10-Q 1 h85963e10-q.txt EL PASO TENNESSEE PIPELINE CO - PERIOD 3/31/2001 1 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------- FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 May 4, 2001: 1,971 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 2 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 3 EL PASO TENNESSEE PIPELINE CO. CONDENSED CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE AMOUNTS) (UNAUDITED)

See accompanying notes. 2 4 EL PASO TENNESSEE PIPELINE CO. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS) (UNAUDITED)

See accompanying notes. 3 5 EL PASO TENNESSEE PIPELINE COMPANY CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (IN MILLIONS) (UNAUDITED)

See accompanying notes. 4 6 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 at March 31, 2001, and for the quarters ended March 31, 2001 and 2000, are unaudited. The balance sheet at December 31, 2000, is derived from the audited financial statements. 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 charges described 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 includes reclassifications which were made to conform to the current presentation. These reclassifications have no effect on our reported net income or stockholders' equity. 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. With the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivatives and Hedging Activities, we now record all derivative instruments on the balance sheet at their fair value. 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 quality as hedge 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 under the provisions of SFAS No. 133, the appropriate accounting treatment depends on each instrument's intended use and how it is designated. Derivative instruments that qualify as hedges may be designated as: - hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedges); - hedges of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedges); - foreign currency fair value or cash flow hedges (foreign currency hedges); or - hedges of a net investment in a foreign operation (net investment hedges). 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; 5 7 - 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. 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 for derivative instruments that qualify as hedges is 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, we may document 6 8 those contracts as normal purchases and normal sales and 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 of the host 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 During the quarter ended March 31, 2001, we incurred merger-related costs of $29 million associated with El Paso Corporation's merger with The Coastal Corporation. These charges consist of $4 million in employee severance, retention, and transition costs and a $25 million charge for a series of payments in connection with the Federal Trade Commission's (FTC) ordered divestiture of our interests in assets owned by El Paso Energy Partners, L.P. 3. EXTRAORDINARY ITEMS 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. As a result of El Paso's merger with Coastal, we were required by the FTC to sell our Midwestern pipeline system. We completed this sale in April 2001. Net proceeds from the sale were approximately $95 million, and we will recognize an extraordinary gain of $38 million, net of income taxes of $21 million, in the second quarter of 2001. 4. ACCOUNTING FOR HEDGING ACTIVITIES On January 1, 2001, we adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivatives and Hedging Activities. In accordance with the transition provisions of the statement, we recorded a cumulative-effect adjustment of $154 million, net of income taxes, in accumulated other comprehensive income in stockholders' equity to recognize the fair value of all derivatives that we have designated as cash flow hedging instruments. The majority of the initial charge related to hedging forecasted purchases and sales of natural gas for 2001. During the quarter ended March 31, 2001, $116 million, net of income taxes, of this initial transition adjustment was reclassified to earnings as a result of hedged sales and purchases during the period and an additional $15 million of this adjustment will be reclassified by the end of 2001. A discussion of our hedging activities is as follows: Cash Flow Hedges. A majority of our commodity sales and purchases are at spot market or forward market prices. In order to reduce volatility of earnings and cash flows, 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 March 31, 2001, the value of cash flow hedges included in accumulated other comprehensive income was an unrealized loss of $321 million, net of income taxes. Of this amount, we estimate that $287 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 $42 million representing our proportionate share of amounts recorded in other comprehensive income by our unconsolidated affiliates that 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 ended March 31, 2001, we recognized a net gain of $1 million, net of income taxes, related to the ineffective portion of all cash flow hedges. 7 9 5. INVENTORY Our inventory consisted of the following:

6. PROPERTY, PLANT, AND EQUIPMENT Our property, plant, and equipment consisted of the following:

7. DEBT AND OTHER CREDIT FACILITIES At March 31, 2001, our weighted average interest rate on short-term borrowings was 6.5% and at December 31, 2000, it was 7.6%. We had the following short-term borrowings, including current maturities of long-term debt:

Other Financing Arrangements In February 2001, we redeemed $340 million of debt assumed in our December 2000 acquisition of PG&E's Texas Midstream operations, and we retired approximately $24 million aggregate principal amount of 9.875% Debentures. 8. COMMITMENTS AND CONTINGENCIES Legal Proceedings In August 2000, the Liquidating Trustee in the bankruptcy of Power Corporation of America (PCA) sued El Paso Merchant Energy (EPME), and several other power traders, in the U.S. Bankruptcy Court in Connecticut, claiming EPME improperly cancelled its contracts with PCA during the summer of 1998. The 8 10 trustee alleges we breached contracts damaging PCA in the amount of $120 million. We have entered into a joint defense agreement with the other defendants. This matter will be mediated in the second quarter of 2001. In a related matter, PCA appealed the Federal Energy Regulatory Commission's (FERC) ruling that power marketers such as EPME did not have to give 60 days notice to cancel its power contracts under the Federal Power Act. PCA has appealed this decision to the United States Court of Appeals. Oral arguments were heard in January 2001, and the Court ruled in the FERC's favor. In late 2000, EPME and several of our subsidiaries were named as defendants in four purported class action lawsuits filed in state courts in Los Angeles and San Diego, California (a list of the California 2000 is included in Part II, Item 1). Two of these cases, filed in Los Angeles, contend, generally that our entities conspired with other unrelated companies to create artificially high prices for natural gas in California. The other two cases, filed in San Diego, assert that our companies used EPME's acquisition of capacity on the El Paso Natural Gas Company (EPNG) pipeline system to manipulate the market for natural gas in California. We have remanded each of these cases to the federal courts in California and have filed motions to dismiss in the San Diego actions. In addition, three additional lawsuits were filed, with two filed in Los Angeles on March 20, 2001, and the third filed on March 22, 2001, on behalf of a purported class in San Francisco (a list of the California 2001 cases is included in Part II, Item 1). These cases seek monetary damages against us and several of our subsidiaries and make allegations similar to the California 2000 cases filed in Los Angeles discussed above. 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. The suit claims that the United States and the state of Texas have spent over $125 million in remediating Sikes and seeks to recover that amount plus interest from the defendants to the suit. The Environmental Protection Agency (EPA) has recently indicated that it may seek an additional amount up to $30 million plus interest in indirect costs from the defendants under a new cost allocation methodology. Defendants are challenging this allocation policy. Although an investigation relating to Sikes is ongoing, we believe that the amount of material, if any, disposed at Sikes by us was small, possibly de minimis. However, the plaintiffs have alleged that the defendants are each jointly and severally liable for the entire remediation costs and have also sought a declaration of liability for future response costs such as groundwater monitoring. In 1997, a number of our subsidiaries were served as 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). A number of our subsidiaries were named defendants in Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al, filed in 1999 in the District Court of Stevens County, Kansas. 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 same court handling the Grynberg complaint and has now been sent back to Kansas State Court for further proceedings. In November 1988, the Kentucky environmental agency filed a complaint in a Kentucky state court alleging that Tennessee Gas Pipeline (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, received water discharge permits from the agency for its Kentucky compressor stations, and continues to work to resolve the remaining issues. The relevant Kentucky compressor stations are being characterized and remediated under a 1994 consent order with the EPA. 9 11 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, we do not expect the ultimate resolution of these matters will have a material adverse effect on our 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 March 31, 2001, we had a reserve of approximately $118 million for expected remediation costs. In addition, we expect to make capital expenditures for environmental matters of approximately $88 million in the aggregate for the years 2001 through 2006. These expenditures primarily relate to compliance with 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 (the Environmental Stipulation) with FERC that established a mechanism for recovering a substantial portion of the environmental costs identified in its internal project. The Environmental Stipulation was effective July 1, 1995, and as of December 31, 1999, all amounts had 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 a lubricant containing 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 8 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 March 31, 2001, we have estimated our share of the remediation costs at these sites to be between $1 million and $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 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 10 12 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 EPNG's sale of capacity to EPME was anticompetitive and an abuse of the affiliate relationship under FERC's policies. The CPUC served data requests on us, which were substantially answered or contested. In August 2000, the CPUC filed a motion requesting that the contract between EPNG and EPME be terminated and other parties in the proceedings have requested that the original complaint be set for hearings and that EPME pay back any profits it has earned under the contract. On March 28, 2001, FERC issued an order dismissing arguments that the sale of capacity to EPME violated the marketing affiliate rule and concluded that allegations regarding the awarding of capacity to EPME were unsupported. FERC further established a hearing, before an administrative law judge, to address the issue of whether EPNG and/or EPME had market power and, if so, had exercised it. A hearing date has been set by FERC for mid-May 2001. 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 will not have a material adverse effect on our financial position, results of operations, or cash flows. 9. 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). Following are our results as of and for the periods ended March 31:

--------------- (1) Includes Corporate, eliminations, and other non-operating segment activities. 11 13 10. 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:

12 14 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 of this Quarterly Report on Form 10-Q. RESULTS OF OPERATIONS For the quarter ended March 31, 2001, we had net income of $168 million versus $185 million for the quarter ended March 31, 2000. The 2001 results included merger-related costs totaling $29 million, or $20 million after taxes, related to El Paso's merger with Coastal. During the first quarter of 2000, we recorded gains on FTC ordered sales of our East Tennessee Pipeline system totaling $77 million, net of income taxes. Net income, excluding the effects of merger-related charges and extraordinary items, was $188 million in 2001 versus $108 million in 2000. 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 sales) provides a more accurate and meaningful basis for analyzing operating results for the trading portion of our Merchant Energy segment and the Field Services segment. For a further discussion of our individual segments, see Item 1, Financial Statements, Note 9.

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

13 15 PIPELINES Our Pipelines segment operates our interstate pipeline businesses. Each pipeline system operates under a separate tariff that governs its operations and rates. Operating results for our pipeline systems have generally been stable because the majority of the revenues are based on fixed demand 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 system to system, and are impacted by factors such as weather, operating efficiencies, competition from other pipelines, and fluctuations in natural gas prices. Results of operations of our Pipelines segment were as follows for the quarters ended March 31:

Operating revenues for the quarter ended March 31, 2001, were $6 million higher than the same period in 2000. The increase was a result of higher gas prices on fuel over recoveries in 2001, partially offset by lower revenues resulting from contract remarketing and lower rates on TGP's throughput in 2001 as a result of a higher proportion of short versus long hauls compared to 2000. Operating expenses for the quarter ended March 31, 2001, were $11 million lower than the same period in 2000. The decrease was primarily a result of reduced operating expenses as a result of the sale of East Tennessee in the first quarter of 2000 along with lower shared service allocations in 2001. Other income for the quarter ended March 31, 2001, was $4 million lower than the same period in 2000. The decrease was a result of equity losses related to our interest in EPIC Australia, a regulated pipeline in Australia. Following the merger between El Paso and Coastal, the Pipelines segment assumed responsibility for these operations. 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 position risk across multiple commodities and over seasonally fluctuating energy demands. Merchant Energy's asset ownership activities include a 20 percent ownership interest in Chaparral Investors, L.L.C., an entity established to acquire, hold, and manage domestic power generation assets. During the quarters ended March 31, 2001 and 2000, Merchant Energy earned $37 million and $20 million in fee-based revenue from Chaparral and was reimbursed $5 million for operating expenses during both periods. 14 16 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, but in Canada. Below are Merchant Energy's operating results and an analysis of those results for each of the quarters ended March 31:

Volumes Physical Natural gas (BBtue/d).................................. 10,390 5,555 Power (MMWh)........................................... 35,393 95 Financial settlements (BBtue/d)............................. 169,493 91,583

Trading and origination gross margin consists of operating revenues from commodity trading and origination activities less the cost of commodities sold. For the quarter ended March 31, 2001, these trading gross margins were $149 million higher than the same period in 2000. The increase was primarily due to increased natural gas and power margins resulting from increased trading volumes and price volatility, primarily in the western United States. These increases were partially offset by the income recorded on transportation and storage transactions originating during the first quarter of 2000. Merchant Energy is a provider of power and natural gas to the state of California. During the latter half of 2000, and continuing into 2001, California experienced sharp increases in natural gas prices and wholesale power prices due to energy shortages resulting 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 all parties in California to be a part of the long-term, stable solution to California's energy needs. As of March 31, 2001, Merchant Energy believes its exposure for sales of power and natural gas to the state of California, including receivables related to its interest in California power plant investments, is less than $50 million, net of credit reserves to reflect market uncertainties. Chaparral, our investee, has ownership interests in 11 power plants in the state of California. As of March 31, 2001, customers of these facilities had not paid for power generated. This, coupled with Pacific Gas and Electric's bankruptcy declaration, has resulted in an event of default under the terms of each facility's loan 15 17 agreement. Operations of these plants have been reduced and each facility continues to take necessary actions to enforce the terms of their power purchase agreements. Management of Chaparral has indicated that it believes existing reserves against potential uncollectible accounts are adequate. We do not believe, based on information known to date, that the impact of these matters will have a material impact on our operating results. However, 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 domestic and international power generation facilities and revenues from the financial services businesses of Merchant Energy. For the quarter ended March 31, 2001, operating revenues were $41 million higher than the same period in 2000. The increase was a result of higher management fees on Chaparral, which increased by approximately $17 million in the first quarter of 2001, higher earnings on investments and activities of EnCap in 2001, and contributions from Enerplus acquired during the latter part of 2000. Also contributing to the increase were revenues from the CEBU power project in the Philippines, in which we acquired an additional interest and began consolidating during the first quarter of 2001, as well as higher revenues on the EMA power facility located in Hungary in 2001. Operating expenses for the quarter ended March 31, 2001, were $53 million higher than the same period in 2000. The increase was primarily a result of higher operating expenses, including payroll and personnel costs, corporate allocations, and costs associated with our European operations, all a result of the expansion of the merchant business from operating levels in the first quarter of 2000. Other income for the quarter ended March 31, 2001, was $12 million higher than the same period in 2000. We experienced higher equity earnings from our investment in CE Generation as a result of higher power prices in California, higher earnings from Hanhwa, a Korean investment acquired in the third quarter of 2000, lower equity losses on the East Asia Power project, and higher interest income on over-the-counter margin deposits. The increase was partially offset by gains in the first quarter of 2000 from the transfer of a portion of our interest in East Asia Power, income recorded in the first quarter of 2000 related to mark-to-market increases on a swap on our CAPSA investment, and lower equity earnings from the Samalayuca project in northern Mexico. 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. Our gathering and treating operations earn margins substantially from fixed fee-based services; however, some of these operations earn margins from commodity-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. 16 18 Field Services' operating results and an analysis of those results are as follows for each of the quarters ended March 31:

Total gross margin for the quarter ended March 31, 2001, was $54 million higher than the same period in 2000. The increase was a result of higher gathering and treating margins, which increased approximately 76 percent, primarily due to higher San Juan gathering rates along with higher volumes as a result of our acquisition of PG&E's Texas Midstream operations in December 2000. Processing margins in 2001 were also higher, increasing $3 million, or 21 percent over 2000, as a result of contributions from the processing operations acquired from PG&E, partially offset by lower natural gas liquids margins as a result of higher natural gas prices. Operating expenses for the quarter ended March 31, 2001, were $73 million higher than the same period in 2000. The increase was a result of higher operating costs from the addition of the PG&E's Texas Midstream operations, merger-related costs arising from payments made to Energy Partners related to FTC ordered sales of assets owned by the partnership, and higher corporate allocations as a result of growth in the midstream segment. Other income for the quarter ended March 31, 2001, was $5 million lower than the same period in 2000. The decrease was a result of 2000 gains on the sales of the Colorado dry gathering system along with equity losses in 2001 associated with investments acquired in connection with our acquisition of PG&E's Texas Midstream operations in the fourth quarter of 2000. NON-AFFILIATED INTEREST AND DEBT EXPENSE Non-affiliated interest and debt expense for the quarter ended March 31, 2001, was $2 million higher than the same period in 2000 primarily due to long-term debt assumed by Field Services in relation to its acquisition of the PG&E's Texas Midstream operations in December 2000 and decreased capitalized interest related to Merchant Energy's completion of the West Georgia power facility in June 2000. The increase was partially offset by a decrease in short-term interest expense related to lower average commercial paper balances. 17 19 AFFILIATED INTEREST EXPENSE, NET Affiliated interest expense, net for the quarter ended March 31, 2001, was $54 million higher than the same period in 2000 due to an increase in advances from El Paso for ongoing capital projects, investment programs, and operating requirements. INCOME TAX EXPENSE The income tax expense for the quarters ended March 31, 2001 and 2000, was $72 million and $46 million resulting in an effective tax rate of 30 percent for both periods. 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 $1,287 million for the quarter ended March 31, 2001, compared to net cash used in operating activities of $9 million for 2000. The increase was primarily a result of higher cash generated from our price risk management activities compared to 2000. 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 $554 million for the quarter ended March 31, 2001. Our investing activities principally consisted of additions to property, plant, and equipment, primarily related to our Field Services and Pipeline groups as well as expenditures for expansion and construction projects. We also had additions to joint ventures and investments in unconsolidated affiliates, primarily related to our investment in El Paso Energy Araucaria Company (an international power company). CASH FROM FINANCING ACTIVITIES Net cash used in our financing activities was $712 million for the quarter ended March 31, 2001. During 2000, we retired long-term debt 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 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 Part I, Financial Information, Note 8, which is incorporated by reference herein. 18 20 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. 19 21 PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS See Part I, Financial Information, Note 8, which is incorporated by reference herein. The California 2000 cases are: two filed in the Superior Court of Los Angeles County (Continental Forge Company, et al v. Southern California Gas Company, et al, filed on September 25, 2000; and Berg v. Southern California Gas Company, et al, filed on December 18, 2000); and 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 on December 13, 2000). The California 2001 cases are: two filed in the Superior Court of Los Angeles County (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 on March 20, 2001); and one filed in the Superior Court of San Francisco County (Sweeties v. El Paso Corporation, et al, filed on March 22, 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. 20 22 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: May 14, 2001 /s/ H. BRENT AUSTIN ------------------------------------ H. Brent Austin Executive Vice President and Chief Financial Officer Date: May 14, 2001 /s/ JEFFREY I. BEASON ------------------------------------ Jeffrey I. Beason Senior Vice President and Controller (Chief Accounting Officer) 21

EL PASO TENNESSEE PIPELINE CO 10-Q