10-Q 1 h90886e10-q.txt EL PASO TENNESSEE PIPELINE CO. - 9/30/2001 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 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, 2001 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 1-9864 --------------------- EL PASO TENNESSEE PIPELINE CO. (Exact Name of Registrant as Specified in its Charter) DELAWARE 76-0233548 (State or Other Jurisdiction (I.R.S. Employer of Incorporation or Organization) Identification No.) EL PASO BUILDING 1001 LOUISIANA STREET HOUSTON, TEXAS 77002 (Address of Principal Executive Offices) (Zip Code)

Registrant's Telephone Number, Including Area Code: (713) 420-2600 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate 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 $.01 per share. Shares outstanding on November 6, 2001: 1,971 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- PART I -- FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS EL PASO TENNESSEE PIPELINE CO. CONDENSED CONSOLIDATED STATEMENTS OF INCOME (IN MILLIONS) (UNAUDITED)

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

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

See accompanying notes. 3 EL PASO TENNESSEE PIPELINE CO. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS) (UNAUDITED)

See accompanying notes. 4 EL PASO TENNESSEE PIPELINE COMPANY CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (IN MILLIONS) (UNAUDITED)

See accompanying notes. 5 EL PASO TENNESSEE PIPELINE CO. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. BASIS OF PRESENTATION Our 2000 Annual Report on Form 10-K includes a summary of our significant accounting policies and other disclosures. You should read it in conjunction with this Quarterly Report on Form 10-Q. The financial statements as of September 30, 2001, and for the quarters and nine months ended September 30, 2001 and 2000, are unaudited. The balance sheet as of December 31, 2000, is derived from the audited balance sheet included in our Annual Report on Form 10-K. These financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission and do not include all disclosures required by accounting principles generally accepted in the United States. In our opinion, we have made all adjustments, all of which are of a normal, recurring nature (except for merger-related costs and asset impairments as discussed below), to fairly present our interim period results. Information for interim periods may not necessarily indicate the results of operations for the entire year due to the seasonal nature of our businesses. The prior period information also includes reclassifications which were made to conform to the current period presentation. These reclassifications have no effect on our reported net income or stockholders' equity. Our accounting policies are consistent with those discussed in our Form 10-K, except as discussed below. You should refer to the Form 10-K for a further discussion of those policies. Accounting for Price Risk Management Activities Our business activities expose us to a variety of risks, including commodity price risk, interest rate risk and foreign currency risk. Our corporate risk management group identifies risks associated with our businesses and determines which risks we want to manage and which types of instruments we should use to manage those risks. We record all derivative instruments on the balance sheet at their fair value under the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivatives and Hedging Activities. These instruments consist of two types, those derivatives entered into and held to mitigate, or hedge a particular risk, and those that are entered into and held for purposes other than risk mitigation, such as those in our trading activities. Those instruments that do not qualify as hedges are recorded at their fair value with changes in fair value reported in current period earnings. For those instruments entered into to hedge risk, and which qualify as hedges, we apply the provisions of SFAS No. 133, and the accounting treatment depends on each instrument's intended use and how it is designated. Derivative instruments that qualify as hedges may be designated as fair value hedges, cash flow hedges, foreign currency hedges or net investment hedges as defined in SFAS No. 133. In addition to its designation, a hedge must be effective. To be effective, the value of the derivative or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged. If it is determined that the hedge is no longer effective, hedge accounting is discontinued prospectively. Hedge accounting is also discontinued when: - the derivative instrument expires or is sold, terminated or exercised; - it is no longer probable that the forecasted transaction will occur; - the hedged firm commitment no longer meets the definition of a firm commitment; or - management determines that the designation of the derivative instrument as a hedge is no longer appropriate. 6 At the time we enter into a hedge, we formally document relationships between the hedging instrument and the hedged items. This documentation includes: - the nature of the risk being hedged; - our risk management objectives and strategies for undertaking the hedging activity; - a description of the hedged item and the derivative instrument used to hedge the item; - a description of how effectiveness is tested at the inception of the hedge; and - how effectiveness will be tested on an ongoing basis. When hedge accounting is discontinued, the derivative instrument continues to be carried on the balance sheet at its fair value. However, any further changes in its fair value are recognized in current period earnings. Accounting for the item that was being hedged differs depending on how the hedge was originally designated. Our accounting policies for derivative instruments used in our business that qualify as hedges are discussed below:

Because our business activities encompass all aspects of the wholesale energy marketplace, including the gathering, processing, treating, transmission and the purchase and sale of highly liquid energy commodities, our normal business contracts may qualify as derivative instruments under the provisions of SFAS No. 133. As a result, we evaluate each of our commercial contracts to see if derivative accounting is appropriate. Contracts that meet the criteria of a derivative are then evaluated to determine whether they qualify as a "normal purchase" or a "normal sale" as those terms are defined in SFAS No. 133. If they qualify as normal purchases and normal sales, we may exclude them from SFAS No. 133 treatment. We also evaluate our contracts for "embedded" derivatives. Embedded derivatives have terms that are not clearly and closely related to the terms 7 of the contract in which they are included. If embedded derivatives exist, they are accounted for separately from the host contract as derivatives, with changes in their fair value recorded in current period earnings. 2. MERGER-RELATED COSTS AND ASSET IMPAIRMENTS During the quarter and nine months ended September 30, 2001, we incurred merger-related costs associated with El Paso Corporation's merger with The Coastal Corporation and asset impairments as follows:

Merger-Related Costs Our merger-related costs consisted of the following:

Employee severance, retention and transition costs include direct payments to, and benefit costs for, severed employees and early retirees that occurred as a result of El Paso's merger-related workforce reduction and consolidation. Make-whole commitments relate to a series of payments we will make to El Paso Energy Partners L.P. in connection with the Federal Trade Commission's (FTC) ordered divestiture of interests in assets owned by the partnership. Asset Impairments During the nine months ended September 30, 2001, we incurred an asset impairment charge of $38 million resulting from Merchant Energy's impairment of its East Asia Power investment in the Philippines. This write down was a result of weak economic conditions causing a permanent decline in the value of our investment. We continue to hold this investment. 3. EXTRAORDINARY ITEMS As a result of El Paso's merger with Coastal, we were required by the FTC to sell our Midwestern Gas Transmission system. We completed this sale in April 2001. Net proceeds were approximately $95 million, and we recognized an extraordinary gain of $38 million, net of income taxes of $21 million. During the first quarter of 2000, we sold East Tennessee Natural Gas Company to comply with an FTC order related to El Paso's merger with Sonat Inc. Net proceeds from the sale were approximately $386 million, and we recognized an extraordinary gain of $77 million, net of income taxes of $51 million. 4. ACCOUNTING FOR HEDGING ACTIVITIES On January 1, 2001, we adopted the provisions of SFAS No. 133 and recorded a cumulative-effect adjustment of $154 million, net of income taxes, in accumulated other comprehensive income to recognize the fair value of all derivatives designated as hedging instruments. The majority of the initial charge related to hedging cash flows from anticipated sales of natural gas for 2001 and 2002. During the quarter and nine months ended September 30, 2001, $2 million and $130 million, net of income taxes, of this initial transition 8 adjustment was reclassified to earnings as a result of hedged sales and purchases during the periods, and an additional $1 million of this adjustment is expected to be reclassified by the end of 2001. A majority of our commodity sales and purchases are at spot market or forward market prices. We use futures, forward contracts and swaps to limit our exposure to fluctuations in the commodity markets and allow for a fixed cash flow stream from these activities. As of September 30, 2001, the value of cash flow hedges included in accumulated other comprehensive income was an unrealized loss of $15 million, net of income taxes. Of this amount, we estimate that $4 million will be reclassified from accumulated other comprehensive income over the next 12 months. Reclassifications occur upon physical delivery of the hedged commodity and the corresponding expiration of the hedge. The maximum term of our cash flow hedges is 1 year. Our other comprehensive income includes a loss of $26 million representing our proportionate share of amounts recorded in other comprehensive income by our unconsolidated affiliates who use derivatives as cash flow hedges. The maximum term of these cash flow hedges is 2 years, excluding hedges relating to interest rates on variable debt. For the quarter and nine months ended September 30, 2001, we recognized net losses of $3 million and net gains of $10 million, net of income taxes, related to the ineffective portion of all cash flow hedges. 5. INVENTORY Our inventory consisted of the following:

6. DEBT AND OTHER CREDIT FACILITIES At September 30, 2001, our weighted average interest rate on short-term borrowings was 3.6%, and at December 31, 2000, it was 7.6%. We had the following short-term borrowings, including current maturities of long-term debt:

Acquisition of PG&E's Texas Midstream Operations In connection with our acquisition of PG&E's Texas Midstream operations in December 2000, we assumed $527 million in debt. As of September 2001, we redeemed $341 million of the assumed debt. Revolving Credit Facility In June 2001, El Paso replaced its $2 billion, 364-day revolving credit facility with a renewable $3 billion, 364-day revolving credit and competitive advance facility. Tennessee Gas Pipeline Company (TGP) is a designated borrower under this facility and, as such, is liable for any amounts outstanding under this facility. The interest rate varies and was based on the London Interbank Offered Rate (LIBOR) plus 50 basis points at September 30, 2001. No amounts were outstanding under this facility at September 30, 2001. 9 Other In addition to the items discussed above, during the nine months ended September 30, 2001, we retired long-term debt with the aggregate principal amount of approximately $37 million. 7. COMMITMENTS AND CONTINGENCIES Legal Proceedings El Paso Merchant Energy and several of our affiliates were named defendants in nine purported class action or citizen lawsuits and one shareholder lawsuit filed in California state courts (a list of the California cases is included in Part II, Item 1, Legal Proceedings). The class action cases contend generally that our entities acted alone or in combination with other unrelated companies to limit the construction of new pipeline capacity to California or to manipulate the price of natural gas sold into the California marketplace. The shareholder suit contends that we, through our directors, failed to prevent the conduct alleged in these underlying cases. We removed each of these cases to federal court and have requested that they be consolidated for all pretrial activities. Eight of the nine suits were consolidated in the U.S. District Court in Nevada. On October 25, 2001, the Nevada court remanded these cases to the California State court system for all further proceedings. In September 2001, we received a civil document subpoena from the California Department of Justice, seeking information said to be relevant to the Department's ongoing investigation into the high electricity prices in California. We have produced and expect to continue to produce materials pursuant to this subpoena. In August 2000, the Liquidating Trustee in the bankruptcy of Power Corporation of America sued Merchant Energy, and several other power traders, in the U.S. Bankruptcy Court in Connecticut claiming Merchant Energy improperly cancelled its contracts with Power Corporation during the summer of 1998. The trustee alleged we breached contracts damaging Power Corporation in the amount of $120 million. In May 2001, we agreed to settle this matter for a cash payment of $3 million. In a related matter, Power Corporation appealed the Federal Energy Regulatory Commission's (FERC) ruling that power marketers such as Merchant Energy did not have to give 60 days notice to cancel its power contracts under the Federal Power Act. Power Corporation has appealed this decision to the United States Court of Appeals, which ruled in FERC's favor. In February 1998, the United States and the state of Texas filed in a U.S. District Court a Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) cost recovery action against 14 companies, including us and some of our current and former affiliates, related to the Sikes Disposal Pits Superfund Site located in Harris County, Texas. Plaintiffs, defendants and most of the third-party defendants, including our current and former affiliates, have reached a settlement reflected in a consent decree lodged in the district court on September 20, 2001. If the consent decree is approved by the court, the plaintiffs will be reimbursed $120 million plus interest since June 2001, and the defendants and settling third-party defendants will receive releases and contribution protection. The settlement will not have a material adverse effect on our financial position, operating results or cash flows. The remaining contribution claims by the defendants against the non-settlement third-party defendants are scheduled for trial in late 2001. In 1997, a number of our subsidiaries and affiliates 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 under report 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. 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). In May 2001, the court denied the defendants' motions to dismiss. A number of our subsidiaries and affiliates were named defendants in Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al, filed in 1999 in the District Court of Stevens County, Kansas. This class action complaint alleges that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands. The Quinque complaint was transferred to the 10 same court handling the Grynberg complaint and has now been sent back to Kansas State Court for further proceedings. A motion to dismiss this case is pending. In November 1988, the Kentucky environmental agency filed a complaint in a Kentucky state court alleging that TGP discharged pollutants into the waters of the state and disposed of polychlorinated biphenyls (PCBs) without a permit. The agency sought an injunction against future discharges, an order to remediate or remove PCBs and a civil penalty. TGP entered into agreed orders with the agency to resolve many of the issues raised in the original allegations and received water discharge permits from the agency for its Kentucky compressor stations. The relevant Kentucky compressor stations are being characterized and remediated under a 1994 consent order with the Environmental Protection Agency (EPA). We are also a named defendant in numerous lawsuits and a named party in numerous governmental proceedings arising in the ordinary course of our business. While the outcome of the matters discussed above cannot be predicted with certainty, based on information known to date, we do not expect the ultimate resolution of these matters to have a material adverse effect on our ongoing financial position, operating results or cash flows. Environmental We are subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of September 30, 2001, we had a reserve of approximately $112 million for expected remediation costs. In addition, we expect to make capital expenditures for environmental matters of approximately $103 million in the aggregate for the years 2001 through 2006. These expenditures primarily relate to compliance with clean air regulations. Since 1988, TGP has been engaged in an internal project to identify and deal with the presence of PCBs and other substances, including those on the EPA List of Hazardous Substances, at compressor stations and other facilities it operates. While conducting this project, TGP has been in frequent contact with federal and state regulatory agencies, both through informal negotiation and formal entry of consent orders, to ensure that its efforts meet regulatory requirements. In May 1995, following negotiations with its customers, TGP filed a stipulation and agreement with the Federal Energy Regulatory Commission (FERC) that established a mechanism for recovering a substantial portion of the environmental costs identified in its internal project. The stipulation and agreement was effective July 1, 1995, and most of the amounts have been collected from customers. Refunds may be required to the extent actual eligible expenditures are less than amounts collected. TGP is a party in proceedings involving federal and state authorities regarding the past use of PCBs in its starting air systems. TGP executed a consent order in 1994 with the EPA governing the remediation of the relevant compressor stations and is working with the EPA and the relevant states regarding those remediation activities. TGP is also working with the Pennsylvania and New York environmental agencies regarding remediation and post-remediation activities at the Pennsylvania and New York stations. We have been designated and 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 eight active sites under CERCLA or state equivalents. We have sought to resolve our liability as a PRP at these CERCLA sites, as appropriate, through indemnification by third parties and/or settlements which provide for payment of our allocable share of remediation costs. As of September 30, 2001, we have estimated our share of the remediation costs at these sites to be approximately $2 million and have provided reserves that we believe are adequate for such costs. Since the cleanup 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 11 considered, where appropriate, in the determination of our estimated liabilities. We presently believe that the costs associated with these CERCLA sites will not have a material adverse effect on our financial position, operating results or cash flows. 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 the recorded reserves are adequate. For a further discussion of specific environmental matters, see Legal Proceedings above. Rates and Regulatory Matters In April 2000, the California Public Utilities Commission (CPUC) filed a complaint with FERC alleging that El Paso Natural Gas Company's (EPNG) sale of approximately 1.2 billion cubic feet per day of California capacity to Merchant Energy was anticompetitive and an abuse of the affiliate relationship under FERC's policies. Other parties in the proceeding requested that the original complaint be set for hearing and that Merchant Energy pay back any profits it has earned under the contract. In March 2001, FERC established a hearing, before an administrative law judge, to address the issue of whether EPNG and/or Merchant Energy had market power and, if so, had exercised it. The hearing on the anticompetitive issue concluded in May 2001. In June 2001, FERC issued an order granting the request of the CPUC and others to allow the administrative law judge to take evidence on the affiliate abuse issue. In October 2001, a FERC administrative law judge issued a proposed decision finding that El Paso did not exercise market power and that the market power portion of the CPUC's complaint should be dismissed. The decision further found that El Paso had violated FERC's marketing affiliate regulations. The judge's proposed decision will be briefed to, and will be effective only if approved by, the FERC. On October 30, 2001, the Market Oversight and Enforcement section of the FERC's office of the General Counsel filed comments in this proceeding stating that record development at the trial was inadequate to conclude that EPNG and Merchant Energy complied with FERC's regulation. We have filed a response to this complaint. In June 2001, the Western Australia regulators issued a draft rate decision at lower than expected levels for the Dampier-to-Bunbury pipeline owned by EPIC Energy Australia Trust, in which we have a 33 percent ownership interest and a total investment, including financial guarantees, of approximately $180 million. EPIC Energy Australia has appealed a variety of issues related to the draft decision to the Western Australia Supreme Court. The decision from the court is expected later this year. If the draft decision rates are implemented, the new rates will adversely impact future operating results, liquidity, and debt capacity, possibly reducing the value of our investment by up to $120 million. 12 In September 2001, FERC issued a Notice of Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct governing the relationship between interstate pipelines and marketing affiliates to all energy affiliates. The proposed regulations, if adopted by FERC, would dictate how all our energy affiliates conduct business and interact with our interstate pipelines. We cannot predict the outcome of the NOPR, but adoption of the regulations in substantially the form proposed would, at a minimum, place additional administrative and operational burdens on us. While we cannot predict with certainty the final outcome or the timing of the resolution of all of our rates and regulatory matters, we believe the ultimate resolution of these issues, based on information known to date, will not have a material adverse effect on our financial position, results of operations or cash flows. Other From May to October 2001, we entered into agreements to time charter four separate ships to secure transportation for our developing liquified natural gas business. The agreements provide for deliveries of vessels between 2003 to 2005. Each time charter has a 20-year term commencing when the vessels are delivered with the possibility of two 5-year extensions. We have options to charter up to 4 additional ships. The options expire beginning in November 2001 and we currently do not intend to exercise these options. Our foreign investments are subject to risks and unforeseen obstacles that, in many cases may be beyond our control or ability to manage. We attempt to manage or mitigate these risks through our due diligence and partner selection processes, through the denomination of foreign transactions, where possible, in U.S. Dollars, and by maintaining insurance coverage, whenever obtainable. We have investments in oil and natural gas, power and pipeline projects in Argentina with an aggregate investment, including financial guarantees, of approximately $384 million. The general decline of economic conditions in Argentina led by the possible government default on public debt obligations is causing a significant drop in demand for power on the spot market. We believe that the current economic difficulties in Argentina will not have a material adverse effect on our financial position, results of operations or cash flows. However, we will continue to monitor the economic situation and it is possible that future developments in Argentina could cause us to reassess our exposure. We also currently have one power plant in Pakistan, with a total investment, including financial guarantees, of approximately $50 million. While we are aware of no specific threats or actions against this investment, events in that region, including possible retaliation for American military actions, could impact this projects and our related investments. At this time, we believe that through a combination of commercial insurance, political insurance, and rights under contractual obligations, our financial exposure in Pakistan from acts of war, hostility, terrorism, or political instability is not material. It is possible, however, that new information, future developments in the region, or the inability of a party or parties to fulfill their contractual obligations could cause us to reassess our potential exposure. 13 8. SEGMENT INFORMATION We segregate our business activities into three distinct operating segments: Pipelines, Merchant Energy and Field Services. These segments are strategic business units that provide a variety of energy products and services. They are managed separately as each business unit requires different technology and marketing strategies. We measure segment performance using earnings before interest expense and income taxes (EBIT). The following are our results as of and for the periods ended September 30:

--------------- (1) Includes Corporate, eliminations, and other non-operating segment activities. 14 9. INVESTMENTS IN UNCONSOLIDATED AFFILIATES We hold investments in various affiliates which we account for using the equity method of accounting. Summarized financial information for our proportionate share of these investments is as follows:

In June 2001, we purchased an additional 11 percent interest in the Portland Natural Gas Transmission partnership from two existing partners for a purchase price of approximately $9 million. This purchase increased our ownership interest from approximately 19 percent to approximately 30 percent. Gemstone In November 2001, El Paso and a third party financial investor formed a series of companies that we refer to as Gemstone. Into Gemstone, the third party contributed $50 million in cash and an additional $950 million was raised through a note issuance to other third parties. A portion of these funds were used to acquire a $300 million minority interest in one of our consolidated subsidiaries. We contributed $280 million in cash as well as several Brazilian investments with a total value of $274 million in exchange for our interest in Gemstone. The third party investor is entitled to a preferred return of 8.03% on its minority interest in our subsidiary. Our total investment in Gemstone is $554 million, and we will account for our investment in Gemstone using the equity method of accounting since we do not have the ability to exercise control over the entity. We will account for the investor's preferred interest in our consolidated subsidiary as minority interest in our balance sheet and will account for the preferred return as minority interest in our income statement. 10. TRANSACTIONS WITH RELATED PARTIES We participate in El Paso's cash management program which matches short-term cash excesses and requirements of participating affiliates, thus minimizing total borrowing from outside sources. We had net borrowings of $2,115 million at September 30, 2001, at a market rate of interest which was 3.7%. At December 31, 2000, we had borrowed $3,691 million. At September 30, 2001, we had accounts and notes receivable from other related parties of $452 million and $194 million at December 31, 2000. In addition, we had accounts payable to other related parties of $475 million at September 30, 2001, versus $69 million at December 31, 2000. These balances were incurred in the normal course of business. 11. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED Business Combinations In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, Business Combinations. This statement requires that all transactions that fit the definition of a business combination be accounted for using the purchase method and prohibits the use of the pooling of interests method for all business combinations initiated after June 30, 2001. This statement also establishes specific criteria for the recognition of intangible assets separately from goodwill and requires unallocated negative goodwill to be written off immediately as an extraordinary item. This standard will have an impact on any business combination we undertake in the future. We are currently evaluating the effects of this pronouncement on our historical financial statements. 15 Goodwill and Other Intangible Assets In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. This statement requires that goodwill no longer be amortized but intermittently tested for impairment at least on an annual basis. Other intangible assets are to be amortized over their useful life and reviewed for impairment in accordance with the provisions of SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. An intangible asset with an indefinite useful life can no longer be amortized until its useful life becomes determinable. This statement has various effective dates, the most significant of which is January 1, 2002. We are currently evaluating the effects of this pronouncement. Accounting for Asset Retirement Obligations In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement requires companies to record a liability relating to the retirement and removal of assets used in their business. The liability is discounted to its present value, and the related asset value is increased by the amount of the resulting liability. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. We are currently evaluating the effects of this pronouncement. Accounting for the Impairment or Disposal of Long-Lived Assets In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less cost to sell. The standard also expanded the scope of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of this statement are effective for fiscal years beginning after December 15, 2001. We are currently evaluating the effects of this pronouncement. Derivatives Implementation Group Issue C-16 In September 2001, the Derivatives Implementation Group of the FASB cleared guidance on Issue C-16, Scope Exceptions: Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract. This guidance impacts the accounting for fuel supply contracts that require delivery of a contractual minimum quantity of fuel at a fixed price and have an option that permits the holder to take specified additional amounts of fuel at the same fixed price at various times. We use fuel supply contracts such as these in our power producing operations and currently do not reflect them in our balance sheet since they are considered normal purchases that are not classified as derivative instruments under SFAS No. 133. This guidance becomes effective in the second quarter of 2002, and we will be required to account for these contracts as derivative instruments under SFAS No. 133, which will require us to record them on the balance sheet at fair value. We are currently evaluating the impact of this guidance on our financial statements. 16 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS(1) The information contained in Item 2 updates, and you should read it in conjunction with, information disclosed in Part II, Items 7, 7A, and 8, in our Annual Report on Form 10-K for the year ended December 31, 2000, in addition to the financial statements and notes presented in Item 1, Financial Statements, of this Quarterly Report on Form 10-Q. RESULTS OF OPERATIONS For the quarter ended September 30, 2001, we had net income of $170 million versus $90 million for the quarter ended September 30, 2000. Growth in earnings of our non-regulated segments contributed to the increase in consolidated net income. For the nine months ended September 30, 2001, we had net income of $496 million versus $415 million for the nine months ended September 30, 2000. The 2001 results included merger-related costs and asset impairments totaling $73 million, or $48 million after taxes. In addition, we recorded extraordinary gains totaling $38 million, net of income taxes, as a result of FTC ordered sales of our Midwestern Gas Transmission system. For the nine months ended September 30, 2000, we recorded extraordinary gains on FTC ordered sales of our East Tennessee Natural Gas Company totaling $77 million, net of income taxes. Net income, excluding the after-tax effects of these charges and extraordinary items, would have been $506 million in 2001 versus $338 million in 2000, or an increase of 50 percent. SEGMENT RESULTS Our business activities are segregated into three segments: Pipelines, Merchant Energy and Field Services. These segments are strategic business units that offer a variety of different energy products and services, and each requires different technology and marketing strategies. Operating revenues and expenses by segment include intersegment revenues and expenses which are eliminated in consolidation. Because changes in energy commodity prices have a similar impact on both our operating revenues and cost of products sold from period to period, we believe that gross margin (revenue less cost of products sold) provides a more accurate and meaningful basis for analyzing operating results for the trading portion of Merchant Energy and the Field Services segment. For a further discussion of our individual segments, see Item 1, Financial Statements, Note 8. The segment results presented below include merger-related costs and asset impairments as discussed above:

--------------- (1) Below is a list of terms that are common to our industry and used throughout our Management's Discussion and Analysis: Bbl = barrel MBbls = thousand barrels BBtu/d = billion British thermal units per day MMBtu = million British thermal units BBtue/d = billion British thermal unit equivalents Mcf = thousand cubic feet per day Btu = British thermal unit MMWh = thousand megawatt hours

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 is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at 14.73 pounds per square inch. 17 PIPELINES Our Pipelines segment operates our interstate pipeline business. Operating results for our pipeline system has generally been stable because the majority of its revenues are based on fixed reservation charges. As a result, we expect changes in this aspect of our business to be primarily driven by regulatory actions and contractual events. Commodity or throughput-based revenues account for a smaller portion of our operating results. These revenues vary from period to period, and are impacted by factors such as weather, operating efficiencies, competition from other pipelines and fluctuations in natural gas prices. Results of operations of the Pipelines segment were as follows for the periods ended September 30:

--------------- (1) Throughput volumes exclude those related to pipeline systems sold in connection with our Coastal and Sonat mergers including the Midwestern Gas Transmission and East Tennessee Natural Gas systems. Third Quarter 2001 Compared to Third Quarter 2000 Operating revenues for the quarter ended September 30, 2001, were $24 million lower than the same period in 2000. The decrease was due to lower 2001 revenues resulting from contract remarketing during 2000, lower sales of excess natural gas in 2001 as a result of lower volumes and lower natural gas prices and the impact of the sale of the Midwestern Gas Transmission system in April 2001. Operating expenses for the quarter ended September 30, 2001, were $1 million higher than the same period in 2000. The increase was due to higher electric compression costs in 2001 and lower project development costs in 2000, partially offset by lower ad valorem taxes in 2001 and reduced depreciation expense due to the sale of Midwestern Gas Transmission system. Nine Months Ended 2001 Compared to Nine Months Ended 2000 Operating revenues for the nine months ended September 30, 2001, were $38 million lower than the same period in 2000. The decrease was due to lower 2001 revenues resulting from contract remarketing during 2000 and the sales of the Midwestern Gas Transmission system in April 2001 and the East Tennessee Natural Gas system in the first quarter of 2000, including contract quantity reductions or cancellations on our pipeline system by East Tennessee customers resulting from FTC ordered sales of that system. Also contributing to the decrease were lower transportation revenues on throughput in 2001 as a result of higher proportion of short versus long hauls compared to 2000. Partially offsetting the decrease was the favorable resolution of issues related to natural gas purchase contracts, higher sales of excess natural gas in the first nine months of 2001 and higher revenues from other transportation services. Operating expenses for the nine months ended September 30, 2001, were $15 million lower than the same period in 2000. The decrease was due to lower corporate allocations and operating expenses as a result of cost savings following El Paso's merger with Coastal, decreased depreciation expense resulting from the retirement of assets, reduced operating and depreciation expenses from the sales of Midwestern and East Tennessee and lower project development costs. The decrease was partially offset by higher electric compression costs in 2001. 18 MERCHANT ENERGY Merchant Energy is involved in a wide range of activities in the wholesale energy marketplace, including trading and risk management, asset ownership and financial services. Each market served by Merchant Energy is highly competitive and is influenced directly or indirectly by energy market economics. Merchant Energy's trading and risk management activities provide energy trading and energy management solutions for its customers and affiliates involving primarily natural gas and power. The segment maintains a substantial trading portfolio that manages its risk across multiple commodities and over seasonally fluctuating energy demands. Merchant Energy's asset ownership activities include ownership interests in 75 power plants in 16 countries and domestic and international refining, transportation and chemical operations, as well as a 20 percent interest in Chaparral Investors, L.L.C., an entity established to acquire, hold and manage domestic power generation assets. During the nine months ended September 30, 2001, Merchant Energy earned $110 million in fee-based revenues from Chaparral and was reimbursed $15 million for operating expenses. For the nine months ended September 30, 2000, fee-based revenues were $60 million, and expense reimbursements were $15 million. In the financial services area, Merchant Energy owns EnCap Investments and Enerplus Global Energy Management, Inc. and conducts other energy financing activities. EnCap manages three separate oil and natural gas investment funds in the U.S. and serves as an investment advisor to one fund in Europe. EnCap also holds investments in emerging energy companies and earns a return from these investments. In 2000, Merchant Energy acquired Enerplus, a Canadian investment management company, through which it conducts fund management activities similar to EnCap. Below are Merchant Energy's operating results and an analysis of these results for the periods ended September 30:

Volumes Physical Natural gas (BBtue/d).................... 7,318 7,021 8,760 6,222 Power (MMWh)............................. 61,407 41,641 142,990 89,147 Petroleum (MBbls)........................ 5,414 54 10,750 7,754 Financial settlements (BBtue/d)............. 141,349 97,009 143,820 87,135

Third Quarter 2001 Compared to Third Quarter 2000 Trading gross margin consists of revenues from commodity trading and origination activities less the cost of commodities sold. For the quarter ended September 30, 2001, these trading gross margins were $128 million higher than the same period in 2000. The increase was primarily due to increased natural gas and power trading margins resulting from increased trading volumes and price volatility as well as increased income from transactions originated during the third quarter of 2001. Partially offsetting the increase were revenues recorded in 2000 on our West Georgia power generation facility which was sold in the fourth quarter of 2000. 19 In October 2000, Coastal, our affiliate, terminated their Engage joint venture with WestCoast Energy, Inc. In the transaction, they assumed the U.S. portion of Engage and WestCoast assumed the Canadian operations. As a result, they began consolidating these U.S. operations and conducting trading activities. In February 2001, Coastal transferred these activities, which included Engage's marketing contracts and other assets, to El Paso Merchant Energy, our subsidiary, in exchange for 22 percent interest in El Paso Merchant Energy. In September of 2001, we redeemed Coastal's interest in the partnership for $114 million. Merchant Energy is a provider of power and natural gas to the state of California. During the latter half of 2000 and continuing into the first and second quarters of 2001, California experienced sharp increases in natural gas prices and wholesale power prices due to energy shortages resulting in part from a combination of unusually warm summer weather followed by high winter demand, low gas storage levels, lower hydroelectric power generation, maintenance downtime of significant generation facilities and price caps that discouraged power movement from other nearby states into California. The increase in power prices caused by the imbalance of natural gas and power supply and demand coupled with electricity price caps imposed on rates allowed to be charged to California electricity customers has resulted in large cash deficits of the two major California utilities, Southern California Edison and Pacific Gas and Electric. As a result, both utilities have defaulted on payments to creditors and have accumulated substantial under-collections from customers. This resulted in their credit ratings being downgraded in 2001 from above investment grade to below investment grade, and in April 2001, Pacific Gas & Electric filed for bankruptcy. Both utilities have filed for emergency rate increases with the CPUC and are working with the state authorities to restore the companies' financial viability. We have historically been one of the largest suppliers of energy to California, and we are actively participating with other parties in California to be a part of the long-term, stable solution to California's energy needs. We have established reserves that we believe are sufficient to cover our exposure to payment defaults from our California sales activities. As a result, we do not believe, based on information known to date, these matters will have a material impact on our operating results. Our investee, Chaparral, has ownership interests in 11 power plants in the state of California. As of September 30, 2001, customers of these facilities had only partially paid for power generated, all of which arose prior to Pacific Gas & Electric's bankruptcy declaration. The combination of partial payments and Pacific Gas and Electric's bankruptcy declaration resulted in an event of default under the terms of each facility's loan agreement. Chaparral and Pacific Gas and Electric have amended the terms of existing power purchase agreements. In addition, Chaparral has received waivers from its lenders for the events of default. Management of Chaparral has indicated that it believes existing reserves against potential uncollectible accounts are adequate. Our management fee from Chaparral is based on the value of its assets. As a result, if the value of these power plants is permanently reduced, it could have a similar effect on our management fee in future years. Operating and other revenues consist of revenues from consolidated international power generation facilities and revenues from the financial services and asset management businesses of Merchant Energy. For the quarter ended September 30, 2001, operating revenues were $58 million higher than the same period in 2000. The increase resulted from higher management fees from Chaparral and revenues from the CEBU power project, a Philippine project in which we acquired an additional interest and began consolidating during the first quarter of 2001. Operating expenses for the quarter ended September 30, 2001, were $57 million higher than the same period in 2000. The increase was a result of higher operating expenses resulting from the expansion of our trading operations as well as our operations in Europe, Mexico, Brazil, Singapore, our liquefied natural gas business and the consolidation of the CEBU power project. 20 Other income for the quarter ended September 30, 2001, was $6 million higher than the same period in 2000. The increase resulted from marketing, agency and technical services fees on a Brazilian power transaction recorded in the third quarter of 2001, partially offset by lower equity earnings on unconsolidated investments, primarily CE Generation. Nine Months Ended 2001 Compared to Nine Months Ended 2000 Trading gross margin for the nine months ended September 30, 2001, was $265 million higher than the same period in 2000. The increase was primarily due to increased natural gas and power trading margins resulting from increased trading volumes and price volatility as well as increased income from transactions originated during 2001. Partially offsetting the increase were revenues recorded in 2000 on our West Georgia power generation facility which was sold in the fourth quarter of 2000. Operating and other revenues for the nine months ended September 30, 2001, were $140 million higher than the same period in 2000. The increase resulted from higher management fees from Chaparral, higher revenues from our financial services businesses, and revenues from the CEBU power project, a Philippine project in which we acquired an additional interest and began consolidating during the first quarter of 2001. Operating expenses for the nine months ended September 30, 2001, were $179 million higher than the same period in 2000. The increase was due to the write-down of our investment in the East Asia power project in the Philippines due to weak economic conditions which caused a permanent decline in the value of that investment. Also contributing to the increase were higher operating expenses resulting from the expansion of our trading operations as well as our operations in Europe, Mexico, Brazil, Singapore, our liquefied natural gas business and the consolidation of the CEBU power project. Other income for the nine months ended September 30, 2001, was $69 million higher than the same period in 2000. The increase resulted from higher equity earnings on unconsolidated investments and marketing, agency and technical services fees on a Brazilian power transaction partially offset by lower earnings on an Argentine investment and gains in 2000 from the sale of a portion of our East Asia Power project. FIELD SERVICES Field Services provides a variety of services for the midstream component of our operations, including gathering and treating of natural gas, processing and fractionation of natural gas, natural gas liquids and natural gas derivative products, such as ethane, propane and butane. Field Services attempts to balance its earnings from its activities through a combination of fixed-fee-based and market-based services. Our gathering and treating operations earn margins substantially from fixed-fee-based services; however, some of these operations earn margins from market-based rates. Revenues for these commodity rate services are the product of the market price, usually related to the monthly natural gas price index and the volume gathered. Processing and fractionation operations earn a margin based on fixed-fee contracts, percentage-of-proceeds contracts and make-whole contracts. Percentage-of-proceeds contracts allow us to retain a percentage of the product as a fee for processing or fractionation service. Make-whole contracts allow us to retain the extracted liquid products and return to the producer a Btu equivalent amount of natural gas. Under our percentage-of-proceeds contracts and make-whole contracts, Field Services may have more sensitivity to price changes during periods when natural gas and natural gas liquids prices are volatile. 21 Field Services' operating results and an analysis of these results are as follows for each of the periods ended September 30:

Third Quarter 2001 Compared to Third Quarter 2000 Total gross margin for the quarter ended September 30, 2001, was $40 million higher than the same period in 2000. The increase was a result of higher gathering, treating and processing margins primarily due to higher volumes as a result of our acquisition of PG&E's Texas Midstream operations in December 2000. During the quarter ended September 30, 2001, average gathering, treating and processing rates were lower due to the different mix of assets acquired from PG&E. Operating expenses for the quarter ended September 30, 2001, were $39 million higher than the same period in 2000. The increase was a result of higher operating, depreciation and tax expenses from the addition of PG&E's Texas Midstream operations, as well as increased general and administrative costs. Nine Months Ended 2001 Compared to Nine Months Ended 2000 Total gross margin for the nine months ended September 30, 2001, was $129 million higher than the same period in 2000. The increase was a result of higher gathering, treating and processing margins primarily due to higher volumes as a result of our acquisition of PG&E's Texas Midstream operations in December 2000. Also contributing to the increase were higher natural gas and natural gas liquids prices in the San Juan Basin. During the nine months ended September 30, 2001, average gathering, treating and processing rates were lower compared to 2000 due to the different mix of assets resulting from the acquisition of PG&E. Operating expenses for the nine months ended September 30, 2001, were $151 million higher than the same period in 2000. The increase was a result of higher operating, depreciation and tax expenses from the addition of PG&E's Texas Midstream operations, increased general and administrative costs and merger-related costs arising from commitments made related to FTC ordered sales of assets owned by El Paso Energy Partners. NON-AFFILIATED INTEREST AND DEBT EXPENSE Non-affiliated interest and debt expense for the nine months ended September 30, 2001, was $6 million higher than the same periods in 2000 primarily due to long-term debt assumed by Field Services in relation to its acquisition of PG&E's Texas Midstream operations in December 2000 and decreased capitalized interest related to Merchant Energy's completion of the West Power facility in June 2000. 22 AFFILIATED INTEREST EXPENSE, NET Affiliated interest expense, net for the quarter ended September 30, 2001, was $16 million lower than the same period in 2000 primarily due to lower short-term interest rates under our cash management program on average advances to El Paso in 2001. Affiliated interest expense, net for the nine months ended September 30, 2001, was $58 million higher than the same periods in 2000 due to an increase in advances from El Paso for ongoing capital projects; investment programs and operating requirements partially offset by lower short-term interest rates on average advances to El Paso under our cash management program. INCOME TAXES The income tax expense for the quarters ended September 30, 2001 and 2000, were $98 million and $47 million, resulting in effective tax rates of 37 percent and 34 percent. Our effective tax rates were different than the statutory tax rate of 35 percent primarily due to the following: - state income taxes; - earnings from unconsolidated affiliates where we anticipate receiving dividends; and - foreign income not taxed in the U.S., but taxed at foreign rates. The income tax expense for the nine months ended September 30, 2001 and 2000, were $245 million and $167 million, resulting in effective tax rates of 35 percent and 33 percent. Our effective tax rates were different than the statutory tax rate of 35 percent primarily due to the following: - state income taxes; - earnings from unconsolidated affiliates where we anticipate receiving dividends; and - foreign income not taxed in the U.S., but taxed at foreign rates. LIQUIDITY AND CAPITAL RESOURCES CASH FROM OPERATING ACTIVITIES Net cash provided by our operating activities was $2,524 million for the nine months ended September 30, 2001, compared to net cash used of $461 million for the same period of 2000. The increase was primarily due to liquidations of net derivative trading positions during the first half of 2001, coupled with the impact of lower commodity prices. Partially offsetting these increases were cash payments in 2001 for charges related to broker and over-the-counter margins and higher interest payments. CASH FROM INVESTING ACTIVITIES Net cash used in our investing activities was $799 million for the nine months ended September 30, 2001. Our investing activities principally consisted of additions to property, plant and equipment primarily in our Field Services and Pipelines Segments for expansion and construction projects. We had additions to joint ventures and investments in unconsolidated affiliates, primarily related to our investment in five coal-fired power plants and two international power companies located in Brazil and China. Our investing activities also included the buyout of Coastal's interest in El Paso Merchant Energy, L.P. Cash inflows from investment-related activities included proceeds from the sale of our Midwestern Gas Transmission system. CASH FROM FINANCING ACTIVITIES Net cash used in our financing activities was $1,735 million for the nine months ended September 30, 2001. During 2001, we retired long-term debt, paid dividends and paid advances to El Paso. Cash provided from our financing activities included borrowings from commercial paper. We expect that future funding for our working capital needs, capital expenditures, acquisitions, other investing activities, long-term debt retirements, payments of dividends and other financing expenditures will 23 be provided by internally generated funds, commercial paper issuances, available capacity under existing credit facilities, the issuance of new long-term debt or equity, and/or contributions from El Paso. COMMITMENTS AND CONTINGENCIES See Item 1, Financial Statements, Note 7, which is incorporated herein by reference. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED See Item 1, Financial Statements, Note 11, which is incorporated herein by reference. CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 This report contains or incorporates by reference forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any forward-looking statement includes a statement of the assumptions or bases underlying the forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from the actual results, and the differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the statement of expectation or belief will result or be achieved or accomplished. The words "believe," "expect," "estimate," "anticipate" and similar expressions will generally identify forward-looking statements. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK This information updates, and you should read it in conjunction with, information disclosed in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2000, in addition to the information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There have been no material changes in our quantitative and qualitative disclosures about market risks from those reported in our Annual Report on Form 10-K for the year ended December 31, 2000. 24 PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS See Part I, Item 1, Financial Statements, Note 7, which is incorporated herein by reference. The California cases are: four filed in the Superior Court of Los Angeles County (Continental Forge Company, et al v. Southern California Gas Company, et al, filed September 25, 2000; and Berg v. Southern California Gas Company, et al, filed December 18, 2000); (The City of Los Angeles, et al v. Southern California Gas Company, et al and The City of Long Beach, et al v. Southern California Gas Company, et al, both filed March 20, 2001); two filed in the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso Merchant Energy and John Phillip v. El Paso Merchant Energy, both filed December 13, 2000); and three filed in the Superior Court of San Francisco County (Sweetie's, et al v. El Paso Corporation, et al, filed March 22, 2001; Philip Hackett, et al v. El Paso Corporation, et al, filed May 9, 2001; and California Dairies, Inc., et al v. El Paso Corporation, et al, filed May 21, 2001). All of the cases except Hackett were consolidated before the U.S. District Court in Nevada for pretrial activities. The shareholder case is styled Clark, et al v. Allumbaugh, et al, Superior Court of Orange County, filed August 23, 2001. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS None. ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a. Exhibits None 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 these instruments does not exceed 10 percent of our total consolidated assets. b. Reports on Form 8-K None. 25 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 TENNESSEE PIPELINE CO. Date: November 13, 2001 /s/ H. BRENT AUSTIN ------------------------------------ H. Brent Austin Executive Vice President and Chief Financial Officer Date: November 13, 2001 /s/ JEFFREY I. BEASON ------------------------------------ Jeffrey I. Beason Senior Vice President and Controller (Chief Accounting Officer) 26

EL PASO TENNESSEE PIPELINE CO 10-Q