10-K405 1 h93214e10-k405.txt TENNESSEE GAS PIPELINE COMPANY - 12/31/2001 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------- FORM 10-K (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 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 1-4101 TENNESSEE GAS PIPELINE COMPANY (Exact name of registrant as specified in its charter) DELAWARE 74-1056569 (State or Other Jurisdiction of (I.R.S. Employer 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 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE 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 by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT.......................................... NONE INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE. Common Stock, par value $5 per share. Shares outstanding on March 22, 2002: 208 TENNESSEE GAS PIPELINE COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION. DOCUMENTS INCORPORATED BY REFERENCE: NONE -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- TENNESSEE GAS PIPELINE COMPANY TABLE OF CONTENTS
CAPTION PAGE ------- ---- PART I Item 1. Business.................................................... 1 Item 2. Properties.................................................. 3 Item 3. Legal Proceedings........................................... 3 Item 4. Submission of Matters to a Vote of Security Holders......... * PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................................... 3 Item 6. Selected Financial Data..................................... * Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 4 Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995................................................... 5 Item 7A. Quantitative and Qualitative Disclosures About Market Risk...................................................... 6 Item 8. Financial Statements and Supplementary Data................. 7 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................. 24 PART III Item 10. Directors and Executive Officers of the Registrant.......... * Item 11. Executive Compensation...................................... * Item 12. Security Ownership of Management............................ * Item 13. Certain Relationships and Related Transactions.............. * PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................................................... 24 Signatures.................................................. 26
--------------- * We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K. Below is a list of terms that are common to our industry and used throughout this document: /d = per day BBtu = billion British thermal units Bcf = billion cubic feet MMcf = million cubic feet
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch. When we refer to "us", "we", "our", "ours", we are describing Tennessee Gas Pipeline Company and/or our subsidiaries. i PART I ITEM 1. BUSINESS GENERAL We are a Delaware corporation incorporated in 1947, and a wholly owned subsidiary of El Paso Tennessee Pipeline Co., a direct subsidiary of El Paso Corporation. Our primary business is the interstate transportation and storage of natural gas. We conduct our business activities through two natural gas pipeline systems and a storage facility, each of which is discussed below: The TGP system. The Tennessee Gas Pipeline system consists of approximately 14,200 miles of pipeline with a design capacity of 6,194 MMcf/d. During 2001, 2000 and 1999, average throughput on the TGP system was 4,405 BBtu/d, 4,354 BBtu/d and 4,253 BBtu/d. This multiple-line system begins in the natural gas producing regions of Louisiana, the Gulf of Mexico and south Texas and extends to the northeast section of the U.S., including the New York City and Boston metropolitan areas. TGP also has an interconnect at the U.S.-Mexico border. Along its system, TGP has approximately 95 Bcf of underground working gas storage capacity, of which 5 Bcf is contracted from ANR Pipeline Company, our affiliate. The Portland System. We have a 30 percent ownership interest in the Portland Natural Gas Transmission system. Portland consists of approximately 300 miles of interstate natural gas pipeline, including lateral lines, with a design capacity of 214 MMcf/d. During 2001, 2000 and 1999, average throughput on the Portland system was 123 BBtu/d, 110 BBtu/d and 61 BBtu/d. Portland's system extends from the Canadian border near Pittsburg, New Hampshire to Dracut, Massachusetts. Bear Creek Storage. We own a 50 percent interest in Bear Creek Storage Company, which owns and operates an underground natural gas storage facility located in Louisiana. Southern Natural Gas Company, our affiliate, owns the remaining 50 percent interest. The facility has a capacity of 50 Bcf of base gas and 58 Bcf of working storage. Bear Creek's working storage capacity is committed equally to the Southern Natural Gas system, which is owned by our affiliate, and our pipeline system under long-term contracts. The following transmission system expansion projects have been approved by the Federal Energy Regulatory Commission (FERC):
ANTICIPATED PROJECT CAPACITY DESCRIPTION COMPLETION DATE ------- -------- ----------- --------------- (MMCF/D) Stagecoach 100 Connects the Stagecoach Storage Field in New York to our Completed mainline in Pennsylvania and expands our 300 Line to provide February 2002 firm transportation service to interconnect with New Jersey Natural in Passaic, New Jersey. FPL 90 Installation of compression and a meter to supply Florida September 2002 project Power and Light's facility in Rhode Island.
REGULATORY ENVIRONMENT Our interstate natural gas transmission systems and storage operations are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each operates under separate FERC approved tariffs that establish rates, terms and conditions under which we provide services to our customers. Generally, the FERC's authority extends to: - transportation and storage of natural gas, rates and charges; - certification and construction of new facilities; - extension or abandonment of services and facilities; - maintenance of accounts and records; - relationships between pipeline and marketing affiliates; - depreciation and amortization policies; - acquisition and disposition of facilities; and - initiation and discontinuation of services. 1 Our pipelines and storage facility have tariffs established through filings with the FERC that have a variety of terms and conditions, each of which affects our operations and our ability to recover fees for the services we provide. Generally, changes to these fees or terms of service can only be implemented upon approval by the FERC. Our interstate pipeline systems are also subject to the Natural Gas Pipeline Safety Act of 1968, which establishes pipeline safety requirements, the National Environmental Policy Act and other environmental legislation. Each system has a continuing program of inspection designed to keep all of our facilities in compliance with pollution control and pipeline safety requirements. We believe that our systems are in compliance with the applicable requirements. We are also subject to regulation over the safety requirements in the design, construction, operation and maintenance of our interstate natural gas transmission systems and storage facility by the U.S. Department of Transportation. Operations on U.S. government land are regulated by the U.S. Department of the Interior. For a discussion of significant rate and regulatory matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 5. MARKETS AND COMPETITION Our interstate transmission systems face varying degrees of competition from other pipelines, as well as alternative energy sources, such as electricity, hydroelectric power, coal and fuel oil. Also, the potential consequences of proposed and ongoing restructuring and deregulation of the electric power industry are currently unclear. Restructuring and deregulation may benefit the natural gas industry by creating more demand for natural gas turbine generated electric power, or it may hamper demand by allowing a more effective use of surplus electric capacity through increased wheeling as a result of open access. On our TGP system, we have approximately 430 firm and interruptible customers, including natural gas producers, marketers, end-users and other natural gas transmission, distribution and electric generation companies. We have approximately 500 firm transportation contracts with remaining terms that extend from 1 month to 10 years and with an average remaining term of 5 years. Approximately 95 percent of our total capacity is subscribed under firm transportation agreements. Our TGP system faces strong competition in the Northeast, Appalachian, Midwest and Southeast market areas. We compete with interstate pipelines for deliveries to multiple-connection customers. Natural gas delivered on our system competes with alternate fuels, principally oil and coal. We also compete with pipelines and local distribution companies to connect new loads. In addition, we compete with pipelines and gathering systems for connection to new supply sources in Texas, the Gulf of Mexico and at the Canadian border. Our ability to extend existing contracts or re-market expiring capacity with our customers is based on a variety of factors, including competitive alternatives, the regulatory environment at the local, state and federal levels and market supply and demand factors at the relevant extension or expiration dates. While we make every attempt to re-negotiate contract terms at fully-subscribed quantities and at maximum rates allowed under our tariffs, we must, at times, discount our rates to remain competitive. ENVIRONMENTAL A description of our environmental activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 5, and is incorporated herein by reference. EMPLOYEES As of March 20, 2002, we had approximately 1,600 full-time employees, none of whom are subject to collective bargaining arrangements. 2 ITEM 2. PROPERTIES A description of our properties is included in Item 1, Business, and is incorporated herein by reference. We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions that do not materially detract from the value of these properties or our interests therein, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future. ITEM 3. LEGAL PROCEEDINGS A description of our legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 5, and is incorporated herein by reference. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Item 4, Submission of Matters to a Vote of Security Holders, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of our common stock, par value $5 per share, is owned by El Paso Tennessee Pipeline Co. and, accordingly, there is no public trading market for our securities. We pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors. No common stock dividends were declared or paid in 2001 or 2000. ITEM 6. SELECTED FINANCIAL DATA Item 6, Selected Financial Data, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K. 3 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. The notes to our consolidated financial statements contain information that is pertinent to the following analysis, including a discussion of our significant accounting policies. RESULTS OF OPERATIONS Below are the operating results and an analysis of those results for the year ended December 31:
2001 2000 -------- -------- (IN MILLIONS, EXCEPT VOLUME AMOUNTS) Operating revenues.......................................... $ 728 $ 748 Operating expenses.......................................... (414) (427) Other income................................................ 23 16 ------ ------ Earnings before interest and income taxes (EBIT).......... $ 337 $ 337 ====== ====== Total throughput (BBtu/d)(1)...................... 4,441 4,375 ====== ======
--------------- (1) Amounts include our proportionate share of throughput on the Portland system. YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000 Operating revenues for the year ended December 31, 2001, were $20 million lower than the same period in 2000. The decrease was due to lower 2001 revenues resulting from remarketed contracts during 2000 and lower transportation revenues on throughput in 2001 as a result of a higher proportion of short versus long hauls compared to 2000. Our revenues from period to period are impacted not only by the overall volume of gas transported, but the distances this gas is shipped on our system. Also contributing to the decrease were contract quantity reductions or cancellations on our pipeline system by customers of our affiliate, East Tennessee Natural Gas Company, resulting from the Federal Trade Commission (FTC) ordered sale of this system in the first quarter of 2000. Partially offsetting the decrease were the impact of higher sales of excess natural gas in 2001, the favorable resolution of issues related to natural gas purchase contracts in 2001 and higher revenues from other transportation services. Operating expenses for the year ended December 31, 2001, were $13 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 and decreased depreciation expenses resulting from the retirement of assets. The decrease was partially offset by higher electric compression costs and higher project development costs in 2001. Other income for the year ended December 31, 2001, was $7 million higher than the same period in 2000. The increase was due to favorable resolution of regulatory issues in 2001 and higher earnings on equity investments. INTEREST AND DEBT EXPENSE Non-affiliated Interest and Debt Expense Non-affiliated interest and debt expense for the year ended December 31, 2001, was $8 million lower than 2000 primarily due to lower interest rates on short term borrowings and an increase in capitalized interest on construction projects. 4 Affiliated Interest Income, Net Affiliated interest income, net, for the year ended December 31, 2001, was $19 million lower than 2000 due to lower short-term interest rates and a decrease in average advances to El Paso in 2001 under our cash management program. INCOME TAXES The effective income tax rate for the years ended December 31, 2001 and 2000, was 32 percent and 31 percent. The effective tax rates were lower than the statutory rate of 35 percent primarily due to state income tax benefits. For a reconciliation of the statutory rate to the effective rates, see Item 8, Financial Statements and Supplementary Data, Note 2. OTHER In February 2001, we received and accepted a FERC order issuing a certificate for our Stagecoach Expansion project. The project connects the Stagecoach Storage Field in Tioga County, New York, to our mainline at our compressor station 319 in Bradford County, Pennsylvania. The new lateral consists of 23.7 miles of pipe and has a capacity of 500 MMcf/d. In addition, the project expands our 300 Line to provide 100 MMcf/d of firm transportation service from station 319 to its interconnect with New Jersey Natural in Passaic, New Jersey. The cost of constructing these facilities was approximately $80 million, and the project was completed in February 2002. As of December 31, 2001, total year to date expenditures on the Stagecoach Expansion project were $63 million. In October 2001, we announced the development of our Blue Atlantic Transmission System. This pipeline project consists of approximately 750 miles of 36-inch pipe designed to carry up to 1 Bcf/d. The pipeline will follow a sub-sea route from an anticipated production area offshore on the Scotian shelf, make landfall on the Southern coast of Nova Scotia, then continue sub-sea to landing points in the New York and New Jersey areas. Current cost estimates are approximately $2 billion, and current expenditures to date are less than $1 million. We anticipate that all necessary regulatory filings will be made by the end of 2002, and the system will be placed in service by the fourth quarter 2005. COMMITMENTS AND CONTINGENCIES For a discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 5, 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 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. Our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany those statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report. 5 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Our primary market risk is exposure to changing interest rates. The table below shows the carrying value and related weighted average interest rates on our interest bearing securities, by expected maturity dates. As of December 31, 2001, the carrying amounts of short-term borrowings are representative of fair values because of the short-term maturity of these instruments. The fair value of our long-term debt has been estimated based on quoted market prices for the same or similar issues.
DECEMBER 31, 2001 DECEMBER 31, 2000 --------------------------------------------------- --------------------- EXPECTED FISCAL YEAR OF MATURITY OF CARRYING VALUE --------------------------------------------------- CARRYING 2002 2003-2006 THEREAFTER TOTAL FAIR VALUE AMOUNTS FAIR VALUE ---- --------- ---------- ------ ---------- -------- ---------- (DOLLARS IN MILLIONS) LIABILITIES: Short-term debt -- variable rate... $424 $ 424 $ 424 $ 215 $ 215 Average interest rate....... 2.4% Long-term debt, including current portion -- fixed rate.... $1,356 $1,356 $1,283 $1,354 $1,322 Average interest rate....... 7.4%
6 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TENNESSEE GAS PIPELINE COMPANY CONSOLIDATED STATEMENTS OF INCOME (IN MILLIONS)
YEAR ENDED DECEMBER 31, ------------------------ 2001 2000 1999 ------ ------ ------ Operating revenues.......................................... $728 $748 $785 ---- ---- ---- Operating expenses Operation and maintenance................................. 238 249 275 Depreciation, depletion and amortization.................. 132 134 137 Taxes, other than income taxes............................ 44 44 43 ---- ---- ---- 414 427 455 ---- ---- ---- Operating income............................................ 314 321 330 ---- ---- ---- Other income Earnings from unconsolidated affiliates................... 14 11 9 Other, net................................................ 9 5 13 ---- ---- ---- 23 16 22 ---- ---- ---- Income before interest and income taxes..................... 337 337 352 ---- ---- ---- Non-affiliated interest and debt expense.................... 112 120 120 Affiliated interest income, net............................. (1) (20) (24) Income taxes................................................ 72 74 82 ---- ---- ---- 183 174 178 ---- ---- ---- Net income.................................................. $154 $163 $174 ==== ==== ====
See accompanying notes. 7 TENNESSEE GAS PIPELINE COMPANY CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE AMOUNTS)
DECEMBER 31, ---------------- 2001 2000 ------ ------ ASSETS Current assets Cash and cash equivalents................................. $ 4 $ 4 Accounts and notes receivable, net of allowance of $6 in 2001 and $4 in 2000 Customer............................................... 78 210 Affiliates............................................. 196 60 Other.................................................. 121 98 Materials and supplies.................................... 22 19 Deferred income taxes..................................... 90 12 Other..................................................... 14 14 ------ ------ Total current assets.............................. 525 417 ------ ------ Property, plant and equipment, at cost...................... 2,923 2,612 Less accumulated depreciation............................. 417 347 ------ ------ 2,506 2,265 Additional acquisition cost assigned to utility plant, net of accumulated amortization............................... 2,271 2,292 ------ ------ Total property, plant and equipment, net.......... 4,777 4,557 ------ ------ Investments in unconsolidated affiliates.................... 155 134 ------ ------ Other....................................................... 70 96 ------ ------ Total assets...................................... $5,527 $5,204 ====== ====== LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities Accounts and notes payable Trade.................................................. $ 137 $ 198 Affiliates............................................. 30 18 Other.................................................. 37 47 Short-term borrowings..................................... 424 215 Taxes payable............................................. 99 124 Other..................................................... 74 70 ------ ------ Total current liabilities......................... 801 672 ------ ------ Long-term debt.............................................. 1,356 1,354 ------ ------ Deferred income taxes....................................... 1,243 1,144 ------ ------ Other....................................................... 226 292 ------ ------ 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 1,405 Retained earnings......................................... 491 337 ------ ------ Total stockholder's equity........................ 1,901 1,742 ------ ------ Total liabilities and stockholder's equity........ $5,527 $5,204 ====== ======
See accompanying notes. 8 TENNESSEE GAS PIPELINE COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS)
YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 1999 ----- ----- ----- Cash flows from operating activities Net income.................................................. $ 154 $ 163 $ 174 Adjustments to reconcile net income to net cash from operating activities Depreciation, depletion and amortization............... 132 134 137 Undistributed earnings from unconsolidated affiliates............................................ (14) (11) (3) Deferred income tax expense............................ 37 11 22 Net gain on the sale of assets......................... -- -- (2) Working capital changes, net of non-cash transactions Accounts and notes receivable........................ 108 (143) (34) Accounts payable..................................... (61) 83 17 Accounts payable/receivable with affiliates.......... 17 (12) -- Taxes payable........................................ (22) 20 73 Other working capital changes........................ (14) 31 (91) Non-working capital changes and other.................. (87) 2 8 ----- ----- ----- Net cash provided by operating activities......... 250 278 301 ----- ----- ----- Cash flows from investing activities Additions to property, plant and equipment................ (303) (202) (177) Additions to investments.................................. (9) -- (46) Proceeds from the sales of assets......................... -- 2 10 Cost of removal of assets................................. (8) (18) (20) Net change in affiliated advances......................... (139) 409 (451) ----- ----- ----- Net cash provided by (used in) investing activities...................................... (459) 191 (684) ----- ----- ----- Cash flows from financing activities Net borrowings (repayments) of commercial paper........... 209 (434) 459 Decrease in note payable to affiliate..................... -- (34) (76) Payments to retire long-term debt......................... -- (1) (1) ----- ----- ----- Net cash provided by (used in) financing activities...................................... 209 (469) 382 ----- ----- ----- Decrease in cash and cash equivalents....................... -- -- (1) Cash and cash equivalents Beginning of period....................................... 4 4 5 ----- ----- ----- End of period............................................. $ 4 $ 4 $ 4 ===== ===== =====
See accompanying notes. 9 TENNESSEE GAS PIPELINE COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (IN MILLIONS, EXCEPT SHARE AMOUNTS)
COMMON STOCK ADDITIONAL TOTAL --------------- PAID-IN RETAINED STOCKHOLDER'S SHARES AMOUNT CAPITAL EARNINGS EQUITY ------ ------ ---------- -------- ------------- January 1, 1999.......................................... 208 $ -- $1,388 $ -- $1,388 Net income............................................. 174 174 --- ---- ------ ---- ------ December 31, 1999........................................ 208 -- 1,388 174 1,562 Net income............................................. 163 163 Allocated tax benefit of El Paso equity plans.......... 7 7 Non-cash contributions from El Paso Tennessee.......... 10 10 --- ---- ------ ---- ------ December 31, 2000........................................ 208 -- 1,405 337 1,742 Net income............................................. 154 154 Allocated tax benefit of El Paso equity plans.......... 5 5 --- ---- ------ ---- ------ December 31, 2001........................................ 208 $ -- $1,410 $491 $1,901 === ==== ====== ==== ======
See accompanying notes. 10 TENNESSEE GAS PIPELINE COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Our consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation. Those reclassifications had no impact on reported net income or stockholder's equity. Principles of Consolidation We consolidate entities when we have the ability to control the operating and financial decisions and policies of that entity. Where we can exert significant influence over, but do not control, those policies and decisions, we apply the equity method of accounting. We use the cost method of accounting where we are unable to exert significant influence over the entity. The determination of our ability to control or exert significant influence over an entity involves the use of judgment of the extent of our control or influence and that of the other equity owners or participants of the entity. Use of Estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues, and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates. Accounting for Regulated Operations Our interstate natural gas systems and storage operations are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and we apply the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Accounting requirements for regulated businesses can differ from the accounting requirements for non-regulated businesses. Transactions that have been recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, employee related benefits and other costs and taxes included in, or expected to be included in, future rates. We will continue to evaluate the application of regulatory accounting principles as there are on-going changes in the regulatory and economic environment. Things that may influence this assessment are: - inability to recover cost increases due to rate caps and rate case moratoriums; - inability to recover capitalized costs, including an adequate return on those costs through the ratemaking process; - excess capacity; - discounting rates in the markets we serve; and - impacts of ongoing initiatives in, and deregulation of, the natural gas industry. Cash and Cash Equivalents We consider short-term investments with an original maturity of less than three months to be cash equivalents. 11 Allowance for Doubtful Accounts We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method. Materials and Supplies We value materials and supplies at the lower of cost or market value with cost determined using the average cost method. Natural Gas Imbalances Natural gas imbalances occur when the actual amount of natural gas delivered from or received by a pipeline system differs from the contractual amount scheduled to be delivered or received. We value these imbalances due to or from shippers and operators at an appropriate index price. Imbalances are settled in cash or made up in-kind, subject to the contractual terms of settlement. Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported on the balance sheet as either trade accounts payable or accounts payable to affiliates. In addition, we classify all imbalances as current since we expect to settle them within the next twelve months. Property, Plant and Equipment Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. We capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and equity return component on regulated projects. We capitalize the major units of property replacements or improvements and expense minor items. We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate approved in our tariff to the total cost of the group until its net book value equals its salvage value. Currently, our depreciation rates vary from 1 to 24 percent. Using these rates, the remaining useful lives of these assets range from 2 to 33 years. We reevaluate depreciation rates each time we redevelop our transportation rates when we file with the FERC for an increase or decrease in rates. When we retire property, plant and equipment, we charge accumulated depreciation and amortization for the original cost, plus the cost of retirement (the cost to remove, sell or dispose), less its salvage value. We do not recognize a gain or loss unless we sell an entire operating unit. We include gains or losses on dispositions of operating units in income. Additional acquisition cost assigned to utility plant represents the excess of allocated purchase costs over historical costs of these facilities. These costs are amortized on a straight-line basis using FERC approved rates, and we do not recover those excess costs in our rates. At December 31, 2001 and 2000, we had approximately $232 million and $243 million of construction work in progress included in our property, plant and equipment. Asset Impairments We evaluate our long-lived assets for impairment in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. If an adverse event or change in circumstances occurs, we estimate the future cash flows from the asset, grouped together at the lowest level for which separate cash flows can be measured, to determine if the asset is impaired. If the total of the undiscounted future cash flows is less than the carrying amount for the assets, we calculate the fair value of the 12 assets either through reference to sales data for similar assets, or by estimating the fair value using a discounted cash flow approach. These cash flow estimates require us to make estimates and assumptions for many years into the future for pricing, demand, competition, operating costs, legal, regulatory and other factors, and these assumptions can change either positively or negatively. On January 1, 2002, we adopted the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which will impact how we account for asset impairments and the accounting for discontinued operations in the future. Revenue Recognition We recognize revenues from natural gas transportation service and services other than transportation in the period when the service is provided. In the future, we will record reserves on revenues collected that may be subject to refund. Environmental Costs and Other Contingencies We expense or capitalize expenditures for ongoing compliance with environmental regulations that relate to past or current operations as appropriate. We expense amounts for clean up of existing environmental contamination caused by past operations which do not benefit future periods by preventing or eliminating future contamination. We record liabilities when our environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies' clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. These estimates are subject to revision in future periods based on actual costs or new circumstances and are included in our balance sheet in other current and long-term liabilities at their undiscounted amounts. We evaluate recoveries from insurance coverage, government sponsored and other programs separately from our liability and, when recovery is assured, we record and report an asset separately from the associated liability in our financial statements. We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against a reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount, or at least the minimum of the range of probable loss. Income Taxes We report current income taxes based on our taxable income along with a provision for deferred income taxes. Deferred income taxes reflect the estimated future tax consequences of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. El Paso maintains a tax sharing policy for companies included in its consolidated federal income tax return which provides, among other things, that (i) each company in a taxable income position will be currently charged with an amount equivalent to its federal income tax computed on a separate return basis, and (ii) each company in a tax loss position will be reimbursed currently to the extent its deductions, including general business credits, were utilized in the consolidated return. Under the policy, El Paso pays all federal income taxes directly to the IRS and bills or refunds its subsidiaries for their portion of these income tax payments. 13 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. 2. INCOME TAXES The following table reflects the components of income tax expense included in net income for each of the three years ended December 31:
2001 2000 1999 ---- ---- ---- (IN MILLIONS) Current Federal .................................................. $ 58 $ 79 $ 76 State..................................................... (23) (16) (16) ---- ---- ---- 35 63 60 ---- ---- ---- Deferred Federal .................................................. 25 7 17 State..................................................... 12 4 5 ---- ---- ---- 37 11 22 ---- ---- ---- Total income tax expense.......................... $ 72 $ 74 $ 82 ==== ==== ====
Our income tax expense included in net income differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31:
2001 2000 1999 ---- ---- ---- (IN MILLIONS) Income tax expense at the statutory federal rate of 35%..... $79 $83 $90 Decrease State income tax, net of federal income tax benefit....... (7) (8) (7) Other..................................................... -- (1) (1) --- --- --- Income tax expense.......................................... $72 $74 $82 === === === Effective tax rate.......................................... 32% 31% 32% === === ===
14 The following are the components of our net deferred tax liability as of December 31:
2001 2000 ------ ------ (IN MILLIONS) Deferred tax liabilities Property, plant and equipment............................. $1,397 $1,398 Other..................................................... 131 70 ------ ------ Total deferred tax liability...................... 1,528 1,468 ------ ------ Deferred tax assets U.S. net operating loss and tax credit carryovers......... 151 97 Accrual for regulatory issues............................. 56 61 Environmental liability................................... 68 64 Other liabilities......................................... 102 116 Valuation allowance....................................... (2) (2) ------ ------ Total deferred tax asset.......................... 375 336 ------ ------ Net deferred tax liability.................................. $1,153 $1,132 ====== ======
Under El Paso's tax sharing policy, we are allocated the tax benefit associated with our employees' exercise of non-qualified stock options and the vesting of restricted stock as well as restricted stock dividends. This allocation reduced taxes payable by $5 million in 2001 and $7 million in 2000. These benefits are included in additional paid-in capital in our balance sheet. As of December 31, 2001, we had $1 million of alternative minimum tax credit carryovers and $428 million of net operating loss carryovers. The alternative minimum tax credits carryover indefinitely. The carryover period for the net operating loss ends as follows: approximately $4 million in 2006; $94 million in 2011; $130 million in 2018; $75 million in 2019; $17 million in 2020; and $108 million in 2021. Usage of these carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations. We recorded a valuation allowance to reflect the estimated amount of deferred tax assets which we may not realize due to the expiration of net operating loss carryovers of an acquired company. 3. FINANCIAL INSTRUMENTS Fair Value of Financial Instruments As of December 31, 2001 and 2000, the carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables are representative of fair value because of the short-term maturity of these instruments. We estimated the fair value of debt with fixed interest rates based on quoted market prices for the same or similar issues. The carrying amounts and estimated fair values of our financial instruments are as follows at December 31:
2001 2000 --------------------- --------------------- CARRYING CARRYING AMOUNT FAIR VALUE AMOUNT FAIR VALUE -------- ---------- -------- ---------- (IN MILLIONS) Balance sheet financial instruments: Long-term debt, including current maturities....... $1,356 $1,283 $1,354 $1,322
15 4. DEBT AND OTHER CREDIT FACILITIES At December 31, 2001, our weighted average interest rate on our commercial paper was 3.2%, and it was 7.6% at December 31, 2000. We had the following short-term borrowings at December 31:
2001 2000 ---- ---- (IN MILLIONS) Commercial paper............................................ $424 $215 ==== ====
Our long-term debt outstanding consisted of the following at December 31:
2001 2000 ------ ------ (IN MILLIONS) 6.0% Debentures due 2011................................... $ 86 $ 86 7.5% Debentures due 2017................................... 300 300 7.0% Debentures due 2027................................... 300 300 7.0% Debentures due 2028................................... 400 400 7.625% Debentures due 2037................................. 300 300 ------ ------ 1,386 1,386 Less: Unamortized discount................................. 30 32 Current maturities................................... -- -- ------ ------ Total long-term debt, less current maturities.... $1,356 $1,354 ====== ======
None of our long-term debt matures within the next 5 years. We are eligible to borrow up to $1 billion under a commercial paper program. The program is used to manage our short-term cash requirements. As of December 31, 2001, El Paso has a $3 billion, 364-day revolving credit and competitive advance facility, which replaced its $2 billion renewable credit and competitive advance facility in June 2001, and a $1 billion, 3-year revolving credit and competitive advance facility. We are a designated borrower under these facilities and, as such, are liable for any amounts outstanding under these facilities. Our interest rate for these facilities varies and was LIBOR plus 50 basis points on December 31, 2001. No amounts were outstanding under these facilities as of December 31, 2001. As of March 2002, we have $200 million of capacity remaining under our shelf registration statement on file with the Securities and Exchange Commission. Other Financing Arrangements During 1999, our parent company formed Sabine Investors, L.L.C., a wholly owned limited liability company, and other separate legal entities, for the purpose of generating funds to invest in capital projects and other assets. The proceeds are collateralized by various assets of our parent, including our 50 percent ownership interest in Bear Creek. 5. 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 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, filed June 1997). In May 2001, the court denied the defendants' motions to dismiss. 16 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, we and our subsidiaries are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case, our exposure to the matter and 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 make the necessary accruals. As new information becomes available, our estimates may change. The impact of these changes may have a material effect on our results of operations. As of December 31, 2001, we had reserves totaling $14 million for all outstanding legal matters. 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 will have a material adverse effect on our financial position, operating results or cash flows. 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 December 31, 2001, we had a reserve of $92 million for expected remediation costs. In addition, we expect to make capital expenditures for environmental matters of approximately $67 million in the aggregate for the years 2002 through 2006. These expenditures primarily relate to compliance with clean air regulations. 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 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. 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 a 1994 consent order with the Environmental Protection Agency (EPA). Despite these remediation efforts, the agency may raise additional technical issues or require additional remediation work in the future. Since 1988, we have 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 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. In May 1995, following negotiations with our customers, we filed a stipulation and agreement with the FERC that established a mechanism for recovering a substantial portion of the environmental costs identified in our internal project. The stipulation and agreement was effective July 1, 1995. Refunds may be required to the extent actual eligible expenditures are less than amounts collected. We are a party in proceedings involving federal and state authorities regarding the past use of PCBs in our starting air systems. 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 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. We have been designated, 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 17 (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 December 31, 2001, we have estimated our share of the remediation costs at these sites to be between approximately $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 the determination of our estimated liabilities. We presently believe that based on our existing reserves, and information known to date, the impact of 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. Rates and Regulatory Matters 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 December 31, 2001, $60 million of the interruptible transportation surcharge has 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. Our current tariff structure was established through a settlement approved by the FERC in October 1996. This settlement included a rate design change that resulted in a larger portion of our transportation revenues being dependent on throughput. Following this settlement, one of our competitors filed an appeal arguing that our cost allocation methodology deters the development of market centers. On August 11, 2000, we and that competitor jointly filed a proposed settlement to resolve this issue. The settlement provided for a discount on the transportation rates for receipts at the interconnect shared by us and them. On October 17, 2000, an administrative law judge certified the settlement and submitted it to the FERC for approval. On February 8, 2001, the FERC issued an order approving the settlement. On April 11, 2001, the FERC issued an order granting our request for clarification on their February 8, 2001 order, and no requests for rehearing were filed on the clarification. 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 all our energy affiliates conduct business and interact with our interstate pipelines. In December 2001, we filed comments with the FERC addressing our concerns with the proposed rules. 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. 18 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. Capital Commitments and Purchase Obligations At December 31, 2001, we had capital and investment commitments of $11 million for 2002. Our other planned capital and investment projects are discretionary in nature, with no substantial capital commitments made in advance of the actual expenditures. We have entered into unconditional purchase obligations for products and services, including financing commitments with one of our joint ventures, totaling $157 million at December 31, 2001. Our annual obligations under these agreements are $28 million for 2002, $25 million for 2003, $27 million for 2004 and 2005, $20 million for 2006 and $30 million in total thereafter. 6. RETIREMENT BENEFITS Pension and Retirement Benefits El Paso maintains a pension plan to provide benefits determined under a cash balance formula covering substantially all of its U.S. employees, including our employees. El Paso also maintains a defined contribution plan covering its U.S. employees, including our employees. El Paso matches 75 percent of participant basic contributions of up to 6 percent, with the matching contributions made in El Paso common stock, which participants may diversify at any time. El Paso is responsible for benefits accrued under its plan and allocates the related costs to its affiliates. See Note 8 for a summary of transactions with affiliates. Other Postretirement Benefits Following El Paso's acquisition of us in 1996, we retained responsibility for postretirement medical and life insurance benefits for former employees of operations previously disposed of by our former parent, and for employees, including our employees, added as a result of the merger who were eligible to retire on December 31, 1996, and did so by July 1, 1997. Medical benefits for this closed group of retirees may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs. We have reserved the right to change these benefits. Employees who retired after July 1, 1997, will continue to receive limited postretirement life insurance benefits. Postretirement benefit plan costs are prefunded to the extent these costs are recoverable through rates. Effective February 1, 1992, we began recovering through our rates the other postretirement benefits (OPEB) costs included in the June 1993 rate case settlement. To the extent actual OPEB costs differ from the amounts funded, a regulatory asset or liability is recorded. The following table sets forth the change in benefit obligation, change in plan assets, reconciliation of funded status, and components of net periodic benefit cost for other postretirement benefits as of and for the twelve months ended September 30:
2001 2000 ----- ----- (IN MILLIONS) Change in benefit obligation Benefit obligation at beginning of period................. $ 27 $ 29 Interest cost............................................. 2 2 Participant contributions................................. 1 1 Actuarial loss............................................ 1 -- Benefits paid............................................. (5) (5) ---- ---- Benefit obligation at end of period....................... $ 26 $ 27 ==== ====
19
2001 2000 ----- ----- (IN MILLIONS) Change in plan assets Fair value of plan assets at beginning of period.......... $ 6 $ 6 Actual return on plan assets.............................. 2 -- Employer contributions.................................... 5 4 Participant contributions................................. 1 1 Benefits paid............................................. (5) (5) ---- ---- Fair value of plan assets at end of period................ $ 9 $ 6 ==== ==== Reconciliation of funded status Funded status at September 30,............................ $(17) $(21) Fourth quarter contributions and income................... 1 2 Unrecognized net actuarial gain........................... (5) (5) Unrecognized prior service cost........................... (1) (1) ---- ---- Accrued benefit cost at December 31,...................... $(22) $(25) ==== ====
The current liability portion of our postretirement benefits was $2 million as of December 31, 2001, 2000 and 1999. Net periodic benefit cost for our plans consisted of interest costs of $2 million, for each of the years ended December 31, 2001, 2000 and 1999. Our benefit obligations are based upon actuarial estimates as described below:
2001 2000 ----- ----- Weighted average assumptions Discount rate............................................. 7.25% 7.75% Expected return on plan assets............................ 7.50% 7.50%
Actuarial estimates for our postretirement benefits plans assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 9.5 percent in 2001, gradually decreasing to 6 percent by the year 2008. Assumed health care cost trends can have a significant effect on the amounts reported for other postretirement benefit plans. However, it does not affect our costs because our costs are limited by defined dollar caps. 7. SUPPLEMENTAL CASH FLOW INFORMATION The following table contains supplemental cash flow information for each of the three years ended December 31:
2001 2000 1999 ---- ---- ---- (IN MILLIONS) Interest paid............................................... $116 $128 $135 Income tax payments......................................... 81 62 2
8. INVESTMENTS IN AND TRANSACTIONS WITH AFFILIATES We hold investments in various affiliates which are accounted for on the equity method of accounting. Our principal equity method investment is a 50 percent ownership interest in Bear Creek. Our investment in Bear Creek as of December 31, 2001 was $116 million and as of December 31, 2000 was $101 million. We recognized equity earnings of $14 million in 2001 and $13 million in 2000. During 1999, our parent formed Sabine Investors, L.L.C., a wholly owned limited liability company, and other separate legal entities, for the purpose of generating funds for El Paso to invest in capital projects and other assets. The proceeds are collateralized by specific assets of El Paso, including our 50 percent investment in Bear Creek. In addition, we have a 30 percent ownership interest in Portland. As of December 31, 2001 and 2000, our investment in Portland was $39 million and $33 million. We recognized an equity loss of less than $1 million in 2001 and $2 million in 2000. 20 El Paso allocates a portion of its general and administrative expenses to us. The allocation is based on the estimated level of effort devoted to our operations and the relative size of our revenues, gross property and payroll. During 2001, we performed operational, financial, accounting and administrative services for El Paso's other pipeline systems. We recorded the amounts billed as a reduction of our operating expenses. We believe the allocation methods are reasonable. In addition, we enter into transactions with other El Paso subsidiaries in the ordinary course of our business to transport natural gas. Services provided to these affiliates are based on the same terms as non-affiliates. The following table shows revenues and charges from our affiliates for each of the three years ended December 31:
2001 2000 1999 ---- ---- ---- (IN MILLIONS) Revenues from affiliates.................................... $ 78 $68 $ 37 Charges from affiliates..................................... 76 87 150 Reimbursement for costs from affiliates..................... 38 -- --
We participate in El Paso's cash management program which matches short-term cash surpluses and needs of its participating affiliates, thus minimizing total borrowing from outside sources. We had advanced $153 million at December 31, 2001, at a market rate of interest which was 2.1%. At December 31, 2000, we had advanced $33 million at a market rate of interest which was 6.7%. In addition, we have a demand note receivable with El Paso of $28 million at December 31, 2001, at an interest rate of 2.73%. At December 31, 2000, the demand note receivable was $9 million at an interest rate of 7.26%. At December 31, 2001 and 2000, we had other accounts receivable from related parties of $15 million and $18 million. In addition, we had accounts payable to related parties of $30 million and $18 million at December 31, 2001 and 2000. These balances arose in the normal course of business. 9. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Financial information by quarter is summarized below:
OPERATING OPERATING NET QUARTER REVENUES INCOME INCOME ------- --------- --------- ------ (IN MILLIONS) 2001 1st................................................... $214 $112 $ 60 2nd................................................... 170 69 35 3rd................................................... 156 58 20 4th................................................... 188 75 39 ---- ---- ---- $728 $314 $154 ==== ==== ==== 2000 1st................................................... $196 $ 86 $ 46 2nd................................................... 185 79 40 3rd................................................... 179 82 40 4th................................................... 188 74 37 ---- ---- ---- $748 $321 $163 ==== ==== ====
21 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholder of Tennessee Gas Pipeline Company: In our opinion, the consolidated financial statements listed in the Index appearing under Item 14(a)(1) present fairly, in all material respects, the financial position of Tennessee Gas Pipeline Company and its subsidiaries at December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 14(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP Houston, Texas March 6, 2002 22 SCHEDULE II TENNESSEE GAS PIPELINE COMPANY VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (IN MILLIONS)
BALANCE AT CHARGED TO CHARGED TO BALANCE BEGINNING COSTS AND OTHER AT END DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD ----------- ---------- ---------- ---------- ---------- --------- 2001 Allowance for doubtful accounts....... $ 4 $ 2 $ -- $ -- $ 6 Valuation allowance on deferred tax assets............................. 2 -- -- -- 2 Legal reserves........................ 17 (3) -- -- 14 Environmental reserves................ 99 -- -- (7) 92 Regulatory reserves................... 33 (12)(1) (11)(1) -- 10 2000 Allowance for doubtful accounts....... $ 5 $ 6 $ (4) $ (3)(2) $ 4 Valuation allowance on deferred tax assets............................. 4 -- -- (2) 2 Legal reserves........................ 17 -- -- -- 17 Environmental reserves................ 107 -- -- (8) 99 Regulatory reserves................... 38 (5) -- -- 33 1999 Allowance for doubtful accounts....... $ 11 $ (2) $ (2) $ (2)(2) $ 5 Valuation allowance on deferred tax assets............................. 4 -- -- -- 4 Legal reserves........................ 30 (9) (4) -- 17 Environmental reserves................ 114 -- 4 (11) 107 Regulatory reserves................... 113 (75)(3) -- -- 38
--------------- (1) Upon favorable resolution of issues related to natural gas purchase contracts, we reversed the regulatory reserve to revenue and the regulatory asset account. (2) Primarily accounts written off. (3) Primarily represents favorable resolution of various regulatory issues. 23 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III Item 10, "Directors and Executive Officers of the Registrant;" Item 11, "Executive Compensation;" Item 12, "Security Ownership of Management;" and Item 13, "Certain Relationships and Related Transactions;" have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT: 1. Financial statements. The following consolidated financial statements are included in Part II, Item 8 of this report:
PAGE ---- Consolidated Statements of Income...................... 7 Consolidated Balance Sheets............................ 8 Consolidated Statements of Cash Flows.................. 9 Consolidated Statements of Stockholder's Equity........ 10 Notes to Consolidated Financial Statements............. 11 Report of Independent Accountants...................... 22 2. Financial statement schedules and supplementary information required to be submitted. Schedule II -- Valuation and Qualifying Accounts....... 23 All other schedules are omitted because they are not applicable, or the required information is shown in the Consolidated Financial Statements or accompanying Notes. 3. Exhibit list............................................ 25
(b) REPORTS ON FORM 8-K: None. 24 TENNESSEE GAS PIPELINE COMPANY EXHIBIT LIST DECEMBER 31, 2001 Exhibits not incorporated by reference to a prior filing are designated by an asterisk; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.A -- Restated Certificate of Incorporation dated May 11, 1999 (Exhibit 3.A to our 1999 Second Quarter Form 10-Q). 3.B -- By-laws dated March 1, 1998 (Exhibit 3.B to our 1999 First Quarter Form 10-Q). 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). 10.A -- $3,000,000,000 364-day Revolving Credit and Competitive Advance Facility Agreement dated as of June 11, 2001, by and among El Paso, El Paso Natural Gas Company (EPNG), TGP, the several banks and other financial institutions from time to time parties to the Agreement, The Chase Manhattan Bank, ABN Amro Bank, N.V., and Citibank N.A., as co-documentation agents for the Lenders, and Bank of America, N.A. and Credit Suisse First Boston, as co-syndication agents for the Lenders (Exhibit 10.A to our 2001 Second Quarter Form 10-Q). 10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive Advance Facility Agreement dated as of August 4, 2000, by and among El Paso, EPNG, TGP, the several banks and other financial institutions from time to time parties to the Agreement, The Chase Manhattan Bank, Citibank N.A. and ABN Amro Bank, N.V. as co-documentation agents for the Lenders and Bank of America, N.A. as syndication agent for the Lenders (Exhibit 10.B to our 2000 Third Quarter Form 10-Q). 21 -- Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K. *23 -- Consent of Independent Accountants.
UNDERTAKING We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and our consolidated subsidiaries 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. 25 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, Tennessee Gas Pipeline Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 25th day of March, 2002. TENNESSEE GAS PIPELINE COMPANY Registrant By: /s/ JOHN W. SOMERHALDER II ---------------------------------- John W. Somerhalder II Chairman of the Board Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of Tennessee Gas Pipeline Company and in the capacities and on the dates indicated:
SIGNATURE TITLE DATE --------- ----- ---- /s/ JOHN W. SOMERHALDER II Chairman of the Board and March 25, 2002 ----------------------------------------------------- Director (Principal (John W. Somerhalder II) Executive Officer) /s/ EDWARD J. HOLM Chief Executive Officer and March 25, 2002 ----------------------------------------------------- Director (Edward J. Holm) /s/ STEPHEN C. BEASLEY President and Director March 25, 2002 ----------------------------------------------------- (Stephen C. Beasley) /s/ GREG G. GRUBER Senior Vice President, Chief March 25, 2002 ----------------------------------------------------- Financial Officer and (Greg G. Gruber) Treasurer (Principal Financial and Accounting Officer)
26 EXHIBIT INDEX Exhibits not incorporated by reference to a prior filing are designated by an asterisk, all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.A -- Restated Certificate of Incorporation dated May 11, 1999 (Exhibit 3.A to our 1999 Second Quarter Form 10-Q). 3.B -- By-laws dated March 1, 1998 (Exhibit 3.B to our 1999 First Quarter Form 10-Q). 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). 10.A -- $3,000,000,000 364-day Revolving Credit and Competitive Advance Facility Agreement dated as of June 11, 2001, by and among El Paso, El Paso Natural Gas Company (EPNG), TGP, the several banks and other financial institutions from time to time parties to the Agreement, The Chase Manhattan Bank, ABN Amro Bank, N.V., and Citibank N.A., as co-documentation agents for the Lenders, and Bank of America, N.A. and Credit Suisse First Boston, as co-syndication agents for the Lenders (Exhibit 10.A to our 2001 Second Quarter Form 10-Q). 10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive Advance Facility Agreement dated as of August 4, 2000, by and among El Paso, EPNG, TGP, the several banks and other financial institutions from time to time parties to the Agreement, The Chase Manhattan Bank, Citibank N.A. and ABN Amro Bank, N.V. as co-documentation agents for the Lenders and Bank of America, N.A. as syndication agent for the Lenders (Exhibit 10.B to our 2000 Third Quarter Form 10-Q). 21 -- Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K. *23 -- Consent of Independent Accountants.