10-Q 1 h20734qe10vq.txt EL PASO CGP COMPANY - SEPTEMBER 30, 2004 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 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 SEPTEMBER 30, 2004 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 77002 HOUSTON, TEXAS (Zip Code) (Address of Principal Executive Offices)

Telephone Number: (713) 420-2600 Internet Website: www.elpaso.com 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 [ ] No [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange 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 $3 per share. Shares outstanding on December 21, 2004: 1,000 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 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................................. 2425 Cautionary Statement Regarding Forward-Looking Statements... 3739 Item 3. Quantitative and Qualitative Disclosures About Market Risk...................................................... 3840 Item 4. Controls and Procedures..................................... 3941 PART II -- Other Information Item 1. Legal Proceedings........................................... 42 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.................................................. 42 Item 3. Defaults Upon Senior Securities............................. 42 Item 4. Submission of Matters to a Vote of Security Holders......... 42 Item 5. Other Information........................................... 42 Item 6. Exhibits.................................................... 42 Signatures.................................................. 4344

--------------- 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 Bcf = billion cubic feet Bcfe = billion cubic feet of natural gas equivalents MBbls = thousand barrels Mcf = thousand cubic feet Mcfe = thousand cubic feet of natural gas equivalents MMBtu = million British thermal units MMcf = million cubic feet MMcfe = million cubic feet of natural gas equivalents MW = megawatt

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. Oil includes natural gas liquids unless otherwise specified. 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)

QUARTER ENDED ~~SIX~~NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, ~~JUNE~~SEPTEMBER 30, ------------------ ------------------- 2003 2003 2004 (RESTATED) 2004 (RESTATED) ----- ---------- ------ ---------- Operating revenues....................................... $518 ~~505~~ $ ~~604~~496 $1,~~042~~560 $ 1,~~327~~823 ----- ----- ------ ------- Operating expenses Cost of products and services.......................... ~~104~~141 ~~134~~99 ~~212~~353 ~~309~~408 Operation and maintenance.............................. ~~120~~147 ~~132~~137 ~~247~~394 ~~261~~398 Depreciation, depletion and amortization............... ~~115~~116 121 ~~228~~344 ~~242~~363 Loss (gain) on long-lived assets....................... --6 ~~(30)~~6 8894 (3125) Ceiling test charges................................... -- 39 -- 39 Taxes, other than income taxes......................... 1817 1915 3047 4661 ----- ----- ------ ------- ~~357~~427 ~~376~~417 ~~805~~1,232 ~~827~~1,244 ----- ----- ------ ------- Operating income......................................... ~~148~~91 ~~228~~79 ~~237~~328 ~~500~~579 Earnings (losses) from unconsolidated affiliates......... 2422 ~~(54)~~8 5981 (157) Other income, net........................................ 716 712 1329 1325 Interest and debt expense................................ (9175) (~~101~~104) (~~192~~267) (~~200~~304) Affiliated interest income (expense), net................ 5 (711) (94) (1425) Distributions on preferred interests of consolidated subsidiaries........................................... -- (71) -- (1415) ----- ----- ------ ------- Income (loss) before income taxes........................~~......~~ 9359 66(17) ~~108~~167 ~~270~~253 Income taxes............................................. 3221 19(17) 3758 8972 ----- ----- ------ ------- Income from continuing operations........................ 6138 47-- 71109 181 Discontinued operations, net of income taxes............. (1112) (~~931~~69) (~~139~~151) (1,~~151~~220) Cumulative effect of accounting changes, net of income taxes.................................................. -- -- -- (12) ----- ----- ------ ------- Net income (loss)........................................ $ 5026 $ (~~884~~69) $ (6842) $ (~~982~~1,051) ===== ===== ====== =======

See accompanying notes. 1 EL PASO CGP COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE AMOUNTS) (UNAUDITED)

~~JUNE~~SEPTEMBER 30, DECEMBER 31, 2004 2003 ------------- ------------ ASSETS Current assets Cash and cash equivalents................................. $ 86174 $ 150 Accounts and notes receivable Customers, net of allowance of $3431 in 2004 and $37 in 2003.................................................. ~~200~~220 291 Affiliates............................................. ~~436~~413 442 Other.................................................. ~~152~~115 86 Inventory................................................. 4955 55 Assets held for sale and from discontinued operations..... ~~172~~114 1,406 Other..................................................... 72105 220 ------- ------- Total current assets.............................. 1,~~167~~196 2,650 ------- ------- Property, plant and equipment, at cost Pipelines................................................. 6,~~701~~908 6,478 Natural gas and oil properties, at full cost.............. 7,~~244~~130 7,230 Power facilities.......................................... 373 372 Gathering and processing systems.......................... ~~144~~146 151 Other..................................................... 97 119 ------- ------- 14,~~559~~654 14,350 Less accumulated depreciation, depletion and amortization........................................... 87,~~092~~969 8,003 ------- ------- Total property, plant and equipment, net.......... 6,~~467~~685 6,347 ------- ------- Other assets Investments in unconsolidated affiliates.................. 1,~~187~~186 1,312 Assets from price risk management activities.............. -- 845 Goodwill and other intangible assets, net................. ~~415~~422 415 Assets of discontinued operations......................... -- 405 Other..................................................... ~~209~~243 435 ------- ------- 1,~~811~~851 3,412 ------- ------- Total assets...................................... $ 9,~~445~~732 $12,409 ======= =======

See accompanying notes. 2 EL PASO CGP COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS -- (CONTINUED) (IN MILLIONS, EXCEPT SHARE AMOUNTS) (UNAUDITED)

~~JUNE~~SEPTEMBER 30, DECEMBER 31, 2004 2003 ------------- ------------ LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities Accounts payable Trade.................................................. $ ~~163~~199 $ 196 Affiliates............................................. 8891 110 Other.................................................. ~~162~~209 201 Short-term financing obligations, including current maturities............................................. ~~349~~348 310 Notes payable to affiliates............................... 32126 906 Liabilities related to discontinued operations............ 3214 696 Other..................................................... ~~374~~467 363 ------- ------- Total current liabilities......................... 1,~~200~~454 2,782 ------- ------- Long-term financing obligations............................. 3,~~640~~636 5,011 ------- ------- Other Deferred income taxes..................................... ~~767~~807 732 Other..................................................... ~~423~~404 432 ------- ------- 1,~~190~~211 1,164 ------- ------- Commitments and contingencies Securities of subsidiaries.................................. ~~156~~155 107 ------- ------- Stockholder's equity Common stock, par value $1 per share; authorized and issued 1,000 shares.................................... -- -- Additional paid-in capital................................ 3,136 3,136 Retained earnings......................................... ~~156~~182 224 Accumulated other comprehensive loss...................... (3342) (15) ------- ------- Total stockholder's equity........................ 3,~~259~~276 3,345 ------- ------- Total liabilities and stockholder's equity........ $ 9,~~445~~732 $12,409 ======= =======

See accompanying notes. 3 EL PASO CGP COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS) (UNAUDITED)

~~SIX~~NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, ----------------------- 2003 2004 (RESTATED)(1) ------- ------------- Cash flows from operating activities Net loss.................................................. $ (6842) $ (~~982~~1,051) Less loss from discontinued operations, net of income taxes................................................. (~~139~~151) (1,~~151~~220) ------- ------- Net income before discontinued operations................. 71109 169 Adjustments to reconcile net income to net cash from operating activities Depreciation, depletion and amortization................ ~~228~~344 ~~242~~363 Loss (gain) on long-lived assets........................ 8894 (3125) Ceiling test charges.................................... -- 39 Earnings from unconsolidated affiliates, adjusted for cash distributions.................................... (126) 4465 Deferred income taxes................................... 3245 6433 Cumulative effect of accounting changes................. -- 12 Other non-cash items.................................... 1115 ~~(20)~~5 Asset and liability changes............................. 34109 ~~451~~476 ------- ------- Cash provided by continuing operations.................. ~~452~~710 ~~931~~1,137 Cash provided by discontinued operations................ ~~159~~188 9931 ------- ------- Net cash provided by operating activities.......... ~~611~~898 1,~~030~~168 ------- ------- Cash flows from investing activities Additions to property, plant and equipment................ (~~296~~562) (~~540~~761) Purchases of interests in equity investments.............. (12) (34) Net proceeds from the sale of assets and investments...... 8196 ~~293~~351 Net change in restricted cash............................. 3433 (4733) Net change in notes receivable from unconsolidated affiliates.............................................. 20(48) (~~259~~167) Other..................................................... 3135 2221 ------- ------- Cash used in continuing operations...................... (~~142~~458) (~~534~~593) Cash provided by discontinued operations................ 1,~~113~~141 ~~245~~298 ------- ------- Net cash provided by (used in) investing activities....................................... ~~971~~683 (~~289~~295) ------- ------- Cash flows from financing activities Payments to retire long-term debt and other financing obligations............................................. (~~460~~465) (~~297~~627) Net change in affiliated advances payable................. (~~896~~801) (~~682~~285) Proceeds from issuance of securities of subsidiaries...... 7475 -- Dividends paid............................................ -- (181) Net proceeds from the issuance of long-term debt and other financing obligations................................... -- 288 Contributions from discontinued operations................ ~~907~~964 ~~344~~329 Other..................................................... (1) 16 ------- ------- Cash used in continuing operations...................... (~~374~~228) (~~346~~470) Cash used in discontinued operations.................... (1,~~272~~329) (~~344~~329) ------- ------- Net cash used in financing activities.............. (1,~~646~~557) (~~690~~799) ------- ------- Change in cash and cash equivalents......................... ~~(64)~~24 5174 Cash and cash equivalents Beginning of period....................................... 150 128 ------- ------- End of period............................................. $ 86174 $ ~~179~~202 ======= =======

--------------- (1) Only individual line items in cash flows from operating activities have been restated. Total cash flows from continuing operating, investing and financing activities, as well as discontinued operations, were unaffected. See accompanying notes. 4 EL PASO CGP COMPANY CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (IN MILLIONS) (UNAUDITED)

QUARTER ENDED ~~SIX~~NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, ~~JUNE~~SEPTEMBER 30, ----------------- ----------------- 2003 2003 2004 (RESTATED) 2004 (RESTATED) ---- ---------- ---- ---------- Net income (loss)......................................... $ 5026 $(~~884~~69) $(6842) $(~~982~~1,051) ---- ----- ---- ------- Foreign currency translation adjustments.................. (1) 50-- (12) 90 Unrealized net gains (losses) from cash flow hedging activity Unrealized mark-to-market losses arising during period (net of income taxes of $78 and $1523 in 2004 and $1611 and $4029 in 2003)..................................... (12) ~~(28)~~19 (2638) (7253) Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $2 and $68 in 2004 and $8 and $3038 in 2003)............ 24 15 13 969 54 ---- ----- ---- ------- Other comprehensive income (loss).................. (119) 3534 (1827) 72106 ---- ----- ---- ------- Comprehensive income (loss)............................... $ 3917 $(~~849~~35) $(8669) $ (~~910~~945) ==== ===== ==== =======

See accompanying notes. 5 EL PASO CGP COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. BASIS OF PRESENTATION AND LIQUIDITY UPDATE Basis of Presentation We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). 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 this Quarterly Report on Form 10-Q along with our 2003 Annual Report on Form 10-K, which includes a summary of our significant accounting policies and other disclosures. The financial statements as of September 30, 2004, and for the quarters and nine months ended September 30, 2004 and 2003, are unaudited. We derived the balance sheet as of December 31, 2003, from the audited balance sheet filed in our 2003 Annual Report on Form 10-K. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our businesses, information for interim periods may not be indicative of the results of operations for the entire year. Our results for all periods presented have been reclassified to reflect our Canadian and certain other international natural gas and oil production operations as discontinued operations. Also, our results for the quarter and nine months ended September 30, 2003 have been restated to reflect the accounting impact of a reduction in our historically reported proved natural gas and oil reserves as further discussed in our 2003 Annual Report on Form 10-K. Finally, the prior period information presented in these financial statements includes reclassifications which were made to conform to the current period presentation. These reclassifications had no effect on our previously reported net income or stockholder's equity. Liquidity Update We rely on cash generated from our internal operations and loans from El Paso Corporation (El Paso), our direct parent, through its cash management program as our primary sources of liquidity, as well as proceeds from asset sales and capital contributions from El Paso. We expect that our future funding for working capital needs, capital expenditures and debt service will continue to be provided from some or all of these sources. Under El Paso's cash management program, we have historically and consistently borrowed cash. From August 2004 until November 2004, one of our subsidiaries, Colorado Interstate Gas Company (CIG), did not advance funds to El Paso via the cash management program due to its anticipated cash needs. With the completion of El Paso's new credit agreement as further discussed below, CIG began participating in the program once again. For a further discussion of our participation in El Paso's cash management program, see Note 11. During 2004, El Paso restated its historical financial statements to reflect the accounting impact of revisions to its natural gas and oil reserve estimates and changes in the manner in which it accounted for certain derivative contracts, primarily those related to the hedging of its natural gas production. Based on its belief that the restatements would cause a delay in filing its financial statements and that the representations and warranties related to its historical financial statements and its debt to total capitalization ratio would not be accurate, El Paso obtained waivers and amended its previous revolving credit facility (under which some of our subsidiaries were eligible borrowers and also served as collateral for the facility) and various other financing arrangements. El Paso has filed its financial statements within the time frames provided by these waivers. In November 2004, El Paso replaced its previous revolving credit facility with a new credit agreement with a group of lenders for an aggregate of $3 billion in financings. The new credit agreement consists of a $1.25 billion term loan, a $750 million funded letter of credit facility, and a $1 billion revolving credit facility. Upon closing of the new credit agreement, El Paso borrowed $1.25 billion under the term loan and utilized the $750 million letter of credit facility and approximately $0.4 billion of the $1 billion revolving credit facility to replace approximately $1.2 billion of letters of credit issued under its previous revolving credit facility. Our 6 subsidiaries, ANR Pipeline Company (ANR) and CIG, continue to be eligible borrowers under the new credit agreement. Additionally, our interests in ANR, CIG, Wyoming Interstate Company Ltd. (WIC), and ANR Storage Company continue to be pledged as collateral under the new credit agreement. For a further discussion of El Paso's new credit agreement and other information regarding our financing obligations, see Note 7. 2. SIGNIFICANT ACCOUNTING POLICIES Our significant accounting policies are discussed in our 2003 Annual Report on Form 10-K. The information below provides updating information or required interim disclosures with respect to those policies or disclosure where our policies have changed. Consolidation of Variable Interest Entities In January 2003, the Financial Accounting Standards Board (FASB) issued Financial Interpretation (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 or a controlling financial interest in the entity. This standard requires a company to consolidate a variable interest entity if it is allocated a majority of the entity's losses or returns, including fees paid by the entity. In December 2003, the FASB issued FIN No. 46-R, which amended FIN No. 46 to extend its effective date until the first quarter of 2004 for all types of entities, except special purpose entities. In addition, FIN No. 46-R limited the scope of FIN No. 46 to exclude certain joint ventures or other entities that meet the characteristics of businesses. On January 1, 2004, we adopted this standard. Upon adoption, we consolidated Blue Lake Gas Storage Company. The overall impact of this action is described in the following table:

Blue Lake Gas Storage Company owns and operates a 47 Bcf gas storage facility in Michigan. One of our subsidiaries operates the natural gas storage facility and we inject and withdraw all natural gas stored in the facility. We own a 75 percent equity interest in Blue Lake. As of September 30, 2004, Blue Lake has $9 million of third party debt that is non-recourse to us. We consolidated Blue Lake because we are allocated a majority of its losses and returns through our equity interest. We have significant interests in a number of other variable interest entities. We were not required to consolidate these entities under FIN No. 46 and, as a result, our method for accounting for these entities did not change. As of September 30, 2004, these entities consisted primarily of 10 equity investments held in our Power segment that had interests in power generation and transmission facilities with a total generating capacity of approximately 3,000 gross MW. We operate many of these facilities but do not supply a significant portion of the fuel consumed or purchase a significant portion of the power generated by these facilities. The long-term debt issued by these entities is recourse only to the power project. As a result, our exposure to these entities is limited to our equity investments in and advances to the entities (approximately $818 million as of September 30, 2004) and our guarantees and other agreements associated with these entities (a maximum of $42 million as of September 30, 2004). 7 Accounting for Asset Retirement Obligations On January 1, 2003, we adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations. This standard required that we record a liability for retirement and removal costs of long-lived assets used in our businesses. In 2003, we recorded a charge as a cumulative effect of accounting change of approximately $12 million, net of income taxes related to its adoption. New Accounting Pronouncements Not Yet Adopted Accounting for Natural Gas and Oil Producing Activities. In September 2004, the SEC issued Staff Accounting Bulletin No. 106. This pronouncement will require companies that use the full cost method for accounting for their oil and gas producing activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of depreciation, depletion and amortization. It will also require these companies to exclude future cash outflows associated with settling asset retirement liabilities from their full cost ceiling test calculation. Finally, this standard will require disclosure of the impact of a company's asset retirement obligations on its oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. We will adopt the provisions of this pronouncement in the first quarter of 2005 and are currently evaluating its impact, if any, on our consolidated financial statements. Accounting for Inventory Costs. In November 2004, the FASB issued SFAS No. 151, Inventory Costs, an amendment of ARB No. 43, Chapter 4. This statement clarifies the types of costs that should be expensed rather than capitalized as inventory. This statement also clarifies the circumstances under which fixed overhead costs associated with operating facilities involved in inventory processing should be capitalized. The provisions of SFAS No. 151 are effective for fiscal years beginning after June 15, 2005, and may impact certain inventory costs we incur after January 1, 2006. We are currently evaluating the impact, if any, of this standard on our consolidated financial statements. Accounting for Deferred Taxes on Foreign Earnings. In December 2004, the FASB is expected to issue FASB Staff Position (FSP) No. 109-2, Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Job Creation Act of 2004. FSP No. 109-2 will amend the existing accounting literature that requires companies to record deferred taxes on foreign earnings, unless they intend to indefinitely reinvest those earnings outside the U.S. This pronouncement will temporarily allow companies that are evaluating whether to repatriate foreign earnings under the American Jobs Creation Act of 2004 to delay recognizing any related taxes until that decision is made. This pronouncement will also require companies that are considering repatriating earnings to disclose the status of their evaluation and the potential amounts being considered for repatriation. The U.S. Treasury Department has not issued final guidelines for applying the repatriation provisions of the American Jobs Creation Act. We continue to evaluate this legislation and FSP No. 109-2 to determine whether we will repatriate any foreign earnings and the impact, if any, that this pronouncement will have on our consolidated financial statements. 8 3. DIVESTITURES Sales of Assets and Investments During the nine months ended September 30, 2004, we completed the sale of a number of assets and investments. The following table summarizes the proceeds from these sales (in millions): Production.................................................. $ 24 - Brazilian exploration and production assets Power....................................................... 92 - Utility Contract Funding (UCF) - Mohawk River Funding IV - Bastrop power investment Field Services - Dauphin Island and Mobile Bay equity investments........ 3 ------ Total continuing............................................ 119(1) Discontinued................................................ 1,289 - Natural gas and oil production properties in Canada and other international production assets - Aruba and Eagle Point refineries and other petroleum assets(2) ------ Total....................................................... $1,408 ======

--------------- (1) Proceeds exclude returns of invested capital and cash transferred with the assets sold and include costs incurred in preparing assets for disposal. These items decreased our sales proceeds by $23 million for the nine months ended September 30, 2004. Proceeds also exclude any non-cash consideration received in these sales. (2) We sold an additional $2 million of petroleum assets in the fourth quarter of 2004. 9

~~COMPLETED COMPLETED THROUGH AFTER JUNE 30, 2004~~ SIGNIFICANT ASSETS AND INVESTMENTS SOLD ~~JUNE~~PROCEEDS ~~30, 2004 OR ANNOUNCED TO DATE(1) TOTAL~~ --------------------------------------- --------~~-----~~ ~~----------------------- -----~~ (IN MILLIONS) ~~Unregulated~~Through ~~Production~~September 30, 2003 Pipelines................................................. $ 82 -- ~~$24~~Panhandle $gathering 24system located in Texas - ~~Brazilian~~2.1 ~~exploration~~percent equity interest in Alliance pipeline and ~~production~~related assets~~(2)~~ ~~Power~~- Helium processing operations in Oklahoma - Table Rock sulfur extraction facility - Horsham pipeline in Australia Production.................................................. 92164 -- 92Natural -gas ~~Utility~~and ~~Contract~~oil ~~Funding~~properties ~~(UCF)(3)~~in -New ~~Mohawk~~Mexico, ~~River~~Texas, ~~Funding~~Louisiana ~~IV(3)~~and -the ~~Bastrop~~Gulf ~~Company~~of ~~equity~~Mexico ~~investment(3)~~- Drilling rigs Field Services............................................ 94 - ~~Dauphin~~Gathering ~~Island~~systems ~~and~~located ~~Mobile~~in ~~Bay~~Wyoming ~~equity~~ -- 3Midstream 3assets ~~investments(4)~~in the Mid-Continent region Corporate................................................. ~~------~~3 --- Aircraft ------ Total continuing............................................ 92343(41) ~~27 119~~ Discontinued................................................ ~~1,261~~655 30- ~~1,291~~Corpus Christi refinery - ~~Natural~~Florida ~~gas~~petroleum terminals and ~~oil~~tug ~~production~~and ~~properties~~barge inoperations ~~Canada(3)~~- Louisiana lease crude business - ~~Aruba~~Coal reserves and ~~Eagle~~properties ~~Point~~in ~~refineries~~West ~~and~~Virginia, ~~other~~Virginia ~~petroleum~~and ~~assets(3)~~Kentucky - ~~Remaining~~Natural ~~Canadian~~gas and ~~other~~oil ~~international~~ production ~~assets(2)~~properties ~~------~~in Canada --- Petroleum asphalt facilities ------ Total....................................................... $~~1,353~~ ~~$57~~998 ~~$1,410~~ =====~~= === ======~~

--------------- (1) Proceeds include costs incurred in preparing assets for disposal and exclude returns of invested capital and cash transferred with the assets sold. These items increased our sales proceeds by $8 million for the nine months ended September 30, 2003. See Notes 4 and 11 for a discussion of gains, losses and asset impairments related to the sales above. 10 Discontinued Operations Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we classify assets being disposed of as held for sale or, if appropriate, discontinued operations if they have received appropriate approvals by El Paso's management or Board of Directors and have met other criteria. International Natural Gas and Oil Production Operations. During 2004, our Canadian and certain other international natural gas and oil production operations were approved for sale. As of November 2004, we have completed the sale of all of our Canadian operations and substantially all of our operations in Indonesia for total proceeds of approximately $389 million. During the nine months ended September 30, 2004, we recognized approximately $98 million in realized losses on asset sales and asset impairments based on El Paso's decision to sell these assets. We expect to complete the sale of the remainder of these properties in early 2005. Petroleum Markets. During 2003, El Paso's Board of Directors approved the sales of our petroleum markets businesses and operations. These businesses and operations consisted of our Eagle Point and Aruba refineries, our asphalt business, our Florida terminal, tug and barge business, our lease crude operations, our Unilube blending operations, our domestic and international terminalling facilities and our petrochemical and chemical plants. Based on our intent to dispose of these operations, we were required to adjust these assets to their estimated fair value. As a result, we recognized pre-tax impairment charges of approximately $1,337 million during the nine months ended September 30, 2003 related to these assets. These impairments were based on a comparison of the carrying value of these assets to their estimated fair value, less selling costs. We also recorded realized gains of approximately $59 million in the first nine months of 2003 from the sale of our Corpus Christi refinery, our asphalt assets and our Florida terminalling and marine assets. In the first and second quarters of 2004, we completed the sales of our Aruba and Eagle Point refineries for $880 million and used a portion of the proceeds to repay $370 million of debt associated with the Aruba refinery. These sales resulted in realized losses of approximately $37 million in the first nine months of 2004. In addition, in the first quarter of 2004, we reclassified our petroleum ship charter operations from discontinued operations to continuing operations in our financial statements based on our decision to retain these operations. Our financial statements for all periods presented reflect this change. Coal Mining. In 2002, El Paso's Board of Directors authorized the sale of our coal mining operations. These operations consisted of fifteen active underground and two surface mines located in Kentucky, Virginia and West Virginia. The sale of these operations was completed in 2003 for $92 million in cash and $24 million in notes receivable, which were settled in the second quarter of 2004. We did not record a significant gain or loss on these sales. Our petroleum markets, coal mining and other international natural gas and oil production operations discussed above are classified as discontinued operations in our financial statements for all of the historical periods presented. All of the assets and liabilities of these discontinued businesses are classified as current assets and liabilities as of September 30, 2004. The summarized financial results and financial position data of our discontinued operations were as follows: 11

~~SIGNIFICANT~~INTERNATIONAL ~~ASSETS~~NATURAL GAS AND ~~INVESTMENTS~~OIL ~~SOLD~~PETROLEUM ~~PROCEEDS~~PRODUCTION COAL MARKETS OPERATIONS MINING TOTAL --------- ------------- ------- ------- (IN MILLIONS) Operating Results Data QUARTER ENDED SEPTEMBER 30, 2004 Revenues................................................ $ 44 $ 1 $ -- $ 45 Costs and expenses...................................... (52) (4) -- (56) Gain (loss) on long-lived assets........................ 1 (5) -- (4) Other income............................................ 13 -- -- 13 ------- ------- ------- ------- Income (INloss) ~~MILLIONS~~before income taxes....................... 6 (8) As-- (2) Income taxes............................................ 10 -- -- 10 ------- ------- ------- ------- Loss from discontinued operations, net of ~~June~~income taxes................................................. $ (4) $ (8) $ -- $ (12) ======= ======= ======= ======= QUARTER ENDED SEPTEMBER 30, 2003 ~~Regulated Pipelines~~Revenues................................................. $ 63907 $ 20 $ -- ~~Panhandle~~$ ~~gathering~~927 ~~system~~Costs ~~located~~and inexpenses...................................... ~~Texas~~(953) (56) (1) (1,010) Gain (loss) on long-lived 2assets........................ 8 1 ~~percent~~(8) ~~equity~~1 ~~interest~~Other inexpense........................................... ~~Alliance~~(2) ~~pipeline~~-- -- (2) Interest and ~~related~~debt ~~assets~~expense............................... (4) 1 -- ~~Helium~~(3) ~~processing~~------- ~~operations~~------- in------- ~~Oklahoma~~------- Loss before income taxes................................ (44) (34) (9) (87) Income taxes............................................ (5) (13) -- ~~Table~~(18) ~~Rock~~------- ~~sulfur~~------- ~~extraction~~------- ~~facility~~------- ~~Unregulated~~Loss ~~Production~~from discontinued operations, net of income taxes................................................. ~~144~~$ -(39) ~~Natural~~$ ~~gas~~(21) ~~and~~$ ~~oil~~(9) ~~properties~~$ in(69) ~~New~~======= ~~Mexico~~======= ~~and~~======= ~~the~~======= ~~Gulf~~NINE ofMONTHS ~~Mexico~~ENDED ~~Field~~SEPTEMBER ~~Services~~30, 2004 Revenues................................................ 94$ 737 $ 29 $ -- ~~Gathering~~$ ~~systems~~766 ~~located~~Costs inand ~~Wyoming~~expenses...................................... (782) (51) -- ~~Midstream~~(833) Loss on long-lived assets............................... in(37) ~~the~~(98) ~~Mid~~-~~Continent~~- ~~region~~(135) Other income............................................ 12 -- -- ~~Total~~12 ~~continuing~~Interest and debt expense............................... (3) 1 -- (2) ------- ------- ------- ------- Loss before income taxes................................ ~~301~~(73) (119) -- (192) Income taxes............................................ 1 (42) ~~Discontinued~~-- (41) ------- ------- ------- ------- Loss from discontinued operations, net of income taxes................................................. ~~581~~$ -(74) ~~Corpus~~$ ~~Christi~~(77) ~~refinery~~$ -- ~~Florida~~$ ~~petroleum~~(151) ~~terminals~~======= ~~and~~======= ~~tug~~======= ~~and~~======= ~~barge~~NINE ~~operations~~MONTHS -ENDED ~~Louisiana~~SEPTEMBER ~~lease~~30, ~~crude~~2003 ~~business~~Revenues................................................ -$ ~~Coal~~4,586 ~~reserves~~$ ~~and~~66 ~~properties~~$ in27 ~~West~~$ ~~Virginia~~4,679 ~~Virginia~~Costs and ~~Kentucky~~expenses...................................... (4,697) (103) (22) (4,822) Loss on long-lived ~~Natural~~assets............................... ~~gas~~(1,278) (13) (11) (1,302) Other income (expense).................................. (16) -- 1 (15) Interest and ~~oil~~debt ~~production~~expense............................... ~~properties~~(8) in2 ~~Canada~~-- (6) ------- ~~Total~~------- ------- ------- Loss before income taxes................................ (1,413) (48) (5) (1,466) Income taxes............................................ (231) (16) 1 (246) ------- ------- ------- ------- Loss from discontinued operations, net of income taxes................................................. $~~882~~(1,182) $ (32) $ (6) $(1,220) ======= ======= ======= =======

INTERNATIONAL NATURAL GAS AND OIL PETROLEUM PRODUCTION ~~COAL~~ MARKETS OPERATIONS ~~MINING~~ TOTAL --------- ------------- ------ -~~------~~ (IN MILLIONS) ~~Operating~~Financial ~~Results~~Position Data ~~QUARTER~~SEPTEMBER ~~ENDED JUNE~~ 30, 2004 ~~Revenues~~Assets of discontinued operations Accounts and notes receivable............................. $ 49 $ 1 $ 50 Inventory................................................. $8 ~~54 $ 1 $~~ -- $8 55Other ~~Costs~~current ~~and expenses~~assets...................................... ~~(77)~~1 ~~(3)~~1 --2 ~~(80)~~Property, ~~Gain~~plant onand ~~long-lived~~equipment, ~~assets~~net........................ 422 --6 --28 4 Other ~~income~~non-current assets..................................~~...~~ 126 -- --26 1 ------- ----- ---- ------- ~~Loss~~Total ~~before~~assets........................................... ~~income~~$ ~~taxes~~106 $ 8 $ 114 ======= ======= ======= Liabilities of discontinued operations Accounts payable.......................................... ~~(18)~~$ ~~(2)~~5 $ -- ~~(20)~~$ ~~Income~~5 ~~taxes~~Other current liabilities................................. 5 -- 5 Other non-current liabilities............................. ~~(3)~~4 ~~(6)~~ -- ~~(9)~~4 ------- ----- ---- ------- ~~Income~~Total ~~(loss) from discontinued operations, net of income taxes~~liabilities...................................... $ ~~(15)~~14 $ ~~4 $~~ -- $ ~~(11)~~14 ======= ===== ==== ======= ~~QUARTER~~DECEMBER ~~ENDED JUNE 30~~31, 2003 ~~Revenues~~Assets of discontinued operations Accounts and notes receivable............................. $ 259 $ 22 $ 281 Inventory............ ~~$ 1,511 $ 20 $ -- $ 1,531 Costs and expenses~~..................................... ~~(1,612)~~385 ~~(33)~~3 --388 ~~(1,645)~~Other ~~Loss~~current ~~on long-lived~~ assets........................ ~~(990) (5) -- (995) Other expense~~.............. 131 8 139 Property, plant and equipment, net........................ ~~(21)~~521 --399 --920 ~~(21)~~Other ~~Interest~~non-current ~~and debt expense~~assets.................................. ~~(4)~~70 --6 --76 ~~(4)~~ ------- ----- ---- ------- ~~Loss~~Total ~~before income taxes~~assets(1)........................................ ($ 1,~~116)~~366 ~~(18)~~$ --438 ($ 1,~~134)~~804 ~~Income~~======= ~~taxes~~======= ======= Liabilities of discontinued operations Accounts payable.......................................... ~~(198)~~$ ~~(5)~~172 $ 38 $ 210 Other current liabilities................................. 86 -- ~~(203)~~86 Long-term debt............................................ 374 -- 374 Other non-current liabilities............................. 26 3 29 --- ----- ------- ------- ~~Loss~~Total ~~from discontinued operations, net of income taxes~~liabilities......................................~~....~~ $ ~~(918)~~658 $ ~~(13)~~41 $ --699 ~~$ (931)~~ ======= ===== ==== =======

--------------- (1) We also had $7 million of current assets held for sale related to a domestic power plant in our Power segment as of December 31, 2003. We did not have any assets held for sale as of September 30, 2004. 4. LOSS (GAIN) ON LONG-LIVED ASSETS Our loss (gain) on long-lived assets consists of realized gains and losses on sales of long-lived assets and impairments of long-lived assets, goodwill and other intangible assets that are a part of our continuing operations. During each of the periods ended September 30, our loss (gain) on long-lived assets was as follows:

~~INTERNATIONAL~~NINE ~~NATURAL~~MONTHS ~~GAS~~QUARTER ~~AND~~ENDED ~~OIL~~ENDED ~~PETROLEUM~~SEPTEMBER ~~PRODUCTION~~30, ~~COAL~~SEPTEMBER ~~MARKETS~~30, ~~OPERATIONS MINING TOTAL~~ --------- ----- -------- ------ ~~-------~~2004 ~~(IN~~2003 ~~MILLIONS) SIX MONTHS ENDED JUNE 30,~~ 2004 ~~Revenues.........................................~~2003 ~~$ 693 $ 28 $~~ -- ~~$ 721 Costs and expenses............................... (730) (47)~~ -- ~~(777) Loss on long~~-~~lived~~ ~~assets........................ (38) (93)~~ -- ~~(131) Other expense.................................... (1)~~ -- -- ~~(1) Interest and debt expense........................ (3) 1~~ -- ~~(2)~~ ---~~----~~ ----- ~~---- ------- Loss before income taxes.........................~~ (~~79)~~IN ~~(111~~MILLIONS) --Net ~~(190)~~realized ~~Income taxes~~gain..................................... ~~(9) (42) -- (51) ------- ----- ---- ------- Loss from discontinued operations, net of income taxes~~..~~........................................~~ $ (702) $ (694) $ ~~-- $~~ (~~139~~5) ~~======= ===== ==== ======= SIX MONTHS ENDED JUNE 30, 2003 Revenues.........................................~~ $ ~~3,679 $ 46 $ 27 $ 3,752 Costs and expenses...............................~~ (~~3,744~~35) ~~(47)~~Asset ~~(21) (3,812) Loss on long-lived assets~~impairments........................ ~~(1,286) (14) (3) (1,303) Other income (expense)~~...............~~............~~ ~~(14)~~8 --10 199 ~~(13)~~10 ~~Interest and debt expense........................ (4) 1~~ -- ~~(3)~~ -~~------~~ ----- ---- ----~~---~~ ~~Income~~Loss (~~loss~~gain) ~~before~~on ~~income taxes................ (1,369) (14) 4 (1,379) Income taxes..................................... (226) (3) 1 (228)~~ long-~~------~~lived ~~----- ---- ------- Income (loss) from discontinued operations, net of income taxes~~assets......................~~..........~~ $~~(1,143)~~ 6 $ ~~(11)~~6 $94 3 $(~~1,151~~25) ===~~====~~ ===== ==== ====~~===~~

13 Our 2004 loss on long-lived assets occurred primarily in our Power segment, where we recognized an $89 million impairment in the first quarter of 2004 related to the sale of UCF, which owned a restructured power contract. We also recorded a $6 million impairment charge in the third quarter of 2004 on our CDECCA power plant to adjust its carrying value to the expected sales proceeds. Our 2003 gains on long-lived assets were primarily related to a $19 million gain recorded in the second quarter of 2003 on the sale of our Mid-Continent midstream assets in our Field Services segment, a $2 million gain on aircraft sales associated with our corporate operations, a $6 million gain on the sale of our Table Rock sulfur extraction facility in the second quarter of 2003 and a $2 million gain on the sale of our Horsham pipeline in the third quarter of 2003 in our Pipelines segment. Our Production segment also recorded a $5 million gain on the sale of non-full cost pool assets in the second quarter of 2003 and a $10 million impairment in the third quarter of 2003 related to a crude oil pipeline. 5. PRICE RISK MANAGEMENT ACTIVITIES The following table summarizes the carrying value of the derivatives used in our price risk management activities as of September 30, 2004 and December 31, 2003. In the table, derivatives designated as hedges primarily consist of instruments used to hedge our natural gas and oil production. Derivatives from power contract restructuring activities relate to power purchase and sale agreements that arose from our activities in that business.

~~INTERNATIONAL~~SEPTEMBER ~~NATURAL~~30, ~~GAS~~DECEMBER ~~AND~~31, ~~OIL~~2004 ~~PETROLEUM~~2003 ~~PRODUCTION MARKETS OPERATIONS TOTAL~~ --------- ---- --------- ---~~---~~ (IN MILLIONS) ~~Financial~~Net ~~Position~~assets ~~Data~~(liabilities) ~~JUNE~~Derivatives ~~30,~~designated ~~2004~~as ~~Assets of discontinued operations Accounts and notes receivable~~hedges.................... ~~$ 60 $ 11 $ 71 Inventory~~......~~..................................~~ 7$(191) --$(124) 7Derivatives ~~Other~~from ~~current~~power ~~assets~~contract restructuring activities(1)............................. ~~7 2 9 Property, plant and equipment, net~~............... ~~22 33 55 Other non~~-~~current assets......................... 23~~ -- 23942 ------ ---- -~~-----~~ ~~Total~~Net assets~~...................................~~ ~~$ 119 $ 46 $ 165 ====== ==== ====== Liabilities of discontinued operations Accounts payable................................. $ 12 $ -- $ 12 Other current~~ (liabilities~~........................~~) 14from --price 14risk ~~Other~~management ~~non-current liabilities~~activities(2).................... ~~6 -- 6 ------ ---- ------ Total liabilities~~....................~~..........~~ $(191) 32 $ --818 ~~$ 32~~ ====== ==== =~~=====~~

--------------- (1) We sold our subsidiaries that own these derivative contracts in 2004. (2) Included in non-current assets from price risk management activities, other non-current liabilities and other current assets and liabilities in our balance sheet. 6. INVENTORY We had $55 million of inventory as of September 30, 2004 and December 31, 2003, of which the majority was materials and supplies. 14 7. DEBT, OTHER FINANCING OBLIGATIONS AND OTHER CREDIT FACILITIES Long-Term Financing Obligations From January 1, 2004 through the date of this filing, we had the following changes in our long-term financing obligations:

~~INTERNATIONAL~~NET ~~NATURAL~~INCREASE/ ~~GAS~~REDUCTION ~~AND~~COMPANY ~~OIL~~TYPE ~~PETROLEUM~~INTEREST ~~PRODUCTION~~RATE ~~MARKETS~~PRINCIPAL ~~OPERATIONS~~IN ~~TOTAL~~DEBT DUE DATE ------- ---- ------------- --------- ------------- -------- (IN MILLIONS) ~~DECEMBER~~Issuances ~~31,~~and ~~2003~~other ~~Assets~~increases ofBlue ~~discontinued~~Lake ~~operations~~Gas ~~Accounts~~Storage(1) ~~and~~Non-recourse ~~notes~~term ~~receivable....................~~loan $LIBOR ~~259~~+ 1.2% $ 2214 $ ~~281~~14 ~~Inventory........................................~~2006 ~~385~~------ 3------ ~~388~~Increase ~~Other~~through ~~current~~September ~~assets~~30, 2004...............~~..............~~ ~~131~~$ 814 ~~139~~$ ~~Property~~14 ====== ====== Repayments, ~~plant~~repurchases and ~~equipment,~~other ~~net~~retirements El Paso CGP Note LIBOR + 3.5% $ 200 $ 200 El Paso CGP Note 6.2% 190 190 El Paso CGP Recourse note 8.~~............~~5% ~~521~~45 ~~399~~45 ~~920~~Mohawk ~~Other~~River ~~non~~Funding IV(2) Non-~~current~~recourse ~~assets~~note 7.75% 72 72 UCF(2) Non-recourse senior notes 7.~~.......................~~944% 70815 6815 76Other Long-term debt Various 30 30 ----- -~~---~~ ------ ~~Total~~Decreases ~~assets~~through September 30, 2004..............~~.....................~~ $1,~~366~~352 ~~$438 $~~1,~~804~~352 ~~======~~El ~~====~~Paso ~~======~~CGP ~~Liabilities~~Note of6.5% ~~discontinued~~91 ~~operations~~94 ~~Accounts~~El ~~payable.................................~~Paso $CGP ~~172~~Note $7.5% 3855 $58 ~~210~~El ~~Other~~Paso ~~current~~CGP ~~liabilities~~Notes 10.~~.......................~~25% 8638 --38 86Other Long-term debt~~...................................~~ ~~374~~Various --3 ~~374 Other non-current liabilities.................... 26~~ 3 29 ------ ---- --~~----~~ ~~Total~~Decreases ~~liabilities~~through date of filing..................~~............~~ $1,539 ~~658~~ $1,545 ~~41 $ 699~~ ====== ==== ==~~====~~

--------------- (1) This debt was consolidated as a result of adopting FIN No. 46 (see Note 2). (2) This debt was eliminated when we sold our interests in Mohawk River Funding IV and UCF. Credit Facilities In November 2004, El Paso replaced its previous revolving credit facility with a new credit agreement with a group of lenders for an aggregate of $3 billion in financings. The new credit agreement consists of a $1.25 billion term loan, a $750 million funded letter of credit facility, and a $1 billion revolving credit facility. Upon closing of the new credit agreement, El Paso borrowed $1.25 billion under the term loan and utilized the $750 million letter of credit facility and approximately $0.4 billion of the $1 billion revolving credit facility to replace approximately $1.2 billion of letters of credit issued under its previous revolving credit facility. Our subsidiaries, ANR and CIG, continue to be eligible borrowers under the new credit agreement. Additionally, our interests in ANR, CIG, WIC, and ANR Storage Company continue to be pledged as collateral under the new credit agreement. Restrictive Covenants Our restrictive covenants are discussed in our 2003 Annual Report on Form 10-K. For an update of matters that have or could impact these covenants, including the restatements of El Paso's and our historical financial statements and associated waivers obtained, see Note 1. 8. COMMITMENTS AND CONTINGENCIES Legal Proceedings Grynberg. A number of our subsidiaries were named defendants in actions filed in 1997 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 15 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 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). 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 are named as defendants in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands and seek to recover royalties that they contend they 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, attorneys' 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 of a nationwide class of natural gas working interest owners and natural gas royalty owners was denied in April 2003. Plaintiffs' were granted leave to file a Fourth Amended Petition, which narrows the proposed class to royalty owners in wells in Kansas, Wyoming and Colorado and removes claims as to heating content. A second class action has since been filed as to the heating content claims. Our costs and legal exposure related to these lawsuits and claims are not currently determinable. MTBE. In compliance with the 1990 amendments to the Clean Air Act, we used the gasoline additive methyl tertiary-butyl ether (MTBE) in some of our gasoline. We have also produced, bought, sold and distributed MTBE. A number of lawsuits have been filed throughout the U.S. regarding MTBE's potential impact on water supplies. We and our subsidiaries are currently one of several defendants in 59 such lawsuits nationwide, which have been or are in the process of being consolidated for pre-trial purposes in multi-district litigation in the U.S. District Court for the Southern District of New York. The plaintiffs generally seek remediation of their groundwater, prevention of future contamination, a variety of compensatory damages, punitive damages, attorney's fees, and court costs. Our costs and legal exposure related to these lawsuits are not currently determinable. Reserves. We have been named as a defendant in a purported class action claim styled, GlickenHaus & Co. et. al. v. El Paso Corporation, El Paso CGP Company, et. al., filed in April 2004 in federal court in Houston. The plaintiffs have additionally sued several individuals. The plaintiffs generally allege that our reporting of oil and gas reserves was materially false and misleading between February 2000 and February 2004. This lawsuit has been consolidated with other purported securities class action lawsuits in Oscar S. Wyatt et. al. v. El Paso Corporation et. al. pending in federal court in Houston. Our costs and legal exposure related to this lawsuit and claims are not currently determinable. Governmental Investigations Power Restructuring. In October 2003, El Paso announced that the SEC had authorized the staff of the Fort Worth Regional Office to conduct an investigation of certain aspects of our periodic reports filed with the SEC. The investigation appears to be focused principally on our power plant contract restructurings and the related disclosures and accounting treatment for the restructured power contracts, including in particular the Eagle Point restructuring transaction completed in 2002. We are cooperating with the SEC investigation. Reserve Revisions. In March 2004, El Paso received a subpoena from the SEC requesting documents relating to its December 31, 2003 natural gas and oil reserve revisions. El Paso and its Audit Committee have also received federal grand jury subpoenas for documents with regard to those reserve revisions. We are assisting El Paso and its Audit Committee in their efforts to cooperate with the SEC's and the U.S. Attorney's investigations of this matter. 16 Storage Reporting. In April 2004, our affiliates elected to voluntarily cooperate with the Commodity Futures Trading Commission (CFTC) in connection with the CFTC's industry-wide investigation of activities affecting the price of natural gas in the fall of 2003. Specifically, our affiliates provided information relating to storage reports provided to the Energy Information Administration (EIA) for the period of October 2003 through December 2003. In August 2004, the CFTC announced they had completed the investigation and found no evidence of wrongdoing. In November 2004, ANR received a data request from the FERC in connection with its investigation into the weekly storage withdrawal number reported by the EIA for the eastern region on November 24, 2004, that was subsequently revised downward by the EIA. Specifically, ANR provided information on its weekly EIA submissions, which was unrevised subsequent to its original submissions. Although ANR made a correction to one daily posting on its electronic bulletin board during this period, those postings are unrelated to EIA submissions. In December 2004, ANR received a similar data request from the CFTC. We are cooperating with the CFTC's request. Iraq Oil Sales. In September 2004, we received a subpoena from the grand jury of the U.S. District Court for the Southern District of New York to produce records regarding the United Nations' Oil for Food Program governing sales of Iraqi oil. The subpoena seeks various records relating to transactions in oil of Iraqi origin during the period from 1995 to 2003. In November 2004, we received an order from the SEC to provide a written statement and to produce certain documents in connection with the Oil for Food Program. We have also received an inquiry from the United States Senate's Permanent Subcommittee of Investigations related to a specific transaction in 2000. In September 2004, the Special Advisor to the Director of Central Intelligence issued a report on the Iraqi regime, including the Oil for Food Program. In part, the report found that the Iraqi regime earned kick backs or surcharges associated with the Oil for Food program. The report did not name U.S. companies or individuals for privacy reasons, but according to various news reports congressional sources have identified The Coastal Corporation (Coastal) and the former chairman and CEO of Coastal, among others, as having purchased Iraqi crude during the period when allegedly improper surcharges were assessed by Iraq. We are cooperating with investigations of this matter by the U.S. Attorney, the SEC and the Senate Subcommittee. 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. There are also other regulatory rules and orders in various stages of adoption, review and/or implementation, none of which we believe will have a material impact on us. 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 this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate. As of September 30, 2004, we had approximately $31 million accrued for all outstanding legal matters. Environmental Matters We are subject to 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 September 30, 2004, we had accrued approximately $127 million, including approximately $126 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $1 million for related environmental legal costs, which we anticipate incurring through 2027. Of the $127 million accrual, $86 million was reserved for facilities we currently operate, and $41 million was reserved for non-operating sites (facilities that are shut down or have been sold) and Superfund sites. 17 Our reserve estimates range from approximately $127 million to approximately $199 million. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($35 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($92 million to $164 million) and if no one amount in that range is more likely than any other, the lower end of the range has been accrued. By type of site, our reserves are based on the following estimates of reasonably possible outcomes.

~~SIX~~SEPTEMBER ~~MONTHS QUARTER ENDED ENDED JUNE~~ 30, ~~JUNE~~2004 ~~30,~~ -------------- ----~~--------~~ ~~2004~~SITES ~~2003~~EXPECTED ~~2004~~HIGH ~~2003~~ ----- ----- ---- ----- (IN MILLIONS) ~~Net realized gain~~Operating................................................... $ ~~(2)~~86 $~~(30)~~126 $Non-operating............................................... ~~(3)~~37 ~~$(31)~~64 ~~Asset impairments~~Superfund................................................... 24 --9 91 -- ---- ---- ~~---- ---- Loss (gain) on long-lived assets~~Total..................................................... $127 -- $~~(30)~~199 ~~$ 88 $(31)~~ ==== ==== ~~==== ====~~

Below is a reconciliation of our accrued liability from January 1, 2004 to September 30, 2004 (in millions): Balance as of January 1, 2004............................... $131 Additions/adjustments for remediation activities............ 3 Payments for remediation activities......................... (11) Other charges, net.......................................... 4 ---- Balance as of September 30, 2004............................ $127 ====

For the remainder of 2004, we estimate that our total remediation expenditures will be approximately $8 million. In addition, we expect to make capital expenditures for environmental matters of approximately $29 million in the aggregate for the years 2004 through 2008. These expenditures primarily relate to compliance with clean air regulations. 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 27 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 September 30, 2004, we have estimated our share of the remediation costs at these sites to be between $4 million and $9 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 estimating our liabilities. Accruals for these issues are included in the previously indicated estimates for Superfund sites. 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. 18 Rates and Regulatory Matters Proposed Release Regarding Pipeline Integrity Cost. In November 2004, the FERC issued an industry-wide Proposed Accounting Release that, if enacted as written, would require our interstate pipelines to expense rather than capitalize certain costs that are part of our pipeline integrity program. The accounting release is proposed to be effective January 2005 following a period of public comment on the release. We are currently reviewing the release and have not determined the impact, if any, this release will have on our consolidated financial statements. Inquiry Regarding Income Tax Allowances. On December 2, 2004, the Federal Energy Regulatory Commission (FERC) issued a notice of inquiry in response to a recent D.C. Circuit decision that held the FERC had not adequately justified its policy of providing a certain oil pipeline limited partnership with an income tax allowance equal to the proportion of its limited partnership interests owned by corporate partners. The FERC seeks comments on whether the court's reasoning should be applied to other partnerships or other ownership structures. We own interests in non-taxable entities that could be affected by this ruling. We cannot predict what impact this inquiry will have on our interstate pipelines, including those pipelines that are not owned by a corporate entity, such as Great Lakes Gas Transmission Limited Partnership which is jointly owned with unaffiliated parties. While the outcome of these matters cannot be predicted with certainty, we believe we have established appropriate reserves for these matters. However, it is possible that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly. The impact of these changes may have a material effect on our results of operations, our financial position and our cash flows in the periods these events occur. Guarantees We are involved in various joint ventures and other ownership arrangements that sometimes require additional financial support that results in the issuance of financial and performance guarantees that are further described in our 2003 Report on Form 10-K. As of September 30, 2004, we had approximately $11 million of both financial and performance guarantees not otherwise reflected in our consolidated financial statements. 9. RETIREMENT BENEFITS The components of net benefit cost (income) for our pension and postretirement benefit plans for the periods ended September 30 are as follows:

~~JUNE~~QUARTER ENDED SEPTEMBER 30, ~~DECEMBER~~NINE 31MONTHS ENDED SEPTEMBER 30, ------------------------------ -------------------------------- OTHER OTHER PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS ------------ -------------- -------------- -------------- 2004 2003 2004 2003 2004 2003 2004 2003 ---- ---- ----- ----- ----- ----- ----- ----- (IN MILLIONS) ~~Net~~Service ~~assets (liabilities) Derivatives designated as hedges~~cost.......................... $~~(161)~~-- $~~(124)~~ ~~Derivatives~~1 ~~from~~$-- ~~power~~$-- ~~contract~~$-- ~~restructuring~~$ ~~activities(1)~~2 $-- $-- Interest cost....................... 2 2 2 2 4 4 4 5 Expected return on plan assets......~~.............~~ --(2) ~~942~~(2) ~~-----~~(1) ~~-----~~(1) ~~Net~~(4) ~~assets~~(5) (~~liabilities~~2) ~~from~~(2) ~~price~~Amortization ~~risk~~of ~~management~~net ~~activities(2)~~actuarial loss.............................. -- -- -- (1) -- -- -- (1) Settlements, curtailment, and special termination benefits...... -- -- -- -- -- -- -- (6) --- --- --- --- --- --- --- --- Net benefit cost (income)......... $-- $ 1 $ 1 $-- $-- $ 1 $ 2 $(~~161~~4) $=== ~~818~~=== === === === === === ===

We made $10 million of cash contributions to our other postretirement plans during the nine months ended September 30, 2004 and $11 million of cash contributions during the nine months ended September 30, 2003. We expect to contribute an additional $3 million to our other postretirement plans during the remainder of 2004 and do not anticipate making any other contributions to our other retirement benefit 19 plans in 2004. We are currently evaluating the impact of the Pension Funding Equity Act enacted in 2004 on our projected funding. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law. Benefit obligations and costs reported that are related to prescription drug coverage do not reflect the impact of this legislation. In addition, we will adopt a new accounting standard in the fourth quarter of 2004 (FSP No. 106-2) that we believe will not materially affect our previously reported benefit information and our net benefit cost for the year ending December 31, 2004. 10. SEGMENT INFORMATION During 2004, El Paso reorganized its business structure into two primary business lines, regulated and unregulated. Historically, our operating segments included Pipelines, Production, Merchant Energy and Field Services. As a result of El Paso's reorganization, we renamed our Merchant Energy segment as our Power segment. All periods presented reflect this change in segments. Our regulated business consists of our Pipelines segment, while our unregulated businesses consist of our Production, Power and Field Services segments. Our segments are strategic business units that provide a variety of energy products and services. They are managed separately as each segment requires different technology and marketing strategies. Our corporate operations include our general and administrative functions as well as other unregulated operations, including our petroleum ship charter operations and various other contracts and assets. During the first quarter of 2004, we reclassified our petroleum ship charter operations from discontinued operations to continuing corporate operations. During the second quarter of 2004, we reclassified our Canadian and certain other international natural gas and oil production operations from our Production segment to discontinued operations in our consolidated financial statements. Our operating results for all periods presented reflect these changes. 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 net income (loss) adjusted for (i) items that do not impact our income (loss) from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) distributions on preferred interests of consolidated subsidiaries. Our business operations consist of both consolidated businesses as well as substantial investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to more effectively evaluate the performance of all of our businesses and investments. Also, we exclude interest and debt expense and distributions on preferred interests of consolidated subsidiaries so that investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow. Below is a reconciliation of our EBIT to our income from continuing operations for the periods ended September 30:

~~JUNE~~NINE MONTHS QUARTER ENDED ENDED SEPTEMBER 30, ~~DECEMBER~~SEPTEMBER 3130, ~~2004 2003~~ -------------- ------------- ~~(IN~~2004 ~~MILLIONS)~~2003 ~~Current~~2004 ~~maturities~~2003 of----- ~~long~~-~~term~~----- ~~debt~~----- ~~and~~----- ~~other~~(IN ~~financing~~MILLIONS) ~~obligations~~Total EBIT............................................~~...~~ $129 ~~348~~$ 99 $ ~~310~~438 ~~Short-term~~$ ~~financing~~597 ~~obligations~~Interest and debt expense............................. 1(75) --(104) ~~------~~(267) ~~------~~(304) ~~Total~~Affiliated ~~short-term~~interest ~~financing~~income ~~obligations~~(expense), net............. 5 (11) (4) (25) Distributions on preferred interests of consolidated subsidiaries........................................ $-- ~~349~~(1) ~~$ 310 ====== ====== Long~~-~~term~~- ~~financing~~(15) ~~obligations~~Income taxes.......................................... (21) 17 (58) (72) ---- ----- ----- ----- Income from continuing operations................ $~~3,640~~ 38 $~~5,011~~ -- $ 109 $ 181 ==== ===== ===== =====

20 The following tables reflect our segment results for the periods ended September 30:

~~NET~~REGULATED ~~INCREASE/~~UNREGULATED ~~REDUCTION~~--------- ~~COMPANY~~----------------------------- ~~TYPE~~FIELD ~~INTEREST~~QUARTER ~~RATE~~ENDED ~~PRINCIPAL~~SEPTEMBER IN30, ~~DEBT~~PIPELINES ~~DUE~~PRODUCTION ~~DATE~~POWER SERVICES CORPORATE(1) TOTAL ------- ---- ---------------- --------- ---------- ----- -------- ------------ --------- (IN MILLIONS) ~~Issuances~~2004 ~~and~~Revenues ~~other~~from ~~increases~~external ~~Blue~~customers............. ~~Lake~~$186 ~~Gas~~$ ~~Storage~~151(2) $ 28 $139 $ 14 $ 518 Intersegment revenues........................ 1 14 -- -- (15) ~~Non~~-~~recourse~~- ~~term~~Operation ~~loan~~and ~~LIBOR~~maintenance.................... +68 146 25 6 2 147 Depreciation, depletion and amortization..... 31 78 3 2% 2 116 (Gain) loss on long-lived assets............. (1) -- 5 2 -- 6 Operating income (loss)...................... $ 1458 $ 31 $(10) $ 14 ~~2006~~$ (2) $ 91 Earnings from unconsolidated affiliates...... 16 (1) 2 5 -- 22 Other income, net............................ 6 1 7 -- 2 16 ---- ------ ~~Increases~~---- ~~through~~---- ~~June~~---- ~~30,~~--------- ~~2004~~EBIT......................................... $ 1480 $ 1431 $ (1) $ 19 $ -- $ 129 ==== ====== ==== ==== ~~Repayments~~==== ~~and~~========= ~~other~~2003 ~~retirements~~Revenues Elfrom ~~Paso~~external ~~CGP~~customers............. ~~Note~~$192 ~~LIBOR~~$ +141(2) ~~3.5%~~ $ ~~200~~59 $ ~~200~~69 El$ ~~Paso~~10 ~~CGP~~$ ~~Note~~471 6Intersegment revenues.2%....................... ~~190~~1 ~~190~~42 El-- ~~Paso~~-- ~~CGP~~(18) ~~Recourse~~25(3) ~~note~~Operation 8and maintenance.5%................... 4557 4549 ~~Mohawk~~31 ~~River~~6 ~~Funding IV~~(26) ~~Non-recourse~~137 ~~note~~Depreciation, 7depletion and amortization.~~75%~~.... 7227 7286 ~~Utility~~3 ~~Contract~~2 ~~Funding~~3 121 (2Gain) ~~Non-recourse~~loss ~~senior~~on ~~notes~~long-lived 7assets.~~944%~~............ ~~815~~(2) ~~815~~10 ~~Other~~1 ~~Long~~-~~term~~- ~~debt~~(3) ~~Various~~6 25Ceiling 25test charges......................... -- 39 -- -- --~~----~~ ~~Decreases~~39 ~~through~~Operating ~~June~~income ~~30, 2004~~(loss)...................... ~~1,347~~$ ~~1,347~~75 El$ ~~Paso~~(6) ~~CGP~~$ ~~Notes~~(2) 10$ 8 $ 4 $ 79 Earnings (losses) from unconsolidated affiliates.~~25%~~................................ 3815 382 ~~Other~~(7) ~~Long~~(2) -~~term~~- ~~debt~~8 ~~Various~~Other income (expense), net.................. 2 -- 5 -- 5 12 ---- ------ ---- ---- ---- --------- EBIT......................................... $~~1,390~~ 92 $~~1,390~~ (4) $ (4) $ 6 $ 9 $ 99 ==== ====== ==== ==== ==== =========

~~JUNE~~REGULATED UNREGULATED --------- ----------------------------- FIELD NINE MONTHS ENDED SEPTEMBER 30, ~~2004~~PIPELINES PRODUCTION POWER SERVICES CORPORATE(1) TOTAL ------------------------------- ~~SITES~~--------- ~~EXPECTED~~---------- ~~HIGH~~----- -------- ------------ --------- (IN MILLIONS) ~~Operating~~2004 Revenues from external customers............. $612 $ 476(2) $127 $301 $ 44 $ 1,560 Intersegment revenues........................ 1 35 -- 1 (37) -- Operation and maintenance.................... 181 123 70 18 2 394 Depreciation, depletion and amortization..... 91 234 9 4 6 344 (Gain) loss on long-lived assets............. (1) -- 92 3 -- 94 Operating income (loss)...................... $239 87$ 135 $~~139~~(84) ~~Non~~$ 35 $ 3 $ 328 Earnings (losses) from unconsolidated affiliates................................. 55 (3) 20 9 -~~operating~~- 81 Other income, net............................ 7 1 16 -- 5 29 ---- ------ ---- ---- ---- --------- EBIT......................................... 39$301 66$ ~~Superfund~~133 $(48) $ 44 $ 8 $ 438 ==== ====== ==== ==== ==== ========= 2003 Revenues from external customers............. $694 $ 565(2) $189 $270 $ 28 $ 1,746 Intersegment revenues........................ -- 99 -- 25 (47) 77(3) Operation and maintenance.................... 173 129 79 21 (4) 7398 Depreciation, depletion and amortization..... 82 256 10 6 9 363 (Gain) loss on long-lived assets............. (11) 5 1 (18) (2) (25) Ceiling test charges......................... -- 39 -- -- -- ~~Total~~39 Operating income (loss)...................... $317 $ 190 $ 41 $ 47 $(16) $ 579 Earnings (losses) from unconsolidated affiliates................................. 54 3 20 (84) -- (7) Other income, net............................ -- 2 11 -- 12 25 ---- ------ ---- ---- ---- --------- EBIT......................................... $~~130~~371 $~~212~~ 195 $ 72 $(37) $ (4) $ 597 ==== ====== ==== ==== ==== =========

--------------- (1) Includes our corporate activities, petroleum ship charter operations, various other contracts and assets 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 "Corporate" column, to remove intersegment transactions. 21 (2) Revenues from external customers include gains and losses related to our hedging of price risk associated with our natural gas and oil production. (3) Relates to intercompany activities between our continuing operations and our discontinued operations. Total assets by segment are presented below:

~~QUARTER~~SEPTEMBER ~~ENDED JUNE~~ 30, ~~SIX~~DECEMBER ~~MONTHS ENDED JUNE 30~~31, ------------------------------ ------------------------------ OTHER OTHER PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS ------------ -------------- ------------ -------------- 2004 2003 ~~2004 2003 2004 2003 2004 2003~~ ---- ---- ----- ----- ---- ---- ~~----- -----~~ (IN MILLIONS) ~~Service~~Regulated ~~cost~~Pipelines................................................ $--5,739 $-- ~~$--~~5,395 ~~$--~~Unregulated ~~$-- $ 1 $-- $-- Interest cost~~Production............................................... ~~1 1 1 1~~ 2,151 2,334 ~~2 3 Expected return on plan assets~~Power.................................................... (1),012 ~~(1) -- -- (~~2~~) (3) (1) (1) Settlements~~,121 ~~curtailment,~~Field ~~and special termination benefits~~Services........................................... --298 --224 -- -- -- -- -- ~~(6)~~ --- ~~---~~Total ~~---~~segment ~~---~~assets.................................. ~~---~~9,200 ~~---~~10,074 ~~---~~Corporate.................................................. ~~---~~418 ~~Net~~531 ~~benefit~~Discontinued ~~cost (income)~~operations.................................... $114 1,804 -- $-- ~~$ 1 $ 1 $~~-- $------- $Total 1consolidated assets............................. $~~(4)~~9,732 ~~===~~$12,409 === === === === =~~== === ===~~

11. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS We hold investments in various unconsolidated affiliates which are accounted for using the equity method of accounting. The summarized financial information below includes our proportionate share of the operating results of our unconsolidated affiliates, including affiliates in which we hold a less than 50 percent interest as well as those in which we hold a greater than 50 percent interest.

~~SIX~~NINE MONTHS ENDED QUARTER ENDED ~~ENDED~~SEPTEMBER ~~JUNE~~ 30, ~~JUNE~~SEPTEMBER 30, --------------------------- --------------------------- ~~2004~~GREAT ~~2003~~OTHER ~~2004~~GREAT ~~2003~~OTHER LAKES INVESTMENTS TOTAL LAKES INVESTMENTS TOTAL ----- ----------- ----- ----- ----------- ----- (IN MILLIONS) ~~Total~~2004 ~~EBIT~~Operating results data: Operating revenues...............~~................................~~ $~~179~~31 $~~181~~195 $~~309~~226 $~~498~~99 ~~Interest~~$513 ~~and~~$612 ~~debt~~Operating ~~expense~~expenses............... 15 170 185 41 429 470 Income from continuing operations.................... ~~(91)~~9 ~~(101)~~8 ~~(192)~~17 ~~(200)~~33 ~~Affiliated~~30 ~~interest~~63 ~~income~~Net income(~~expense~~1)~~, net~~.................... 59 ~~(7)~~8 ~~(9)~~17 ~~(14)~~33 ~~Distributions~~30 on63 ~~preferred~~2003 ~~interests~~Operating ofresults ~~consolidated~~data: ~~subsidiaries~~Operating revenues............... $31 $167 $198 $96 $501 $597 Operating expenses...............~~.............~~ --15 ~~(7)~~151 --166 43 404 447 Income (14loss) ~~Income~~from ~~taxes~~continuing operations....................~~.........................~~ ~~(32)~~7 (192) ~~(37)~~5 ~~(89)~~27 ~~----~~31 ~~----~~58 ~~----~~Net ~~----~~income ~~Income from continuing operations~~(loss)(1).............~~......~~ $7 61(2) $5 4727 $31 ~~71 $181 ==== ==== ==== ====~~58

--------------- (1)Includes net income of $3 million for each of the quarters ended September 30, 2004 and 2003, and $18 million and $11 million for the nine months ended September 30, 2004 and 2003, related to our proportionate share of affiliates in which we hold a greater than 50 percent interest. 22 Our income statement reflects our share of net earnings (losses) from unconsolidated affiliates, which includes income or losses directly attributable to the net income or loss of our equity investments as well as impairments and other adjustments. The table below reflects our earnings (losses) from unconsolidated affiliates for the periods ended September 30:

~~REGULATED~~NINE ~~UNREGULATED~~MONTHS ~~--------- ----------------------------- FIELD~~ QUARTER ENDED ~~JUNE~~ENDED SEPTEMBER 30, ~~PIPELINES~~SEPTEMBER ~~PRODUCTION~~30, ~~POWER SERVICES CORPORATE(1) TOTAL~~ -------------~~---------~~ --------- -----~~-----~~ 2004 2003 2004 2003 ----- ----~~----~~ -----~~-------~~ ----- (IN MILLIONS) ~~2004~~Proportional ~~Revenues~~share ~~from~~of ~~external~~income ~~customers~~of investees............... $~~189~~17 $~~174(2)~~5 $4563 $ 8358 $Impairment 14charges ~~$505~~and ~~Intersegment~~gains ~~revenues~~and losses on sale of investments Dauphin Island/Mobile Bay impairment(1)...............~~........~~ -- 9-- -- 1 (1080) --Other ~~Operation~~gains and ~~maintenance~~impairment charges................... ~~54 38 22 6 -- 120 Depreciation, depletion and amortization~~.~~...~~ ~~30 80~~ 2 ~~1 2 115 Loss (gain) on long~~-~~lived assets............~~ -- --5 (1) ~~1 -- -- Operating income~~Other............................ ~~$ 71 $ 59 $ 6 $ 10 $ 2 $148 Earnings from unconsolidated affiliates~~..... ~~17 -- 6 1 -- 24 Other income, net~~..................~~.........~~ 13 --3 413 --14 ~~2 7~~ ---- ---- --- ---- ~~----~~Total ~~----~~earnings ~~EBIT~~(losses) from unconsolidated affiliates............................................ $22 89 $8 59 $1681 $ 11(7) ~~$ 4 $179~~ ==== ==== === ==== ~~==== ====~~

--------------- (1) This impairment resulted from the anticipated sales of these investments, which were completed in the third quarter of 2004. We received distributions and dividends from our investments of $29 million for both of the quarters ended September 30, 2004 and 2003, and $76 million and $60 million for the nine months ended September 30, 2004 and 2003. In January 2004, we also received $54 million of non-cash assets and liabilities as a liquidating distribution of our equity investment in Noric Holdings I, LLC. We did not recognize any gain or loss on this distribution. Related Party Transactions We enter into a number of transactions with our unconsolidated affiliates in the ordinary course of conducting our business. The following table shows the income statement impact of transactions with our affiliates for the periods ended September 30:

~~REGULATED~~NINE ~~UNREGULATED~~MONTHS ~~--------- ----------------------------- FIELD~~ QUARTER ENDED ~~JUNE~~ENDED SEPTEMBER 30, ~~PIPELINES~~SEPTEMBER ~~PRODUCTION~~30, ~~POWER SERVICES CORPORATE(1) TOTAL~~ -------------~~---------~~ --------- ----~~------~~ 2004 2003 2004 2003 ----- -----~~---~~ -----~~-------~~ ----- (IN MILLIONS) ~~2003~~Operating ~~Revenues from external customers............ $209 $206(2) $71 $ 87 $ 10 $583 Intersegment~~ revenues....................... ~~-- 27 -- 12 (18) 21(3) Operation and maintenance~~................~~...~~ 58$232 45$228 21$637 6$877 2Cost ~~132~~of ~~Depreciation,~~products ~~depletion~~ and ~~amortization~~services.... ~~27 87 3 2 2 121 Loss (gain) on long-lived assets~~............ ~~(9) (5) -- (17) 1 (30) Operating income (loss)~~............~~.........~~ $52 8922 $82 9369 ~~$31~~Operation $and ~~27 $(12) $228 Earnings (losses) from unconsolidated affiliates~~maintenance................................ 1647 ~~(2)~~68 12153 ~~(81)~~226 ~~1 (54)~~ Other income~~, net~~........................... ~~1 2 1 -- 3 7 ---- ---- --- ---- ---- ---- EBIT~~.................. 3 3 10 11 Reimbursement for operating expenses...................... ~~$106~~1 $-- 932 ~~$44 $(54) $ (8) $181 ==== ==== === ==== ==== ====~~--

We are a party to a master hedging contract with El Paso Marketing, L.P., (EPM), a wholly-owned subsidiary of El Paso, which was formerly known as El Paso Merchant Energy L.P. Pursuant to that agreement, we hedge a portion of our natural gas production with EPM. Realized gains and losses on these hedges are included in operating revenues. In September 2004, El Paso restated its financial statements for the manner in which it accounted for certain hedges of our anticipated natural gas production. While the restatement did not directly affect our financial statements, its effects were that many of the financial instruments that hedge commodity price risk in our financial statements did not qualify as hedges in El Paso's consolidated financial statements. We have historically hedged a portion of our anticipated natural gas and oil production with affiliates of El Paso, and it has been El Paso's intent that these positions qualify as hedges in El Paso's consolidated financial statements. As a result, we executed a series of transactions in order to make our hedge relationships consistent with El Paso's consolidated hedge relationships following the restatement. 23 On December 1, 2004, through these transactions, we replaced existing hedges on approximately 51 TBtu of natural gas with new hedge transactions at the same volume and over the same time period. The combination of our original hedges and the new transactions will not change the average price at which we are hedged and will not have an impact on our realized prices. As a result, these transactions will have the same overall impact on our accumulated other comprehensive income balances, cash flow and income statement as our original derivative positions that existed prior to December 1, 2004. However, these transactions "locked in" a pre-tax loss of approximately $180 million in accumulated other comprehensive income that will be recognized in earnings as our original hedged transactions settle in 2005. We have also entered into a service agreement with El Paso that provides for a reimbursement of 2.5 cents per MMBtu in 2005 for our expected administrative costs associated with these transactions. Affiliated Receivables and Payables. 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. We have historically and consistently borrowed cash from El Paso under this program. From August 2004 until November 2004, one of our subsidiaries, CIG, did not advance funds to El Paso via the cash management program due to its anticipated cash needs. With the completion of El Paso's new credit agreement, CIG began participating in the program once again. As of September 30, 2004 and December 31, 2003, we had borrowed $126 million and $906 million. The interest rate as of September 30, 2004, and December 31, 2003, was 2.7% and 2.8%. In addition, we had a demand note receivable with El Paso of $374 million and $275 million at September 30, 2004 and December 31, 2003. The interest rate for this demand note receivable was approximately 2.5% at September 30, 2004 and 1.7% at December 31, 2003. At September 30, 2004, and December 31, 2003, we had current accounts and notes receivable from related parties of $39 million and $167 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 $110 million and $127 million included in other non-current assets at September 30, 2004 and at December 31, 2003. At September 30, 2004, and December 31, 2003, we had other accounts payable to related parties of $91 million and $110 million. These balances were incurred in the normal course of business. Other. During the first quarter of 2004, Coastal Stock Company, our wholly-owned subsidiary, issued 68,000 shares of its Class A Preferred Stock to a subsidiary of El Paso for $71 million. We included the proceeds from the issuance of these shares as securities of subsidiaries in our balance sheet. 24 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 Annual Report on 2003 Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q. During the second quarter of 2004, we reclassified our historical Canadian and certain other international natural gas and oil production operations from our Production segment to discontinued operations in our financial statements for all periods presented. In addition, our results for the quarter and nine months ended September 30, 2003 have been restated to reflect the accounting impact of a reduction in our historically reported proved natural gas and oil reserves as further discussed in our 2003 Annual Report on Form 10-K. LIQUIDITY AND CAPITAL RESOURCES LIQUIDITY We rely on cash generated from our internal operations and loans from El Paso through its cash management program as our primary sources of liquidity, as well as proceeds from asset sales and capital contributions from El Paso. We expect that our future funding for working capital needs, capital expenditures and debt service will continue to be provided from some or all of these sources. Under El Paso's cash management program, we have historically and consistently borrowed cash. From August 2004 until November 2004, one of our subsidiaries, CIG, did not advance funds to El Paso via the cash management program due to its anticipated cash needs. With the completion of El Paso's new credit agreement as further discussed below, CIG began participating in the program once again. For a further discussion of our participation in El Paso's cash management program, see Item 1, Financial Statements, Note 11. During 2004, El Paso restated its historical financial statements to reflect the accounting impact of revisions to its natural gas and oil reserve estimates and changes in the manner in which it accounted for certain derivative contracts, primarily those related to the hedging of its natural gas production. Based on its belief that the restatements would cause a delay in filing its financial statements and that the representations and warranties related to its historical financial statements and its debt to total capitalization ratio would not be accurate, El Paso obtained waivers and amended its previous revolving credit facility (under which some of our subsidiaries were eligible borrowers and also served as collateral for the facility) and various other financing arrangements. El Paso has filed its financial statements within the time frames provided by these waivers. In November 2004, El Paso replaced its previous revolving credit facility with a new credit agreement with a group of lenders for an aggregate of $3 billion in financings. The new credit agreement consists of a $1.25 billion term loan, a $750 million funded letter of credit facility, and a $1 billion revolving credit facility. Upon closing of the new credit agreement, El Paso borrowed $1.25 billion under the term loan and utilized the $750 million letter of credit facility and approximately $0.4 billion of the $1 billion revolving credit facility to replace approximately $1.2 billion of letters of credit issued under its previous revolving credit facility. Our subsidiaries, ANR and CIG, continue to be eligible borrowers under the new credit agreement. Additionally, our interests in ANR, CIG, WIC, and ANR Storage Company continue to be pledged as collateral under the new credit agreement. For a further discussion of El Paso's new credit agreement and other information regarding our financing obligations, see Item 1, Financial Statements, Note 7. We believe we will be able to meet our ongoing liquidity and cash needs through a combination of sources, including cash on hand, cash generated from our operations, proceeds from asset sales, financing activities and advances from El Paso. However, a number of factors could influence our liquidity sources, as well as the timing and ultimate outcome of our ongoing efforts and plans, which are discussed in our 2003 Annual Report on Form 10-K. 25 OVERVIEW OF CASH FLOW ACTIVITIES FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004 AND 2003 For the nine months ended September 30, 2004 and 2003, our cash flows from continuing operations are summarized as follows:

~~REGULATED~~2004 ~~UNREGULATED~~2003 -----~~----~~ ------~~-----------------------~~ ~~FIELD SIX MONTHS ENDED JUNE 30, PIPELINES PRODUCTION POWER SERVICES CORPORATE~~(~~1) TOTAL ------------------------- --------- ---------- ----- -------- ------------ ------ (~~IN MILLIONS) ~~2004~~Cash ~~Revenues~~flows from ~~external~~operating ~~customers~~activities............ ~~$426 $325(2) $ 99 $162 $ 30 $1,042 Intersegment revenues~~............~~...........~~ -- 21 -- 1 (22) -- Operation and maintenance................... 113 77 45 12 -- 247 Depreciation, depletion and amortization.... 60 156 6 2 4 228 Loss on long-lived assets................... -- -- 87 1 -- 88 Operating income (loss)..................... $~~181~~ ~~$104~~710 $~~(74) $ 21 $ 5 $ 237 Earnings (losses) from unconsolidated affiliates................................ 39 (2) 18 4 -- 59 Other income~~1,137 ~~net...........................~~Cash 1flows ~~-- 9 -- 3 13 ---- ---- ---- ---- ---- ------ EBIT........................................ $221 $102 $(47) $ 25 $ 8 $ 309 ==== ==== ==== ==== ==== ====== 2003 Revenues~~ from ~~external~~investing ~~customers~~activities............ ~~$502 $438(2) $130 $201 $ 18 $1,289 Intersegment revenues~~............~~...........~~ (1458) ~~43 -- 25~~ (29593) ~~38(3)~~Cash ~~Operation~~flows and maintenance................... 116 80 48 15 2 261 Depreciation, depletion and amortization.... 55 170 7 4 6 242 Loss (gain) on long-lived assets............ (9) (5) -- (18) 1 (31) Operating income (loss)..................... $242 $196 $ 43 $ 39 $(20) $ 500 Earnings (losses) from ~~unconsolidated~~financing ~~affiliates~~activities........................~~........~~ ~~39 1 27~~ (82228) -- (15470) Other income (expense), net................. (2) 2 6 -- 7 13 ---- ---- ---- ---- ---- ------ EBIT........................................ $279 $199 $ 76 $(43) $(13) $ 498 ==== ==== ==== ==== ==== ======

Cash from Continuing Operating Activities Net cash generated from our continuing operating activities was $0.7 billion during the first nine months of 2004 versus $1.1 billion during the same period in 2003. We experienced a $0.4 billion decline in 2004 in cash generated from our operations primarily as a result of sales of operating assets during both 2003 and 2004 and the effects on operations of lower capital spending in our Production segment. Cash from Continuing Investing Activities Net cash used by our continuing investing activities was $0.5 billion for the nine months ended September 30, 2004, due to $0.6 billion in capital expenditures partially offset by $0.1 billion of proceeds from the sale of assets and investments. Our capital expenditures for the nine months ended September 30, 2004 are as follows (in billions):

~~JUNE 30, DECEMBER 31, 2004 2003 -------- ------------ (IN MILLIONS) Regulated~~ Pipelines................................................... $~~5,486~~0.4 ~~$ 5,395 Unregulated~~ Production................................................ ~~2,198 2,334 Power~~..~~...................................................~~ ~~1,009~~ 0.2~~,121~~ ~~Field Services............................................ 234 224~~ ------ ~~-------~~ Total ~~segment assets~~................................... ~~8,927 10,074 Corporate~~...............~~....................................~~ ~~353 531 Discontinued operations~~$0.~~....................................~~6 ~~165 1,804 ------ ------- Total consolidated assets.............................. $9,445 $12,409~~ ====~~== =======~~

For the remainder of 2004, we expect our total capital expenditures to be approximately $0.3 billion, which includes approximately $0.2 billion for our Pipelines segment and $0.1 billion for our Production segment. Cash from Continuing Financing Activities Net cash used in our continuing financing activities for the nine months ended September 30, 2004 primarily consisted of payments on affiliated notes payable of $0.8 billion and payments to retire long-term debt and other financing obligations of $0.5 billion. Offsetting these uses of cash were the proceeds received from El Paso primarily related to the issuance of the preferred stock of Coastal Stock Company, our wholly-owned subsidiary and $1.0 billion of cash contributed by our discontinued operations as further discussed below. We reflect the net cash generated by our discontinued operations as a cash inflow to our continuing financing activities. Cash from Discontinued Operations During the first nine months of 2004, our discontinued operations contributed $1.0 billion of cash. We generated $0.2 billion in cash in these operations and received $1.2 billion of proceeds from the sales of our Eagle Point and Aruba refineries and our western Canada production operations. These inflows were offset by $0.4 billion of repayments of long-term debt related to the Aruba refinery. 26 SEGMENT RESULTS Below are our results of operations (as measured by EBIT) by segment. During 2004, El Paso reorganized its business structure into two primary business lines, regulated and unregulated. Historically, our operating segments included Pipelines, Production, Merchant Energy and Field Services. As a result of El Paso's reorganization, we renamed our Merchant Energy segment as our Power segment. All periods presented reflect this change in segments. Our regulated business consists of our Pipelines segment, while our unregulated businesses consist of our Production, Power and Field Services segments. Our segments are strategic business units that provide a variety of energy products and services. They are managed separately as each segment requires different technology and marketing strategies. Our corporate operations include our general and administrative functions as well as other unregulated activities, including our petroleum ship charter operations and various other contracts and assets. During the first quarter of 2004, we reclassified our petroleum ship charter operations from discontinued operations to continuing corporate operations. During the second quarter of 2004, we reclassified our Canadian and certain other international natural gas and oil production operations from our Production segment to discontinued operations in our consolidated financial statements. Our operating results for all periods presented reflect these changes. 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 net income (loss) adjusted for (i) items that do not impact our income (loss) from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) distributions on preferred interests of consolidated subsidiaries. Our business operations consist of both consolidated businesses as well as substantial investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to more effectively evaluate the performance of all of our businesses and investments. Also, we exclude interest and debt expense and distributions on preferred interests of consolidated subsidiaries so that investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow. Below is a reconciliation of our consolidated EBIT to our consolidated net income (loss) for the periods ended September 30:

NINE MONTHS QUARTER ENDED ~~JUNE~~ENDED SEPTEMBER 30, ~~SIX~~SEPTEMBER ~~MONTHS ENDED JUNE~~ 30, -------------- --------------- 2004 2003 2004 2003 ----- ------ ----- -------~~-------~~ ~~GREAT~~(IN ~~OTHER~~MILLIONS) ~~GREAT~~Regulated ~~OTHER~~Businesses ~~LAKES~~Pipelines................................................. ~~INVESTMENTS~~$ ~~TOTAL~~80 ~~LAKES~~$ ~~INVESTMENTS~~92 ~~TOTAL~~$ 301 $ 371 Unregulated Businesses Production................................................ 31 (4) 133 195 Power..................................................... (1) (4) (48) 72 Field Services............................................ 19 6 44 (37) ----- ----- ------ ------- Segment EBIT............................................ 129 90 430 601 Corporate................................................... -- 9 8 (4) ---- ----- ------ ------- ~~(IN~~Consolidated ~~MILLIONS)~~EBIT ~~2004~~from ~~Operating~~continuing ~~results~~operations............ ~~data:~~129 ~~Operating~~99 ~~revenues~~438 597 Interest and debt expense................................... ~~$32~~(75) ~~$184~~(104) ~~$216~~(267) ~~$68~~(304) $Affiliated ~~318~~interest $income ~~386~~(expense), ~~Operating expenses~~net................... 135 ~~156~~(11) ~~169~~(4) 26(25) ~~259~~Distributions ~~285~~on ~~Income~~preferred ~~from~~interests ~~continuing~~of ~~operations~~consolidated subsidiaries.............................................. 11-- 5(1) 16-- ~~24 22 46 Net income~~(115) Income taxes................................................ 11(21) 517 16(58) 24(72) 22---- 46----- ~~2003~~----- ~~Operating~~------- ~~results~~Income ~~data:~~from ~~Operating~~continuing ~~revenues~~operations......................... ~~$30~~38 ~~$176~~-- ~~$206~~109 ~~$65~~181 $Discontinued ~~334~~operations, $net ~~399~~of ~~Operating~~income ~~expenses~~taxes................ 14(12) ~~134~~(69) ~~148~~(151) 28(1,220) ~~253~~Cumulative ~~281~~effect ~~Income~~of ~~from~~accounting ~~continuing~~changes, ~~operations~~net of income taxes..................................................... 7-- -- -- (12) 19---- 20----- 33----- 53------- Net income (1loss)......................................... 7$ 1226 19$ 20(69) 33$ 53(42) $(1,051) ==== ===== ===== =======

27 The following is a discussion of the comparative quarterly and nine month period results of each of our business segments as well as our corporate operations; interest and debt expense; affiliated interest income (expense), net; distributions on preferred interests of consolidated subsidiaries; income taxes and the results of our discontinued operations. REGULATED BUSINESSES -- PIPELINES SEGMENT Our Pipelines segment owns and operates our interstate natural gas transmission businesses. For a further discussion of the business activities of our Pipelines segment, see our 2003 Annual Report on Form 10-K. Below are the operating results and analysis of these results for our Pipelines segment for the periods ended September 30:

QUARTER ENDED ~~SIX~~NINE MONTHS ~~JUNE~~ENDED SEPTEMBER 30, ~~ENDED~~SEPTEMBER ~~JUNE~~ 30, ---------------- ------------------ PIPELINES SEGMENT RESULTS 2004 2003 2004 2003 ------------------------- ------ ------ ------- ------- (IN MILLIONS), ~~Proportional~~EXCEPT ~~share~~VOLUME ofAMOUNTS) ~~income~~Operating ~~of investees~~revenues.............................. $16 187 $ 19193 $46 613 $ 53694 ~~Impairment~~Operating ~~charges and gains and losses on sale of investments Dauphin Island/Mobile Bay impairment(1)~~expenses.............................. --(129) (80118) --(374) (80377) ~~Other~~------ ~~gains,~~------ ~~net~~------ ------ Operating income..............................~~.......~~ 358 175 3239 1317 Other income....................................~~..............~~ 522 617 1062 1154 ------ ------ ------ ------ ~~Total earnings (losses) from unconsolidated affiliates~~EBIT........................................... $24 80 $~~(54)~~ 92 $59 301 $ 371 ====== ====== ====== ====== Throughput volumes (15BBtu/d)(1).................. 7,334 7,334 7,960 8,219 ====== ====== ====== ======

--------------- (1) Throughput volumes exclude intrasegment activities. Operating Results (EBIT) Some of the key items affecting our Pipelines segment operations for the periods ending September 30, 2004 include the impact on revenues and operating expenses of our efforts to recontract available capacity, the impact of selling excess fuel over the amount needed to operate the facilities and higher operating costs. The following contributed to our overall EBIT decrease of $12 million and $70 million for the quarter and nine months ended September 30, 2004 as compared to the same periods ended September 30, 2003:

QUARTER ENDED ~~SIX~~SEPTEMBER ~~MONTHS JUNE~~ 30, NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, --------------------------------------- --------------------------------------- ~~2004~~REVENUE ~~2003~~EXPENSE ~~2004~~OTHER ~~2003~~EBIT IMPACT REVENUE EXPENSE OTHER EBIT IMPACT ------- ------- ----- ----------- ------- ------- ----- ----------- FAVORABLE/(UNFAVORABLE) FAVORABLE/(UNFAVORABLE) (IN MILLIONS) ~~Operating~~(IN ~~revenues~~MILLIONS) Contract modifications/terminations..... $(9) $ 10 $ -- $ 1 $(64) $37 $ -- $(27) Fuel recoveries, net of gas used........................... 7 (11) -- (4) (13) (12) -- (25) Table Rock facility sold in 2003........................... ~~$212~~-- ~~$338~~-- ~~$405~~-- ~~$580~~-- ~~Cost~~-- (6) -- (6) Replacement of ~~sales~~storage gas loss in 2004........................ -- -- -- -- -- (6) -- (6) Change to regulated depreciation method......................... 15-- 29(2) 30-- 69(2) ~~General,~~-- ~~administrative~~(7) ~~and~~-- ~~other~~(7) ~~expenses~~Higher overhead allocation....... -- (5) -- (5) -- (1) -- (1) Equity earnings from Great Lakes........ ~~55 78 106 158 Other income~~.................. -- -- 3 3 -- -- 8 8 Other............................ (4) (3) 2 (5) (4) 7(2) 8-- ~~Reimbursement~~(6) ~~for~~--- ~~operating~~---- ~~expenses~~----- ---- ---- --- ----- ---- Total...................... 1$(6) --$(11) 1$ --5 $(12) $(81) $ 3 $ 8 $(70) === ==== ===== ==== ==== === ===== ====

Our contract modifications/terminations include the renegotiation or restructuring of several contracts on our pipeline systems, including our contracts with ANR's customer, We Energies. The modification of the We Energies contracts will continue to unfavorably impact our operating results and EBIT for the remainder of 2004, among other items noted below. Guardian Pipeline, which is owned in part by We Energies, is 28 currently providing a portion of its firm transportation requirements and directly competes with ANR for a portion of the markets in Wisconsin. Additionally, ANR will continue to experience lower operating revenues and lower operating expenses for the remainder of 2004 based on the termination of the Dakota gasification facility contract on its system. However, the termination of this contract will not have a significant overall impact on our operating income or EBIT. Finally, ANR has entered into an agreement with a shipper to restructure another of its transportation contracts on its Southeast Leg as well as a related gathering contract. We anticipate this restructuring will be completed in March 2005 upon which ANR will receive and reflect in its earnings approximately $26 million. In November 2004, the FERC issued an industry-wide Proposed Accounting Release that, if enacted as written, would require our interstate pipelines to expense rather than capitalize certain costs that are part of our pipeline integrity program. The accounting release is proposed to be effective January 2005 following a period of public comment on the release. We are currently reviewing the release and have not determined the impact, if any, this release will have on our consolidated financial statements. On December 1, 2004, the mainline of our newly constructed Cheyenne Plains Gas Pipeline was placed in service. Compression and gas treatment facilities are scheduled to be completed at the beginning of 2005, which will finalize the first phase of the project. UNREGULATED BUSINESSES -- PRODUCTION SEGMENT Our Production segment conducts our natural gas and oil exploration and production activities. Our operating results are driven by a variety of factors including the ability to locate and develop economic natural gas and oil reserves, extract those reserves with minimal production costs and sell the products at attractive prices. El Paso's long-term strategy for us includes developing our production opportunities primarily in the U.S. and Brazil, while currently divesting our international production properties outside of these areas. As of November 2004, we have sold all of our Canadian operations and substantially all of our operations in Indonesia. Beginning in the second quarter of 2004, these operations have been treated as discontinued operations as further discussed in Item 1, Financial Statements, Note 3. All periods reflect this change. Production and Capital Expenditures For the nine months ended September 30, 2004, our total equivalent production has declined approximately 42 Bcfe or 31 percent as compared to the same period in 2003, primarily due to normal production declines, asset sales and disappointing drilling results. We expect our fourth quarter of 2004 production to average 330 MMcfe/d and our annual production to average 295 MMcfe/d. The 2004 projected annual production average excludes approximately 15 MMcfe/d related to our discontinued production operations. Our expected fourth quarter of 2004 production levels will also be negatively impacted by Hurricane Ivan that occurred in September 2004 in the Gulf of Mexico. The hurricane caused us to shut-in production and also caused damage to third party facilities that process or transport our production. We continue to experience reduced production levels in this region as a result of the damage and do not expect to return to full production until mid-2005. Our future production levels are dependent upon the amount of capital allocated to us, the level of success in our drilling programs and future asset sales or acquisitions. Through October 2004, we have spent $240 million in capital expenditures for acquisition, exploration, and development activities. Based on the results to date of our 2004 drilling program, we expect our domestic unit of production depletion rate to increase from $2.48 per Mcfe during the third quarter of 2004 to $2.68 per Mcfe for the fourth quarter of 2004. Production Hedging We conduct hedging activities to stabilize cash flows and reduce the risk of downward commodity price movements on our sales. We conduct these activities through natural gas and oil derivatives on our natural gas and oil production with EPM. Because our hedging strategy only partially reduces our exposure to downward movements in commodity prices, our reported results of operations, financial position and cash flows can be 29 impacted significantly by movements in commodity prices from period to period. For a further discussion of our hedging program, refer to our 2003 Annual Report on Form 10-K. In September 2004, El Paso restated its financial statements for the manner in which it accounted for certain hedges of our anticipated natural gas production. While the restatement did not directly affect our financial statements, its effects were that many of the financial instruments that hedge commodity price risk in our financial statements did not qualify as hedges in El Paso's consolidated financial statements. We have historically hedged a portion of our anticipated natural gas and oil production with affiliates of El Paso, and it has been El Paso's intent that these positions qualify as hedges in El Paso's consolidated financial statements. As a result, we executed a series of transactions in order to make our hedge relationships consistent with El Paso's consolidated hedge relationships following the restatement. On December 1, 2004, through these transactions, we replaced existing hedges on approximately 51 TBtu of natural gas with new hedge transactions at the same volume and over the same time period. The combination of our original hedges and the new transactions will not change the average price at which we are hedged and will not have an impact on our realized prices. As a result, these transactions will have the same impact on our overall accumulated other comprehensive income balances, cash flow and income statement as our original derivative positions that existed prior to December 1, 2004. However, these transactions "locked in" a pre-tax loss of approximately $180 million in accumulated other comprehensive income that will be recognized in earnings as our original hedged transactions settle in 2005. We have also entered into a service agreement with El Paso that provides for a reimbursement of 2.5 cents per MMBtu in 2005 for our expected administrative costs associated with these transactions. Operating Results Below are the operating results and analysis of these results for our Production segment for each of the periods ended September 30:

QUARTER ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------- -------------------- PRODUCTION SEGMENT RESULTS 2004 2003 2004 2003 -------------------------- -------- -------- -------- --------- (IN MILLIONS), ~~Cash~~EXCEPT ~~flows~~VOLUMES ~~from~~AND ~~operating~~PRICES) ~~activities~~Operating revenues: Natural gas......................................... $ ~~452~~126 $ ~~931~~148 ~~Cash~~$ ~~flows~~399 ~~from~~$ ~~investing~~547 ~~activities~~Oil, condensate and liquids......................... 39 39 111 112 Other............................................... -- (~~142~~4) 1 5 ------- ------- ------- -------- Total operating revenues.................... 165 183 511 664 Transportation and net product costs(~~534~~1)............... ~~Cash~~(4) ~~flows~~(4) ~~from~~(11) ~~financing~~(24) ~~activities~~------- ------- ------- -------- Total operating margin...................... 161 179 500 640 Operating expenses: Depreciation, depletion and amortization............ (~~374~~78) (~~346~~86) (234) (256) Production costs(2)................................. (34) (26) (77) (83) Ceiling test and other charges(3)................... -- (49) -- (44) General and administrative expenses................. (19) (24) (55) (66) Taxes, other than production and income taxes....... 1 -- 1 (1) ------- ------- ------- -------- Total operating expenses(1)................. (130) (185) (365) (450) ------- ------- ------- -------- Operating income (loss)............................. 31 (6) 135 190 Other income (expense)................................ -- 2 (2) 5 ------- ------- ------- -------- EBIT................................................ $ 31 $ (4) $ 133 $ 195 ======= ======= ======= ========

~~Pipelines~~QUARTER ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------- -------------------- PRODUCTION SEGMENT RESULTS 2004 2003 2004 2003 -------------------------- -------- -------- -------- --------- (IN MILLIONS, EXCEPT VOLUMES AND PRICES) Volumes, prices and costs per unit: Natural gas Volumes (MMcf)................................... 23,448 31,818 74,322 110,393 ======= ======= ======= ======== Average realized prices including hedges ($/Mcf)(4)..................................... $~~161~~ ~~Production~~5.37 $ 4.65 $ 5.37 $ 4.96 ======= ======= ======= ======== Average realized prices excluding hedges ($/Mcf)(4)..................................... $ 5.75 $ 5.11 $ 5.80 $ 5.72 ======= ======= ======= ======== Average transportation and net product costs ($/Mcf)........................................ ~~133~~$ ~~Other~~0.12 $ 0.12 $ 0.10 $ 0.16 ======= ======= ======= ======== Oil, condensate and liquids Volumes (MBbls).................................. 1,039 1,573 3,299 4,352 ======= ======= ======= ======== Average realized prices including hedges ($/Bbl)(4)..................................... 2$ 37.29 $ 24.94 $ 33.54 $ 25.74 ======= ======= ======= ======== Average realized prices excluding hedges ($/Bbl)(4)..................................... $ 37.29 $ 24.94 $ 33.54 $ 25.74 ======= ======= ======= ======== Average transportation and net product costs ($/Bbl)........................................ $ 1.12 $ 0.87 $ 1.16 $ 0.85 ======= ======= ======= ======== Production cost ($/Mcfe) Average lease operating costs.................... $ 0.91 $ 0.60 $ 0.72 $ 0.46 Average production taxes......................... 0.23 0.03 0.09 0.15 ------- ------- ------- -------- Total production cost(1).................... $ 1.14 $ 0.63 $ 0.81 $ 0.61 ======= ======= ======= ======== Average general and administrative expenses ($/Mcfe)............................................ $~~296~~ 0.63 $ 0.59 $ 0.59 $ 0.48 ======= ======= ======= ======== Unit of production depletion cost ($/Mcfe)............ $ 2.48 $ 1.99 $ 2.35 $ 1.78 ======= ======= ======= ========

--------------- (1) Transportation and net product costs are included in operating expenses on our consolidated statements of income. (2) Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes). (3) Includes ceiling test charges, asset impairments and gains on asset sales. (4) Prices are stated before transportation costs. Quarter Ended September 30, 2004 Compared to Quarter Ended September 30, 2003 EBIT. For the quarter ended September 30, 2004, EBIT was $35 million higher than the same period in 2003. The increase in EBIT was primarily due to ceiling test charges recorded in the third quarter of 2003 and higher natural gas and oil prices in 2004, offset partially by the impact on revenues of lower production volumes due to normal production declines and disappointing drilling results. Operating Revenues. The following table describes the variance in revenue between the quarters ended September 30, 2004 and 2003 due to: (i) changes in average realized market prices excluding hedges, (ii) changes in production volumes, and (iii) the effects of hedges.

~~QUARTER~~VARIANCE ~~ENDED SIX MONTHS JUNE 30, ENDED JUNE 30,~~ -------------- ------------------- ~~2004~~PRODUCTION ~~2003~~REVENUE ~~2004~~VARIANCE ~~2003~~ANALYSIS PRICES VOLUMES HEDGES TOTAL ----- ------ ----- ------- (IN MILLIONS) Regulated Businesses Pipelines................................................. $ 89 $ 106 $ 221 $ 279 Unregulated Businesses Production................................................ 59 93 102 199 Power..................................................... 16 44 (47) 76 Field Services............................................ 11 (54) 25 (43) ---- ----- ----- ------- ~~Segment EBIT............................................ 175 189 301 511 Corporate................................................... 4 (8) 8 (13)~~ ---- ----- ------ ------- ~~Consolidated~~(IN ~~EBIT~~MILLIONS) ~~from~~Natural ~~continuing operations~~gas............ ~~179 181 309 498 Interest and debt expense~~................................... ~~(91) (101) (192) (200) Affiliated interest income (expense), net~~..~~.................~~ 5$15 $(743) ~~(9)~~$6 $(1422) ~~Distributions~~Oil, oncondensate ~~preferred~~and ~~interests of consolidated subsidiaries~~liquids.................................~~.............~~ --13 (713) -- ~~(14) Income taxes................................................ (32) (19) (37) (89)~~ ---- ----- ----- -- ----- ~~Income~~$28 ~~from continuing operations......................... 61 47 71 181 Discontinued operations, net of income taxes................~~ $(1156) ~~(931)~~$6 (~~139~~22) ~~(1,151)~~=== ~~Cumulative~~==== ~~effect~~== ~~of accounting changes, net of income taxes~~Other....................................................... --4 -- -- ~~(12)~~Total ~~----~~operating ~~-----~~revenue ~~----- ------- Net income (loss)~~variance..........................~~...............~~ $ ~~50 $~~(~~884~~18) ~~$ (68) $ (982)~~ ==== ~~===== ===== =======~~

For the quarter ended September 30, 2004, operating revenues were $18 million lower than the same period in 2003 due to lower production volumes, partially offset by higher natural gas and oil prices. The 31 decline in production volumes resulted from normal production declines in our Texas Gulf Coast and offshore Gulf of Mexico regions and disappointing drilling results. Production in the third quarter of 2004 was also impacted by Hurricane Ivan in September 2004 in the Gulf of Mexico, which caused us to shut-in production and also caused damage to third party facilities that process or transport our production. Average realized natural gas prices for the third quarter of 2004, excluding hedges, were $0.64 per Mcf higher than the same period in 2003, an increase of 13 percent. In addition, our natural gas hedging losses decreased from $15 million in 2003 to $9 million in 2004. We expect to continue to incur hedging losses for the remainder of 2004. Operating Expenses. Total operating expenses were $55 million lower for the third quarter of 2004 compared with the same period in 2003. The decrease was primarily due to ceiling test charges of $39 million in our domestic and Brazilian operations and a $10 million impairment of non-full cost pool assets in the third quarter of 2003. Total depreciation, depletion, and amortization expense decreased $8 million in the third quarter of 2004 compared with the same period in 2003. Lower production volumes in 2004 due to the production declines discussed above reduced our depreciation, depletion, and amortization expense by $23 million. Partially offsetting this decrease were higher depletion rates due to higher finding and development costs which contributed an increase of $15 million. Production costs increased by $8 million in the third quarter of 2004 compared with the same period in 2003 due to an increase in lease operating costs and production taxes. Lease operating cost increased due to higher workover costs in 2004 in our offshore Gulf of Mexico region, while production taxes were higher due to the favorable settlement of ad valorem tax issues in 2003. On a per Mcfe basis, production taxes increased $0.20 in 2004 and lease operating costs increased $0.31 in 2004 primarily due to the higher costs and the lower production volumes discussed above. General and administrative expenses decreased by $5 million for the third quarter of 2004 compared with the same period in 2003. The increase on a per unit basis was primarily due to lower production volumes. For the fourth quarter of 2004, we expect our allocated expenses will be approximately the same as the third quarter of 2004. Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003 EBIT. For the nine months ended September 30, 2004, EBIT was $62 million lower than the same period in 2003. The decrease in EBIT was primarily due to the impact on revenues of lower production volumes due to normal production declines, asset sales and disappointing drilling results. Partially offsetting these decreases was a reduction in losses in 2004 from our hedging program, higher natural gas and oil prices, and lower operating expenses in 2004, primarily due to ceiling test charges recorded in 2003. Operating Revenues. The following table describes the variance in revenue between the nine months ended September 30, 2004 and 2003 due to: (i) changes in average realized market prices excluding hedges, (ii) changes in production volumes, and (iii) the effects of hedges.

~~QUARTER~~VARIANCE ~~ENDED SIX MONTHS ENDED JUNE 30, JUNE 30,~~ ---------------- ----------------- ~~PIPELINES~~PRODUCTION ~~SEGMENT~~REVENUE ~~RESULTS~~VARIANCE ~~2004~~ANALYSIS ~~2003~~PRICES ~~2004~~VOLUMES ~~2003~~HEDGES TOTAL ------------------------- ----------- ------ ------- ------ ----- (IN MILLIONS~~, EXCEPT VOLUME AMOUNTS~~) ~~Operating~~Natural ~~revenues~~gas................................................. $ ~~189~~6 $(206) ~~209~~ $52 ~~426~~ $(148) ~~501~~Oil, ~~Operating~~condensate ~~expenses~~and liquids................................. ~~(118)~~26 (~~120~~27) ~~(245)~~-- (~~259~~1) ---~~---~~ ------ ---~~---~~ ------ ~~Operating~~$32 ~~income~~$(233) $52 (149) === ===== === Other.............................. ~~71 89 181 242 Other income~~.........................~~...........~~ 18(4) ~~17 40 37~~ ------ ~~------~~Total ~~------~~operating ~~------~~revenue ~~EBIT~~variance..........................~~................~~ $ ~~89 $ 106 $ 221 $ 279 ====== ====== ====== ====== Throughput volumes~~ (~~BBtu/d~~153)~~(1)..................~~ ~~7,654 7,520 8,278 8,670~~ =====~~= ====== ====== ======~~

For the nine months ended September 30, 2004, operating revenues were $153 million lower than the same period in 2003 primarily due to lower production volumes, partially offset by higher natural gas and oil 32 prices and a decrease in our hedging losses. The decline in natural gas volumes is primarily due to normal production declines, particularly in our Texas Gulf Coast and offshore Gulf of Mexico regions, the impact of sales of properties in New Mexico and disappointing drilling results. Production for the nine months ended September 30, 2004 was also impacted by Hurricane Ivan in September 2004 in the Gulf of Mexico, which caused us to shut-in production and damaged third party facilities that process or transport our production. Average realized oil, condensate, and liquids prices for 2004, were $7.80 per Bbl higher than the same period in 2003, an increase of 30 percent. In addition, hedging losses decreased from $84 million in 2003 to $32 million in 2004 relating to our natural gas hedge positions. We expect to continue to incur hedging losses for the remainder of 2004. Operating Expenses. Total operating expenses were $85 million lower in 2004 compared with the same period in 2003 primarily due to ceiling test charges of $39 million for our domestic and Brazilian operations and a $10 million impairment of non-full cost pool assets in the third quarter of 2003. In addition, we experienced lower depreciation, depletion, and amortization expense, lower production costs and lower general and administrative expenses in 2004 compared with the same period in 2003. Total depreciation, depletion, and amortization expense decreased by $22 million in 2004 compared with the same period in 2003. Lower production volumes in 2004 due to asset sales and other production declines discussed above reduced our depreciation, depletion, and amortization expenses by $76 million. Partially offsetting this decrease were higher depletion rates due to higher finding and development costs which contributed an increase of $53 million. Production costs decreased by $6 million in 2004 compared with the same period in 2003 primarily due to a decrease in production taxes resulting from high cost gas well tax credits in 2004 and lower production volumes in 2004 as compared to 2003. Partially offsetting the decrease were higher lease operating costs due to higher workover costs in 2004 primarily in our offshore Gulf of Mexico region. On a per Mcfe basis, production taxes decreased $0.06 in 2004. However, our total production costs per Mcfe increased $0.20 as lease operating expenses increased $0.26 per Mcfe due to the higher costs and lower production volumes discussed above. General and administrative expenses decreased by $11 million in 2004 compared with the same period in 2003. The decrease was primarily due to lower allocated expenses. However, the cost per unit increased $0.11 per Mcfe due to lower production volumes. For the fourth quarter of 2004, we expect our allocated expenses will be approximately the same as the third quarter of 2004. UNREGULATED BUSINESSES -- POWER SEGMENT Our Power segment includes the ownership and operation of domestic and international power generation facilities and the management of restructured power contracts. Below are the operating results and an analysis of these results for our Power segment for the periods ended September 30:

NINE MONTHS QUARTER ENDED ~~JUNE~~ENDED SEPTEMBER 30, ~~SIX~~SEPTEMBER ~~MONTHS ENDED JUNE~~ 30, -------------~~--------------------------~~ --------------~~-------------------------~~ ~~REVENUE~~POWER ~~EXPENSE~~SEGMENT ~~OTHER~~RESULTS ~~EBIT~~2004 ~~IMPACT~~2003 ~~REVENUE~~2004 ~~EXPENSE~~2003 ~~OTHER EBIT IMPACT~~ ------- ------- ----- -- -----~~----~~ ------- ------- ----- ~~----------- FAVORABLE/~~(~~UNFAVORABLE) (~~IN MILLIONS) ~~ANR~~Gross ~~Dakota contract termination~~margin(1)....... ~~$(12) $ 12 $ -- $ -- $(28) $ 27 $ -- $ (1) Contract remarketing/restructurings~~...... ~~(6) -- -- (6) (26) -- -- (26) CIG Table Rock facility sold in 2003~~............................ --$ ~~(6)~~23 --$ ~~(6)~~35 --$ ~~(6)~~89 --$135 ~~(6)~~Operating ~~Storage facility gas loss replacement in 2004~~expenses............. ~~-- -- -- -- -- (6) -- (6) Change to regulated depreciation method~~.......................... --(33) (237) --(173) (294) ---- ~~(4)~~---- ----- ~~(4)~~---- ~~OTHER~~Operating ~~Fuel~~income ~~recoveries, net of gas used~~(loss)............................... (410) ~~-- --~~ (42) (2084) --41 --Other income (20expense) ~~Other~~.................................. 29 (2) 136 131 ~~(1) 3 3 5~~ ---- ---- ---- -~~---~~ ---- ~~---- ---- ---- Total~~EBIT.................................................. $ (201) $ ~~2 $ 1 $~~(174) $ (7548) $ 1472 ~~$ 3 $(58)~~ ==== ==== ==== =~~===~~ ==== ~~==== ==== ====~~

--------------- (1) Gross margin consists of revenues from our power plants and the initial net gains and losses incurred in connection with the restructuring of power contracts, as well as the subsequent revenues, cost of electricity purchases and changes in fair value of those contracts. The cost of fuel used in the power generation process is included in operating expenses. 33 Quarter Ended September 30, 2004 Compared to Quarter Ended September 30, 2003 For the quarter ended September 30, 2004, our EBIT was $3 million higher than the same period in 2003. During 2004, we experienced lower operating costs of $7 million at our Eagle Point power facility as a result of leasing the facility to a third party in the first quarter of 2004. We also experienced $6 million in higher operating expenses in 2003 to convert our Eagle Point power facility to operate it on a merchant basis. Also contributing to the increase in EBIT was a $5 million increase in equity earnings from our investment in a power facility located in Pakistan and a $4 million increase in equity earnings from our investment in Midland Cogeneration Venture in 2004 compared to the same period in 2003. Partially offsetting these increases was a $13 million increase in 2003 in the fair value of the restructured power contracts held by Utility Contract Funding and Mohawk River Funding IV, which were sold in the first half of 2004, and a $6 million impairment charge recorded in 2004 on our CDECCA power plant to adjust the carrying value of this plant to the expected sales proceeds. Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003 For the nine months ended September 30, 2004, our EBIT was $120 million lower than the same period in 2003. This decrease was primarily due to the sale of Utility Contract Funding and its restructured power contract and related debt, which resulted in an $89 million impairment loss in 2004 including in operating expenses. As a result of the sale of our restructured power contracts in 2004, the fair value of these contracts increased by only $36 million in 2004 compared to an increase of $49 million in 2003. Further contributing to the decrease was an $18 million reduction in equity earnings in 2004 compared to the same period in 2003 from our investment in Midland Cogeneration Venture, an $8 million gain in 2003 on the termination of a steam contract at our Fulton power plant and a 2003 reduction of $8 million of estimated costs associated with our power contract restructuring activities. Partially offsetting these decreases was the increase in equity earnings from a Pakistani investment and lower Eagle Point conversion costs, net of the CDECCA power plant impairment described above. We currently anticipate selling a number of our domestic and international power assets. As these sales occur or as agreements are negotiated, we may incur future losses if the sales proceeds are less than the carrying value of the assets, and these losses may be significant. 34 UNREGULATED BUSINESSES -- FIELD SERVICES SEGMENT Our Field Services segment conducts our midstream activities, which include gathering and processing of natural gas. During 2004, we sold our Dauphin Island and Mobile Bay investments. Following these sales, our assets principally consist of our processing plants in south Louisiana. Below are the operating results and analysis of these results for our Field Services segment for the periods ended September 30:

NINE MONTHS QUARTER ENDED ~~SIX MONTHS~~ ENDED ~~JUNE~~SEPTEMBER 30, ~~JUNE~~SEPTEMBER 30, ------------------- ------------------- ~~PRODUCTION~~FIELD SERVICES SEGMENT RESULTS 2004 2003 2004 2003 ------------------------------ -------- -------- -------- -------- (IN MILLIONS, EXCEPT VOLUMES AND PRICES) ~~Operating~~Processing ~~revenues:~~and ~~Natural~~gathering ~~gas~~gross margins(1)..........~~.....................~~ $ ~~148~~23 $ ~~196~~17 $ ~~273~~62 $ ~~399~~60 ~~Oil,~~Operating ~~condensate and liquids~~expenses............... ~~35 30 72 73 Other~~..................~~...................~~ ~~-- 7 1 9 ------- ------- ------- ------- Total operating revenues.......... 183 233 346 481 Transportation and net product costs........~~ (29) (79) (727) (2013) ------- ------- ------- ------- ~~Total operating margin............ 181 226 339 461~~ Operating ~~expenses: Depreciation, depletion and amortization~~income........................... ~~(80) (87) (156) (170) Production costs(1)~~......~~.................~~ ~~(22)~~14 ~~(30)~~8 ~~(43)~~35 ~~(57)~~47 ~~Gain~~Other onincome ~~long-lived assets................. -- 5 -- 5 General and administrative expenses.......~~ (20expense) ~~(21) (36) (42) Taxes, other than production and income taxes~~.............................~~.....~~ --5 ~~-- --~~ (~~1) ------- ------- ------- ------- Total operating expenses(~~2)~~.......~~ ~~(122)~~9 (~~133~~84) ~~(235) (265)~~ ------- ------- ------- ------- ~~Operating income~~EBIT.......................... ~~59 93 104 196 Other income (expense)~~...................~~...~~ ~~-- -- (2) 3 ------- ------- ------- ------- EBIT......................................~~ $ 5919 $ 936 $ ~~102~~44 $ ~~199~~(37) ======= ======= ======= ======= Volumes, ~~prices~~ and ~~costs per unit~~Prices: ~~Natural~~Processing ~~gas~~ Volumes (~~MMcf~~BBtu/d).............................. 261,~~099~~693 401,~~131~~550 501,~~874~~674 781,~~575~~667 ======= ======= ======= ======= ~~Average~~Prices ~~realized prices including hedges~~ ($/~~Mcf~~MMBtu)~~(3)~~.................... ~~$ 5~~.~~65 $ 4~~.~~91 $ 5~~.~~37 $ 5~~.~~08 ======= ======= ======= ======= Average realized prices excluding hedges ($/Mcf)(3)~~......~~..............~~ $ ~~5.99 $ 5.25 $ 5.83 $ 5.97 ======= ======= ======= ======= Average transportation costs ($/Mcf)... $~~ 0.0514 $ 0.1410 $ 0.0913 $ 0.1811 ======= ======= ======= ======= ~~Oil,~~Gathering ~~condensate and liquids~~ Volumes (~~MBbls~~BBtu/d)........................ ~~1,062 1,188 2,260 2,779 ======= ======= ======= ======= Average realized prices including hedges ($/Bbl)(3)~~......~~..............~~ ~~$ 33.~~17 $23 ~~25.16~~19 $116 ~~31.81 $ 26.20~~ ======= ======= ======= ======= ~~Average~~Prices ~~realized prices excluding hedges~~ ($/~~Bbl~~MMBtu)~~(3)~~.................... ~~$ 33~~.~~17 $ 25~~.~~16 $ 31~~.~~81 $ 26~~.~~20 ======= ======= ======= ======= Average transportation costs ($/Bbl)~~...... $ 10.2606 $ 0.7209 $ 10.1808 $ 0.8415 ======= ======= ======= =======

--------------- (1) Gross margins consist of operating revenues less cost of products sold. We believe this measurement is more meaningful for understanding and analyzing our operating results because commodity costs play such a significant role in the determination of profit from our midstream activities. For the quarter and nine months ended September 30, 2004, our EBIT was $13 million and $81 million higher than the same periods in 2003. Below is a summary of significant factors affecting EBIT.

QUARTER ENDED ~~SIX~~SEPTEMBER 30, NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, ~~JUNE 30,~~ ------------------------------------ ------------------------------------ ~~PRODUCTION~~GROSS ~~SEGMENT~~OPERATING ~~RESULTS~~OTHER ~~2004~~EBIT ~~2003~~GROSS ~~2004~~OPERATING ~~2003~~OTHER EBIT MARGIN EXPENSE INCOME IMPACT MARGIN EXPENSE INCOME IMPACT ------ --------- ------ ------ ------- ------- -- ------ ------- FAVORABLE (INUNFAVORABLE) ~~MILLIONS,~~FAVORABLE ~~EXCEPT~~(UNFAVORABLE) ~~VOLUMES~~(IN ~~AND PRICES~~MILLIONS) ~~Production cost~~ (~~$/Mcfe~~IN MILLIONS) ~~Average~~Asset ~~lease~~Sales ~~operating~~Impact ~~costs~~of reduced operations...~~.......~~ $ ~~0.59~~1 $ ~~0.50~~1 $ ~~0.63~~-- $ ~~0.40~~2 ~~Average~~$(8) ~~production~~$ ~~taxes~~7 $-- $ (1) Gain on Mid-Continent midstream assets in 2003............... ~~0.10 0.13 0.03 0.19~~ -- -- --- --~~-----~~ --~~-----~~ (19) --~~-----~~ ~~Total~~(19) ~~production cost~~Impairments(1)............. ~~$ 0~~.~~69 $ 0~~.~~63 $ 0~~.66. $-- ~~0.59~~(1) ~~=======~~-- ~~=======~~(1) ~~=======~~-- ~~=======~~(1) ~~Average~~80 ~~general~~79 ~~and~~Higher ~~administrative~~NGL ~~expenses~~Prices ~~($/Mcfe)~~Processing.....................~~.............~~ $5 ~~0.60~~-- $-- ~~0.44~~5 $8 ~~0.56~~-- $-- ~~0.44~~8 ~~=======~~Javelina ~~=======~~equity ~~=======~~investment..... ~~=======~~-- ~~Unit~~-- of5 ~~production~~5 ~~depletion~~-- ~~cost~~-- ~~($/Mcfe)~~13 13 Other............................~~......~~ $-- -- 2~~.32~~ $2 2 (1~~.74~~) -- 1 ----- ---- ----- --- --- ---- --- ---- $ 6 $ -- $ 7 $13 $ 2~~.29~~ $(14) ~~1.70~~$93 $ 81 ===== ==== ===== === === ==== === ====

--------------- (1) Our equity investments in Dauphin Island and Mobile Bay were impaired in 2003 based on our anticipated losses on the sales of these investments, which were completed in the third quarter of 2004. 35 CORPORATE, NET Our corporate operations include our general and administrative functions as well as other unregulated activities, including our petroleum ship charter operations and various other contracts and assets, all of which are immaterial to our results in 2004 and do not constitute separate operating segments. During the first quarter of 2004, we reclassified our petroleum ship charter operations from discontinued operations to our continuing corporate operations. Our operating results for all periods reflect this change. For the quarter ended September 30, 2004, EBIT decreased $9 million from the same period in 2003. This decrease was primarily due to higher legal and environmental costs and higher minority interest expense in 2004. For the nine months ended September 30, 2004, EBIT increased by $12 million compared with the same period in 2003. This increase was due to higher operating income in 2004 on petroleum ship charters of $10 million due to higher demand for those services, and the favorable impact of 2003 losses of $13 million related to a gas supply contract with one of our affiliates that was terminated. Partially offsetting these favorable items were the higher costs discussed above. INTEREST AND DEBT EXPENSE Interest and debt expense for the quarter and nine months ended September 30, 2004, was $29 million and $37 million lower than the same periods in 2003. Below is an analysis of our interest expense for the periods ended September 30:

~~VARIANCE~~NINE ~~---------------------------------~~MONTHS ~~PRODUCTION~~QUARTER ~~REVENUE~~ENDED ~~VARIANCE~~ENDED ~~ANALYSIS~~SEPTEMBER ~~PRICES~~30, ~~VOLUMES~~SEPTEMBER ~~HEDGES~~30, ~~TOTAL~~ ------------- -------------~~----------~~ 2004 2003 2004 2003 ------ ------- ------ ----- (IN MILLIONS) ~~Natural~~Long-term ~~gas~~debt, including current maturities.......... $79 $106 $275 $307 Other interest........................................ $-- 201 ~~$(73)~~1 $ 5 ~~$(48)~~Capitalized ~~Oil, condensate and liquids~~interest.................................. 8(4) (3) --(9) 5(8) ---- ---- ---- ---- $Total 28interest ~~$(76)~~and $debt ~~5 $(43) ==== ==== === Other~~expense................~~.......................................~~ ~~(7)~~$75 ~~----~~$104 ~~Total~~$267 ~~operating~~$304 ~~revenue~~=== ~~variance..........................~~==== ~~$(50)~~==== ====

Interest expense on long-term debt decreased primarily due to net retirements of debt during 2003 and 2004. Partially offsetting these retirements was the reclassification of our Coastal Finance I mandatorily redeemable preferred securities to long-term debt as a result of the adoption of SFAS No. 150 in 2003. Based on this reclassification, we began recording the preferred returns on these securities as interest expense rather than as distributions on preferred interests. Other interest decreased due to the retirements of other financing obligations. AFFILIATED INTEREST INCOME (EXPENSE), NET Net affiliated interest expense decreased for the quarter and nine months ended September 30, 2004 compared with the same periods in 2003 primarily due to lower average advances balances with El Paso under our cash management program in 2004, partially offset by higher average short-term interest rates. During the fourth quarter of 2003, we received a $1.5 billion contribution from El Paso. This contribution lowered our average balances under El Paso's cash management program in 2004. The average advances balance for the third quarter decreased from a net liability of $2.1 billion in 2003 to a net asset of $0.2 billion in 2004 and for the nine months decreased from a net liability of $2.1 billion in 2003 to $0.3 billion in 2004. However, the average short-term interest rates for 2003 increased from 1.9% for the third quarter and 1.6% for the nine months to 2.5% for both the third quarter and the nine month periods in 2004. DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES Distributions on preferred interests of consolidated subsidiaries for the quarter and nine months ended September 30, 2004, were $1 million and $15 million lower than the same periods in 2003 primarily due to the 36 reclassification of our Coastal Finance I mandatorily redeemable preferred securities to long-term financing obligations as a result of the adoption of SFAS No. 150 in 2003. Based on this reclassification, we began recording the preferred returns on these securities as interest expense rather than as distributions on preferred interests. Also contributing to the decrease was the redemption of the preferred stock of Coastal Securities Company Limited. INCOME TAXES Income taxes included in our income from continuing operations and our effective tax rates for the periods ended September 30 were as follows:

~~VARIANCE~~NINE ~~---------------------------------~~MONTHS ~~PRODUCTION~~QUARTER ~~REVENUE~~ENDED ~~VARIANCE~~ENDED ~~ANALYSIS~~SEPTEMBER ~~PRICES~~30, ~~VOLUMES~~SEPTEMBER ~~HEDGES~~30, ~~TOTAL~~ ---------------- ---------------~~-----~~ 2004 2003 2004 2003 ------ ------- ------ ------ (IN MILLIONS, EXCEPT FOR RATES) ~~Natural~~Income ~~gas~~taxes..............................................~~...~~ $21 ~~(7)~~ $~~(165)~~ ~~$46 $~~(~~126~~17) ~~Oil, condensate and liquids................................. 13 (14) -- (1) ---- ----- --- -----~~ $58 6 $~~(179)~~72 ~~$46~~Effective ~~$(127)~~tax ~~==== ===== === Other~~rate........................................~~...............~~ ~~(8)~~36% ~~-----~~100% ~~Total~~35% ~~operating revenue variance.......................... $(135) =====~~28%

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to our year-to-date income or loss except for significant unusual or extraordinary transactions. Changes to these anticipated annual rates during an interim period can significantly affect our quarterly income taxes as we apply the revised rate to year-to-date income or loss. Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. Our effective tax rates were different than the statutory tax rate of 35 percent in 2004 and 2003 primarily due to: - state income taxes, net of federal income tax benefit; and - foreign income taxed at different rates. Additionally, during 2003 our effective tax rate was different than the statutory tax rate of 35 percent due to the abandonment of certain foreign investments. During the quarter ended September 30, 2003, we revised our anticipated annual effective tax rate due to the U.S. tax benefits associated with the abandonment of certain foreign investments. Our effective rate and the tax benefit recorded for the third quarter of 2003 reflects the downward revision of our federal taxable income for the nine months ended September 30, 2003, as a result of these abandonments, combined with low third quarter pretax book losses. On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law. This legislation creates, among other things, a temporary incentive for U.S. multinational companies to repatriate accumulated income earned outside the U.S. at an effective tax rate of 5.25%. The U.S. Treasury Department has not issued final guidelines for applying the repatriation provisions of the American Jobs Creation Act. We have not provided deferred taxes on foreign earnings because such earnings were intended to be indefinitely reinvested outside the U.S. We are currently evaluating whether we will repatriate any foreign earnings under the American Jobs Creation Act, and are evaluating the other provisions of this legislation, which may impact our taxes in the future. DISCONTINUED OPERATIONS For the nine months ended September 30, 2004, the loss from our discontinued operations was $151 million compared to a loss of $1,220 million during the same period in 2003. In 2004, we incurred $77 million of losses and impairments related to the sales of our discontinued Canadian and certain other international production operations, and $74 million from our discontinued petroleum markets activities, primarily related to losses on the completed sales of our Eagle Point and Aruba refineries along with other operational and severance costs. The losses in 2003 primarily related to impairment charges on our Aruba and Eagle Point refineries and on chemical assets, and ceiling test charges on our Canadian production operations. 37 COMMITMENTS AND CONTINGENCIES See Item 1, Financial Statements, Note 8, which is incorporated herein by reference. 38 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS We have made statements in this document that constitute forward-looking statements, as that term is defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include information concerning possible or assumed future results of operations. The words "believe," "expect," "estimate," "anticipate" and similar expressions will generally identify forward-looking statements. These statements may relate to information or assumptions about: - capital and other expenditures; - dividends; - financing plans; - capital structure; - liquidity and cash flow; - pending legal proceedings, claims and governmental proceedings, including environmental matters; - future economic performance; - operating income; - management's plans; and - goals and objectives for future operations. Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these variances can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in the forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in forward-looking statements are described in our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission on October 12, 2004. 39 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK This information updates, and you should read it in conjunction with, information disclosed in our 2003 Annual Report on Form 10-K, 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 2003 Annual Report on Form 10-K, except as discussed below: INTEREST RATE RISK During 2004, we sold our remaining third party long-term power purchase and our power supply derivative contracts held by Utility Contract Funding and Mohawk River Funding IV, which eliminated our exposure to interest rate risk related to these contracts. Our remaining exposure to interest rate risk relates to our long-term financing obligations. 40 ITEM 4. CONTROLS AND PROCEDURES During 2004, we have been reviewing our internal controls over financial reporting as part of our compliance efforts under Section 404 of the Sarbanes-Oxley Act (SOX), which will apply to us at December 31, 2005, as well as in connection with investigations into matters that required the restatement of our historical financial statements for the periods from 1999 to 2002 and the first nine months of 2003. Our SOX review is being performed consistent with the guidance for independent auditors established by the Public Company Accounting Oversight Board in Auditing Standard No. 2, An Audit of Internal Control Over Financial Reporting Performed in Conjunction with an Audit of Financial Statements. The project has entailed the detailed review and documentation of the processes that impact the preparation of our financial statements, an assessment of the risks that could adversely affect the accurate and timely preparation of those financial statements and the identification of the controls in place to mitigate the risks of untimely or inaccurate preparation of those financial statements. Following the documentation of these processes, financial management responsible for those processes internally reviewed or "walked-through" these financial processes to evaluate the design effectiveness of the controls identified to mitigate the risk of material misstatements occurring in our financial statements. We also initiated a detailed process to evaluate the operating effectiveness of our controls over financial reporting. This involves testing the controls, including a review and inspection of the documentation supporting the operation of the controls on which we are placing reliance. During our reviews, we identified a number of deficiencies in our internal controls over financial reporting that we determined were material weaknesses in our internal control structure. These deficiencies, which we have previously disclosed, generally involved the control environment, information system access, documentation and application of generally accepted accounting principles, and deficiencies related to segregation of duties, account reconciliations and change management over information systems. Our management, with the oversight of El Paso's Audit Committee, has devoted considerable effort to remediating the material weaknesses identified, and has made improvements in our internal controls over financial reporting to address these weaknesses. Specifically, in the quarter ending September 30, 2004, we implemented new controls to improve our account reconciliation process, improve segregation of duties and strengthen information system change management processes. We believe that we have remediated the deficiencies in our internal controls related to all of the material weaknesses previously identified. However, we continue to test to determine whether the remediated controls are operating effectively. We expect to complete this testing by early February 2005. We are currently finalizing a framework upon which we will evaluate and classify the significance of deficiencies identified in our testing process. This is an area that involves judgment, and where interpretation and guidance continue to evolve. At this time, we have identified a number of deficiencies and areas where we can improve our internal controls. Following the completion of our testing procedures, we will assess whether there are any remaining material weaknesses, represented by either individually material deficiencies or an aggregation of significant deficiencies. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules. Our disclosure controls and procedures are also designed to ensure that such information is accumulated and communicated to our management to allow timely decisions regarding required disclosure. Because we have not completed the testing of many of the processes and controls intended to remediate the control deficiencies identified in our reviews and of internal controls, we were unable to conclude that our disclosure controls and procedures were effective as of September 30, 2004. However, we did perform additional procedures to ensure that our disclosure controls and procedures were effective over the preparation of these financial statements. 41 PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS See Part I, Item 1, Note 8, which is incorporated herein by reference. Additional information about our legal proceedings can be found in Part I, Item 3 of our Annual Report on Form 10-K filed with the Securities and Exchange Commission on October 12, 2004. ITEM 2. UNREGISTERED SALES OF EQUITY 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 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.

~~QUARTER~~EXHIBIT ~~ENDED~~NUMBER ~~SIX~~DESCRIPTION ~~MONTHS JUNE 30, ENDED JUNE 30,~~ -------~~-------~~ -----------~~---~~ ~~POWER~~10.D ~~SEGMENT~~Amended ~~RESULTS~~and ~~2004~~Restated ~~2003~~Credit Agreement dated as of November 23, 2004, ~~2003~~among ~~---------------------~~El ~~------~~Paso ~~-----~~Corporation, ~~------~~ANR ~~-----~~Pipeline ~~(IN~~Company, ~~MILLIONS)~~Colorado ~~Gross~~Interstate ~~margin(1)~~Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (Exhibit 99.B to our Form 8-K filed November 29, 2004). 10.E Amended and Restated Security Agreement dated as of November 23, 2004, made by among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank (Exhibit 99.C to our Form 8-K filed November 29, 2004). 10.~~..............................~~F $Amended 31and $Restated 56Subsidiary $Guarantee 66Agreement ~~$100~~dated ~~Operating~~as ~~expenses~~of November 23, 2004, made by each of the Subsidiary Guarantors, as defined therein, in favor of JPMorgan Chase Bank, N.A.~~...................................~~, ~~(25)~~as ~~(25)~~collateral ~~(140)~~agent (~~57)~~Exhibit ~~-----~~99.D ~~----~~to ~~-----~~our Form 8-~~---~~K ~~Operating~~filed ~~income~~November ~~(loss~~29, 2004). *31.A Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002. *31.B Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002. *32.A Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec.~~.................~~ 6906 31of ~~(74)~~the 43Sarbanes-Oxley ~~Other~~Act ~~income~~of 2002. *32.~~.........................................~~B 10Certification 13of 27Chief 33Financial ~~-----~~Officer ~~----~~pursuant ~~-----~~to ~~----~~18 ~~EBIT~~U.S.C. sec.~~.............................................~~ $1350 16as $adopted 44pursuant $to ~~(47)~~sec. $906 76of ~~=====~~the ~~====~~Sarbanes-Oxley ~~=====~~Act ~~====~~of 2002.

42 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. 43 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 CORPORATION Date: December 21, 2004 /s/ D. DWIGHT SCOTT ------------------------------------ D. Dwight Scott Executive Vice President, Chief Financial Officer, and Director (Principal Financial Officer) Date: December 21, 2004 /s/ JEFFREY I. BEASON ------------------------------------ Jeffrey I. Beason Senior Vice President and Controller (Principal Accounting Officer) 44 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.

~~QUARTER~~EXHIBIT ~~ENDED~~NUMBER ~~SIX~~DESCRIPTION ~~MONTHS ENDED JUNE 30, JUNE 30,~~ -------~~------------~~ -----------~~----------~~ ~~FIELD~~10.D ~~SERVICES~~Amended ~~SEGMENT~~and ~~RESULTS~~Restated ~~2004~~Credit ~~2003~~Agreement dated as of November 23, 2004, ~~2003~~among ~~------------------------------~~El ~~--------~~Paso ~~--------~~Corporation, ~~---------~~ANR ~~---------~~Pipeline ~~(IN~~Company, ~~MILLIONS~~Colorado Interstate Gas Company, ~~EXCEPT~~El ~~VOLUMES~~Paso ~~AND~~Natural ~~PRICES)~~Gas ~~Processing~~Company, Tennessee Gas Pipeline Company, the several banks and ~~gathering~~other ~~gross~~financial ~~margins(1)..........~~institutions $from 19time $to 19time $parties 39thereto $and 43JPMorgan ~~Operating~~Chase ~~expenses~~Bank, N.A.~~...............................~~, ~~(9)~~as 8administrative ~~(18)~~agent and as collateral agent (4)Exhibit ~~------~~99.B ~~------~~to ~~------~~our Form 8-~~-----~~K ~~Operating~~filed ~~income~~November 29, 2004).~~................................~~ 10.E 27Amended 21and 39Restated ~~Other~~Security ~~income~~Agreement ~~(expense).............................~~dated 1as ~~(81)~~of 4November ~~(82)~~23, ~~------~~2004, ~~------~~made ~~------~~by ~~------~~among ~~EBIT~~El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A.~~...........................................~~, $not 11in $its ~~(54)~~individual $capacity, 25but $solely ~~(43)~~as ~~======~~collateral ~~======~~agent ~~======~~for ~~======~~the ~~Volumes~~Secured Parties and ~~Prices:~~as ~~Processing~~the ~~Volumes~~depository bank (~~BBtu/d~~Exhibit 99.C to our Form 8-K filed November 29, 2004). 10.~~............................~~F 1Amended and Restated Subsidiary Guarantee Agreement dated as of November 23,~~641~~ 12004,~~748~~ 1made by each of the Subsidiary Guarantors,~~664~~ 1as defined therein,~~726~~ ~~======~~in ~~======~~favor ~~======~~of ~~======~~JPMorgan ~~Prices~~Chase ~~($/MMBtu)~~Bank, N.A., as collateral agent (Exhibit 99.D to our Form 8-K filed November 29, 2004). *31.A Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002. *31.~~......................~~B $Certification ~~0.12~~of $Chief ~~0.12~~Financial $Officer ~~0.12~~pursuant $to 0sec.12 ~~======~~302 ~~======~~of ~~======~~the ~~======~~Sarbanes-Oxley ~~Gathering~~Act ~~Volumes~~of ~~(BBtu/d)~~2002. *32.A Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002. *32.~~.....................~~B 20Certification ~~125~~of 20Chief ~~163~~Financial ~~======~~Officer ~~======~~pursuant ~~======~~to ~~======~~18 ~~Prices ($/MMBtu)~~U.S.C. sec.~~..........................~~ $1350 ~~0.10~~as $adopted ~~0.06~~pursuant $to 0sec.07 $906 ~~0.16~~of ~~======~~the ~~======~~Sarbanes-Oxley ~~======~~Act ~~======~~of 2002.

QUARTER ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, ------------------------------------ ------------------------------------ GROSS OPERATING OTHER EBIT GROSS OPERATING OTHER EBIT MARGIN EXPENSE INCOME IMPACT MARGIN EXPENSE INCOME IMPACT ------ --------- ------ ------ ------ --------- ------ ------ FAVORABLE (UNFAVORABLE) (IN MILLIONS) ASSET SALES Impact of reduced operations... $(1) $ 2 $ -- $ 1 $ (9) $ 6 $ -- $ (3) Gain on Mid-Continent midstream assets in 2003.............. -- (19) -- (19) -- (19) -- (19) Impairments(1)................. -- -- 80 80 -- -- 80 80 HIGHER NGL PRICES Processing..................... 1 -- -- 1 3 -- -- 3 Javelina equity investment..... -- -- 4 4 -- -- 8 8 OTHER............................ -- -- (2) (2) 2 (1) (2) (1) --- ---- ---- ---- ---- ---- ---- ---- $-- $(17) $ 82 $ 65 $ (4) $(14) $ 86 $ 68 === ==== ==== ==== ==== ==== ==== ====

QUARTER ENDED SIX MONTHS JUNE 30, ENDED JUNE 30, ------------- --------------- 2004 2003 2004 2003 ---- ----- ----- ------ (IN MILLIONS) Gross margin.......................................... $ 4 $ (6) $ 9 $(11) Operating expenses.................................... (2) (6) (4) (9) ---- ---- --- ---- Operating income (loss)............................. 2 (12) 5 (20) Other income.......................................... 2 4 3 7 ---- ---- --- ---- EBIT................................................ $ 4 $ (8) $ 8 $(13) ==== ==== === ====

QUARTER ENDED SIX MONTHS JUNE 30, ENDED JUNE 30, ------------- --------------- 2004 2003 2004 2003 ---- ----- ----- ------ (IN MILLIONS) Long-term debt, including current maturities.......... $ 93 $102 $196 $201 Other interest........................................ -- 1 1 4 Capitalized interest.................................. (2) (2) (5) (5) ---- ---- ---- ---- Total interest and debt expense................ $ 91 $101 $192 $200 ==== ==== ==== ====

SIX MONTHS QUARTER ENDED ENDED JUNE 30, JUNE 30, --------------- ------------- 2004 2003 2004 2003 ------ ------ ----- ----- (IN MILLIONS, EXCEPT FOR RATES) Income taxes.............................................. $ 32 $19 $ 37 $89 Effective tax rate........................................ 34% 29% 34% 33%

EXHIBIT NUMBER DESCRIPTION ------- ----------- *31.A Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002. *31.B Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002. *32.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. *32.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.

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