10-Q 1 h97436e10vq.txt TENNESSEE GAS PIPELINE CO - JUNE 30, 2002 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 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 JUNE 30, 2002 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 1-4101 --------------------- TENNESSEE GAS PIPELINE COMPANY (Exact Name of Registrant as Specified in its Charter) DELAWARE 74-1056569 (State or Other Jurisdiction (I.R.S. Employer of Incorporation or Organization) Identification No.) EL PASO BUILDING 1001 LOUISIANA STREET HOUSTON, TEXAS 77002 (Address of Principal Executive Offices) (Zip Code)
Telephone Number: (713) 420-2600 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate 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 $5 per share. Shares outstanding on August 13, 2002: 208 TENNESSEE GAS PIPELINE COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- PART I -- FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS TENNESSEE GAS PIPELINE COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME (IN MILLIONS) (UNAUDITED)
QUARTER ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, -------------- ---------------- 2002 2001 2002 2001 ---- ---- ----- ----- Operating revenues...................................... $165 $170 $353 $384 ---- ---- ---- ---- Operating expenses Operation and maintenance............................. 74 56 134 112 Depreciation, depletion and amortization.............. 38 33 74 66 Taxes, other than income taxes........................ 12 12 25 25 ---- ---- ---- ---- 124 101 233 203 ---- ---- ---- ---- Operating income........................................ 41 69 120 181 ---- ---- ---- ---- Other income Earnings from unconsolidated affiliates............... 3 2 8 7 Other, net............................................ 4 5 5 5 ---- ---- ---- ---- 7 7 13 12 ---- ---- ---- ---- Income before interest, income taxes and other charges............................................... 48 76 133 193 ---- ---- ---- ---- Non-affiliated interest and debt expense................ 31 29 59 57 Affiliated interest income, net......................... (2) (1) (4) -- Income taxes............................................ 5 13 22 41 ---- ---- ---- ---- 34 41 77 98 ---- ---- ---- ---- Income before cumulative effect of accounting change.... 14 35 56 95 ---- ---- ---- ---- Cumulative effect of accounting change, net of income taxes................................................. -- -- 10 -- ---- ---- ---- ---- Net income.............................................. $ 14 $ 35 $ 66 $ 95 ==== ==== ==== ====
See accompanying notes. 1 TENNESSEE GAS PIPELINE COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE AMOUNTS) (UNAUDITED)
JUNE 30, DECEMBER 31, 2002 2001 -------- ------------ ASSETS Current assets Cash and cash equivalents................................. $ 4 $ 4 Accounts and notes receivable, net Customer................................................ 116 78 Affiliates.............................................. 364 196 Other................................................... 126 121 Materials and supplies.................................... 25 22 Deferred income taxes..................................... 83 90 Other..................................................... 12 14 ------ ------ Total current assets............................... 730 525 ------ ------ Property, plant and equipment, at cost...................... 2,994 2,923 Less accumulated depreciation, depletion and amortization............................................ 453 417 ------ ------ 2,541 2,506 Additional acquisition cost assigned to utility plant, net..................................................... 2,254 2,271 ------ ------ Total property, plant and equipment, net........... 4,795 4,777 ------ ------ Other assets Investments in unconsolidated affiliates.................. 173 155 Other..................................................... 59 70 ------ ------ 232 225 ------ ------ Total assets....................................... $5,757 $5,527 ====== ====== LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities Accounts payable Trade................................................... $ 156 $ 137 Affiliates.............................................. 9 30 Other................................................... 24 37 Short-term borrowings..................................... 363 424 Taxes payable............................................. 108 99 Other..................................................... 71 74 ------ ------ Total current liabilities.......................... 731 801 ------ ------ Long-term debt.............................................. 1,594 1,356 ------ ------ Other liabilities Deferred income taxes..................................... 1,256 1,243 Other..................................................... 209 226 ------ ------ 1,465 1,469 ------ ------ Commitments and contingencies Stockholder's equity Common stock, par value $5 per share; authorized 300 shares; issued 208 shares............................... -- -- Additional paid-in capital................................ 1,410 1,410 Retained earnings......................................... 557 491 ------ ------ Total stockholder's equity......................... 1,967 1,901 ------ ------ Total liabilities and stockholder's equity......... $5,757 $5,527 ====== ======
See accompanying notes. 2 TENNESSEE GAS PIPELINE COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS) (UNAUDITED)
SIX MONTHS ENDED JUNE 30, ---------------- 2002 2001 ----- ----- Cash flows from operating activities Net income................................................ $ 66 $ 95 Adjustments to reconcile net income to net cash from operating activities Depreciation, depletion and amortization............... 74 66 Undistributed earnings of unconsolidated affiliates.... (8) (7) Deferred income tax expense............................ 20 31 Cumulative effect of accounting change................. (10) -- Working capital changes................................... (43) (9) Non-working capital changes and other..................... (12) (65) ---- ---- Net cash provided by operating activities......... 87 111 ---- ---- Cash flows from investing activities Additions to property, plant and equipment................ (78) (96) Additions to investments.................................. -- (8) Net change in affiliated advances receivable.............. (178) 24 Other..................................................... (8) 1 ---- ---- Net cash used in investing activities............. (264) (79) ---- ---- Cash flows from financing activities Net repayments of commercial paper........................ (61) (47) Net proceeds from the issuance of long-term debt.......... 238 -- Net change in other affiliated advances payable........... -- 15 ---- ---- Net cash provided by (used in) financing activities....................................... 177 (32) ---- ---- Net change in cash and cash equivalents..................... -- -- Cash and cash equivalents Beginning of period....................................... 4 4 ---- ---- End of period............................................. $ 4 $ 4 ==== ====
See accompanying notes. 3 TENNESSEE GAS PIPELINE COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. BASIS OF PRESENTATION We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles. You should read it along with our 2001 Annual Report on Form 10-K which includes a summary of our significant accounting policies and other disclosures. The financial statements as of June 30, 2002, and for the quarters and six months ended June 30, 2002 and 2001, are unaudited. We derived the balance sheet as of December 31, 2001, from the audited balance sheet filed in our Form 10-K. In our opinion, we have made all adjustments, all of which are of a normal, recurring nature (except for a cumulative effect of accounting change, which is discussed below), to fairly present our interim period results. Due to the seasonal nature of our business, information for interim periods may not necessarily indicate the results of operations for the entire year. Our accounting policies are consistent with those discussed in our Form 10-K, except as discussed below: Goodwill and Other Intangible Assets On January 1, 2002, we adopted Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that upon adoption of SFAS No. 142, any negative goodwill should be written off as a cumulative effect of an accounting change. Prior to adoption of the standards, we had negative goodwill associated with an investment in an unconsolidated affiliate that we amortized using the straight-line method. As a result of our adoption of these standards on January 1, 2002, we stopped this amortization, and recognized a pretax and after-tax gain of $10 million related to the write-off of negative goodwill as a cumulative effect of an accounting change. Had we continued to amortize negative goodwill our reported income for the quarter and six months ended June 30, 2002, would not have been materially different. In addition, had we applied the amortization provisions of these standards on January 1, 2001, our reported income for the quarter and six months ended June 30, 2001, would not have materially differed. Asset Impairments On January 1, 2002, we adopted SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 changed the accounting requirements related to when an asset qualifies as held for sale or as a discontinued operation and the way in which we evaluate impairments of assets. It also changes accounting for discontinued operations such that we can no longer accrue future operating losses in these operations. There was no initial financial statement impact of adopting this statement. 2. DEBT AND OTHER CREDIT FACILITIES At June 30, 2002, we had $363 million in commercial paper with a weighted average interest rate of 2.6%, and at December 31, 2001, it was $424 million at 3.2%. In May 2002, El Paso Corporation (El Paso), our parent, renewed its $3 billion, 364-day revolving credit and competitive advance facility. We remain a designated borrower under this facility and, as such, are liable for any amounts outstanding under this facility. This facility matures in May 2003. In June 2002, El Paso amended its existing $1 billion, 3-year revolving credit and competitive advance facility to permit El Paso to issue up to $500 million in letters of credit and to adjust pricing terms. This facility matures in August 2003, and we are a designated borrower under this facility and, as such, are liable for any amounts outstanding under this facility. The interest rate under both of these facilities varies based on El Paso's senior unsecured debt rating, and as of June 30, 2002, an initial draw would have had a rate of LIBOR plus 0.625%, plus a 0.25% 4 utilization fee for drawn amounts above 25% of the committed amounts. As of June 30, 2002, there were no borrowings outstanding, and $450 million in letters of credit were issued under the $1 billion facility. In June 2002, we issued $240 million aggregate principal amount 8.375% notes due 2032. Proceeds were approximately $238 million, net of issuance costs. As a result, we have no remaining capacity under a shelf registration on file with the SEC. 3. COMMITMENTS AND CONTINGENCIES Legal Proceedings In 1997, we and a number of our 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 underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). In May 2001, the court denied the defendants' motions to dismiss. We and a number of our 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 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 addition to the above matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. As of June 30, 2002, we had reserves totaling $4 million for all outstanding legal matters. While the outcome of our outstanding legal matters cannot be predicted with certainty, based on the information known to date and our existing accruals, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows. As new information becomes available or relevant developments occur, we will review our accruals and make any appropriate adjustments. The impact of these changes may have a material effect on our results of operations. Environmental Matters We are subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of June 30, 2002, we had a reserve of approximately $98 million for expected remediation costs (including related environmental litigation). In addition, we expect to make capital expenditures for environmental matters of approximately $63 million in the aggregate for the years 2002 through 2007. These expenditures primarily relate to compliance with clean air regulations. Since 1988, we have been engaged in an internal project to identify and deal with the presence of polychlorinated biphenyls (PCBs) and other substances, including those on the Environmental Protection Agency's (EPA) List of Hazardous Substances, at compressor stations and other facilities we operate. While conducting this project, we have been in frequent contact with federal and state regulatory agencies, both through informal negotiation and formal entry of consent orders, to ensure that our efforts meet regulatory requirements. We executed a consent order in 1994 with the EPA, governing the remediation of the relevant compressor stations and are working with the EPA, and the relevant states regarding those 5 remediation activities. We are also working with the Pennsylvania and New York environmental agencies regarding remediation and post-remediation activities at the Pennsylvania and New York stations. In November 1988, the Kentucky environmental agency filed a complaint in a Kentucky state court alleging that we discharged pollutants into the waters of the state and disposed of PCBs without a permit. The agency sought an injunction against future discharges, an order to remediate or remove PCBs and a civil penalty. We entered into agreed orders with the agency to resolve many of the issues raised in the complaint and received water discharge permits from the agency for our Kentucky compressor stations. The relevant Kentucky compressor stations are being characterized and remediated under the 1994 consent order with the EPA. Despite these remediation efforts, the agency may raise additional technical issues or require additional remediation work in the future. In May 1995, following negotiations with our customers, we filed an agreement with the Federal Energy Regulatory Commission (FERC) that established a mechanism for recovering a substantial portion of the environmental costs identified in our internal remediation project. The agreement, which was approved by the FERC in November 1995, provided for a PCB surcharge on firm and interruptible customers' rates to pay for eligible costs under the PCB remediation project, with these surcharges to be collected over a defined collection period. We have twice received approval from the FERC to extend the collection period, which is now currently set to expire in June 2004. The agreement also provided for bi-annual audits of eligible costs. As of June 30, 2002, we had over-collected our PCB costs by approximately $113 million for which we have established a non-current liability. The over-collection will be reduced by future eligible costs incurred for the remainder of the remediation project. We are required to refund to our customers the over-collection amount to the extent actual eligible expenditures are less than amounts collected. Presently, we estimate the future refund obligation, at the conclusion of the remediation process, to be approximately $50 million. 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 one active site under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these CERCLA sites, as appropriate, through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of June 30, 2002, 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 clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in determining our estimated liabilities. While the outcome of our outstanding environmental matters cannot be predicted with certainty, based on the information known to date and our existing accruals, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. It is also possible that other developments, such as increasingly strict environmental laws and regulations and claims for damages to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As new information becomes available, or relevant developments occur, we will review our accruals and make any appropriate adjustments. The impact of these changes may have a material effect on our results of operations. Rates and Regulatory Matters In February 2000, the FERC issued Order No. 637 which revised regulations regarding capacity release, capacity segmentation, imbalance management services, operational flow orders and pipeline penalties. We filed our compliance proposals on August 15, 2000, as modified on April 6, 2001, and we received an order on compliance from the FERC on April 3, 2002. Although most of our compliance proposals were accepted, the 6 FERC rejected our proposals regarding overlapping capacity segments, discounting and the priority of capacity. We sought rehearing and made another compliance filing subject to the outcome of our hearing request. In 1997, the FERC approved the settlement of all issues related to the recovery of our Gas Supply Realignment (GSR) and other transition costs. Under the agreement, we are entitled to collect up to $770 million from our customers, $693 million through a demand surcharge and $77 million through an interruptible transportation surcharge. Our final GSR report was approved by the FERC on May 16, 2001. In June 2001, $31 million of the amount collected through the demand surcharge was refunded to our firm transportation contract customers. As of June 30, 2002, $62 million of the interruptible transportation surcharge had been collected. There is no time limit for collection of the remaining interruptible transportation surcharge. This agreement also provides for a rate case moratorium that expired November 2000 and an escalating rate cap, indexed to inflation, through October 2005, for some of our customers. In September 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct governing the relationship between interstate pipelines and marketing affiliates to all energy affiliates. The proposed regulations, if adopted by the FERC, would dictate how we conduct business and interact with our energy affiliates. In December 2001, we filed comments with the FERC addressing our concerns with the proposed rules. A public hearing was held on May 21, 2002, at which interested parties were given an opportunity to comment further on the NOPR. Following the conference, additional comments were filed by El Paso's pipelines and others. 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. On July 17, 2002, the FERC issued a Notice of Inquiry (NOI) that seeks comments regarding its policy, established in 1996, of permitting pipelines to enter into negotiated rates transactions. Our pipeline has entered into such transactions over the years. Specifically, the FERC is now undertaking a review of whether negotiated rates should be capped, whether or not a pipeline's "recourse rate" (cost of service based rate) continues to serve as a viable alternative and safeguard against the exercise of alleged pipeline market power, as well as other issues related to its negotiated rate program. Comments are due on September 25, 2002, with reply comments due on October 25, 2002. We cannot predict the outcome of this NOI. On August 1, 2002, the FERC issued a NOPR requiring that all arrangements concerning the cash management or money pool arrangements between a FERC regulated subsidiary and a non-FERC regulated parent must be in writing, and set forth: the duties and responsibilities of cash management participants and administrators; the methods of calculating interest and for allocating interest income and expenses; and the restrictions on deposits or borrowings by money pool members. The NOPR also requires specified documentation for all deposits into, borrowings from, interest income from, and interest expenses related to, these arrangements. Finally, the NOPR proposed that as a condition of participating in a cash management or money pool arrangement, the FERC regulated entity must maintain a minimum proprietary capital balance of 30 percent, and the FERC regulated entity and its parent must maintain investment grade credit ratings. Comments on the NOPR are due on August 22, 2002. We cannot predict the outcome of this NOPR. Also on August 1, 2002, the FERC's Chief Accountant issued, to be effective immediately, an Accounting Release providing guidance on how jurisdictional entities should account for money pool arrangements and the types of documentation that should be maintained for these arrangements. The Accounting Release sets forth the documentation requirements set forth in the NOPR for money pool arrangements, but does not address the requirements in the NOPR that as a condition for participating in money pool arrangements the FERC regulated entity must maintain a minimum proprietary capital balance of 30 percent and that the entity and its parent must have investment grade credit ratings. Requests for rehearing are due on September 3, 2002. While the outcome of our rates and regulatory matters cannot be predicted with certainty, based on the information known to date and our existing accruals, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows. As new information 7 becomes available or relevant developments occur, we will review our accruals and make any appropriate adjustments. The impact of these changes may have a material effect on our results of operations. Other Matters In December 2001, Enron Corp. and a number of its subsidiaries including, Enron North America Corp. and Enron Power Marketing, Inc. filed for Chapter 11 bankruptcy protection in the United States Bankruptcy Court for the Southern District of New York. Affiliates of Enron held both short-term and long-term capacity on our pipeline system but Enron has now rejected most of these contracts. Future revenue on these contracts will depend upon the outcome of Enron's bankruptcy and our ability to re-market or otherwise maximize the value of the rejected or released capacity. We do not presently know the precise values that will be received by our pipelines as a result of their efforts. As a result of current circumstances surrounding the energy sector, the creditworthiness of several industry participants has been called into question. We have taken actions to mitigate our exposure to these participants; however, should several of these participants file for Chapter 11 bankruptcy protection and our contracts are not assumed by other counterparties, it could have a material adverse effect on our financial position, operating results or cash flows. 4. RELATED PARTY TRANSACTIONS We participate in El Paso's cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowing from outside sources. We had advanced $322 million at June 30, 2002, at a market rate of interest which was 1.9%. At December 31, 2001, we had advanced $153 million, at a market rate of interest which was 2.1%. In addition, we had a demand note receivable with El Paso of $37 million at June 30, 2002, at an interest rate of 2.4%. At December 31, 2001, the demand note receivable was $28 million at an interest rate of 2.7%. At June 30, 2002 and December 31, 2001, we had other accounts receivable from related parties of $5 million and $15 million. In addition, we had accounts payable to related parties of $9 million and $30 million at June 30, 2002 and December 31, 2001. These balances arose in the normal course of business. 5. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED Accounting for Asset Retirement Obligations In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement requires companies to record a liability for the estimated retirement and removal costs of assets used in their business. The liability is recorded at its present value, and the same amount is added to the recorded value of the asset and is amortized over the asset's remaining useful life. The provisions of SFAS No. 143 are effective for fiscal years beginning after June 15, 2002. We are currently evaluating the effects of this statement. Accounting for Costs Associated with Exit or Disposal Activities In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. This statement will require us to recognize costs associated with exit or disposal activities when they are incurred rather than when we commit to an exit or disposal plan. Examples of costs covered by this guidance include lease termination costs, employee severance costs that are associated with a restructuring, discontinued operations, plant closings or other exit or disposal activities. The provisions of this statement are effective for fiscal years beginning after December 31, 2002 and will impact any exit or disposal activities initiated after January 1, 2003. 8 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information contained in Item 2 updates, and you should read it in conjunction with, information disclosed in our Annual Report on Form 10-K filed March 25, 2002, in addition to the financial statements and notes presented in Item 1, Financial Statements, of this Quarterly Report on Form 10-Q. RECENT DEVELOPMENTS As a result of current circumstances surrounding the energy sector, the creditworthiness of several industry participants has been called into question. We have taken actions to mitigate our exposure to these participants; however, should several of these participants file for Chapter 11 bankruptcy protection and our contracts are not assumed by other counterparties, it could have a material adverse effect on our financial position, operating results or cash flows. RESULTS OF OPERATIONS Pipeline results are relatively stable, but can be subject to variability from a number of factors, such as weather conditions, including those conditions that may impact the amount of power produced by natural gas fired turbines, as well as gas supply availability which can displace the pipeline's delivery capabilities to the markets they serve. Results can also be impacted by the ability to market excess natural gas which is influenced by a pipeline's rate of recovery for use and efficiencies of the compression equipment. Future revenues may also be impacted by expansion projects in our service areas, competition by other pipelines for those expansion needs and regulatory impacts on rates. Results of our operations were as follows for the periods ended June 30:
QUARTER ENDED SIX MONTHS ENDED ---------------- ---------------- 2002 2001 2002 2001 ------ ------ ------ ------ (IN MILLIONS, EXCEPT VOLUME AMOUNTS) Operating revenues...................................... $ 165 $ 170 $ 353 $ 384 Operating expenses...................................... (124) (101) (233) (203) Other income............................................ 7 7 13 12 ------ ------ ------ ------ Earnings before interest and income taxes............. $ 48 $ 76 $ 133 $ 193 ====== ====== ====== ====== Throughput volumes (BBtu/d)(1).......................... 4,266 4,111 4,551 4,589 ====== ====== ====== ======
--------------- (1) BBtu/d means billion British thermal units per day. Second Quarter 2002 Compared to Second Quarter 2001 Operating revenues for the quarter ended June 30, 2002, were $5 million lower than the same period in 2001. The decrease was primarily due to the favorable resolution of regulatory issues related to natural gas purchase contracts in 2001 and the impact of lower natural gas prices on excess natural gas recoveries in 2002. The decrease was partially offset by revenues from transmission system expansion projects placed in service in 2002 and a favorable resolution of measurement issues at a processing plant serving the TGP system. Operating expenses for the quarter ended June 30, 2002, were $23 million higher than the same period in 2001. The increase was primarily due to higher shared services costs, higher amortization of additional acquisition cost assigned to utility plant, higher field operational costs, higher costs associated with gas storage and higher electric compression costs in 2002. Six Months Ended 2002 Compared to Six Months Ended 2001 Operating revenues for the six months ended June 30, 2002, were $31 million lower than the same period in 2001. The decrease was primarily due to the favorable resolution of regulatory issues related to natural gas purchase contracts in 2001, the impact of lower natural gas prices on excess natural gas recoveries, lower transportation revenues from capacity sold under short-term contracts and lower revenues due to milder weather in 2002. Partially offsetting the decrease were revenues from transmission system expansion projects 9 placed in service in 2002 and a favorable resolution of measurement issues at a processing plant serving the TGP system. Operating expenses for the six months ended June 30, 2002, were $30 million higher than the same period in 2001. The increase was primarily due to higher shared services costs, higher amortization of additional acquisition cost assigned to utility plant, higher field operational costs, higher costs associated with gas storage and higher electric compression costs in 2002. Also contributing to the increase were lower project development costs in the first quarter of 2001. New Expansion Project. The FERC approved our Can-East project and related compressor facilities on June 26, 2002. Service is anticipated to commence in November 2002. The Can-East project will extend our mainline pipeline system to the Leidy Hub using 280 million cubic feet of capacity per day that we currently intend to lease from Dominion Resources and National Fuel Gas Supply Corp. INTEREST AND DEBT EXPENSE Non-affiliated Interest and Debt Expense, Net Non-affiliated interest and debt expense, net for the quarter and six months ended June 30, 2002, was $2 million higher than the same period in 2001 primarily due to an increase in long-term debt and a decrease in capitalized interest on construction projects due to lower rates. The increase was partially offset by lower interest rates on commercial paper borrowings in 2002. Affiliated Interest Income, Net Affiliated interest income, net for the quarter and six months ended June 30, 2002, was $1 million and $4 million higher than the same period in 2001 due primarily to an increase in average advances to El Paso in 2002 under our cash management program, partially offset by lower 2002 short-term interest rates. INCOME TAXES Income tax expense for the quarter and six months ended June 30, 2002, was $5 million and $22 million, resulting in effective tax rates of 26 percent and 28 percent. Our effective tax rates were different than the statutory rate of 35 percent primarily due to state income taxes. Income tax expense for the quarter and six months ended June 30, 2001, was $13 million and $41 million, resulting in effective tax rates of 27 percent and 30 percent. Our effective tax rates were different than the statutory rate of 35 percent primarily due to state income taxes. COMMITMENTS AND CONTINGENCIES See Item 1, Financial Statements, Note 3, which is incorporated herein by reference. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED See Item 1, Financial Statements, Note 5, which is incorporated herein by reference. 10 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, 2001, in addition to the information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There are no material changes in our quantitative and qualitative disclosures about market risks from those reported in our Annual Report on Form 10-K for the year ended December 31, 2001. 11 PART II -- OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS See Part I, Item 1, Financial Statements, Note 3, which is incorporated herein by reference. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS None. ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a. Exhibits Each exhibit identified below is filed as a part of this report. Exhibits not incorporated by reference to a prior filing are designated by an "*"; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
EXHIBIT NUMBER DESCRIPTION ------- ----------- 4.A -- Indenture dated as of March 4, 1997, between TGP and The Chase Manhattan Bank (Exhibit 4.1 to El Paso Tennessee Pipeline Co's. (EPTP) 1997 Form 10-K); First Supplemental Indenture dated as of March 13, 1997, between TGP and The Chase Manhattan Bank (Exhibit 4.2 to EPTP's 1997 Form 10-K); Second Supplemental Indenture dated as of March 13, 1997, between TGP and The Chase Manhattan Bank (Exhibit 4.3 to EPTP's 1997 Form 10-K); Third Supplemental Indenture dated as of March 13, 1997, between TGP and The Chase Manhattan Bank (Exhibit 4.4 to the EPTP's 1997 Form 10-K); Fourth Supplemental Indenture dated as of October 9, 1998, between TGP and The Chase Manhattan Bank (Exhibit 4.2 to our Form 8-K filed October 9, 1998). 4.A.1 -- Fifth Supplemental Indenture dated June 10, 2002 between TGP and JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank)(Exhibit 4.1 to our Form 8-K dated June 10, 2002). *10.A -- $3,000,000,000 364-Day Revolving Credit and Competitive Advance Facility Agreement dated May 15, 2002, by and among El Paso, EPNG, TGP, the several banks and other financial institutions from time to time parties thereto and JP Morgan Chase Bank, as Administrative Agent and CAF Advance Agent, ABN Amro Bank N.V. and Citibank, N.A., as Co-Documentation Agents, and Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents. *10.B -- Amended and Restated $1,000,000,000 3-Year Revolving Credit and Competitive Advance Facility Agreement dated June 27, 2002 by and among El Paso, EPNG, TGP, El Paso CGP, the several banks and other financial institutions from time to time parties thereto and JP Morgan Chase Bank, as Administrative Agent, CAF Advance Agent and Issuing Bank, Citibank, N.A. and ABN Amro Bank N.V., as Co-Documentation Agents, and Bank of America, N.A., as Syndication Agent. *99.A -- Certification of Chairman of the Board (Principal Executive Officer) pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.
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EXHIBIT NUMBER DESCRIPTION ------- ----------- *99.B -- Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.
Undertaking We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the U.S. Securities and Exchange Commission, upon request, all constituent instruments defining the rights of holders of our long-term debt not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets. b. Reports on Form 8-K We filed a Current Report on Form 8-K dated June 5, 2002 filing the Computation of our Ratio of Earnings to Fixed Charges. We filed a Current Report on Form 8-K dated June 10, 2002 filing exhibits in connection with our issuance of $240,000,000 of 8.375% Notes. 13 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. TENNESSEE GAS PIPELINE COMPANY Date: August 13, 2002 /s/ JOHN W. SOMERHALDER II ------------------------------------ John W. Somerhalder II Chairman of the Board and Director (Principal Executive Officer) Date: August 13, 2002 /s/ GREG G. GRUBER ------------------------------------ Greg G. Gruber Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer) 14 EXHIBIT INDEX Each exhibit identified below is filed as a part of this report. Exhibits not incorporated by reference to a prior filing are designated by an "*"; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
EXHIBIT NUMBER DESCRIPTION ------- ----------- 4.A -- Indenture dated as of March 4, 1997, between TGP and The Chase Manhattan Bank (Exhibit 4.1 to El Paso Tennessee Pipeline Co's. (EPTP) 1997 Form 10-K); First Supplemental Indenture dated as of March 13, 1997, between TGP and The Chase Manhattan Bank (Exhibit 4.2 to EPTP's 1997 Form 10-K); Second Supplemental Indenture dated as of March 13, 1997, between TGP and The Chase Manhattan Bank (Exhibit 4.3 to EPTP's 1997 Form 10-K); Third Supplemental Indenture dated as of March 13, 1997, between TGP and The Chase Manhattan Bank (Exhibit 4.4 to the EPTP's 1997 Form 10-K); Fourth Supplemental Indenture dated as of October 9, 1998, between TGP and The Chase Manhattan Bank (Exhibit 4.2 to our Form 8-K filed October 9, 1998). 4.A.1 -- Fifth Supplemental Indenture dated June 10, 2002 between TGP and JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank)(Exhibit 4.1 to our Form 8-K dated June 10, 2002). *10.A -- $3,000,000,000 364-Day Revolving Credit and Competitive Advance Facility Agreement dated May 15, 2002, by and among El Paso, EPNG, TGP, the several banks and other financial institutions from time to time parties thereto and JP Morgan Chase Bank, as Administrative Agent and CAF Advance Agent, ABN Amro Bank N.V. and Citibank, N.A., as Co-Documentation Agents, and Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents. *10.B -- Amended and Restated $1,000,000,000 3-Year Revolving Credit and Competitive Advance Facility Agreement dated June 27, 2002 by and among El Paso, EPNG, TGP, El Paso CGP, the several banks and other financial institutions from time to time parties thereto and JP Morgan Chase Bank, as Administrative Agent, CAF Advance Agent and Issuing Bank, Citibank, N.A. and ABN Amro Bank N.V., as Co-Documentation Agents, and Bank of America, N.A., as Syndication Agent. *99.A -- Certification of Chairman of the Board (Principal Executive Officer) pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002. *99.B -- Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.