UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q/A

(Amendment No. 1)

(Mark One)

[X]

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2005

OR

[  ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from           to           

Commission File Number 1-14365

El Paso Corporation

(Exact Name of Registrant as Specified in its Charter)

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 þ No o

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).  Yes þ No o

     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 May 6, 2005: 644,556,445

EL PASO CORPORATION

TABLE OF CONTENTS

      Below is a list of terms that are common to our industry and used throughout this document:

     When we refer to natural gas and oil in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

     When we refer to “us”, “we”, “our”, “ours”, or “El Paso”, we are describing El Paso Corporation and/or our subsidiaries.

EXPLANATORY NOTE

      This Form 10-Q/A (Amendment No. 1) is being filed to reflect adjustments in income from continuing operations and discontinued operations for the quarter ended March 31, 2004, resulting from errors in the accounting and reporting for foreign currency translation adjustments (CTA) and the related tax effects. There were no changes in reported operating cash flows in any period. We identified the accounting and reporting errors during the process of remediating the material weakness in internal control over financial reporting reported in our Form 10-K for the year ended December 31, 2004, as amended.

      Following a review of this matter, we determined that balances in CTA contained amounts related to businesses and investments that had previously been sold or abandoned. These balances should have been reclassified to earnings upon the sale or abandonment of these entities. The adjustment of these CTA balances affected losses we recorded on several of these assets and investments including impairment charges. In addition, we determined that upon initially recognizing U.S. deferred income taxes on our investment in certain foreign operations, we did not properly allocate taxes to CTA.

      The income statement impact of these adjustments for the first quarter of 2004 was a $10 million reduction in our net loss. The income effects impacted the results of both continuing and discontinued operations. As of December 31, 2004, the overall effect of the restatement on total stockholders’ equity, which includes the adjustments made for the first quarter of 2004 and in subsequent quarters of 2004, was a decrease of $1 million. The effects of these restatements have been reflected in our March 31, 2005 balance sheet.

      The restatement affects disclosures and tabular amounts in Item 1, Financial Statements and Supplementary Data; Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations; and Item 4, Control and Procedures.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per common share amounts)

(Unaudited)

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

(Unaudited)

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS — (Continued)

(In millions, except share amounts)

(Unaudited)

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

(Unaudited)

See accompanying notes.

EL PASO CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation and Significant Accounting Policies

     Basis of Presentation

      We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles. You should read this Quarterly Report on Form 10-Q along with our Annual Report on Form 10-K for the fiscal year ended December 31, 2004, as amended, which includes a summary of our significant accounting policies and other disclosures. The financial statements as of March 31, 2005, and for the quarters ended March 31, 2005 and 2004, are unaudited. We derived the balance sheet as of December 31, 2004, from the audited balance sheet filed in our 2004 Annual Report on Form 10-K, as amended. 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. In mid 2004, we discontinued our Canadian and certain other international natural gas and oil production operations. Our results for all periods reflect these operations as discontinued.

     Restatement

      Cumulative Foreign Currency Translation Adjustments (CTA). We determined that our CTA balances contained amounts related to businesses that had been previously sold or abandoned. These businesses and investments primarily included our discontinued Canadian exploration and production operations and certain of our discontinued petroleum markets activities, foreign plants in our Power segment, and certain foreign operations in our Marketing and Trading segment, and in our corporate activities. The adjustment of these CTA balances also affected losses we recorded in the first quarter of 2004 on several of these assets and investments, including impairment charges.

      In conjunction with the revisions for CTA, we also determined that upon initially recognizing deferred income taxes on certain of our foreign operations, we did not properly allocate taxes to CTA. As a result, we should have recognized an additional income tax expense in the first quarter of 2004 upon the sale of our discontinued Canadian exploration and production operations, additional tax expense in the second quarter of 2004 upon the sale of an Australian investment and an additional tax benefit in the fourth quarter of 2004 on an investment in Korea.

      The overall impact of these adjustments for CTA and their related tax impact was a $10 million reduction in our net loss for the first quarter of 2004. The income effects impacted the results of both continuing and discontinued operations. As of December 31, 2004, the overall effect of the restatement adjustments on total stockholders’ equity, which includes the adjustments of our first quarter 2004 and adjustments to other quarters in 2004, was a decrease of $1 million. The effects of these restatements have been reflected in our March 31, 2005 balance sheet.

      Below are the effects of the restatement on our income statement, balance sheets and statement of comprehensive income as compared to amounts reported in our Form 10-Q for the first quarter of 2005 filed on May 9, 2005. We have reflected these restatements in Notes 2, 4, 5, 6, 15 and 16.

     Significant Accounting Policies

      Our significant accounting policies are discussed in our 2004 Annual Report on Form 10-K, as amended. The information below provides updating information, disclosure where these policies have changed or required interim disclosures with respect to those policies.

  Variable Interest Entities

      In 2003, the Financial Accounting Standards Board (FASB) issued Financial Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51, which we adopted on January 1, 2004. This interpretation defined 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

required 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 conjunction with our application of FIN No. 46, we attempted to obtain financial information on several potential variable interest entities but were unable to obtain that information. The most significant of these entities is the Cordova power project which is the counterparty to our largest tolling arrangement. Under this tolling arrangement, we supply on average a total of 54,000 MMBtu of natural gas per day to the entity’s two 274 gross MW power facilities and are obligated to market the power generated by those facilities through 2019. In addition, we pay that entity a capacity charge that ranges from $27 million to $32 million per year related to its power plants. The following is a summary of the financial statement impacts of our transactions with this entity for the quarters ended March 31, 2005 and 2004 and as of March 31, 2005 and December 31, 2004:

      As of December 31, 2004, our financial statements included two consolidated entities that own a 238 MW power facility and a 158 MW power facility in Manaus, Brazil. In January 2005, these entities entered into agreements with Manaus Energia, under which Manaus Energia will supply substantially all of the fuel consumed and will purchase all of the power generated by the projects through January 2008, at which time Manaus Energia will assume ownership of the plants. We deconsolidated these two entities in January 2005 because Manaus Energia will absorb a majority of the potential losses of the entities under the new agreements and will assume ownership of the plants at the end of the agreements. The impact of this deconsolidation was an increase in investments in unconsolidated affiliates of $103 million, a decrease in property, plant and equipment of $74 million, a decrease in other assets of $32 million and a decrease in other liabilities of $3 million.

      We account for our stock-based compensation plans using the intrinsic value method under the provisions of Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and its related interpretations. Had we accounted for our stock option grants using Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, rather than APB No. 25, the loss and per share impacts of stock-based compensation on our financial statements would have been different. The following table shows the impact on net income (loss) and income (loss) per share had we applied SFAS No. 123:

      As of March 31, 2005, there were several accounting standards and interpretations that had not yet been adopted by us. Below is a discussion of significant standards that may impact us.

      Accounting for Stock-Based Compensation. In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment: an amendment of SFAS No. 123 and 95. This standard requires that companies measure and record the fair value of their stock based compensation awards at fair value on the date they are granted to employees. This fair value is determined using a variety of assumptions, including those related to volatility rates, forfeiture rates and the option pricing model used (e.g. binomial or Black Scholes). These assumptions could differ from those we have utilized in determining our proforma compensation expense (indicated above). This standard will also impact the manner in which we recognize the income tax impacts of our stock compensation programs in our financial statements. This standard is required to be adopted beginning January 1, 2006. However, companies are permitted to adopt the standard early. Upon adoption, we can select whether to apply the standard retroactively by restating our historical financial statements or prospectively for new stock-based compensation arrangements and the unvested portion of existing arrangements. We are currently evaluating the timing of our adoption and the impact of this standard on our consolidated financial statements.

      Accounting for Deferred Taxes on Foreign Earnings. In December 2004, the FASB issued FASB Staff Position (FSP) No. 109-2, Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004. FSP No. 109-2 clarified 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 also requires 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 have not yet determined the potential range of our foreign earnings that could be impacted by this legislation and FSP No. 109-2, and we continue to evaluate whether we will repatriate any foreign earnings and the impact, if any, that this pronouncement will have on our financial statements.

      Accounting for Asset Retirement Obligations. In March 2005, the FASB Issued FASB Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations. FIN No. 47 requires companies to record a liability for those asset retirement obligations in which the timing or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by SFAS No. 143, which we adopted on January 1, 2003. FIN No. 47 will require us to accrue a liability when a range of scenarios indicate that the potential timing and settlement amounts of our conditional asset retirement obligations can be determined. We will adopt the provisions of this standard in the fourth quarter of 2005 and have not yet determined the impact, if any, that this pronouncement will have on our financial statements.

2. Divestitures

      During the quarters ended March 31, 2005 and 2004, we completed the sale of a number of assets and investments in each of our business segments. The following table summarizes the proceeds from these sales:

     The following table summarizes the significant assets sold during the quarters ended March 31:

      In April 2005, we also completed the sale of our interest in the Enfield power facility in England for approximately $50 million, the sale of a power turbine for $15 million and the sale of real estate for $2 million.

      Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we classify assets to be disposed of as held for sale or, if appropriate, discontinued operations when they have received appropriate approvals by our management or Board of Directors and when they meet other criteria. As of March 31, 2005, we had assets held for sale of $122 million related to our Lakeside Technology Center and certain domestic power assets which were fully impaired in previous years and which we expect to sell within the next twelve months. As of December 31, 2004, we had assets held for sale of $75 million related to our Indian Springs natural gas gathering system and processing facility which were sold in the first quarter of 2005 and certain domestic power assets.

      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 December 31, 2004, we had completed the sale of all of our Canadian operations and substantially all of our operations in Indonesia for total proceeds of approximately $389 million. We expect to complete the sale of the remainder of these properties in 2005.

      Petroleum Markets. During 2003, our 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. In 2004, we completed the sales of our Aruba and Eagle Point refineries for $880 million.

      The petroleum markets and other international natural gas and oil production operations discussed above are classified as discontinued operations in our financial statements. All of the assets and liabilities of these discontinued businesses are classified as current assets and liabilities as of March 31, 2005 and December 31, 2004. The summarized financial results and financial position data of our discontinued operations were as follows:

3. Restructuring Costs

      During 2004, we incurred organizational restructuring costs included in our operation and maintenance expenses as part of our ongoing liquidity enhancement and cost reduction efforts. The discussion below provides additional details of these costs.

      Office relocation and consolidation. In May 2004, we announced that we would consolidate our Houston-based operations into one location. This consolidation was substantially completed by the end of 2004. As a result, as of December 31, 2004, we had established an accrual totaling $80 million to record the discounted liability, net of estimated sub-lease rentals, for our obligations under our existing lease terms. These leases expire at various times through 2014. Of the approximate 888,000 square feet of office space that we lease, we have vacated approximately 741,000 square feet as of March 31, 2005. In addition, we have subleased approximately 238,000 square feet of this space. Actual moving expenses related to the relocation were insignificant and were expensed in the period that they were incurred. All amounts related to the relocation are expensed in our corporate operations. We will incur additional charges as we vacate the remaining space that we lease, and estimate that the total additional accrual and charge could be $10 million to $20 million. In addition, we are currently reviewing our options regarding early release from the lease obligation, which if completed in its current form, will result in a further increase in amounts we have accrued. Based on current negotiations, the termination and early release of our obligations could result in additional accruals of $15 million to $20 million.

      Employee severance, retention, and transition costs. During the quarter ended March 31, 2004, we incurred $27 million of employee severance costs, which included severance payments and costs for pension benefits settled under existing benefit plans. During this period, we eliminated approximately 350 full-time positions from our continuing business and approximately 1,100 positions related to businesses we discontinued. As of March 31, 2005, all but $12 million of the total employee severance, retention and transition costs had been paid.

4. Loss on Long-Lived Assets

      Our loss on long-lived assets consists of realized gains and losses on sales of long-lived assets and impairments of long-lived assets. During the quarters ended March 31, our loss on long-lived assets was as follows:

Net Realized Gain

      Our 2005 net realized gains are primarily related to a gain on the sale of facilities located in the southeastern United States in our Pipelines segment. Our 2004 net realized gains are primarily related to a gain on aircraft sales associated with our corporate activities.

Asset Impairments

      In the first quarter of 2005, we recorded a $15 million impairment of our power turbines based on further information we received about their fair value and a $14 million impairment of our Asian assets based on additional information received during the sales process.

      In the first quarter of 2004, our Power segment recorded a $151 million impairment related to our Manaus and Rio Negro power plants in Brazil based on the status of our negotiations to extend the power contracts at these plants, which was negatively impacted by changes in the Brazilian political environment. Our Power segment also recorded a $98 million impairment charge related to the sale of our subsidiary, Utility Contract Funding, which owned a restructured power contract.

5. Income Taxes

      Income taxes included in our income (loss) from continuing operations for the quarters ended March 31 were as follows:

      We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant unusual or extraordinary transactions. Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. During the first quarter of 2005, our overall effective tax rate on continuing operations was negative (i.e. there was an overall tax benefit in a period in which there was income) due primarily to a $30 million reduction in our liabilities for tax contingencies as a result of an IRS settlement on the 1995 to 1997 Coastal Corporation income tax returns. Also impacting our effective tax rate were tax benefits recognized on the sale of a foreign investment and state tax adjustments to reflect income tax returns as filed. Partially offsetting these items was the tax impact of an impairment of certain of our foreign investments for which there was no corresponding tax benefit. During the first quarter of 2004, our overall effective tax rate on continuing operations was negative due primarily to the impairment of certain of our foreign investments for which there was no corresponding tax benefit.

6. Earnings Per Share

      We calculated basic and diluted earnings per common share amounts as follows for the quarters ended March 31:

      We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on income (loss) per common share is antidilutive. For the quarter ended March 31, 2004, all of our securities were antidilutive due to our loss from continuing operations. For the quarter ended March 31, 2005, we excluded our equity security units, trust preferred securities, and convertible debentures based on their antidilutive impact. Our diluted earnings per share could be negatively impacted by a proposed accounting standard that would affect the manner in which certain redemption features of our convertible debentures are treated for earnings per share calculations. For a further discussion of these convertible debentures, as well as other instruments, refer to our 2004 Annual Report on Form 10-K, as amended.

7. Price Risk Management Activities

      The following table summarizes the carrying value of the derivatives used in our price risk management activities as of March 31, 2005 and December 31, 2004. 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 and other commodity-based derivative contracts relate to our historical energy trading activities.

Interest rate and foreign currency hedging derivatives consist of instruments to hedge our interest rate and currency risks on long-term debt.

8. Inventory

      We have the following inventory recorded on our balance sheets:

9. Western Energy Settlement

      As of December 31, 2004 and March 31, 2005, we had a liability of $395 million and $442 million related to a 20 year cash payment obligation that arose out of the Western Energy Settlement. In the first quarter of 2005, we incurred a charge of approximately $59 million in operation and maintenance expense in our corporate operations associated with the anticipated payment of this obligation earlier than originally expected. In April 2005, we prepaid this deferred obligation.

10. Debt, Other Financing Obligations and Other Credit Facilities

      We had the following long-term and short-term borrowings and other financing obligations:

      From January 1, 2005 through the date of this filing, we had the following changes in our long-term financing obligations:

     Credit Facilities

      As of March 31, 2005, we had borrowing capacity under our $3 billion credit agreement of $0.4 billion. Amounts outstanding under the credit agreement were a $1.2 billion term loan and $1.4 billion of letters of credit. For a further discussion of our $3 billion credit agreement, our other credit facilities and their related restrictive covenants, see our 2004 Annual Report on Form 10-K, as amended.

      The availability of borrowings under our $3 billion credit agreement and our ability to incur additional debt is subject to various financial and non-financial covenants and restrictions. There have been no substantial changes to our restrictive covenants from those described in our Annual Report of Form 10-K, as amended. However, El Paso CGP Company is no longer required to maintain a minimum net worth of $850 million.

     Letters of Credit

      As of March 31, 2005, we had outstanding letters of credit of approximately $1.5 billion, of which $1.4 billion was outstanding under our $3 billion credit agreement and $102 million was supported with cash collateral. Included in our outstanding letters of credit were approximately $1.0 billion credit securing our recorded obligations related to price risk management activities.

11. Commitments and Contingencies

      Western Energy Settlement. In June 2003, we entered into various agreements to resolve the principal litigation, investigations, claims, and regulatory proceedings arising out of the sale or delivery of natural gas

and/or electricity to the western United States (the Western Energy Settlement). These agreements included a Joint Settlement Agreement or JSA where we agreed to certain conditions regarding service and facilities on EPNG. In June 2003, El Paso, the California Public Utilities Commission (CPUC), Pacific Gas and Electric Company, Southern California Edison Company, and the City of Los Angeles filed the JSA with the Federal Energy Regulatory Commission (FERC). In November 2003, the FERC approved the JSA with minor modifications. Our east of California shippers filed requests for rehearing, which were denied by the FERC on March 30, 2004. Certain shippers have appealed the FERC’s ruling to the U.S. Court of Appeals for the District of Columbia, where this matter is pending. We expect this appeal to be fully briefed by the summer of 2005.

          Shareholder/Derivative/ERISA Litigation

      Cash Balance Plan Lawsuit. In December 2004, a lawsuit entitled Tomlinson, et al. v. El Paso Corporation and El Paso Corporation Pension Plan was filed in U.S. District Court for Denver, Colorado. The lawsuit seeks class action status and alleges that the change from a final average earnings formula pension plan to a cash balance pension plan, the accrual of benefits under the plan, and the communications about the change violate the ERISA and/or the Age Discrimination in Employment Act. Our costs and legal exposure related to this lawsuit are not currently determinable.

      Retiree Medical Benefits Matters. We currently serve as the plan administrator for a medical benefits plan that covers a closed group of retirees of the Case Corporation who retired on or before June 30, 1994. Case was formerly a subsidiary of Tenneco, Inc. that was spun off prior to our acquisition of Tenneco in 1996. In connection with the Tenneco-Case Reorganization Agreement of 1994, Tenneco assumed the obligation to

provide certain medical and prescription drug benefits to eligible retirees and their spouses. We assumed this obligation as a result of our merger with Tenneco. However, we believe that our liability for these benefits is limited to certain maximums, or caps, and costs in excess of these maximums are assumed by plan participants. In 2002, we and Case were sued by individual retirees in federal court in Detroit, Michigan in an action entitled Yolton et al. v. El Paso Tennessee Pipeline Company and Case Corporation. The suit alleges, among other things, that El Paso and Case violated ERISA, and that they should be required to pay all amounts above the cap. Although such amounts will vary over time, the amounts above the cap have recently been approximately $1.8 million per month. Case further filed claims against El Paso asserting that El Paso is obligated to indemnify, defend, and hold Case harmless for the amounts it would be required to pay. In February 2004, a judge ruled that Case would be required to pay the amounts incurred above the cap. Furthermore, in September 2004, a judge ruled that pending resolution of this matter, El Paso must indemnify and reimburse Case for the monthly amounts above the cap. These rulings have been appealed. In the meantime, El Paso will indemnify Case for any payments Case makes above the cap. While we believe we have meritorious defenses to the plaintiffs’ claims and to Case’s crossclaim, if we were required to ultimately pay for all future amounts above the cap, and if Case were not found to be responsible for these amounts, our exposure could be as high as $400 million, on an undiscounted basis.

      Natural Gas Commodities Litigation. Beginning in August 2003, several lawsuits were filed against El Paso and El Paso Marketing L.P. (EPM), formerly El Paso Merchant Energy L.P., our affiliate, in which plaintiffs alleged, in part, that El Paso, EPM and other energy companies conspired to manipulate the price of natural gas by providing false price reporting information to industry trade publications that published gas indices. Those cases, all filed in the United States District Court for the Southern District of New York, are as follows: Cornerstone Propane Partners, L.P. v. Reliant Energy Services Inc., et al.; Roberto E. Calle Gracey v. American Electric Power Company, Inc., et al.; and Dominick Viola v. Reliant Energy Services Inc., et al. In December 2003, those cases were consolidated with others into a single master file in federal court in New York for all pre-trial purposes. In September 2004, the court dismissed El Paso from the master litigation. EPM and approximately 27 other energy companies remain in the litigation. In January 2005, a purported class action lawsuit styled Leggett et al. v Duke Energy Corporation et al. was filed against El Paso, EPM and a number of other energy companies in the Chancery Court of Tennessee for the Twenty-Fifth Judicial District at Somerville on behalf of the all residential and commercial purchasers of natural gas in the state of Tennessee during the past three years. Plaintiffs allege the defendants conspired to manipulate the price of natural gas by providing false price reporting information to industry trade publications that published gas indices. We have also had similar purported class claims filed in the U.S. District Court for the Eastern District of California by and on behalf of commercial and residential customers in that state. The case of Texas-Ohio Energy, Inc. v. CenterPoint Energy, Inc., et al. was filed in November 2003; Fairhaven Power v. El Paso Corporation, et al. was filed in September 2004; Utility Savings and Refund Services, et al. v. Reliant Energy, et al. was filed in December 2004; and Abelman Art Glass, et al. v. Encana Corporation, et al. was filed in December 2004. The defendants’ motion to dismiss in the Texas-Ohio matter has been granted and similar motions are anticipated in the other cases. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      Grynberg. In 1997, a number of our subsidiaries were named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. The plaintiff in this case seeks royalties that he contends the government should have received had the volume and heating value 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). Motions to dismiss have been briefed and argued and the parties are awaiting the court’s ruling. 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 petition has since been filed as to the heating content claims. Motions for class certification have been briefed and argued in both proceedings, and the parties are awaiting the court’s ruling. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      Bank of America. We are a named defendant, along with Burlington Resources, Inc., in two class action lawsuits styled as Bank of America, et al. v. El Paso Natural Gas Company, et al., and Deane W. Moore, et al. v. Burlington Northern, Inc., et al., each filed in 1997 in the District Court of Washita County, State of Oklahoma and subsequently consolidated by the court. The plaintiffs seek an accounting and damages for alleged royalty underpayments from 1982 to the present on natural gas produced from specified wells in Oklahoma, plus interest from the time such amounts were allegedly due, as well as punitive damages. The court has certified the plaintiff classes of royalty and overriding royalty interest owners. The plaintiffs have filed expert reports alleging damages in excess of $1 billion. Pursuant to a recent summary judgment decision, the court ruled that claims previously released by the settlement of Altheide v. Meridian, a nation-wide royalty class action against Burlington and its affiliates are barred from being reasserted in this action. We believe that this ruling eliminates a material, but yet unquantified portion of the alleged class damages. The consolidated class action has been set for trial in the third quarter of 2005. While Burlington accepted our tender of the defense of these cases in 1997, pursuant to the spin-off agreement entered into in 1992 between EPNG and Burlington Resources, Inc., and had been defending the matter since that time, at the end of 2003 it asserted contractual claims for indemnity against us. A third action, styled Bank of America, et al. v. El Paso Natural Gas and Burlington Resources Oil and Gas Company, was filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting similar claims as to specified shallow wells in Oklahoma, Texas and New Mexico. Defendants succeeded in transferring this action to Washita County. A class has not been certified. We have filed an action styled El Paso Natural Gas Company v. Burlington Resources, Inc. and Burlington Resources Oil and Gas Company, L.P. against Burlington in state court in Harris County relating to the indemnity issues between Burlington and us. That action is currently stayed. We believe we have substantial defenses to the plaintiffs’ claims as well as to the claims for indemnity by Burlington. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      Araucaria. We own a 60 percent interest in a 484 MW gas-fired power project known as the Araucaria project located near Curitiba, Brazil. The Araucaria project has a 20-year power purchase agreement (PPA) with a government-controlled regional utility. In December 2002, the utility ceased making payments to the project and, as a result, the Araucaria project and the utility are currently involved in international arbitration over the PPA. A Curitiba court has ruled that the arbitration clause in the PPA is invalid, and has enjoined the project company from prosecuting its arbitration under penalty of approximately $173,000 in daily fines. The project company is appealing this ruling, and has obtained a stay order in any imposition of daily fines pending the outcome of the appeal. Our investment in the Araucaria project was $186 million at March 31, 2005. We have political risk insurance that covers a substantial portion of our investment in the project. Based on the future outcome of our dispute under the PPA and depending on our ability to collect amounts from the utility or under our political risk insurance policies, we could be required to write down the value of our investment.

      Macae. We own a 928 MW gas-fired power plant known as the Macae project located near the city of Macae, Brazil with property, plant and equipment having a net book value of $694 million as of March 31, 2005. The Macae project revenues are derived from sales to the spot market, bilateral contracts and minimum capacity and revenue payments. The minimum capacity and energy revenue payments of the Macae project are paid by Petrobras until August 2007 under a participation agreement. Beginning in December 2004, and continuing through the first quarter of 2005, Petrobras has failed to make payments that were due under the participation agreement. In February 2005, Petrobras obtained a ruling from a Brazilian court directing Petrobras to deposit one-half of the payments to a court account and to pay us the other half. This ruling was vacated by another Brazilian court in April 2005 due to Petrobras’ failure to pay the amounts in accordance with the ruling. Due to this ongoing dispute, we have not recognized approximately $45 million of revenues under our participation agreement in the first quarter of 2005, due to the uncertainty about their collectibility. Petrobras has filed a notice of arbitration with an international arbitration institution that effectively seeks rescission of the participation agreement and reimbursement of a portion of the capacity payments that it has made. If such claim were successful, it would result in a termination of the minimum revenue payments as well as Petrobras’s obligation to provide a firm gas supply to the project through 2012. We believe we have substantial defenses to the claims of Petrobras and will vigorously defend our legal rights. In addition, we will continue to seek reasonable negotiated settlements of this dispute, including the restructuring of the participation agreement or the sale of the plant. Macae has non-recourse debt of approximately $275 million at March 31, 2005, and Petrobras’ non-payment has created an event of default under the applicable loan agreements. As a result, we have classified the entire $275 million of debt as current. We also have restricted cash balances of approximately $22 million as of March 31, 2005, which are reflected in current assets, related to required debt service reserve balances, debt service payment accounts and funds held for future distribution by Macae. We have also issued cash collateralized letters of credit of approximately $47 million as part of funding the required debt service reserve accounts. The restricted cash related to these letters of credit has also been classified as a current asset. In light of the default of Petrobras under the participation agreement and the potential inability of Macae to continue to make ongoing payments under its loan agreements, one or more of the lenders could exercise certain remedies under the loan agreements in the future, one of which could be an acceleration of the amounts owed under the loan agreements which could ultimately result in the lenders foreclosing on the Macae project.

      In light of the pending arbitration proceedings, we have evaluated whether any impairment of our interest in the long-lived assets of the project and our remaining accounts receivable from Petrobras of $24 million, is required at March 31, 2005. Based upon our review of the possible outcomes of the arbitration and potential settlements of the dispute, and despite the fact that we have not recognized revenues under the participation agreement in the first quarter of 2005, we do not believe that an impairment of these interests is required at this time. However, if our assessment of the potential outcomes of the arbitration or settlement opportunities changes, we may be required to write down some or all of the project’s long-lived assets and accounts receivable. In the event that the lenders call the loans and ultimately foreclose on the project, our loss would be approximately $479 million as of March 31, 2005. As new information becomes available or future material developments occur, we will reassess the carrying value of our interests in this project.

      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 some of our subsidiaries are among the defendants in over 60 such lawsuits. As a result of a ruling issued on March 16, 2004, these suits 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, certain state attorneys general and various water districts, 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.

      Wise Arbitration. William Wise, our former Chief Executive Officer, initiated an arbitration proceeding alleging that we breached employment and other agreements by failing to make certain payments to him

following his departure from El Paso in 2003. Mr. Wise seeks approximately $20 million in additional compensation. Discovery is underway, with a hearing scheduled in the summer of 2005.

Government Investigations

      Power Restructuring. In October 2003, we 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 have cooperated with the SEC investigation.

      Wash Trades. In June 2002, we received an informal inquiry from the SEC regarding the issue of round trip trades. Although we do not believe any round trip trades occurred, we submitted data to the SEC in July 2002. In July 2002, we received a federal grand jury subpoena for documents concerning round trip or wash trades. We have complied with those requests. We have also cooperated with the U.S. Attorney regarding an investigation of specific transactions executed in connection with hedges of our natural gas and oil production and the restatement of such hedges.

      Price Reporting. In October 2002, the FERC issued data requests regarding price reporting of transactional data to the energy trade press. We provided information to the FERC, the Commodity Futures Trading Commission (CFTC) and the U.S. Attorney in response to their requests. In the first quarter of 2003, we announced a settlement with the CFTC of the price reporting matter providing for the payment of a civil monetary penalty by EPM of $20 million, $10 million of which is payable in 2006, without admitting or denying the CFTC holdings in the order. We are continuing to cooperate with the U.S. Attorney’s investigation of this matter.

      Reserve Revisions. In March 2004, we received a subpoena from the SEC requesting documents relating to our December 31, 2003 natural gas and oil reserve revisions. We have also received federal grand jury subpoenas for documents with regard to these reserve revisions. We are cooperating with the SEC’s and the U.S. Attorney’s investigations of this matter.

      Iraq Oil Sales. In September 2004, The Coastal Corporation (now known as El Paso CGP Company, which we acquired in January 2001) 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 Coastal Corporation’s and El Paso’s participation in the Oil for Food Program. We have also received informal requests for information and documents from the United States Senate’s Permanent Subcommittee of Investigations and the House of Representatives International Relations Committee related to Coastal’s purchases of Iraqi crude under the Oil for Food Program. We are cooperating with the U.S. Attorney’s, the SEC’s, the Senate Subcommittee’s, and the House Committee’s investigations of this matter.

      Carlsbad. In August 2000, a main transmission line owned and operated by EPNG ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve individuals at the site were fatally injured. In June 2001, the U.S. Department of Transportation’s Office of Pipeline Safety (DOT) issued a Notice of Probable Violation and Proposed Civil Penalty to EPNG. The Notice alleged five violations of DOT regulations, proposed fines totaling $2.5 million and proposed corrective actions. In April 2003, the National Transportation Safety Board (NTSB) issued its final report on the rupture, finding that the rupture was probably caused by internal corrosion that was not detected by EPNG’s corrosion control program. In December 2003, this matter was referred by the DOT to the Department of Justice. In addition, we, EPNG and several of its current and former employees have received several federal grand jury subpoenas for documents or testimony related to the Carlsbad rupture. We are cooperating with the Department of Justice’s investigation of this matter.

      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.

Rates and Regulatory Matters

      Accounting for Pipeline Integrity Costs. In November 2004, the FERC issued a proposed accounting release that may impact certain costs our interstate pipelines incur related to their pipeline integrity programs. If the release is enacted as written, we would be required to expense certain future pipeline integrity costs instead of capitalizing them as part of our property, plant and equipment. Although we continue to evaluate the impact of this potential accounting release, we currently estimate that if the release is enacted as written, we would be required to expense an additional amount of pipeline integrity expenditures in the range of approximately $25 million to $41 million annually over the next eight years.

      Selective Discounting Notice of Inquiry. In November 2004, the FERC issued a NOI seeking comments on its policy regarding selective discounting by natural gas pipelines. The FERC seeks comments regarding whether its practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons is appropriate when the discount is given to meet competition from another natural gas pipeline. Our pipelines filed comments on the NOI. Neither the final outcome of this inquiry nor the impact on our pipelines can be predicted with certainty.

Other Contingencies

      Navajo Nation. Nearly 900 looped pipeline miles of the north mainline of our EPNG pipeline system are located on property inside the Navajo Nation. We currently pay approximately $2 million per year for the real property interests, such as easements, leases and rights-of-way located on Navajo Nation trust lands. These real property interests are scheduled to expire in October 2005. We are in negotiations with the Navajo Nation to renew these interests, but the Navajo Nation has made a demand of more than ten times the existing fee. We will continue to negotiate in order to reach an agreement on a renewal, but we are also exploring other options including potentially developing collaborative projects to benefit the Navajo Nation in lieu of cash payments. The outcome of this process is uncertain, but we may incur higher future costs arising from potential litigation or increased right-of-way fees.

      Brazilian Matters. We own a number of interests in various production properties, power and pipeline assets in Brazil, including our Macae project discussed previously. Our total investment in Brazil was approximately $1.6 billion as of March 31, 2005. In a number of our assets and investments, Petrobras either serves as a joint owner, a customer or a shipper to the asset or project. Although we have no material current disputes with Petrobras with regard to the ownership or operation of our production and pipeline assets, current disputes on the Macae power plant between us and Petrobras may negatively impact these investments and the impact could be material. We also own an investment in the Porto Velho power plant. The Porto Velho project is in the process of negotiating certain provisions of its PPAs with Eletronorte, including the amount of installed capacity, energy prices, take or pay levels, the term of the first PPA and other issues. In addition, in October 2004, the project experienced an outage with a steam turbine which resulted in a partial reduction in the plant’s capacity. The project expects to replace or repair the steam turbine by the first quarter of 2006. We are uncertain what impact this outage will have on the PPAs. Although the current terms of the PPAs and the ongoing contract negotiations do not indicate an impairment of our investment, we may be required to write down the value of our investment if these negotiations are resolved unfavorably. Our investment in Porto Velho was approximately $303 million at March 31, 2005.

      For each of our outstanding legal and other contingent 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. While the outcome of these matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, 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. As of March 31, 2005, we had approximately $624 million accrued, net of related insurance receivables, for all outstanding legal and other contingent matters, including amounts accrued for our Western Energy Settlement.

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 March 31, 2005, we had accrued approximately $383 million, including approximately $371 million for expected remediation costs and associated onsite, offsite and groundwater technical studies, and approximately $12 million for related environmental legal costs, which we anticipate incurring through 2027. Of the $383 million accrual, $102 million was reserved for facilities we currently operate, and $281 million was reserved for non-operating sites (facilities that are shut down or have been sold) and Superfund sites.

      Our reserve estimates range from approximately $383 million to approximately $547 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 ($85 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($298 million to $462 million) and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. By type of site, our reserves are based on the following estimates of reasonably possible outcomes.

      Below is a reconciliation of our accrued liability from January 1, 2005, to March 31, 2005 (in millions):

      For the remainder of 2005, we estimate that our total remediation expenditures will be approximately $66 million. In addition, we expect to make capital expenditures for environmental matters of approximately $63 million in the aggregate for the years 2005 through 2009. These expenditures primarily relate to compliance with clean air regulations.

      Polychlorinated Biphenyls (PCB) Cost Recoveries. Pursuant to a consent order executed by Tennessee Gas Pipeline (TGP), our subsidiary, in May 1994, with the EPA, TGP has been conducting various remediation activities at certain of its compressor stations associated with the presence of PCBs, and certain other hazardous materials. In May 1995, following negotiations with its customers, TGP filed an agreement with the FERC that established a mechanism for recovering a substantial portion of the environmental costs identified in its PCB remediation project. The agreement, which was approved by the FERC in November 1995, provided for a PCB surcharge on firm and interruptible customers’ rates to pay for eligible remediation costs, with these surcharges to be collected over a defined collection period. TGP has received approval from the FERC to extend the collection period, which is now currently set to expire in June 2006. The agreement

also provided for bi-annual audits of eligible costs. As of March 31, 2005, TGP had pre-collected PCB costs by approximately $127 million. The pre-collected amount will be reduced by future eligible costs incurred for the remainder of the remediation project. To the extent actual eligible expenditures are less than the amounts pre-collected, TGP will refund to its customers the difference, plus carrying charges incurred up to the date of the refunds. As of March 31, 2005, TGP has recorded a regulatory liability (included in other non-current liabilities on its balance sheet) of $99 million for the estimated future refund obligations.

      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 53 active sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third-parties and settlements which provide for payment of our allocable share of remediation costs. As of March 31, 2005, we have estimated our share of the remediation costs at these sites to be between $29 million and $49 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, regulations, and orders of regulatory agencies, as well as claims for damages to property, the environment and injuries to employees and other persons 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 reserves are adequate.

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. See our 2004 Annual Report on Form 10-K, as amended, for a description of these guarantees. As of March 31, 2005, we had approximately $30 million of both financial and performance guarantees not otherwise reflected in our financial statements. We also periodically provide indemnification arrangements related to assets or businesses we have sold. As of March 31, 2005, we had accrued $65 million related to these arrangements.

12. Preferred Interests of Consolidated Subsidiaries

      As March 31, 2005, our subsidiary, El Paso Tennessee Pipeline Co. (EPTP) had $300 million of 8.25% Series A cumulative preferred stock outstanding. In April 2005, EPTP gave notice of its intent to redeem its preferred stock in May 2005 for $300 million plus accrued dividends.

13. Retirement Benefits

      The components of net benefit cost for our pension and postretirement benefit plans for the quarters ended March 31 are as follows:

     In 2004, we adopted FSP No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. This pronouncement required us to record the impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 on our postretirement benefit plans that provide drug benefits that are covered by that legislation. The adoption of FSP No. 106-2 decreased our accumulated postretirement benefit obligation by $49 million. In addition, it reduced our net periodic benefit cost by approximately $2 million for the first quarter of 2005. Our actual and expected contributions for 2005 were not reduced by subsidies under this legislation.

      We made $18 million and $15 million of cash contributions to our Supplemental Executive Retirement Plan (SERP) and other postretirement plans during the quarters ended March 31, 2005 and 2004. We expect to contribute an additional $4 million to the SERP and $47 million to our other postretirement plans for the remainder of 2005. Contributions to our other retirement benefit plans will be less than $1 million in 2005.

14. Capital Stock

     Dividends

      During the quarter ended March 31, 2005, we paid dividends of approximately $26 million to common stockholders. The dividends on our common stock were treated as a reduction of additional paid-in-capital since we currently have an accumulated deficit. On April 28, 2005, the Board of Directors declared a quarterly dividend of $0.04 per share on our outstanding common stock. This dividend is payable July 5, 2005 to shareholders of record on June 3, 2005. We expect dividends paid on our common stock in 2005 will be taxable to our common stockholders because we anticipate that these dividends will be paid out of current or accumulated earnings and profits for tax purposes.

      In addition, El Paso Tennessee Pipeline Co., our subsidiary, paid dividends (2.0625% per quarter, 8.25% per annum) of approximately $6 million on its Series A cumulative preferred stock.

     Convertible Perpetual Preferred Stock

      In April 2005, we issued $750 million of convertible perpetual preferred stock. Cash dividends on the preferred stock will be paid quarterly at the rate of 4.99% per annum. Each share of the preferred stock will be convertible at the holder’s option, at any time, subject to adjustment, into 76.7754 shares of our common stock under certain conditions. This conversion rate represents an equivalent conversion price of approximately $13.03 per share. The conversion rate is subject to adjustment based on certain events which include, but are not limited to, fundamental changes in our business such as mergers or business combinations as well as distributions of our common stock or adjustments to the current rate of dividends on our common stock. We

will be able to cause the preferred stock to be converted into common stock after five years if our common stock is trading at a premium of 130 percent to the conversion price.

15. Business Segment Information

      Our regulated business consists of our Pipelines segment, while our non-regulated businesses consist of our Production, Marketing and Trading, 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 a telecommunications business and various other contracts and assets, all of which are immaterial. 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 financial statements. Our operating results for all periods presented reflect these operations as discontinued.

      In the first quarter of 2004, our Power and Marketing and Trading segments have been restated to adjust the amount of losses on long-lived assets, earnings from unconsolidated affiliates and other income for certain foreign entities with CTA balances and related tax effects. See Note 1 for a further discussion of the restatement.

      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 (loss) from continuing operations for the quarters ended March 31:

      The following tables reflect our segment results as of and for the quarters ended March 31: