- -------------- --------------------------------------------- (IN MILLIONS) Merchant Energy 339 12 - Petroleum asphalt operations and lease crude business - Eagle Point refinery and related pipeline assets(4) Other 3 (3) - Aircraft ---- --- $412 $32 ==== ===
- --------------- (1) Amounts do not include asset impairments recognized, if any, at the time we decide to sell the asset. See Note 4 for a discussion of impairments taken on long-lived assets. (2) We did not recognize gains or losses on these completed sales of natural gas and oil properties because individually they did not significantly alter the relationship between capitalized costs and proved reserves at the time they were sold. (3) Sales that have been announced, but not completed, are subject to customary regulatory approvals, final sale negotiations and other conditions and are estimates. (4) We have entered into a non-binding letter of intent to sell these assets for estimated net proceeds of $250 million. In the first quarter of 2003, we recognized an impairment of $350 million. See Note 4 for a discussion of this impairment. We evaluate potential asset sales each period to determine if any meet the criteria as held for sale or as discontinued operations under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. The more significant criteria we evaluate are whether: - Management, with the authority to approve the sale, commits to a plan to sell the asset; - The asset is available for immediate sale in its present condition; - An active program to locate a buyer and other actions required to complete the sale have been started; and - The sale of the asset is probable and is expected to be completed within one year. To the extent that all of these criteria as well as the other requirements of SFAS No. 144 are met, we classify an asset as held for sale or, if appropriate, discontinued operations. For example, El Paso's Board of Directors or a designated subcommittee of the Board of Directors is required to approve asset dispositions greater than specified thresholds. Unless specific approval is received by its Board of Directors or its designated subcommittee by the end of the period to commit to a plan to sell an asset, we would not classify it as held for sale or discontinued operations even if it is management's stated intent to sell the asset. In our balance sheet we classified several long-lived assets as held for sale, including Field Services' gathering systems located in Wyoming and Merchant Energy's petroleum asphalt operations and lease crude business and its Florida petroleum terminals and tug and barge operations. The total assets held for sale had net book values in property, plant and equipment of approximately $50 million as of March 31, 2003 and $134 million as of December 31, 2002. These assets were classified as other current assets as of March 31, 2003 and December 31, 2002, since we plan to sell them in the next twelve months. We continue to evaluate assets we may sell in the future. Recently, we announced that we intend to pursue a sale of our Aruba refinery and domestic power assets. These activities are in the early stages and no definitive agreements have been received or approved by El Paso's management or Board of Directors. We believe it is likely that a decision to sell these assets in the current economic environment will result in future impairments or losses. The amounts of the losses will be based on an estimate of the expected fair value of the assets as determined by market data that becomes available to us as the sales process proceeds. As of March 31, 2003, our net investment in the Aruba refinery was approximately $1.2 billion (excluding the Aruba coker facility which will have a carrying value, following its consolidation in the second quarter of 2003, of $0.4 billion). See Note 8 for a discussion of our consolidation of the Aruba coker facility. In March 2002, we sold natural gas and oil properties to El Paso and to third parties. Net proceeds from these sales were approximately $512 million. We did not recognize a gain or loss on these sales because 8 individually at the time these properties were sold these sales did not significantly alter the relationship between capitalized costs and proved reserves. 3. CEILING TEST CHARGES Under the full cost method of accounting for natural gas and oil properties, we perform quarterly ceiling tests to determine whether the carrying value of natural gas and oil properties exceeds the present value of future net revenues, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, net of related income tax effects. For the quarter ended March 31, 2002, we recorded ceiling test charges of $10 million for our Brazilian full cost pool, based upon the daily posted natural gas and oil prices as of March 31, 2002, adjusted for oilfield or natural gas gathering hub and wellhead price differences, as appropriate. We use financial instruments to hedge against the volatility of natural gas and oil prices. The impact of these hedges was considered in determining our ceiling test charges and will be factored into future ceiling test calculations. The charges for our international cost pools would not have changed had the impact of these hedges not been included in calculating our first quarter ceiling test charges since we do not significantly hedge our international production activities. 4. GAIN (LOSS) ON LONG-LIVED ASSETS Our gain (loss) on long-lived assets consists of net realized gains and losses on sales of long-lived assets and impairments of long-lived assets. During each of the quarters ended March 31, our gain (loss) on long-lived assets was as follows:
2003 2002 ----- ---- (IN MILLIONS) Net realized gain........................................... $ 55 $11 Asset impairments........................................... (359) -- ----- --- Gain (loss) on long-lived assets.......................... $(304) $11 ===== ===
Net Realized Gain Our net realized gain on sales of long-lived assets for the quarters ended March 31, 2003 and 2002, was $55 million and $11 million. Our 2003 gains were primarily related to the sales of the Corpus Christi refinery and the Florida petroleum terminals and tug and barge operations in our Merchant Energy segment. See Note 2 for a further discussion of these divestitures. Our 2002 gains were primarily related to the sale of pipeline expansion rights in our Pipelines segment. Asset Impairments We are required to test assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. One triggering event that may indicate an asset's carrying amount may not be recoverable is the expectation that it is more likely than not that we will sell or dispose of an asset before the end of its estimated useful life. Based on our intentions as of March 31, 2003, that we will dispose of some of our assets, we tested those assets for recoverability during the first quarter of 2003 that we believed would be more likely than not be sold. As a result of this assessment, we recognized an impairment of $350 million on our Eagle Point refinery and several of our chemical assets in our Merchant Energy segment. We also recorded impairment charges of approximately $9 million in the first quarter of 2003 which related to non-full cost assets in Canada in our Production segment. 9 5. DISCONTINUED OPERATIONS Coal Mining Operations In the latter part of 2002 and the first quarter of 2003, we sold our coal mining operations. These operations consisted of fifteen active underground and two surface mines located in Kentucky, Virginia and West Virginia. Our coal mining operations have been classified in other current assets and liabilities as discontinued operations in our financial statements for all periods. The summarized financial results of discontinued operations were as follows:
QUARTER ENDED MARCH 31, ------------- 2003 2002 ----- ----- (IN MILLIONS) Operating results: Revenues.................................................. $ 27 $ 67 Costs and expenses........................................ (23) (97) ---- ---- Income (loss) before income taxes......................... 4 (30) Income tax benefit........................................ (1) 11 ---- ---- Income (loss) from discontinued operations, net of income taxes.................................................. $ 3 $(19) ==== ====

DECEMBER 31, 2002 ------------- (IN MILLIONS) Financial position data: Assets of discontinued operations Accounts receivable.................................... $ 29 Inventory.............................................. 14 Property, plant and equipment, net..................... 46 Other.................................................. 17 ---- Total assets...................................... $106 ==== Liabilities of discontinued operations Accounts payable and other............................. $ 25 Environmental remediation reserve...................... 15 ---- Total liabilities................................. $ 40 ====
10 6. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES The following table summarizes the carrying value of our trading and non-trading price risk management assets and liabilities as of March 31, 2003 and December 31, 2002:
MARCH 31, DECEMBER 31, 2003 2002 --------- ------------ (IN MILLIONS) Net assets (liabilities) Trading contracts(1)...................................... $ (19) $ (18) Non-trading contracts Derivatives designated as hedges....................... (167) (146) Other derivatives...................................... 967 968 ----- ----- Net assets from price risk management activities(2)....... $ 781 $ 804 ===== =====
- --------------- (1) Trading contracts are derivative contracts that are entered into for purposes of generating a profit or benefiting from movements in market prices. (2) Net assets from price risk management activities include current and non-current assets and current and non-current liabilities from price risk management activities on the balance sheet. Other derivatives include derivative contracts related to the power restructuring activities of our consolidated subsidiaries of $967 million as of March 31, 2003 and $968 million as of December 31, 2002. Of this amount, $882 million and $878 million relate to a power restructuring transaction at our Eagle Point Cogeneration facility as of March 31, 2003 and December 31, 2002, and $85 million and $90 million relate to a power restructuring transaction at our Capitol District Energy Center Cogeneration Associates plant as of March 31, 2003 and December 31, 2002. 7. INVENTORY Our inventory consisted of the following:
MARCH 31, DECEMBER 31, 2003 2002 --------- ------------ (IN MILLIONS) Current Refined products, crude oil and chemicals................. $600 $584 Materials and supplies and other.......................... 115 113 ---- ---- Total current inventory........................... 715 697 Non-current Turbines(1)............................................... 20 20 ---- ---- Total inventory................................... $735 $717 ==== ====
- --------------- (1) We record these amounts as other non-current assets in our balance sheet. 8. DEBT AND OTHER CREDIT FACILITIES We had $371 million and $369 million of current maturities of long-term debt at March 31, 2003 and December 31, 2002. Credit Facilities In April 2003, El Paso removed us as a borrower under the $1 billion 3-year revolving credit and competitive advance facility, and as such, we are no longer jointly and severally liable for any amounts outstanding under that facility. In addition, El Paso entered into a new $3 billion revolving credit facility, with a $1.5 billion letter of credit sublimit, which matures in June 2005. This facility replaces the previous $3 billion revolving credit facility. El Paso's existing $1 billion revolving credit facility, which matures in August 2003, and approximately $1 billion of other financing arrangements (including leases, letters of credit 11 and other facilities) were also amended to conform El Paso's obligations to the new $3 billion revolving credit facility. The $3 billion revolving credit facility, $1 billion revolving credit facility, and the other financing arrangements are collateralized, along with other assets of El Paso, by our equity in ANR Pipeline Company (ANR), Wyoming Interstate Company, ANR Storage Company and our equity in the companies that own the assets that collateralize the Clydesdale financing arrangement. Long-Term Debt Obligations During the first quarter of 2003, we completed several debt financing transactions related to our long-term debt obligations:
INTEREST NET DATE COMPANY TYPE RATE PRINCIPAL PROCEEDS(1) DUE DATE ---- ------- ---- -------- --------- ----------- -------- (IN MILLIONS) Issuance March ANR Senior notes 8.875% $300 $288 2010 Retirements January El Paso CGP Long-term debt Various $ 50 $ 50 2003 February El Paso CGP Long-term debt 4.49% 240 240 2004 ---- ---- $290 $290 ==== ====
- --------------- (1) Net proceeds were primarily used to repay maturing long-term debt, redeem preferred interests of consolidated subsidiaries, repay short-term borrowings, other financing obligations and for general corporate and investment purposes. Restrictive Covenants We have entered into debt instruments and guaranty agreements that contain covenants such as restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on sales of assets, capitalization requirements, dividend restrictions and cross-acceleration provisions. A breach of any of these covenants could accelerate our debt and other financial obligations and that of our subsidiaries. One of the most significant debt covenants is that we must maintain a minimum net worth of $1.2 billion. If breached, the amounts guaranteed by the guaranty agreements could be accelerated. The guaranty agreements also have a $30 million cross-acceleration provision. In addition, we have indentures associated with our public debt that contain $5 million cross-acceleration provisions. As part of El Paso's $3 billion revolving credit facility, our subsidiaries, ANR and upon the maturity of the Clydesdale financing transaction, Colorado Interstate Gas Company (CIG) cannot incur incremental debt if the incurrence of this incremental debt would cause their debt to EBITDA ratio (as defined in El Paso's new revolving credit facility agreement) for that particular company to exceed 5 to 1. The proceeds from the issuance of debt by the pipeline company borrowers can be used only for maintenance and expansion capital expenditures or investments in other FERC-regulated assets and to refinance existing debt. As mentioned above, we amended a number of other financing arrangements to permit the execution of El Paso's $3 billion revolving credit facility. This included amending an operating lease where El Paso provides a guarantee to the lessor for the residual value of the facility that we lease. The amendments to this operating lease included extending a full guarantee to all of the parties who invested in the lessor, including the equity holder. As a result of the amendments, we will be required to consolidate the lessor in the second quarter of 2003. The operating lease impacted was for a facility at our Aruba refinery. When we consolidate the lessor of this facility, the assets owned by the lessor and the debt that supports the assets will be consolidated in our financial statements. In addition, these assets, once consolidated, will be 12 tested for impairment. Based on our preliminary analysis, we believe the impact on our financial statements will be as follows (in millions): Increase in total assets.................................... $370 Less: Impairment charge..................................... 20 ---- Net increase in assets...................................... $350 ==== Increase in long-term debt.................................. $370 ====

Other Financing Arrangements We collateralize, along with other El Paso assets, a financing arrangement established by El Paso referred to as Clydesdale. In April 2003, El Paso restructured the Clydesdale financing arrangement, and guaranteed the third party equity. The amount of El Paso's obligation at March 31, 2003, was $761 million. In addition, this obligation was refinanced by El Paso in April 2003 as a term loan that will amortize in equal quarterly amounts over the next two years. The term loan remains collateralized by the assets currently supporting the Clydesdale transaction, consisting of a production payment from us, various natural gas and oil properties and our equity in CIG. El Paso repaid $100 million of this term loan in May 2003. 9. COMMITMENTS AND CONTINGENCIES Legal Proceedings Grynberg. In 1997, a number of our subsidiaries were named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. The plaintiff in this case seeks royalties that he contends the government should have received had the volume and heating value of natural gas produced from royalty properties been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). In May 2001, the court denied the defendants' motions to dismiss. Discovery is proceeding. Our costs and legal exposure related to these lawsuits and claims are not currently determinable. Will Price (formerly Quinque). A number of our subsidiaries were named defendants in Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al, filed in 1999 in the District Court of Stevens County, Kansas. Quinque has been dropped as a plaintiff and Will Price has been added. This class action complaint alleges that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands. The plaintiff in this case seeks certification of a nationwide class of natural gas working interest owners and natural gas royalty owners to recover royalties that the plaintiff contends these owners should have received had the volume and heating value of natural gas produced from their properties been differently measured, analyzed, calculated and reported, together with prejudgment and postjudgment interest, punitive damages, treble damages, attorney's fees, costs and expenses, and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. Plaintiffs' motion for class certification was denied on April 10, 2003. Our costs and legal exposure related to this lawsuit are not currently determinable. MTBE. In compliance with the 1990 amendments to the Clean Air Act, we use the gasoline additive, methyl tertiary-butyl ether (MTBE), in some of our gasoline. We also produce, buy, sell and distribute MTBE. A number of lawsuits have been filed throughout the U.S. regarding MTBE's potential impact on water supplies. We are currently one of several defendants in one such lawsuit in New York. The plaintiffs seek remediation of their groundwater and prevention of future contamination, compensatory damages for the 13 costs of replacement water and for diminished property values, as well as punitive damages, attorney's fees, court costs, and, in some cases, future medical monitoring. Our costs and legal exposure related to this lawsuit and claims are not currently determinable. Cimarron County. In January of 2003, one of our subsidiaries, CIG Field Services Company (CIG), was named a defendant in a suit titled Patty Hiner, As Duly Elected County Assessor, The Board of County Commissioners for Cimarron County, Oklahoma v. CIG in Cimarron County District Court, alleging that in 1999 its agents falsely represented the value of its property to the Cimarron County Property Tax Assessor. The plaintiffs seek compensatory and punitive damages. The case has been removed to the United States District Court for the Western District of Oklahoma. Plaintiff's motion to remand was denied. CIG Field Services has filed a Motion to Dismiss. Our costs and legal exposure related to this lawsuit and claims are not currently determinable. In addition to the above matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. As of March 31, 2003, we had approximately $33 million accrued for all outstanding legal matters. Environmental Matters We are subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us 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, 2003, we had accrued approximately $155 million, including approximately $154 million for expected remediation costs at current and former operated sites and associated onsite, offsite and groundwater technical studies, and approximately $1 million for related environmental legal costs, which we anticipate incurring through 2027. The high end of our reserve estimates was approximately $227 million and the low end was approximately $135 million, and our accrual at March 31, 2003 was based on the estimated most likely reasonable amount of liability. By type of site, our reserves are based on the following estimates of reasonably possible outcomes.
MARCH 31, 2003 -------------- SITES LOW HIGH ----- ----- ----- (IN MILLIONS) Operating................................................... $106 $165 Non-operating............................................... 27 59 Superfund................................................... 2 3
Below is a reconciliation of our accrued liability as of March 31, 2003 (in millions):
2003 ------------- (IN MILLIONS) Balance as of January 1..................................... $171 Additions/adjustments for remediation activities............ (15) Payments for remediation activities......................... (5) Other changes, net.......................................... 4 ---- Balance as of March 31...................................... $155 ====
In addition, we expect to make capital expenditures for environmental matters of approximately $199 million in the aggregate for the years 2003 through 2008. These expenditures primarily relate to compliance with clean air regulations. For 2003, we estimate that our total remediation expenditures will be approximately $24 million. In addition, approximately $18 million of this amount will be expended under 14 government directed clean-up plans. The remaining $6 million will be self-directed or in connection with facility closures. Coastal Eagle Point. From May 1999 to March 2001, our Coastal Eagle Point Oil Company received several Administrative Orders and Notices of Civil Administrative Penalty Assessment from the New Jersey Department of Environmental Protection (DEP). All of the assessments are related to alleged noncompliance with the New Jersey Air Pollution Control Act pertaining to excess emissions from the first quarter 1998 through the fourth quarter 2000 reported by our Eagle Point refinery in Westville, New Jersey. The DEP has assessed penalties totaling approximately $1.3 million for these alleged violations. The DEP has indicated a willingness to accept a reduced penalty and a supplemental environmental project. Our Eagle Point refinery has been granted an administrative hearing on issues raised by the assessments. On February 24, 2003, EPA Region 2 issued a Compliance Order based on a 1999 EPA inspection of the refinery's leak detection and repair (LDAR) program. Alleged violations include failure to monitor all components, and failure to timely repair leaking components. During an August 2000 follow-up inspection, the EPA confirmed our Eagle Point refinery had improved its implementation of the program. The Compliance Order requires documentation of compliance with the program. We met with the EPA and DEP in March 2003 to discuss the Order and the possibility for a global settlement pursuant to the EPA's refinery enforcement initiative. Global settlements involving other refiners have included civil penalties and addressed LDAR as well as new source review, the benzene standard, and the standard for combustion of refinery fuel gas. On April 25, 2003, our Eagle Point refinery sent a letter to the EPA committing to global settlement discussions. Our Eagle Point refinery expects to resolve both the DEP assessments and the EPA refinery initiative issues. CERCLA Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to 26 active sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of March 31, 2003, we have estimated our share of the remediation costs at these sites to be between $5 million and $8 million. 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 we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in determining our estimated liabilities. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. 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 and regulations and claims for damages to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties relating to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate. Rates and Regulatory Matters Rate Case. In March 2001, CIG filed a rate case with the Federal Energy Regulatory Commission (FERC) proposing increased rates of $9 million annually and new and enhanced services for its customers. In April 2001, CIG received an order from the FERC, which suspended the rates subject to refund, and subject to the outcome of hearing. On September 26, 2001, the FERC approved certain of its new or enhanced services but rejected two firm services proposed in CIG's rate filing and required it to reallocate the costs allocated to those two services to existing services. CIG complied with this order and arranged with the affected customers to provide service under existing rate schedules. CIG and its customers entered into a settlement agreement in May 2002 settling all issues in the case. The settlement, which contained a small rate increase, was approved by the FERC, and became final in September 2002. The settlement obligates CIG to 15 file a new rate case to be effective no later than October 1, 2006. CIG paid approximately $8 million, including interest, in customer refunds in November 2002. These refunds were included in accrued liabilities, and will not have an adverse effect on our financial position or results of operations. On March 13, 2003, the FERC issued an order approving CIG's refund report. Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct governing the relationship between interstate pipelines and marketing affiliates to all energy affiliates. The proposed regulations, if adopted by the FERC, would dictate how all our energy affiliates conduct business and interact with our interstate pipelines. In December 2001, we filed comments with the FERC addressing our concerns with the proposed rules. A public hearing was held on May 21, 2002, providing an opportunity to comment further on the NOPR. Following the conference, additional comments were filed by our pipeline subsidiaries and others. At this time, we cannot predict the outcome of the NOPR, but adoption of the regulations in their proposed form would, at a minimum, place additional administrative and operational burdens on us. Negotiated Rate NOI. In July 2002, the FERC issued a Notice of Inquiry (NOI) that seeks comments regarding its 1996 policy of permitting pipelines to enter into negotiated rate transactions. Our pipelines have entered into these transactions over the years, and the FERC is now reviewing whether negotiated rates should be capped, whether or not the "recourse rate" (a cost-of-service based rate) continues to safeguard against a pipeline exercising market power and other issues related to negotiated rate programs. On September 25, 2002, our pipelines and others filed comments. Reply comments were filed on October 25, 2002. At this time, we cannot predict the outcome of this NOI. Cash Management NOPR. On August 1, 2002, the FERC issued a NOPR requiring that all cash management or money pool arrangements between a FERC regulated subsidiary and a non-FERC regulated parent must be in writing, and set forth the duties and responsibilities of cash management participants and administrators; the methods of calculating interest and for allocating interest income and expenses; and the restrictions on deposits or borrowings by money pool members. The NOPR also requires specified documentation for all deposits into, borrowings from, interest income from, and interest expenses related to, these arrangements. Finally, the NOPR proposed that as a condition of participating in a cash management or money pool arrangement, the FERC regulated entity maintain a minimum proprietary capital balance of 30 percent, and the FERC regulated entity and its parent maintain investment grade credit ratings. On August 28, 2002, comments were filed. The FERC held a public conference on September 25, 2002, to discuss the issues raised in the comments. Representatives of companies from the gas and electric industries participated on a panel and uniformly agreed that the proposed regulations should be revised substantially and that the proposed capital balance and investment grade credit rating requirements would be excessive. At this time, we cannot predict the outcome of this NOPR. Also on August 1, 2002, the FERC's Chief Accountant issued an Accounting Release, to be effective immediately. The Accounting Release provides guidance on how companies should account for money pool arrangements and the types of documentation that should be maintained for these arrangements. However, it did not address the proposed requirements that the FERC regulated entity maintain a minimum proprietary capital balance of 30 percent and that the entity and its parent have investment grade credit ratings. Requests for rehearing were filed on August 30, 2002. The FERC has not yet acted on the rehearing requests. Emergency Reconstruction of Interstate Natural Gas Facilities NOPR. On January 17, 2003, FERC issued a NOPR proposing, in emergency situations, to (1) expand the scope of construction activities authorized under a pipeline's blanket certificate to allow replacement of mainline facilities; (2) authorize a pipeline to commence reconstruction of the affected system without a waiting period; and (3) authorize automatic approval of construction that would be above the normal cost ceiling. Comments on the NOPR were filed on February 27, 2003. At this time, we cannot predict the outcome of this rulemaking. Pipeline Safety Notice of Proposed Rulemaking. On January 28, 2003, the U.S. Department of Transportation issued a NOPR proposing to establish a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the notice refers to as "high consequence areas." The proposed rule resulted from 16 the enactment of the Pipeline Safety Improvement Act of 2002, a new bill signed into law in December 2002. Comments on the NOPR were filed on April 30, 2003. At this time, we cannot predict the outcome of this rulemaking. FERC Inquiry. On February 26, 2003, El Paso received a letter from the Office of the Chief Accountant at the FERC requesting details of its announcement of 2003 asset sales and plans for us and our pipeline affiliates to issue a combined $700 million of long-term notes. The letter requested that El Paso explain how it intended to use the proceeds from the issuance of the notes and if the notes will be included in the two regulated companies' capital structure for rate-setting purposes. Our response to the FERC was filed on March 12, 2003, and we fully responded to the request. On April 2, 2003, we received an additional request for information, which we fully responded to on April 15, 2003. While the outcome of our outstanding legal matters, environmental matters, and rates and regulatory matters cannot be predicted with certainty, based on current information and our existing accruals, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows. However, it is possible that new information or future developments could require us to reassess our potential exposure related to these matters. It is also possible that these matters could impact our debt rating and credit rating. Further, for environmental matters, it is also possible that other developments, such as increasingly strict environmental laws and regulations and claims for damages to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As new information regarding our outstanding legal matters, environmental matters and rates and regulatory matters becomes available, or relevant developments occur, we will review our accruals and make any appropriate adjustments. The impact of these changes may have a material effect on our results of operations, our financial position, and on our cash flows in the period the event occurs. 10. SEGMENT INFORMATION We segregate our business activities into four operating segments: Pipelines, Production, Field Services and Merchant Energy. These segments are strategic business units that provide a variety of energy products and services. They are managed separately as each business unit requires different technology, operational and marketing strategies. In the second quarter of 2002, we reclassified our historical coal mining operations from our Merchant Energy segment to discontinued operations in our financial statements. Merchant Energy's results for the period ended March 31, 2002, were restated to reflect this change. We use earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business segments. We define EBIT as operating income, adjusted for several items, including: equity earnings from unconsolidated affiliates, minority interests of consolidated, but less than wholly owned operating subsidiaries and other miscellaneous non-operating items. Items that are not included in this measure are financing costs, including interest and debt expense, return on preferred interests of consolidated subsidiaries, income taxes, discontinued operations and the impact of accounting changes. We believe this measurement is useful to our investors because it allows them to evaluate the effectiveness of our businesses and operations and our investments from an operational perspective. This measurement may not be comparable to measurements used by other companies and should not be used as a substitute for net income 17 or other performance measures such as operating income or operating cash flow. The reconciliations of EBIT to income (loss) from continuing operations are presented below:
QUARTERS ENDED MARCH 31, -------------- 2003 2002 ----- ------ (IN MILLIONS) Total EBIT.................................................. $ 58 $ 735 Interest and debt expense................................... (99) (107) Affiliated interest expense, net............................ (7) (3) Return on preferred interests of consolidated subsidiaries.............................................. (7) (10) Income taxes................................................ 18 (202) ---- ----- Income (loss) from continuing operations............... $(37) $ 413 ==== =====
The following are our segment results as of and for the quarters ended March 31:
QUARTER ENDED MARCH 31, 2003 ---------------------------------------------------------------- FIELD MERCHANT PIPELINES PRODUCTION SERVICES ENERGY OTHER(1) TOTAL --------- ---------- -------- -------- -------- ------ (IN MILLIONS) Revenues from external customers............ $294 $249 $115 $2,260 $ -- $2,918 Intersegment revenue........................ (1) 24 13 (25) (11) -- Operating income (loss)..................... $153 $ 97 $ 11 $ (252) $ (3) $ 6 Earnings (losses) from unconsolidated affiliates................................ 23 3 -- 17 (1) 42 Minority interest in consolidated subsidiaries.............................. -- -- -- 2 -- 2 Other income................................ 1 -- -- 9 4 14 Other expense............................... (4) -- -- (1) (1) (6) ---- ---- ---- ------ ---- ------ EBIT........................................ $173 $100 $ 11 $ (225) $ (1) $ 58 ==== ==== ==== ====== ==== ======

QUARTER ENDED MARCH 31, 2002 ---------------------------------------------------------------- FIELD MERCHANT PIPELINES PRODUCTION SERVICES ENERGY OTHER(1) TOTAL --------- ---------- -------- -------- -------- ------ (IN MILLIONS) Revenues from external customers............ $256 $367 $ 90 $1,842(2) $ -- $2,555 Intersegment revenue........................ 7 22 11 (22) (18) -- Operating income (loss)..................... $143 $158 $ 5 $ 427 $(13) $ 720 Earnings from unconsolidated affiliates..... 32 2 -- 17 -- 51 Minority interest in consolidated subsidiaries.............................. -- -- -- (50) -- (50) Other income................................ 3 -- -- 14 1 18 Other expense............................... -- -- -- (4) -- (4) ---- ---- ---- ------ ---- ------ EBIT........................................ $178 $160 $ 5 $ 404 $(12) $ 735 ==== ==== ==== ====== ==== ======
- --------------- (1) Includes our Corporate and eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We record an intersegment revenue elimination, which is the only elimination included in the "Other" column, to remove intersegment transactions. (2) Merchant Energy revenues take into account the adoption of a consensus reached on EITF Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities, which requires us to report all physical sales of energy commodities in our energy trading activities on a net basis as a component of revenues. See our 2002 Form 10-K regarding the adoption of EITF Issue No. 02-3. 18 Total assets by segment are presented below:
MARCH 31, DECEMBER 31, 2003 2002 --------- ------------ (IN MILLIONS) Pipelines................................................... $ 5,321 $ 5,175 Production.................................................. 4,562 4,370 Field Services.............................................. 366 417 Merchant Energy............................................. 5,080 6,485 Corporate and other......................................... 610 680 ------- ------- Total segment assets.............................. 15,939 17,127 Discontinued operations..................................... -- 106 ------- ------- Total consolidated assets......................... $15,939 $17,233 ======= =======
11. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS We hold investments in affiliates which we account for using the equity method of accounting. Summarized financial information of our proportionate share of unconsolidated affiliates below includes affiliates in which we hold an interest of a 50 percent or less, as well as those in which we hold a greater than a 50 percent interest. Our proportional share of the net income of the unconsolidated affiliates in which we hold a greater than 50 percent interest was $8 million and $12 million for the quarters ended March 31, 2003 and 2002.
QUARTERS ENDED MARCH 31, --------------- 2003 2002 ------ ------ (IN MILLIONS) Operating results data: Operating revenues........................................ $280 $229 Operating expenses........................................ 220 172 Income from continuing operations......................... 37 45 Net income................................................ 37 45
Great Lakes We have a 50 percent ownership interest in the Great Lakes Gas Transmission Limited Partnership. Great Lakes Gas Transmission owns and operates a 2,115 mile interstate natural gas pipeline that transports gas to customers in the midwestern and northwestern United States and Canada. Summarized financial information of our proportionate share of Great Lakes Gas Transmission for the quarters ended March 31, 2003 and 2002 are as follows:
QUARTER ENDED MARCH 31, -------------- 2003 2002 ----- ----- Operating results data: Operating revenues........................................ $35 $33 Operating expenses........................................ 14 9 Income from continuing operations......................... 11 13 Net income................................................ 11 13
Related Party Transactions We participate in El Paso's cash management program which matches short-term cash surpluses and needs of its participating affiliates, thus minimizing total borrowing from outside sources. As of March 31, 2003 and December 31, 2002, we had borrowed $2,033 million and $2,374 million. The market rate 19 of interest as of March 31, 2003 and December 31, 2002, was 1.3% and 1.5%. In addition, we had a demand note receivable with El Paso of $199 million at both March 31, 2003 and December 31, 2002. The interest rate for this demand note receivable were 1.9% at March 31, 2003 and 2.2% at December 31, 2002. At March 31, 2003 and December 31, 2002, we had current accounts and notes receivable from related parties of $419 million and $346 million. These balances were incurred in the normal course of our business. In addition, we had a non-current note receivable from a related party of $145 million and $126 million included in other non-current assets at March 31, 2003 and at December 31, 2002. In March 2002, we acquired assets with a net book value, net of deferred taxes, of approximately $8 million from El Paso. Additionally, we sold natural gas and oil properties to El Paso. Net proceeds from these sales were $404 million, and we did not recognize a gain or loss on the properties sold. The proceeds exceeded the net book value by $32 million and we recorded these proceeds as an increase to paid-in-capital. At March 31, 2003 and December 31, 2002, we had other accounts payable to related parties of $140 million and $87 million. We enter into a number of transactions with our unconsolidated affiliates in the ordinary course of conducting our business. The following table shows revenues, income and expenses incurred between us and our unconsolidated affiliates and El Paso's subsidiaries for the quarters ended March 31:
2003 2002 ----- ----- (IN MILLIONS) Revenues.................................................... $251 $485 Cost of sales............................................... 36 49 Charges from affiliates..................................... 53 50 Other income................................................ 2 1
12. NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED In January 2003, the Financial Accounting Standards Board issued FIN No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. This interpretation defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk and/or a controlling financial interest in the entity. This standard requires that companies consolidate a variable interest entity if it is allocated a majority of the entity's losses and/or returns, including fees paid by the entity. The provisions of FIN No. 46 are effective for all variable interest entities created after January 31, 2003, and are effective on July 1, 2003, for all variable interest entities created before January 31, 2003. We currently have interests in and consolidate an entity in which third party investors hold preferred interests. The preferred interests held by the third party investors are reflected in our balance sheet as preferred interests of consolidated subsidiaries. The third party investors are capitalized with five percent equity, which is held by banks in these arrangements, and 95 percent debt. We believe we would consolidate these third party investors under these arrangements because (i) the equity investment in these third party investors is less than the specified 10 percent of total capitalization of the investors and (ii) the rights of the third party investors to expected residual returns from these arrangements is limited. When we consolidate these third party investors, the minority interest that is currently classified as preferred interests of consolidated subsidiaries will be classified as long-term debt. At this time, we believe the holder of the preferred stock of our consolidated subsidiary, Coastal Securities Company Limited, will be impacted by this standard. We believe the impact on our financial statements as a result of implementing this standard will be (in millions): ~~Decrease in preferred interests of consolidated subsidiaries.............................................. $100 Increase in long-term debt.................................. $100~~

20 We have a number of other financial interests that would have been affected by this standard, but as a result of actions taken during the first quarter of 2003, or actions we will take in the second quarter of 2003, including amending and restructuring the underlying agreements, these financial interests will be consolidated prior to our required adoption of this standard. The financial interests affected by these actions include an operating lease with a residual value guarantee for a facility at our Aruba refinery (see Note 8). 21 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information contained in Item 2 updates, and you should read it in conjunction with, information disclosed in our 2002 Annual Report on Form 10-K and the financial statements and notes presented in Item 1, Financial Statements, of this Form 10-Q. SEGMENT RESULTS We use earnings before interest and income taxes (EBIT) to assess the operating results and effectiveness of our business segments. We define EBIT as operating income, adjusted for several items, including: equity earnings from unconsolidated affiliates, minority interests of consolidated, but less than wholly owned operating subsidiaries and other miscellaneous non-operating items. Items that are not included in this measure are financing costs, including interest and debt expense, return on preferred interests of consolidated subsidiaries, income taxes, discontinued operations and the impact of accounting changes. The following is a reconciliation of our operating income to our EBIT and our EBIT to our income (loss) from continuing operations for the quarters ended March 31:
2003 2002 ------- ------- (IN MILLIONS) Operating revenues.......................................... $ 2,918 $ 2,555 Operating expenses.......................................... (2,912) (1,835) ------- ------- Operating income.......................................... 6 720 Earnings from unconsolidated affiliates..................... 42 51 Minority interest in consolidated subsidiaries.............. 2 (50) Other income................................................ 14 18 Other expenses.............................................. (6) (4) ------- ------- EBIT...................................................... 58 735 Interest and debt expense................................... (99) (107) Affiliated interest expense, net............................ (7) (3) Return on preferred interests of consolidated subsidiaries.............................................. (7) (10) Income taxes................................................ 18 (202) ------- ------- Income (loss) from continuing operations.................. $ (37) $ 413 ======= =======
We believe EBIT is a useful measurement for our investors because it allows them to evaluate the effectiveness of our businesses and operations and our investments from an operational perspective. This measurement may not be comparable to measurements used by other companies and should not be used as a substitute for net income or other performance measures such as operating income or operating cash flow. 22 OVERVIEW OF RESULTS OF OPERATIONS Below are our results of operations (as measured by EBIT), by segment for the quarters ended March 31. A reconciliation of operating income to EBIT is provided below for each segment. Our four operating segments -- Pipelines, Production, Field Services and Merchant Energy -- provide a variety of energy products and services. They are managed separately as each business unit requires different technology, operational and marketing strategies. These segment results include the impacts of asset impairments, gains and losses on long-lived assets and other charges, which are discussed further in Item 1, Financial Statements, Notes 3, 4, 5 and 11.
EBIT BY SEGMENT 2003 2002 - --------------- ------ ----- (IN MILLIONS) Pipelines................................................... $ 173 $178 Production.................................................. 100 160 Field Services.............................................. 11 5 Merchant Energy............................................. (225) 404 ----- ---- Segment EBIT.............................................. 59 747 Corporate and other......................................... (1) (12) ----- ---- Consolidated EBIT......................................... $ 58 $735 ===== ====
PIPELINES Our Pipelines segment holds our interstate transmission businesses. For a further discussion of the business activities of our Pipelines segment, see our 2002 Form 10-K. Results of our Pipelines segment operations were as follows for the quarters ended March 31:
PIPELINE SEGMENT RESULTS 2003 2002 - ------------------------ ------- -------- (IN MILLIONS, EXCEPT VOLUME AMOUNTS) Operating revenues.......................................... $ 293 $ 263 Operating expenses.......................................... (140) (120) ----- ------ Operating income.......................................... 153 143 Other income................................................ 20 35 ----- ------ EBIT...................................................... $ 173 $ 178 ===== ====== Throughput volumes (BBtu/d)(1).............................. 9,831 9,140 ===== ======
- --------------- (1) Throughput volumes for 2002 exclude 224 BBtu/d related to the sale of our equity interest in the Alliance pipeline system which was completed in March 2003. Throughput volumes also exclude intersegment activities. Prior period volumes have been restated to reflect current year presentations, which include billable transportation throughput volume for storage withdrawal. Operating revenues for the quarter ended March 31, 2003, were $30 million higher than the same period in 2002. This increase was due to the impact of higher prices in 2003 on natural gas recovered in excess of amounts used in operations of $18 million, $10 million from higher realized prices in 2003 on the resale of natural gas purchased from the Dakota gasification facility, an increase in transportation revenues of $5 million resulting from increased throughput volumes as a result of colder winter weather, $4 million increase in reservation revenues due to system expansion projects placed in service in the latter part of 2002 and $4 million related to a rate settlement in 2003. Also contributing to the increase were storage gas sales of $3 million which commenced in the fourth quarter of 2002, an increase of $3 million in natural gas liquids revenues resulting from higher prices and a $3 million increase in reservation revenues due to an increase in contracted volumes on the WIC system. These increases were partially offset by a $20 million decrease in revenues due to CIG's sale of the Panhandle field and other production properties in July 2002. Operating expenses for the quarter ended March 31, 2003, were $20 million higher than the same period in 2002. The increase was due to an $11 million gain on the sale of pipeline expansion rights in February 2002, 23 an increase of $9 million from higher prices on gas purchase from the Dakota gasification facility, lower benefit costs in 2002 of $6 million and $4 million from higher gas costs for our system supply purchases resulting from higher natural gas prices and volumes in 2003. These increases were partially offset by a $12 million decrease in operating expenses due to CIG's sale of Panhandle field and other production properties in July 2002. Other income for the quarter ended March 31, 2003, was $15 million lower than the same period in 2002. The decrease was due to lower equity earnings of $5 million from Alliance Pipeline due to the sale of our interests in the fourth quarter 2002 and a charge of $4 million related to the partial termination of a hedging obligation for Blue Lake Gas Storage Company, an investment in which we have a 75 percent ownership interest. Also contributing to the decrease were lower equity earnings of $4 million from our investment in Great Lakes Gas Transmission due to a favorable sales and use tax settlement recorded in the first quarter of 2002 and the resolution of uncertainties in 2002 of $3 million associated with the sales of our interests in the Empire State pipeline system and Gulfstream pipeline project in 2001. PRODUCTION Our Production segment conducts our natural gas and oil exploration and production activities. For a further discussion of the business activities of our Production segment, see our 2002 Form 10-K. Results of our Production segment operations were as follows for the quarters ended March 31:
PRODUCTION SEGMENT RESULTS 2003 2002 - -------------------------- --------- --------- (IN MILLIONS, EXCEPT VOLUMES AND PRICES) Operating Revenues: Natural gas............................................... $ 224 $ 347 Oil, condensate and liquids............................... 47 39 Other..................................................... 2 3 ------- ------- Total operating revenues.......................... 273 389 Transportation and net product costs........................ (13) (13) ------- ------- Total operating margin............................ 260 376 Operating expenses(1)....................................... (163) (218) ------- ------- Operating income.......................................... 97 158 Other income................................................ 3 2 ------- ------- EBIT...................................................... $ 100 $ 160 ======= ======= Volumes and prices Natural gas Volumes (MMcf)......................................... 42,311 83,266 ======= ======= Average realized prices with hedges ($/Mcf)(2)......... $ 5.30 $ 4.17 ======= ======= Average realized prices without hedges ($/Mcf)(2)...... $ 6.62 $ 2.30 ======= ======= Average transportation costs ($/Mcf)................... $ 0.22 $ 0.12 ======= ======= Oil, condensate and liquids Volumes (MBbls)........................................ 1,723 2,694 ======= ======= Average realized prices with hedges ($/Bbl)(2)......... $ 27.28 $ 14.48 ======= ======= Average realized prices without hedges ($/Bbl)(2)...... $ 27.29 $ 14.49 ======= ======= Average transportation costs ($/Bbl)................... $ 0.88 $ 1.03 ======= =======
- --------------- (1) Include production costs, depletion, depreciation and amortization, ceiling test charges, asset impairments, gain and loss on long-lived assets, corporate overhead, general and administrative expenses and severance and other taxes. (2) Prices are stated before transportation costs. 24 For the quarter ended March 31, 2003, operating revenues were $116 million lower than the same period in 2002. Our natural gas revenues, including the impact of hedges, were $123 million lower in the first quarter of 2003. Our 2003 natural gas volumes decreased by 49 percent, resulting in a $171 million decrease in revenues, from the same period in 2002. Realized natural gas prices rose in 2003 by 27 percent, resulting in a $48 million increase in revenues, when compared to the same period in 2002. The declines in natural gas volumes were due largely to the sale of properties in Colorado, Utah, Texas and western Canada during 2002 as well as normal production declines. Our oil, condensate and liquids revenues, including the impact of hedges, were $8 million higher in the first quarter of 2003. Realized oil, condensate and liquids prices rose in 2003 by 88 percent, resulting in a $22 million increase in revenues, when compared to the same period in 2002. Our 2003 oil, condensate and liquids volumes decreased by 36 percent, resulting in a $14 million decrease in revenues, from the same period in 2002. These declines were again due largely to the sale of properties and normal declines mentioned above. Operating expenses for the quarter ended March 31, 2003, were $55 million lower than the same period in 2002. Depletion expense was lower by $34 million comprised of a $62 million decrease due to lower production volumes in 2003, partially offset by a $25 million increase resulting from higher depletion rates in 2003 and costs of $3 million related to retirement obligations from our adoption in 2003 of SFAS No. 143. The higher depletion rate resulted from higher capitalized costs in the full cost pool coupled with a lower reserve base. Also contributing to the decrease were a non-cash full cost ceiling test charge of $10 million incurred in the first quarter of 2002 for our international properties in Brazil, lower corporate overhead allocations of $5 million and decreased oilfield service costs of $15 million primarily due to asset dispositions which reduced labor and production processing fees. Partially offsetting the decrease in expenses were asset impairments of $9 million related to non-full cost assets in Canada. FIELD SERVICES Our Field Services segment conducts our midstream activities. In March 2003, we received approval to sell our assets in the Mid-Continent region. These assets primarily include our Greenwood, Hugoton, Keyes and Mocane natural gas gathering systems, our Sturgis, Mocane and Lakin processing plants and our processing arrangements at three additional processing plants. We expect to complete this sale by the end of the second quarter of 2003. These assets generated EBIT of approximately $10 million during the year ended December 31, 2002. Once this sale is completed, our remaining assets will consist primarily of our processing facilities in the south Texas, south Louisiana and Rocky Mountain regions. 25 As a result of our asset sales and the resulting decline in our gathering and treating activities, we expect our future EBIT to decrease considerably. For a further discussion of the business activities of our Field Services segment, see our 2002 Form 10-K. Results of our Field Services segment operations were as follows for the quarters ended March 31:
FIELD SERVICES SEGMENT RESULTS 2003 2002 - ------------------------------ --------- --------- (IN MILLIONS, EXCEPT VOLUMES AND PRICES) Gathering, treating and processing gross margins(1)......... $ 24 $ 23 Operating expenses.......................................... (13) (18) ------ ------ Operating income and EBIT................................. $ 11 $ 5 ====== ====== Volume and prices Gathering and treating Volumes (BBtu/d)....................................... 200 648 ====== ====== Prices ($/MMBtu)....................................... $ 0.22 $ 0.12 ====== ====== Processing Volumes (inlet BBtu/d)................................. 1,703 1,810 ====== ====== Prices ($/MMBtu)....................................... $ 0.12 $ 0.10 ====== ======
- --------------- (1) Gross margins consist of operating revenues less cost of products sold. We believe this measurement is more meaningful to analyzing our Field Services operating results because commodity costs play such a significant role in the determination of profit from our midstream activities. Total gross margins for the quarter ended March 31, 2003, were $1 million higher than the same period in 2002. Gross margins increased by $9 million due to higher natural gas prices and natural gas liquids prices in 2003, which favorably impacted our margins and volumes in the south Louisiana and Rocky Mountain regions. Partially offsetting these increases were $8 million of lower margins resulting from the sales of our Dragon Trail processing plant in May 2002, Natural Buttes and Ouray natural gas gathering systems in December 2002 and Wyoming gathering assets in January 2003. Operating expenses for the quarter ended March 31, 2003, were $5 million lower than the same period in 2002. The decrease was primarily due to lower operating and depreciation expense of $3 million resulting from the sales of assets discussed above. Also contributing to this decrease were lower operating and maintenance expenses as a result of our cost reduction plan initiated in mid-2002. 26 MERCHANT ENERGY Our Merchant Energy segment consists of two primary divisions: global power and petroleum. Below are Merchant Energy's operating results and an analysis of those results for the quarters ended March 31:
DIVISION TOTAL ---------------------------------------------------- MERCHANT OTHER ENERGY MERCHANT ENERGY SEGMENT RESULTS GLOBAL POWER PETROLEUM ACTIVITIES ELIMINATIONS SEGMENT - ------------------------------- ------------ --------- ---------- ------------ -------- (IN MILLIONS) 2003 Gross margin....................... $ 44 $ 239 $(3) $-- $ 280 Operating expenses................. (32) (500) -- -- (532) ----- ----- --- --- ----- Operating income (loss)....... 12 (261) (3) -- (252) Other income....................... 20 7 -- -- 27 ----- ----- --- --- ----- EBIT.......................... $ 32 $(254) $(3) $-- $(225) ===== ===== === === ===== 2002 Gross margin....................... $ 458 $ 197 $ 1 $(4) $ 652 Operating expenses................. (54) (172) (3) 4 (225) ----- ----- --- --- ----- Operating income (loss)....... 404 25 (2) -- 427 Other income (expense)............. (123) 97 3 -- (23) ----- ----- --- --- ----- EBIT.......................... $ 281 $ 122 $ 1 $-- $ 404 ===== ===== === === =====
Global Power Our global power division includes the ownership and operation of domestic and international power generating facilities. El Paso announced in April 2003 its intent to potentially sell our domestic power generation facilities. In this regard, we have commenced a process to sell most of our domestic power generation facilities. For a further discussion of our global power division, see our 2002 Form 10-K. Results of our global power division operations were as follows for the quarters ended March 31:
GLOBAL POWER DIVISION RESULTS 2003 2002 - ----------------------------- ----- ------ (IN MILLIONS) Gross margin................................................ $ 44 $ 458 Operating expenses.......................................... (32) (54) ---- ----- Operating income....................................... 12 404 Other income (expense)...................................... 20 (123) ---- ----- EBIT................................................... $ 32 $ 281 ==== =====
Gross margin consists of revenues from our power plants and the net results from our power restructuring activities. The cost of fuel used in the power generation process is included in operating expenses. For the quarter ended March 31, 2003, our gross margin was $414 million lower than the same period in 2002. The decrease was due primarily to a power contract restructuring for our Eagle Point Cogeneration facility that we completed in the first quarter of 2002, which contributed $409 million to our gross margin in 2002, including an $80 million loss on a power supply agreement that we entered into with El Paso in the first quarter of 2002 associated with the Eagle Point Cogeneration restructuring transaction. Also contributing to this decrease in gross margin was a decrease of $33 million in 2003 power generation revenues primarily due to the shutdown of our Eagle Point Cogeneration facility for maintenance in the first quarter of 2003. Operating expenses for the quarter ended March 31, 2003, were $22 million lower than the same period in 2002. This decrease was primarily due to a $6 million decrease in operating costs related to the shutdown of our Eagle Point Cogeneration facility for maintenance in 2003 and a $6 million decrease in depreciation expense in 2003 primarily due to lower depreciation on our Eagle Point Cogeneration facility. 27 Other income for the quarter ended March 31, 2003, was $143 million higher than the same period in 2002. This increase was primarily due to a $90 million contract termination fee we paid to our petroleum division associated with the termination of a steam contract between our Eagle Point Cogeneration facility and the Eagle Point refinery in 2002 that was eliminated from Merchant Energy's consolidated results. Also contributing to this increase was $52 million of minority interest expense recorded primarily on our power contract restructurings during the first quarter of 2002. Petroleum El Paso announced in 2003 its intent to exit substantially all of our petroleum businesses. El Paso also recently announced its intent to pursue the sale of our Aruba refinery, in which we have a net investment of approximately $1.2 billion, excluding an operating lease for a support facility that will be consolidated in the second quarter of 2003. It is likely that if we pursue a sale of Aruba in the near term, we will not recover our full investment and could recognize an impairment or loss on the sale. For a further discussion of our petroleum division, see our 2002 Form 10-K. Results of our petroleum division operations were as follows for the quarters ended March 31:
PETROLEUM DIVISION RESULTS 2003 2002 - -------------------------- ------ ------ (IN MILLIONS) Gross margin................................................ $ 239 $ 197 Operating expenses.......................................... (500) (172) ------ ------ Operating income....................................... (261) 25 Other income................................................ 7 97 ------ ------ EBIT................................................... $ (254) $ 122 ====== ======
Gross margin consists of revenues from our refineries and commodity trading activities, less costs of the feedstocks used in the refining process and the costs of commodities sold. For the quarter ended March 31, 2003, our gross margin was $42 million higher than the same period in 2002. This increase included higher refining margins of $37 million at our Aruba refinery due to higher spreads between the sales prices of refined products and underlying feedstock costs and $48 million at our Eagle Point refinery due to increased processing volumes and higher spreads between the sales prices of refined products and underlying feedstock costs. These increases were partially offset by lower petroleum trading margins of $41 million on domestic crude and products resulting from the decision to exit our petroleum-related trading operations during 2003. Operating expenses for the quarter ended March 31, 2003, were $328 million higher than the same period in 2002. The increase was primarily due to a $350 million impairment of our Eagle Point refinery and our chemical assets in the first quarter of 2003 resulting from our announced expectation that we will dispose of these assets. Also contributing to this increase was a $28 million increase in non-routine maintenance and other operating costs, primarily at our Aruba facility, and $6 million of employee severance costs incurred in 2003. Partially offsetting this increase was $56 million of net gains primarily from the sale of our Corpus Christi refinery and Florida petroleum terminals and tug and barge operations completed in 2003. Other income for the quarter ended March 31, 2003, was $90 million lower than the same period in 2002. This decrease was primarily due to a $90 million contract termination fee we received from our global power division associated with the termination of a steam contract between our Eagle Point refinery and the Eagle Point Cogeneration facility in 2002, which was eliminated from Merchant Energy's consolidated results. CORPORATE AND OTHER Corporate and other net expenses, which include general and administrative activities and other miscellaneous businesses, for the quarter ended March 31, 2003, were $11 million lower than the same period in 2002. The decrease was primarily due to a write-off of $6 million related to our environmental reserves for Coastal Mart in 2002 as a result of the sale of substantially all of our retail gas stations in the latter part of 28 2001. Also contributing to the decrease was a $2 million increase in interest income related to a notes receivable from our unconsolidated subsidiaries during the first quarter of 2003. INTEREST AND DEBT EXPENSE Interest and debt expense for the quarter ended March 31, 2003, was $99 million, or $8 million lower than the same period in 2002. Below is the analysis of our interest expense for the quarters ended March 31:
2003 2002 ----- ----- (IN MILLIONS) Long-term debt, including current maturities................ $99 $ 98 Other interest.............................................. 3 14 Capitalized interest........................................ (3) (5) --- ---- Total interest expense................................. $99 $107 === ====
Interest expense on long-term debt for the quarter ended March 31, 2003, was $1 million higher than the same period in 2002 primarily due to a $19 million increase in interest from Utility Contract Funding borrowed in July 2002 and Mohawk River Funding IV debt borrowed in June 2002. These debts were borrowed for ongoing capital projects, investment programs and operating requirements. Also contributing to the increase was $2 million of additional interest related to the March issuance of $300 million ANR senior unsecured notes. These increases were partially offset by $19 million decrease in interest due to the retirement of approximately $1.2 billion of long-term debt in 2002 with an average interest rate of 6.7%. Other interest for the quarter ended March 31, 2003, was $11 million lower than the same period in 2002. The decrease was primarily due to $7 million decrease resulting from the retirement of our other financing obligations, $2 million decrease in the factoring of receivables, and $2 million decrease due to the termination of a marketing sales contract during 2002. Capitalized interest for the quarter ended March 31, 2003, was $2 million lower than the same period in 2002 primarily due to the lower interest rates in the first quarter of 2003 than the same period in 2002. AFFILIATED INTEREST EXPENSE, NET Affiliated interest expense net for the quarter ended March 31, 2003, was $7 million, or $4 million higher than the same period in 2002. The increase was primarily due to higher average advances payable to El Paso under our cash management program in 2003, partially offset by lower average short-term interest rates. The average advances payable balance for the first quarter increased from $580 million in 2002 to $2,086 million in 2003. The average short-term interest rates for the first quarter decreased from 1.9% in 2002 to 1.4% in 2003. RETURN ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES Return on preferred interests of consolidated subsidiaries for the quarter ended March 31, 2003, was $3 million lower than the same period in 2002 primarily due to the redemption of all the preferred interests related to El Paso Oil & Gas Resources, El Paso Oil & Gas Associates and Coastal Limited Ventures in July 2002. INCOME TAXES Income tax benefit for the quarter ended March 31, 2003, was $18 million resulting in an effective tax rate of 33 percent. Income tax expense for the quarter ended March 31, 2002, was $202 million, resulting in an effective tax rate of 33 percent. Our effective tax rates were different than the statutory rate of 35 percent primarily due to the following: - state income taxes; and - foreign income taxed at different rates. 29 COMMITMENTS AND CONTINGENCIES See Item 1, Financial Statements, Note 9, which is incorporated herein by reference. NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED See Item 1, Financial Statements, Note 12, which is incorporated herein by reference. 30 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS This report contains or incorporates by reference forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any forward-looking statement includes a statement of the assumptions or bases underlying the forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and 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, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the statement of expectation or belief will result or be achieved or accomplished. The words "believe," "expect," "estimate," "anticipate" and similar expressions will generally identify forward-looking statements. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK This information updates, and you should read it in conjunction with, information disclosed in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2002, in addition to the information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There are no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2002 Annual Report on Form 10-K. ITEM 4. CONTROLS AND PROCEDURES Evaluation of Controls and Procedures. Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures (Disclosure Controls) and internal controls (Internal Controls) within 90 days of the filing date of this Quarterly Report pursuant to Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934 (Exchange Act). Definition of Disclosure Controls and Internal Controls. Disclosure Controls are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified under the Exchange Act. Disclosure Controls include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Internal Controls are procedures which are designed with the objective of providing reasonable assurance that (1) our transactions are property authorized; (2) our assets are safeguarded against unauthorized or improper use; and (3) our transactions are properly recorded and reported, all to permit the preparation of our financial statements in conformity with generally accepted accounting principles. Limitations on the Effectiveness of Controls. El Paso CGP Company's management, including the principal executive officer and principal financial officer, does not expect that our Disclosure Controls and Internal Controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, control may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may 31 deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. No Significant Changes in Internal Controls. We have sought to determine whether there were any "significant deficiencies" or "material weaknesses" in El Paso CGP Company's Internal Controls, or whether the company had identified any acts of fraud involving personnel who have a significant role in El Paso CGP Company's Internal Controls. This information was important both for the controls evaluation generally and because the principal executive officer and principal financial officer are required to disclose that information to our Board's Audit Committee and our independent auditors and to report on related matters in this section of the Quarterly Report. The principal executive officer and principal financial officer note that, from the date of the controls evaluation to the date of this Quarterly Report, there have been no significant changes in Internal Controls or in other factors that could significantly affect Internal Controls, including any corrective actions with regard to significant deficiencies and material weaknesses. Effectiveness of Disclosure Controls. Based on the controls evaluation, our principal executive officer and principal financial officer have concluded that, subject to the limitations discussed above, the Disclosure Controls are effective to ensure that material information relating to El Paso CGP Company and its consolidated subsidiaries is made known to management, including the principal executive officer and principal financial officer, particularly during the period when our periodic reports are being prepared. Officer Certification. The certifications from the principal executive officer and principal financial officer required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included herein, or as Exhibits to this Quarterly Report, as appropriate. 32 PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. See Part I, Item 1, Financial Statements, Note 9, 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 a part of this report. Exhibits not incorporated by reference to a prior filing are designated by an "*"; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
EXHIBIT NUMBER DESCRIPTION - ------- ----------- *99.A Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002. *99.B Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.
Undertaking We hereby undertake, 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 our long-term debt not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets. b. Reports on Form 8-K
DATE EVENT REPORTED ---- -------------- ~~January 28, 2003 Announced the sale of our petroleum terminals and tug & barge operations and provided pro-forma financials of El Paso CGP Company.~~
33 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 CGP COMPANY Date: May 15, 2003 /s/ D. DWIGHT SCOTT ------------------------------------ D. Dwight Scott Executive Vice President and Chief Financial Officer and Director (Principal Financial Officer) Date: May 15, 2003 /s/ JEFFREY I. BEASON ------------------------------------ Jeffrey I. Beason Senior Vice President and Controller (Principal Accounting Officer) 34 CERTIFICATION I, Ronald L. Kuehn, Jr., certify that: 1. I have reviewed this quarterly report on Form 10-Q of El Paso CGP Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ RONALD L. KUEHN, JR. -------------------------------------- Ronald L. Kuehn, Jr. Chairman of the Board and Chief Executive Officer (Principal Executive Officer) El Paso CGP Company Date: May 15, 2003 35 CERTIFICATION I, D. Dwight Scott, certify that: 1. I have reviewed this quarterly report on Form 10-Q of El Paso CGP Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ D. DWIGHT SCOTT -------------------------------------- D. Dwight Scott Executive Vice President and Chief Financial Officer and Director (Principal Financial Officer) El Paso CGP Company Date: May 15, 2003 36 EXHIBIT INDEX 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 "*"; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
EXHIBIT NUMBER DESCRIPTION - ------- ----------- *99.A Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002. *99.B Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.
EX-99.A 3 h04921exv99wa.txt CERTIFICATION OF CEO PURSUANT TO SECTION 906 EXHIBIT 99.A CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report on Form 10-Q for the period ending March 31, 2003, of El Paso CGP Company (the "Company") as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Ronald L. Kuehn, Jr., Chairman of the Board and Chief Executive Officer, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Ronald L. Kuehn, Jr. ------------------------------------- Ronald L. Kuehn, Jr. Chairman of the Board and Chief Executive Officer (Principal Executive Officer) May 15, 2003 A signed original of this written statement required by Section 906 has been provided to El Paso CGP Company and will be retained by El Paso CGP Company and furnished to the Securities and Exchange Commission or its staff upon request. EX-99.B 4 h04921exv99wb.txt CERTIFICATION OF CFO PURSUANT TO SECTION 906 EXHIBIT 99.B CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report on Form 10-Q for the period ending March 31, 2003, of El Paso CGP Company (the "Company") as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, D. Dwight Scott, Executive Vice President and Chief Financial Officer, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ D. Dwight Scott -------------------------------------- D. Dwight Scott Executive Vice President and Chief Financial Officer (Principal Financial Officer) May 15, 2003 A signed original of this written statement required by Section 906 has been provided to El Paso CGP Company and will be retained by El Paso CGP Company and furnished to the Securities and Exchange Commission or its staff upon request. 10-Q 5 h04921e10vqpdf.pdf EL PASO CGP COMPANY - MARCH 31, 2003 begin 644 h04921e10vqpdf.pdf M)5!$1BTQ+C(-)>+CS],-"C$T,B`P(&]B:@T\/"`-+TQI;F5A/5[`=\,AH8G.:93(@*L$K*6K*78?&][WN_ M+-7T"II2_=(KT+_ZWJ_`MY/O>P6@66>QZ*(M2Z^OLTSI]BD0ML]QV=RG?!I; M_!V5@PV/1U>ZG-%9'.CQA:]R>XRA4;>I2Y`M\[SJC; MX'*_H\CD(`GY/O79I4?Z7+X*M&G<;]@TV01HU".8K/G#+G;9RDVHW*W<&I?Y M;%F"_"SDN\0Q%&\)LO@J8'*H&RK[0K[EQ6)'YXL>$)/1N(\7M0I?\&*_TGL\ MNN+%0I./A4"NQF9> MBR^"GJ;*=1(+"J_/=E7N#V3VT=@"E755OF#I'E.YN4M7^(+'E2O`T*AXU`TT MV=24!R@;J#S1ENF4J3$PZ"99"E]QV`0).B%+X0LZB\%!YW3*Y##(.WWLCUJ! 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