-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KSWvDL9Rxh13HqVT5Yd0zTQ0rbQQYLBPM3pWxWX540NrBK10v0m4m19XKExDGV/1 cgzFUo8Y80uO8QbhBnufXQ== 0001014108-02-000143.txt : 20021114 0001014108-02-000143.hdr.sgml : 20021114 20021113200612 ACCESSION NUMBER: 0001014108-02-000143 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20020930 FILED AS OF DATE: 20021114 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KINDER MORGAN ENERGY PARTNERS L P CENTRAL INDEX KEY: 0000888228 STANDARD INDUSTRIAL CLASSIFICATION: PIPE LINES (NO NATURAL GAS) [4610] IRS NUMBER: 760380342 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-11234 FILM NUMBER: 02821636 BUSINESS ADDRESS: STREET 1: 370 VAN GORDON STREET CITY: LAKEWOOD STATE: CO ZIP: 80228 BUSINESS PHONE: 3039144752 MAIL ADDRESS: STREET 1: 370 VAN GORDON STREET STREET 2: 2600 GRAND AVENUE CITY: LAKEWOOD STATE: CO ZIP: 80228-8304 FORMER COMPANY: FORMER CONFORMED NAME: ENRON LIQUIDS PIPELINE L P DATE OF NAME CHANGE: 19970304 10-Q 1 km-form10q_488265.txt FORM 10-Q F O R M 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 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: 1-11234 KINDER MORGAN ENERGY PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 76-0380342 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 500 Dallas Street, Suite 1000, Houston, Texas 77002 (Address of principal executive offices)(zip code) Registrant's telephone number, including area code: 713-369-9000 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 The Registrant had 129,940,018 common units outstanding at November 1, 2002. KINDER MORGAN ENERGY PARTNERS, L.P. TABLE OF CONTENTS Page Number PART I. FINANCIAL INFORMATION Item 1: Financial Statements (Unaudited).................................. Consolidated Statements of Income-Three and Nine Months Ended September 30, 2002 and 2001................................... 3 Consolidated Balance Sheets-September 30, 2002 and December 31, 2001............................................. 4 Consolidated Statements of Cash Flows-Nine Months Ended September 30, 2002 and 2001................................... 5 Notes to Consolidated Financial Statements...................... 6 Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations......................................... Results of Operations........................................... 34 Financial Condition............................................. 40 Information Regarding Forward-Looking Statements................ 43 Item 3: Quantitative and Qualitative Disclosures About Market Risk........ 44 Item 4: Controls and Procedures........................................... 44 PART II. OTHER INFORMATION Item 1: Legal Proceedings................................................. 45 Item 2: Changes in Securities and Use of Proceeds......................... 45 Item 3: Defaults Upon Senior Securities................................... 45 Item 4: Submission of Matters to a Vote of Security Holders............... 45 Item 5: Other Information................................................. 45 Item 6: Exhibits and Reports on Form 8-K.................................. 46 Signatures........................................................ 48 Certifications.................................................... 49 2 PART I. FINANCIAL INFORMATION Item 1. Financial Statements. KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Thousands Except Per Unit Amounts) (Unaudited)
Three Months Ended Sept. 30, Nine Months Ended Sept. 30, 2002 2001 2002 2001 ------------ --------------- ----------- -------------- Revenues Natural gas sales $ 740,377 $ 308,784 $1,926,180 $1,356,092 Services 357,111 263,383 926,365 752,545 Product sales and other 23,832 66,377 162,776 294,307 ---------- ---------- --------- --------- 1,121,320 638,544 3,015,321 2,402,944 ---------- ---------- --------- --------- Costs and Expenses Gas purchases and other costs of sales 729,773 319,887 1,890,342 1,447,939 Operations and maintenance 92,644 80,768 278,399 266,947 Fuel and power 24,932 21,367 64,463 52,828 Depreciation and amortization 42,546 36,701 126,495 102,724 General and administrative 27,476 24,801 87,218 76,436 Taxes, other than income taxes 14,546 10,128 40,798 34,231 ---------- ---------- --------- --------- 931,917 493,652 2,487,715 1,981,105 ---------- ---------- --------- --------- Operating Income 189,403 144,892 527,606 421,839 Other Income (Expense) Earnings from equity investments 22,818 20,899 70,386 63,249 Amortization of excess cost of equity (1,394) (2,253) (4,182) (6,759) investments Interest, net (46,350) (40,985) (129,236) (136,067) Other, net 232 147 617 (256) Minority Interest (2,410) (2,350) (7,458) (7,985) ---------- ---------- --------- --------- Income Before Income Taxes 162,299 120,350 457,733 334,021 Income Taxes (4,119) (4,558) (13,603) (12,336) ---------- ---------- --------- --------- Net Income $ 158,180 $ 115,792 $ 444,130 321,685 ========== ========== ========== ========= General Partner's interest in Net Income $ 70,380 $ 54,824 $ 197,408 $ 147,052 Limited Partners' interest in Net Income 87,800 60,968 246,722 174,633 ---------- ---------- ---------- --------- Net Income $ 158,180 $115,792 $ 444,130 $ 321,685 ========== ======== ========== ========= Basic and Diluted Limited Partners' Net $ 0.50 $ 0.37 $ 1.46 $ 1.16 ========== ======== ========== ========= Income per Unit Weighted Average Number of Units used in Computation of Limited Partners' Net Income per Unit Basic 174,781 165,064 169,171 149,971 ========== ======== ========== ========= Diluted 174,932 165,277 169,345 150,177 ========== ======== ========== =========
The accompanying notes are an integral part of these consolidated financial statements. 3 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Thousands) (Unaudited) September 30, December 31, 2002 2001 ---------- ---------- ASSETS Current Assets Cash and cash equivalents $ 62,380 $ 62,802 Accounts and notes receivable Trade 431,848 215,860 Related parties 38,172 52,607 Inventories Products 3,576 2,197 Materials and supplies 7,086 6,212 Gas imbalances 33,358 15,265 Gas in underground storage 11,758 18,214 Other current assets 62,691 194,886 ---------- ---------- 650,869 568,043 ---------- ---------- Property, Plant and Equipment, net 6,098,444 5,082,612 Investments 452,774 440,518 Notes receivable 3,029 3,095 Intangibles, net 659,293 563,397 Deferred charges and other assets 241,176 75,001 ---------- ---------- TOTAL ASSETS $8,105,585 $6,732,666 ========== ========== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Trade $ 316,428 $ 111,853 Related parties 262 9,235 Current portion of long-term debt -- 560,219 Accrued interest 22,683 34,099 Deferred revenues 1,045 2,786 Gas imbalances 43,335 34,660 Accrued other current liabilities 209,640 209,852 ---------- ---------- 593,393 962,704 ---------- ---------- Long-Term Liabilities and Deferred Credits Long-term debt, outstanding 3,611,061 2,237,015 Market value of interest rate swaps 157,545 (5,441) Deferred revenues 29,837 29,110 Deferred income taxes 38,544 38,544 Other long-term liabilities and deferred credits 226,452 246,464 ---------- ---------- 4,063,439 2,545,692 ---------- ---------- Commitments and Contingencies Minority Interest 41,927 65,236 ---------- ---------- Partners' Capital Common Units 1,848,019 1,894,677 Class B Units 127,186 125,750 i-Units 1,405,424 1,020,153 General Partner 69,293 54,628 Accumulated other comprehensive income (loss) (43,096) 63,826 ---------- ---------- 3,406,826 3,159,034 ---------- ---------- TOTAL LIABILITIES AND PARTNERS' CAPITAL $8,105,58 $6,732,666 ========= ========== The accompanying notes are an integral part of these consolidated financial statements. 4 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands) (Unaudited) Nine Months Ended Sept. 30, --------------------------- 2002 2001 ---------- ---------- Cash Flows From Operating Activities Net income $ 444,130 $ 321,685 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 126,495 102,724 Amortization of excess cost of equity investments 4,182 6,759 Earnings from equity investments (70,386) (63,249) Distributions from equity investments 58,920 50,837 Changes in components of working capital (2,521) (59,768) Other, net (14,551) 45,445 ---------- ---------- Net Cash Provided by Operating Activities 546,269 404,433 ---------- ---------- Cash Flows From Investing Activities Acquisitions of assets (864,311) (1,453,174) Additions to property, plant and equipment for expansion and maintenance projects (342,562) (178,799) Sale of property, plant and equipment, net of removal costs 1,710 8,193 Contributions to equity investments (14,481) (2,658) Other 1,289 (6,442) ---------- ---------- Net Cash Used in Investing Activities (1,218,355) (1,632,880) ---------- ---------- Cash Flows From Financing Activities Issuance of debt 3,205,414 3,736,734 Payment of debt (2,432,731) (3,128,186) Loans to related party -- (17,100) Debt issue costs (14,180) (7,384) Proceeds from issuance of common units 1,464 925 Proceeds from issuance of i-units 331,159 996,869 Contributions from General Partner 3,353 11,716 Distributions to partners: Common units (227,327) (197,254) Class B units (9,298) (5,579) General Partner (182,742) (126,068) Minority interest (7,365) (12,283) Other, net 3,917 1,070 ---------- ---------- Net Cash Provided by Financing Activities 671,664 1,253,460 ---------- ---------- Increase (Decrease) in Cash and Cash Equivalents (422) 25,013 Cash and Cash Equivalents, beginning of period 62,802 59,319 ---------- ---------- Cash and Cash Equivalents, end of period $ 62,380 $ 84,332 ========== ========== Noncash Investing and Financing Activities: Assets acquired by the assumption of liabilities $ 153,430 $ 257,304 The accompanying notes are an integral part of these consolidated financial statements. 5 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. Organization General Unless the context requires otherwise, references to "we", "us", "our" or the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. We have prepared the accompanying unaudited consolidated financial statements under the rules and regulations of the Securities and Exchange Commission. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America. We believe, however, that our disclosures are adequate to make the information presented not misleading. The consolidated financial statements reflect all adjustments that are, in the opinion of our management, necessary for a fair presentation of our financial results for the interim periods. You should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2001. Basis of Presentation Our consolidated financial statements include our accounts and those of our majority-owned and controlled subsidiaries and our operating partnerships. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior periods have been reclassified to conform to the current presentation. Net Income Per Unit We compute Basic Limited Partners' Net Income per Unit by dividing our limited partners' interest in net income by the weighted average number of units outstanding during the period. Diluted Limited Partners' Net Income per Unit reflects the potential dilution, by application of the treasury stock method, that could occur if options to issue units were exercised, which would result in the issuance of additional units that would then share in our net income. 2. Acquisitions and Joint Ventures During the first nine months of 2002, we completed the following acquisitions. Each of the acquisitions was accounted for under the purchase method and the assets acquired and liabilities assumed were recorded at their estimated fair market values as of the acquisition date. The preliminary amounts assigned to assets and liabilities may be adjusted during a short period of time following the acquisition. The results of operations from these acquisitions are included in the consolidated financial statements from the effective date of acquisition. Cochin Pipeline In January 2002, we purchased an additional 10% ownership interest in the Cochin Pipeline System from NOVA Chemicals Corporation for approximately $29 million in cash. We now own approximately 44.8% of the Cochin Pipeline System. The transaction was effective December 31, 2001, and we allocated the purchase price to property, plant and equipment in January 2002. We record our proportional share of joint venture revenues and expenses and cost of joint venture assets with respect to the Cochin Pipeline System as part of our Products Pipelines business segment. Laser Materials Services LLC Effective January 1, 2002, we acquired all of the equity interests of Laser Materials Services LLC for approximately $8.9 million and the assumption of approximately $3.3 million of liabilities, including long-term debt of $0.4 million. Laser Materials Services LLC operates 59 transload facilities in 18 states. The facilities handle dry-bulk products, including aggregates, plastics and liquid chemicals. The acquisition of Laser Materials Services LLC expanded our growing terminal operations and is part of our Terminals business segment. 6 Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs $ 8,916 Debt assumed 357 Liabilities assumed 2,967 ------ Total purchase price $12,240 ======= Allocation of purchase price: Current assets $ 879 Property, plant and equipment 11,361 ------- $12,240 ======= International Marine Terminals Effective January 1, 2002, we acquired a 33 1/3% interest in International Marine Terminals from Marine Terminals Incorporated. Effective February 1, 2002, we acquired an additional 33 1/3% interest in IMT from Glenn Springs Holdings, Inc. Our combined purchase price was approximately $40.5 million, including the assumption of $40 million of long-term debt. IMT is a partnership that operates a bulk terminal site in Port Sulphur, Louisiana. The Port Sulphur terminal is a multi-purpose import and export facility, which handles approximately 7 million tons annually of bulk products including coal, petroleum coke and iron ore. The acquisition complements our existing bulk terminal assets. IMT is part of our Terminals business segment. Our purchase price and our allocation to assets acquired, liabilities assumed and minority interest was as follows (in thousands): Purchase price: Cash received, net of transaction costs $(3,781) Debt assumed 40,000 Liabilities assumed 4,249 ------- Total purchase price: $40,468 ======= Allocation of purchase price: Current assets $ 6,600 Property, plant and equipment 31,781 Deferred charges and other assets 139 Minority interest 1,948 ------- $40,468 ======= Kinder Morgan Tejas Effective January 31, 2002, we acquired all of the equity interests of Tejas Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc., for approximately $832.6 million, including the assumption of approximately $103.8 million of liabilities. Tejas Gas, LLC consists primarily of a 3,400-mile natural gas intrastate pipeline system that extends from south Texas along the Mexico border and the Texas Gulf Coast to near the Louisiana border and north from near Houston to east Texas. The acquisition expands our natural gas operations within the State of Texas. The acquired assets are referred to as Kinder Morgan Tejas in this report and are included in our Natural Gas Pipelines business segment. The allocation of our purchase price to the assets and liabilities of Kinder Morgan Tejas is preliminary, pending final purchase price adjustments. It was based on an independent appraisal of fair market values as follows (in thousands): Purchase price: Cash paid, including transaction costs $ 728,768 Liabilities assumed 103,787 --------- Total purchase price $ 832,555 ========= Allocation of purchase price: Current assets $ 72,610 Property, plant and equipmemt, incl. cushion gas 689,052 Goodwill 70,893 --------- $ 832,555 ========= The $70.9 million of goodwill was assigned to our Natural Gas Pipelines business segment and the entire amount is expected to be deductible for tax purposes. 7 Milwaukee Bagging Operations Effective May 1, 2002, we purchased a bagging operation facility adjacent to our Milwaukee, Wisconsin dry-bulk terminal for $8.5 million. The purchase enhances the operations at our Milwaukee terminal, which is capable of handling up to 150,000 tons per year of fertilizer and salt for de-icing and livestock purposes. The Milwaukee bagging operations are included in our Terminals business segment. Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs $8,500 ------ Total purchase price $8,500 ====== Allocation of purchase price: Current assets $ 40 Property, plant and equipment 3,140 Goodwill 5,320 ------ $8,500 ====== The $5.3 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. Trailblazer Pipeline Company On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68 million in cash. We now own 100% of Trailblazer Pipeline Company. During the first quarter of 2002, we paid $12.0 million to CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, in exchange for CIG's relinquishment of its rights to become a 7% to 8% equity owner in Trailblazer Pipeline Company in mid-2002. Our purchase price and our allocation to assets acquired, liabilities assumed and minority interest was as follows (in thousands): Purchase price: Cash paid, including transaction costs $80,125 ------- Total purchase price $80,125 ======= Allocation of purchase price: Property, plant and equipmemt $41,409 Goodwill 15,000 Minority interest 23,716 ------- $80,125 ======= The $15.0 million of goodwill was assigned to our Natural Gas Pipelines business segment and the entire amount is expected to be deductible for tax purposes. Owensboro Gateway Terminal Effective September 1, 2002, we acquired the Lanham River Terminal near Owensboro, Kentucky and related equipment for $7.7 million. As of September 30, 2002, we have paid approximately $7.2 million and established a $0.5 million liability for final purchase price settlements. The facility is one of the nation's largest storage and handling points for bulk aluminum. The terminal also handles a variety of other bulk products, including petroleum coke, lime and de-icing salt. The terminal is situated on a 92-acre site along the Ohio River, and the purchase expands our presence along the river, complementing our existing facilities located near Cincinnati, Ohio and Moundsville, West Virginia. The acquired terminal will be referred to as the Owensboro Gateway Terminal and is included in our Terminals business segment. 8 Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs $7,140 Purchase price reserve 500 Liabilities assumed 11 ------ Total purchase price $7,651 ====== Allocation of purchase price: Current assets $ 42 Property, plant and equipment 4,265 Intangibles-agreements 54 Goodwill 3,290 ------ $7,651 ====== The $3.3 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. Pro Forma Information The following summarized unaudited Pro Forma Consolidated Income Statement information for the nine months ended September 30, 2002 and 2001, assumes all of the acquisitions we have made since January 1, 2001, including the ones listed above, had occurred as of January 1, 2001. We have prepared these unaudited Pro Forma financial results for comparative purposes only. These unaudited Pro Forma financial results may not be indicative of the results that would have occurred if we had completed these acquisitions as of January 1, 2001 or the results that will be attained in the future. Amounts presented below are in thousands, except for the per unit amounts: Pro Forma Nine Months Ended September 30, 2002 2001 ---- ---- (Unaudited) Revenues $3,257,969 $4,743,371 Operating Income 532,872 472,546 Net Income 452,641 389,660 Basic and diluted Limited Partners' Net Income per unit $ 1.45 $ 1.05 Subsequent Event On October 10, 2002, we announced that we had completed the acquisition of the former ICOM marine terminal in St. Gabriel, Louisiana from the Canadian National Railroad for approximately $17.6 million. The acquisition was made effective September 1, 2002. The facility features 400,000 barrels of liquids storage capacity and a related pipeline network that serves one of the fastest growing petrochemical production areas in the country. The acquisition further expands our terminal businesses along the Mississippi River. The acquired terminal will be referred to as the Kinder Morgan St. Gabriel terminal and will be included in our Terminals business segment. 3. Litigation and Other Contingencies Federal Energy Regulatory Commission Proceedings SFPP, L.P. SFPP, L.P. is the subsidiary limited partnership that owns our Pacific operations, excluding CALNEV pipeline and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at the Federal Energy Regulatory Commission involving shippers' complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services, on our Pacific operations' pipeline systems. Generally, the interstate rates on our Pacific operations' pipeline systems are "grandfathered" under the Energy Policy Act of 1992 unless "substantially changed circumstances" are found to exist. To the extent "substantially changed circumstances" are found to exist, our Pacific operations may be subject to substantial exposure under these FERC complaints. We currently believe that these FERC complaints seek approximately $197 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $45 million. However, even if "substantially changed circumstances" are found to exist, we believe that the resolution of these FERC complaints will be for amounts substantially less than the amount sought. OR92-8, et al. proceedings. In September 1992, El Paso Refinery, L.P. filed a protest/complaint with the FERC: o challenging SFPP's East Line rates from El Paso, Texas to Tucson and Phoenix, Arizona; 9 o challenging SFPP's proration policy; and o seeking to block the reversal of the direction of flow of SFPP's six-inch pipeline between Phoenix and Tucson. At various subsequent dates, the following other shippers on SFPP's South System filed separate complaints, and/or motions to intervene in the FERC proceeding, challenging SFPP's rates on its East and/or West Lines: o Chevron U.S.A. Products Company; o Navajo Refining Company; o ARCO Products Company; o Texaco Refining and Marketing Inc.; o Refinery Holding Company, L.P. (a partnership formed by El Paso Refinery's long-term secured creditors that purchased its refinery in May 1993); o Mobil Oil Corporation; and o Tosco Corporation. Certain of these parties also claimed that a gathering enhancement fee at SFPP's Watson Station in Carson, California was charged in violation of the Interstate Commerce Act. The FERC consolidated these challenges in Docket Nos. OR92-8-000, et al., and ruled that they are complaint proceedings, with the burden of proof on the complaining parties. These parties must show that SFPP's rates and practices at issue violate the requirements of the Interstate Commerce Act. A FERC administrative law judge held hearings in 1996, and issued an initial decision on September 25, 1997. The initial decision agreed with SFPP's position that "changed circumstances" had not been shown to exist on the West Line, and therefore held that all West Line rates that were "grandfathered" under the Energy Policy Act of 1992 were deemed to be just and reasonable and were not subject to challenge, either for the past or prospectively, in the Docket No. OR92-8 et al. proceedings. SFPP's Tariff No. 18 for movement of jet fuel from Los Angeles to Tucson, which was initiated subsequent to the enactment of the Energy Policy Act, was specifically excepted from that ruling. The initial decision also included rulings generally adverse to SFPP on such cost of service issues as: o the capital structure to be used in computing SFPP's 1985 starting rate base; o the level of income tax allowance; and o the recovery of civil and regulatory litigation expenses and certain pipeline reconditioning costs. The administrative law judge also ruled that SFPP's gathering enhancement service at Watson Station was subject to FERC jurisdiction and ordered SFPP to file a tariff for that service, with supporting cost of service documentation. SFPP and other parties asked the Commission to modify various rulings made in the initial decision. On January 13, 1999, the FERC issued its Opinion No. 435, which affirmed certain of those rulings and reversed or modified others. With respect to SFPP's West Line, the FERC affirmed that all but one of the West Line rates are "grandfathered" as just and reasonable and that "changed circumstances" had not been shown to satisfy the complainants' threshold burden necessary to challenge those rates. The FERC further held that the rate stated in Tariff No. 18 did not require rate reduction. Accordingly, the FERC dismissed all complaints against the West Line rates without any requirement that SFPP reduce, or pay any reparations for, any West Line rate. With respect to the East Line rates, Opinion No. 435 made several changes in the initial decision's methodology for calculating the rate base. It held that the June 1985 capital structure of SFPP's parent company at that time, rather than SFPP's 1988 partnership capital structure, should be used to calculate the starting rate base and modified the accumulated deferred income tax and allowable cost of equity used to calculate the rate base. It also ruled that SFPP would not owe reparations to any complainant for any period prior to the date on which that complainant's complaint was filed, thus reducing by two years the potential reparations period claimed by most complainants. SFPP and certain complainants sought rehearing of Opinion No. 435 by the FERC. In addition, ARCO, RHC, Navajo, Chevron and SFPP filed petitions for review of Opinion No. 435 with the U.S. Court of Appeals for the District of Columbia Circuit, all of which were either dismissed as premature or held in abeyance pending FERC 10 action on the rehearing requests. On March 15, 1999, as required by the FERC's order, SFPP submitted a compliance filing implementing the rulings made in Opinion No. 435, establishing the level of rates to be charged by SFPP in the future, and setting forth the amount of reparations that would be owed by SFPP to the complainants under the order. The complainants contested SFPP's compliance filing. On May 17, 2000, the FERC issued its Opinion No. 435-A, which modified Opinion No. 435 in certain respects. It denied requests to reverse its rulings that SFPP's West Line rates and Watson Station gathering enhancement facilities fee are entitled to be treated as "grandfathered" rates under the Energy Policy Act. It suggested, however, that if SFPP had fully recovered the capital costs of the gathering enhancement facilities, that might form the basis of an amended "changed circumstances" complaint. Opinion No. 435-A granted a request by Chevron and Navajo to require that SFPP's December 1988 partnership capital structure be used to compute the starting rate base from December 1983 forward, as well as a request by SFPP to vacate a ruling that would have required the elimination of approximately $125 million from the rate base used to determine capital structure. It also granted two clarifications sought by Navajo, to the effect that SFPP's return on its starting rate base should be based on SFPP's capital structure in each given year (rather than a single capital structure from the outset) and that the return on deferred equity should also vary with the capital structure for each year. Opinion No. 435-A denied the request of Chevron and Navajo that no income tax allowance be recognized for the limited partnership interests held by SFPP's corporate parent, as well as SFPP's request that the tax allowance should include interests owned by certain non-corporate entities. However, it granted Navajo's request to make the computation of interest expense for tax allowance purposes the same as for debt return. Opinion No. 435-A reaffirmed that SFPP may recover certain litigation costs incurred in defense of its rates (amortized over five years), but reversed a ruling that those expenses may include the costs of certain civil litigation with Navajo and El Paso. It also reversed a prior decision that litigation costs should be allocated between the East and West Lines based on throughput, and instead adopted SFPP's position that such expenses should be split equally between the two systems. As to reparations, Opinion No. 435-A held that no reparations would be awarded to West Line shippers and that only Navajo was eligible to recover reparations on the East Line. It reaffirmed that a 1989 settlement with SFPP barred Navajo from obtaining reparations prior to November 23, 1993, but allowed Navajo reparations for a one-month period prior to the filing of its December 23, 1993 complaint. Opinion No. 435-A also confirmed that FERC's indexing methodology should be used in determining rates for reparations purposes and made certain clarifications sought by Navajo. Opinion No. 435-A denied Chevron's request for modification of SFPP's prorationing policy. That policy required customers to demonstrate a need for additional capacity if a shortage of available pipeline space existed. SFPP's prorationing policy has since been changed to eliminate the "demonstrated need" test. Finally, Opinion No. 435-A directed SFPP to revise its initial compliance filings to reflect the modified rulings. It eliminated the refund obligation for the compliance tariff containing the Watson Station gathering enhancement fee, but required SFPP to pay refunds to the extent that the initial compliance tariff East Line rates exceeded the rates produced under Opinion No. 435-A. In June 2000, several parties filed requests for rehearing of rulings made in Opinion No. 435-A. Chevron and RHC both sought reconsideration of the FERC's ruling that only Navajo is entitled to reparations for East Line shipments. SFPP sought rehearing of the FERC's: o decision to require use of the December 1988 partnership capital structure for the period 1984-88 in computing the starting rate base; o elimination of civil litigation costs; o refusal to allow any recovery of civil litigation settlement payments; and o failure to provide any allowance for regulatory expenses in prospective rates. On July 17, 2000, SFPP submitted a compliance filing implementing the rulings made in Opinion No. 435-A, together with a calculation of reparations due to Navajo and refunds due to other East Line shippers. SFPP also filed a tariff stating revised East Line rates based on those rulings. 11 ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of Opinion No. 435-A in the U.S. Court of Appeals for the District of Columbia Circuit. All of those petitions except Chevron's were either dismissed as premature or held in abeyance pending action on the rehearing requests. On September 19, 2000, the court dismissed Chevron's petition for lack of prosecution, and subsequently denied a motion by Chevron for reconsideration of that dismissal. On September 13, 2001, the FERC issued Opinion No. 435-B, which ruled on requests for rehearing and comments on SFPP's compliance filing. Based on those rulings, the FERC directed SFPP to submit a further revised compliance filing, including revised tariffs and revised estimates of reparations and refunds. Opinion No. 435-B denied SFPP's requests for rehearing, which involved the capital structure to be used in computing starting rate base, SFPP's ability to recover litigation and settlement costs incurred in connection with the Navajo and El Paso civil litigation, and the provision for regulatory costs in prospective rates. However, it modified the Commission's prior rulings on several other issues. It reversed the ruling that only Navajo is eligible to seek reparations, holding that Chevron, RHC, Tosco and Mobil are also eligible to recover reparations for East Line shipments. It ruled, however, that Ultramar is not eligible for reparations in the Docket No. OR92-8 et al. proceedings . The FERC also changed prior rulings that had permitted SFPP to use certain litigation, environmental and pipeline rehabilitation costs that were not recovered through the prescribed rates to offset overearnings (and potential reparations) and to recover any such costs that remained by means of a surcharge to shippers. Opinion No. 435-B required SFPP to pay reparations to each complainant without any offset for unrecovered costs. It required SFPP to subtract from the total 1995-1998 supplemental costs allowed under Opinion No. 435-A any overearnings not paid out as reparations, and allowed SFPP to recover any remaining costs from shippers by means of a five-year surcharge beginning August 1, 2000. Opinion No. 435-B also ruled that SFPP would only be permitted to recover certain regulatory litigation costs through the surcharge, and that the surcharge could not include environmental or pipeline rehabilitation costs. Opinion No. 435-B directed SFPP to make additional changes in its revised compliance filing, including: o using a remaining useful life of 16.8 years in amortizing its starting rate base, instead of 20.6 years; o removing the starting rate base component from base rates as of August 1, 2001; o amortizing the accumulated deferred income tax balance beginning in 1992, rather than 1988; o listing the corporate unitholders that were the basis for the income tax allowance in its compliance filing and certifying that those companies are not Subchapter S corporations; and o "clearly" excluding civil litigation costs and explaining how it limited litigation costs to FERC-related expenses and assigned them to appropriate periods in making reparations calculations. On October 15, 2001, Chevron and RHC filed petitions for rehearing of Opinion No. 435-B. Chevron asked the FERC to clarify: o the period for which Chevron is entitled to reparations; and o whether East Line shippers that have received the benefit of Commission-prescribed rates for 1994 and subsequent years must show that there has been a substantial divergence between the cost of service and the change in the Commission's rate index in order to have standing to challenge SFPP rates for those years in pending or subsequent proceedings. RHC's petition contended that Opinion No. 435-B should be modified on rehearing, to the extent it: o suggested that a "substantial divergence" standard applies to complaint proceedings challenging the total level of SFPP's East Line rates subsequent to the Docket No. OR92-8 et al. proceedings; o required a substantial divergence to be shown between SFPP's cost of service and the change in the FERC oil pipeline index in such subsequent complaint proceedings, rather than a substantial divergence between the cost of service and SFPP's revenues; and o permitted SFPP to recover 1993 rate case litigation expenses through a surcharge mechanism. ARCO, Ultramar and SFPP filed petitions for review of Opinion No. 435-B (and in SFPP's case, Opinion Nos. 435 and 435-A) in the U.S. Court of Appeals for the District of Columbia Circuit. The court consolidated the Ultramar and SFPP petitions with the consolidated cases held in abeyance and ordered that the consolidated cases be returned to its active docket. 12 On November 7, 2001, the FERC issued an order ruling on the petitions for rehearing of Opinion No. 435-B. The FERC held that Chevron's eligibility for reparations should be measured from August 3, 1993, rather than the September 23, 1992 date sought by Chevron. The FERC also clarified its prior ruling with respect to the "substantial divergence" test, holding that in order to be considered on the merits, complaints challenging the SFPP rates set by applying the FERC's indexing regulations to the 1994 cost of service derived under the Opinion No. 435 orders must demonstrate a substantial divergence between the indexed rates and the pipeline's actual cost of service. Finally, the FERC held that SFPP's 1993 regulatory costs should not be included in the surcharge for the recovery of supplemental costs. On November 20, 2001, SFPP submitted its compliance filing and tariffs implementing Opinion No. 435-B and the FERC's November 7, 2001 order. Motions to intervene and protest were subsequently filed by ARCO, Mobil (which now submits filings under the name ExxonMobil), RHC, Navajo and Chevron, alleging that SFPP: o should have calculated the supplemental cost surcharge differently; o did not provide adequate information on the taxpaying status of its unitholders; and o failed to estimate potential reparations for ARCO. On December 7, 2001, Chevron filed a petition for rehearing of the FERC's November 7, 2001 order. The petition requested the Commission to specify whether Chevron would be entitled to reparations for the two year period prior to the August 3, 1993 filing of its complaint. On December 10, 2001, SFPP filed a response to those claims. On December 14, 2001, SFPP filed a revised compliance filing and new tariff correcting an error that had resulted in understating the proper surcharge and tariff rates. On December 20, 2001, the FERC's Director of the Division of Tariffs and Rates Central issued two letter orders rejecting SFPP's November 20, 2001 and December 14, 2001 tariff filings because they were not made effective retroactive to August 1, 2000. On January 11, 2002, SFPP filed a request for rehearing of those orders by the Commission, on the ground that the FERC has no authority to require retroactive reductions of rates filed pursuant to its orders in complaint proceedings. On January 7, 2002, SFPP and RHC filed petitions for review of the FERC's November 7, 2001 order in the U.S. Court of Appeals for the District of Columbia Circuit. On January 8, 2002, the court consolidated those petitions with the petitions for review of Opinion Nos. 435, 435-A and 435-B. On January 24, 2002, the court ordered the consolidated proceedings to be held in abeyance until the FERC acts on Chevron's request for rehearing of the November 7, 2001 order. Motions to intervene and protest the December 14, 2001 corrected submissions were filed by Navajo, ARCO and ExxonMobil. Ultramar requested leave to file an out-of-time intervention and protest of both the November 20, 2001 and December 14, 2001 submissions. On January 14, 2002, SFPP responded to those filings to the extent they were not mooted by the orders rejecting the tariffs in question. On February 15, 2002, the Commission denied rehearing of the Director of the Division of Tariffs and Rates Central's letter orders. On February 21, 2002, SFPP filed a motion requesting that the FERC clarify whether it intended SFPP to file a retroactive tariff or simply make a compliance filing calculating the effects of Opinion No. 435-B back to August 1, 2000; in the event the order was clarified to require a retroactive tariff filing, SFPP asked the FERC to stay that requirement pending judicial review. On April 8, 2002, SFPP filed a petition for review of the FERC's February 15, 2002 Order in the U.S. Court of Appeals for the District of Columbia Circuit. BP West Coast Products, LLC (formerly ARCO); ExxonMobil; Tosco Corporation; and Ultramar, Inc. and Valero Energy Corporation filed motions to intervene in that proceeding. On April 9, 2002, the Court of Appeals consolidated SFPP's petition with the petitions for review of the FERC's prior orders and directed the parties "to file motions to govern future proceedings" by May 9, 2002. Motions were filed by SFPP, RHC, Navajo, Chevron and the "Indicated Parties" (BP West Coast Products, ExxonMobil, Ultramar and Tosco). The FERC requested that the Court continue to hold the consolidated cases in abeyance pending the completion of proceedings before the agency on rehearing. On June 25, 2002, the Court granted the ExxonMobil and Valero Energy motions to intervene, and directed intervenors on the side of petitioners to notify the court of that status and provide a statement of issues to be raised. ExxonMobil filed a notice on July 2, 2002; Ultramar, Inc. and Valero Energy on July 10, 2002. On July 12, 2002, SFPP responded to the ExxonMobil notice in order to urge the Court not to rely on ExxonMobil's categorization of 13 the issues and party alignments in allocating briefing. On May 31, 2002, SFPP filed FERC Tariff No. 70, which implemented the FERC's annual indexing adjustment. Motions to intervene and protest were filed by Navajo and Chevron, contesting any indexing adjustment to the litigation surcharge permitted by Opinion No. 435-B. On June 28, 2002, the FERC's Director of the Division of Tariffs and Rates rejected Tariff No. 70 on the ground that the surcharge should not be indexed. On July 2, 2002, SFPP filed FERC Tariff No. 73 to replace Tariff No. 70 in compliance with that decision, which resulted in an average reduction from Tariff No. 70 of approximately $.0002 per barrel. On September 26, 2002, the FERC issued an order ruling on the protests against SFPP's November 20, 2001 and December 14, 2001 compliance filings implementing Opinion No. 435-B and the November 7, 2001 Order. The FERC held that: o SFPP must measure supplemental costs against the total amount of reparations for the entire reparations period (as opposed to year-by-year); o SFPP will not be permitted to include in its supplemental costs (a) litigation expenses incurred during 1999 and 2000 or (b) payments made to Navajo and RHC to settle certain FERC litigation; o the tariff surcharge collected by SFPP for all shipments between August 1, 2000 and December 1, 2001 is subject to refund; and o in calculating its tax allowance, SFPP must exclude the ownership interest attributable to an entity that the FERC found to be a mutual fund. The FERC rejected the requests by Navajo, ARCO (now BP West Coast Products) and Mobil (now ExxonMobil) to extend the period for which they are entitled to reparations beyond the periods specified in prior orders. The September 26, 2002 Order also ruled on SFPP's request for clarification of the February 15, 2002 Order as to whether it was required to make a retroactive tariff filing or rather a compliance filing calculating the effects of Opinion No. 435-B beginning August 1, 2000. The FERC held that SFPP was required to file a tariff retroactive to August 1, 2000. The FERC did not rule on SFPP's alternative request for a stay. The FERC also ruled on Chevron's request for rehearing of the November 7, 2001 Order, clarifying that Chevron was eligible for reparations for shipments on the East Line for the two years prior to the filing of its complaint. On October 22, 2002, ExxonMobil filed a Request for Clarification or, in the Alternative, Rehearing of the September 26, 2002 Order. ExxonMobil requested that the FERC clarify that ExxonMobil was eligible for reparations for East Line rates. On October 28, 2002, SFPP submitted its compliance and tariff filing implementing the September 26, 2002 Order. Following the September 26, 2002 Order, several parties filed motions to govern future proceedings with the U.S. Court of Appeals for the District of Columbia Circuit. BP West Coast Products LLC and ExxonMobil (the "Indicated Parties") and Valero Energy Corporation, Ultramar Inc. and Tosco Corporation (the "Joint Parties") requested that the court return the petitions for review to its active docket but sever the docket involving compliance filing issues. The FERC filed a motion that did not take a definitive position on whether the petitions for review should continue to be held in abeyance, but noted that compliance filing issues were still pending before the FERC. SFPP, Chevron, Navajo and RHC filed responses to the motions to govern future proceedings. On October 18, 2002, Chevron filed a petition for review of Opinion Nos. 435, 435-A and 435-B in the U.S. Court of Appeals for the District of Columbia Circuit. Petitions for review of the September 26, 2002 Order have been filed in the U.S. Court of Appeals for the District of Columbia Circuit by Navajo, on October 24, 2002, and by SFPP, on November 8, 2002. Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC (Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject to FERC's jurisdiction under the Interstate Commerce Act, and, if so, claimed that the rate for that service was unlawful. Texaco sought to have its claims addressed in the OR92-8 proceeding discussed above. Several other West Line shippers filed similar complaints and/or motions to intervene. The FERC consolidated all of these filings into Docket Nos. OR96-2 and set the claims for a separate hearing. A hearing before an administrative law judge was held in December 1996. 14 In March 1997, the judge issued an initial decision holding that the movements on the Sepulveda pipelines were not subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that decision. On October 6, 1997, SFPP filed a tariff establishing the initial interstate rate for movements on the Sepulveda pipelines at the preexisting rate of five cents per barrel. Several shippers protested that rate. In December 1997, SFPP filed an application for authority to charge a market-based rate for the Sepulveda service, which application was protested by several parties. On September 30, 1998, the FERC issued an order finding that SFPP lacks market power in the Watson Station destination market and that, while SFPP appeared to lack market power in the Sepulveda origin market, a hearing was necessary to permit the protesting parties to substantiate allegations that SFPP possesses market power in the origin market. A hearing before a FERC administrative law judge on this limited issue was held in February 2000. On December 21, 2000, the FERC administrative law judge issued his initial decision finding that SFPP possesses market power over the Sepulveda origin market. The ultimate disposition of SFPP's application is pending before the FERC. Following the issuance of the initial decision in the Sepulveda case, the FERC judge indicated an intention to proceed to consideration of the justness and reasonableness of the existing rate for service on the Sepulveda pipelines. On February 22, 2001, the FERC granted SFPP's motion to block such consideration and to defer consideration of the pending complaints against the Sepulveda rate until after FERC's final disposition of SFPP's market rate application. OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar filed a complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates, claiming they were unjust and unreasonable and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of SFPP's interstate rates, raising claims against SFPP's East and West Line rates similar to those that have been at issue in Docket Nos. OR92-8, et al., but expanding them to include challenges to SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno, Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In November 1997, Ultramar Diamond Shamrock Corporation filed a similar, expanded complaint (Docket No. OR98-2). Tosco Corporation filed a similar complaint in April 1998. The shippers seek both reparations and prospective rate reductions for movements on all of the lines. SFPP answered each of these complaints. FERC issued orders accepting the complaints and consolidating them into one proceeding (Docket No. OR96-2, et al.), but holding them in abeyance pending a FERC decision on review of the initial decision in Docket Nos. OR92-8, et al. In a companion order to Opinion No. 435, the FERC gave the complainants an opportunity to amend their complaints in light of Opinion No. 435, which the complainants did in January 2000. On May 17, 2000, the FERC issued an order finding that the various complaining parties had alleged sufficient grounds for their complaints to go forward to a hearing to assess whether any of the challenged rates that are grandfathered under the Energy Policy Act will continue to have such status and, if the grandfathered status of any rate is not upheld, whether the existing rate is just and reasonable. In August 2000, Navajo and RHC filed complaints against SFPP's East Line rates and Ultramar filed an additional complaint updating its pre-existing challenges to SFPP's interstate pipeline rates. In September 2000, FERC accepted these new complaints and consolidated them with the ongoing proceeding in Docket No. OR96-2, et al. A hearing in this consolidated proceeding was held from October 2001 to March 2002. An initial decision by the administrative law judge is expected in the fourth quarter of 2002. The complainants have alleged a variety of grounds for finding "substantially changed circumstances." Applicable rules and regulations in this field are vague, relevant factual issues are complex, and there is little precedent available regarding the factors to be considered or the method of analysis to be employed in making a determination of "substantially changed circumstances," which is the showing necessary to render "grandfathered" rates subject to challenge. Given the newness of the grandfathering standard under the Energy Policy Act and limited precedent, we cannot predict how these allegations will be viewed by the FERC. If "substantially changed circumstances" are found, SFPP rates previously "grandfathered" under the Energy Policy Act will lose their "grandfathered" status. If these rates are found to be unjust and unreasonable, shippers may be entitled to a prospective rate reduction and a complainant may be entitled to reparations for periods from the date of its complaint to the date of the implementation of the new rates. 15 OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the OR96-2 proceeding, filed a complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate the complaint with the OR96-2 proceeding. On May 21, 2002, the FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a request for rehearing and on September 25, 2002, the FERC dismissed Chevron's rehearing request. Chevron continues to participate in the OR96-2 proceeding as an intervenor. We are not able to predict with certainty the final outcome of the pending FERC proceedings involving SFPP, should they be carried through to their conclusion, or whether we can reach a settlement with some or all of the complainants. Although it is possible that current or future proceedings could be resolved in a manner adverse to us, we believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations. CALNEV Pipe Line LLC We acquired CALNEV Pipe Line LLC in March 2001. CALNEV provides interstate and intrastate transportation from an interconnection with SFPP at Colton, California to destinations in and around Las Vegas, Nevada. In April 2002, Chevron filed a complaint against CALNEV's interstate rates, making allegations of unjust and unreasonable rates. CALNEV answered Chevron's complaint on May 16, 2002, and Chevron moved for leave to respond to CALNEV's answer on June 17, 2002. In September of 2002, CALNEV and Chevron were able to reach a mutually agreeable resolution of the disputed claims, and a settlement was executed. In the settlement agreement, the parties agreed, among other things, that for a period of five years, CALNEV would not seek a rate increase at the FERC or the California Public Utilities Commission except as permitted under four specific exceptions and that Chevron would not file complaints against CALNEV's rates, provided it complies with such exceptions. On October 10, 2002, the FERC granted the parties' joint motion to dismiss the complaint with prejudice. California Public Utilities Commission Proceeding ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission on April 7, 1997. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the State of California and requests prospective rate adjustments. On October 1, 1997, the complainants filed testimony seeking prospective rate reductions aggregating approximately $15 million per year. On August 6, 1998, the CPUC issued its decision dismissing the complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited rehearing of its August 1998 decision for the purpose of addressing the proper ratemaking treatment for partnership tax expenses, the calculation of environmental costs and the public utility status of SFPP's Sepulveda Line and its Watson Station gathering enhancement facilities. In pursuing these rehearing issues, complainants seek prospective rate reductions aggregating approximately $10 million per year. On March 16, 2000, SFPP filed an application with the CPUC seeking authority to justify its rates for intrastate transportation of refined petroleum products on competitive, market-based conditions rather than on traditional, cost-of-service analysis. On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC asserting that SFPP's California intrastate rates are not just and reasonable based on a 1998 test year and requesting the CPUC to reduce SFPP's rates prospectively. The amount of the reduction in SFPP rates sought by the complainants is not discernible from the complaint. The rehearing complaint was heard by the CPUC in October 2000 and the April 2000 complaint and SFPP's market-based application were heard by the CPUC in February 2001. All three matters stand submitted as of April 13, 2001, and a decision addressing the submitted matters is expected within three to four months. The CPUC has recently issued a resolution approving a 2001 request by SFPP to raise its California rates to reflect increased power costs. The resolution approving the requested rate increase also requires SFPP to submit cost data for 2001, 2002, and 2003 to assist the CPUC in determining whether SFPP's overall rates for California intrastate transportation 16 services are reasonable. The resolution reserves the right to require refunds, from the date of issuance of the resolution, to the extent the CPUC's analysis of cost data to be submitted by SFPP demonstrates that SFPP's California jurisdictional rates are unreasonable in any fashion. There is no way to quantify the potential extent to which the CPUC could determine that SFPP's existing California rates are unreasonable or estimate the amount of dollars potentially subject to refund if the draft order is adopted by the CPUC. SFPP believes that if it is required by the CPUC to submit cost data in justification of its rates that representative data will indicate that SFPP's existing rates for California intrastate services remain reasonable and that no refunds are justified. We believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations. FERC Order 637 Kinder Morgan Interstate Gas Transmission LLC On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's compliance plan to implement the changes required by FERC dealing with the way business is conducted on interstate natural gas pipelines. All interstate natural gas pipelines were required to make such compliance filings, according to a schedule established by FERC. From October 2000 through June 2001, KMIGT held a series of technical and phone conferences to identify issues, obtain input, and modify its Order 637 compliance plan, based on comments received from FERC staff and other interested parties and shippers. On June 19, 2001, KMIGT received a letter from FERC encouraging it to file revised pro-forma tariff sheets, which reflected the latest discussions and input from parties into its Order 637 compliance plan. KMIGT made such a revised Order 637 compliance filing on July 13, 2001. The July 13, 2001 filing contained little substantive change from the original pro-forma tariff sheets that KMIGT originally proposed on June 15, 2000. On October 19, 2001, KMIGT received an order from FERC, addressing its July 13, 2001 Order 637 compliance plan. In the Order addressing the July 13, 2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed to make several changes to its tariff, and in doing so, was directed that it could not place the revised tariff into effect until further order of the FERC. KMIGT filed its compliance filing with the October 19, 2001 Order on November 19, 2001 and also filed a request for rehearing/clarification of the FERC's October 19, 2001 Order on November 19, 2001. The November 19, 2001 compliance filing has been protested by several parties. KMIGT filed responses to those protests on December 14, 2001. At this time, it is unknown when this proceeding will be finally resolved. The full impact of implementation of Order 637 on the KMIGT system is under evaluation. We believe that these matters will not have a material adverse effect on our business, financial position or results of operations. Separately, numerous petitioners, including KMIGT, have filed appeals of Order 637 in the D.C. Circuit, potentially raising a wide array of issues related to Order 637 compliance. Initial briefs were filed on April 6, 2001, addressing issues contested by industry participants. Oral arguments on the appeals were held before the courts in December 2001. On April 5, 2002, the D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C. Circuit remanded the FERC's decision to impose a 5-year cap on bids that an existing shipper would have to match in the right of first refusal process. The D.C. Circuit also remanded the FERC's decision to allow forward-hauls and backhauls to the same point. Finally, the D.C. Circuit held that several aspects of the FERC's segmentation policy and its policy on discounting at alternate points were not ripe for review. The FERC has requested comments from the industry with respect to the issues remanded by the D.C. Circuit. They were due July 17 30, 2002. On October 31, 2002, the FERC issued an order in response to the D.C. Circuit's remand of certain Order 637 issues. The order: o eliminated the requirement of a 5-year cap on bid terms that an existing shipper would have to match in the right of first refusal process, and found that no term matching cap at all is necessary given existing regulatory controls; o affirmed FERC's policy that a segmented transaction consisting of both a forwardhaul up to contract demand and a backhaul up to contract demand to the same point is permissible; and o accordingly required, under Section 5 of the NGA, pipelines that the FERC had previously found must permit segmentation on their systems to file tariff revisions within 30 days to permit such segmented forwardhaul and backhaul transactions to the same point. Trailblazer Pipeline Company On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing reflected changes in: o segmentation; o scheduling for capacity release transactions; o receipt and delivery point rights; o treatment of system imbalances; o operational flow orders; o penalty revenue crediting; and o right of first refusal language. On October 15, 2001, FERC issued its order on Trailblazer's Order No. 637 compliance filing. FERC approved Trailblazer's proposed language regarding operational flow orders and the right of first refusal, but is requiring Trailblazer to make changes to its tariff related to the other issues listed above. Trailblazer anticipates no adverse impact on its business as a result of the implementation of Order No. 637. On November 14, 2001, Trailblazer made its compliance filing pursuant to the FERC order of October 15, 2001. That compliance filing has been protested. Separately, also on November 14, 2001, Trailblazer filed for rehearing of that FERC order. These pleadings are pending FERC action. Standards of Conduct Rulemaking On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10 in which it proposed new rules governing the interaction between an interstate natural gas pipeline and its affiliates. If adopted as proposed, the Notice of Proposed Rulemaking could be read to limit communications between KMIGT, Trailblazer and their respective affiliates. In addition, the Notice could be read to require separate staffing of KMIGT and its affiliates, and Trailblazer and its affiliates. Comments on the Notice of Proposed Rulemaking were due December 20, 2001. Numerous parties, including KMIGT, have filed comment on the Proposed Standards of Conduct Rulemaking. On May 21, 2002, FERC held a technical conference dealing with the FERC's proposed changes in the Standard of Conduct Rulemaking. On June 28, 2002, KMIGT and numerous other parties flied additional written comments under a procedure adopted at the technical conference. The Proposed Rulemaking is awaiting further FERC action. We believe that these matters, as finally adopted, will not have a material adverse effect on our business, financial position or results of operations. The FERC also issued a Notice of Proposed Rulemaking in Docket No. RM02-14-000 in which it proposed new regulations for cash management practices, including establishing limits on the amount of funds that can be swept from a regulated subsidiary to a non-regulated parent company. Kinder Morgan Interstate Gas Transmission LLC filed comments on August 28, 2002. We believe that these matters, as finally adopted, will not have a material adverse effect on our business, financial position or results of operations. In addition to the matters described above, we may face additional challenges to our rates in the future. Shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. In addition, since many of our assets are subject to regulation, we are subject to potential future changes in applicable rules and regulations that may have an adverse effect on our business, financial position or results of operations. Southern Pacific Transportation Company Easements SFPP and Southern Pacific Transportation Company are engaged in a judicial reference proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by SPTC should be adjusted pursuant to existing contractual arrangements (Southern Pacific Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc., Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the State of California for the County of San Francisco, filed August 31, 1994). Although SFPP received a favorable ruling from the trial court in May 1997, in September 1999, the California Court of Appeals remanded the case back to the trial court for further proceeding. SFPP claims that the rent payable for each of the years 1994 through 2004 should be approximately $4.4 million and SPTC claims it should be approximately $15.0 million. We believe SPTC's position in this case is without merit and we have set aside reserves that we believe are adequate to address any reasonably foreseeable outcome of this matter. As of mid-October 2002, the matter is currently in trial. Carbon Dioxide Litigation Kinder Morgan CO2 Company, L.P. directly or indirectly through its ownership interest in the Cortez Pipeline Company, along with other entities, is a defendant in several actions in which the plaintiffs allege that the defendants undervalued carbon dioxide produced from the McElmo Dome field and overcharged for transportation costs, thereby allegedly underpaying royalties and severance tax payments. The plaintiffs, who are seeking monetary damages and injunctive relief, are comprised of royalty, overriding royalty and small share working interest owners who claim that they were underpaid by the defendants. These cases are: CO2 Claims Coalition, LLC v. Shell Oil Co., et al., No. 96-Z-2451 (U.S.D.C. Colo. filed 8/22/96); Rutter & Wilbanks et al. v. Shell Oil Co., et al., No. 00-Z-1854 (U.S.D.C. Colo. filed 9/22/00); Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo. filed 9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C. Colo. filed 9/22/00); United 18 States ex rel. Crowley v. Shell Oil Company, et al., No. 00-Z-1220 (U.S.D.C. Colo. filed 6/13/00); Shell Western E&P Inc. v. Bailey, et al., No 98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et al. v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court, Denton County filed 12/22/99); First State Bank of Denton v. Mobil Oil Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County filed 3/29/01); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct. Montezuma County filed 3/21/98). At a hearing conducted in the United States District Court for the District of Colorado on April 8, 2002, the Court orally announced that it had approved the certification of proposed plaintiff classes and approved a proposed settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson, Ainsworth and United States ex rel. Crowley cases. The Court entered a written order approving the Settlement on May 6, 2002; plaintiffs counsel representing Shores, et al. appealed the court's decision to the 10th Circuit Court of Appeals. RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et al. Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the First Supplemental Petition filed by RSM Production Corporation on behalf of the County of Zapata, State of Texas and Zapata County Independent School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15 other defendants, including two other Kinder Morgan affiliates. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. The Petition alleges that these taxing units relied on the reported volume and analyzed heating content of natural gas produced from the wells located within the appropriate taxing jurisdiction in order to properly assess the value of mineral interests in place. The suit further alleges that the defendants undermeasured the volume and heating content of that natural gas produced from privately owned wells in Zapata County, Texas. The Petition further alleges that the County and School District were deprived of ad valorem tax revenues as a result of the alleged undermeasurement of the natural gas by the defendants. On December 15, 2001, the defendants filed motions to transfer venue on jurisdictional grounds. There are no further pretrial proceedings at this time. Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating Company et al. v. Gas Pipelines, et al.) Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999, three plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a purported nationwide class action in the Stevens County, Kansas District Court against some 250 natural gas pipelines and many of their affiliates. The District Court is located in Hugoton, Kansas. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. The Petition (recently amended) alleges a conspiracy to underpay royalties, taxes and producer payments by the defendants' undermeasurement of the volume and heating content of natural gas produced from nonfederal lands for more than twenty-five years. The named plaintiffs purport to adequately represent the interests of unnamed plaintiffs in this action who are comprised of the nation's gas producers, State taxing agencies and royalty, working and overriding owners. The plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees from the defendants, jointly and severally. This action was originally filed on May 28, 1999 in Kansas State Court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. Subsequently, one of the defendants removed the action to Kansas Federal District Court and the case was styled as Quinque Operating Company, et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the District of Kansas. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claim Act cases referred to below, because of common factual questions. On April 10, 2000, the MDL Panel ordered that this case be consolidated with the Grynberg federal False Claims Act cases. On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling remanding the case back to the State Court in Stevens County, Kansas. The Court in Kansas has issued a case management order addressing the initial phasing of the case. In this initial phase, the court will rule on motions to dismiss (jurisdiction and sufficiency of pleadings), and if the action is not dismissed, on class certification. Merits discovery has been stayed. Recently, the defendants filed a motion to dismiss on grounds other than personal jurisdiction, which was denied by the Court in August, 2002. The Motion to Dismiss for lack of Personal Jurisdiction of the nonresident defendants has been briefed and is awaiting decision. The current named plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and Stixon Petroleum, Inc. Quinque Operating Company has been dropped from the action as a named plaintiff. United States of America, ex rel., Jack J. Grynberg v. K N Energy Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claim Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. The MDL case is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to Dismiss were filed and an oral argument on the Motion to Dismiss occurred on March 17, 2000. On July 20, 2000 the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases. Judge Downes denied the defendant's motion to dismiss on May 18, 2001. Pretrial proceedings are underway. Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et al. Mel R. Sweatman and Paz Gas Corporation vs. Gulf Energy Marketing, LLC, et al. On July 25, 2002, we were served with this suit for breach of contract, tortious interference with existing contractual relationships, conspiracy to commit tortuous interference and interference with prospective business relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and Paz Gas Corporation claim they are entitled under an agreement with a subsidiary of ours acquired in the Tejas Gas acquisition. We have filed a motion to remove the case from venue in Dewitt County, Texas to Harris County, Texas, and a hearing has been set for November 2002 to argue this motion. Based on the 19 information available to date and our preliminary investigation, we believe this suit is without merit and we intend to defend it vigorously. Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy, Incorporated, Reliant Energy Resources Corp., Entex Gas Marketing Company, Kinder Morgan Texas Pipeline, L.P., Kinder Morgan Energy Partners, L.P., Houston Pipeline Company, L.P. and AEP Gas Marketing, L.L.C., No. 30875 (District Court, Wharton County Texas). On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan Energy Partners, L.P. were served with the above-entitled Complaint. A First Amended Complaint was served on October 23, 2002, adding additional defendants Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc., Kinder Morgan Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The First Amended Complaint purports to bring a class action on behalf of those Texas residents who purchased natural gas for residential purposes from the so-called "Reliant Defendants" in Texas at any time during the period encompassing "at least the last ten years." The Complaint alleges that Reliant Energy Resources Corp., by and through its affiliates, has artificially inflated the price charged to residential consumers for natural gas that it allegedly purchased from the non-Reliant defendants, including the above-listed Kinder Morgan entities. The Complaint further alleges that in exchange for Reliant Energy Resources Corp.'s purchase of natural gas at above market prices, the non-Reliant defendants, including the above-listed Kinder Morgan entities, sell natural gas to Entex Gas Marketing Company at prices substantially below market, which in turn sells such natural gas to commercial and industrial consumers and gas marketers at market price. The Complaint purports to assert claims for fraud, violations of the Texas Deceptive Trade Practices Act, and violations of the Texas Utility Code against some or all of the Defendants, and civil conspiracy against all of the defendants, and seeks relief in the form of, inter alia, actual, exemplary and statutory damages, civil penalties, interest, attorneys' fees and a constructive trust ab initio on any and all sums which allegedly represent overcharges by Reliant and Reliant Energy Resources Corp. The Kinder Morgan defendants' answers to this Complaint have not yet become due. Based on the information available to date and our preliminary investigation, the Kinder Morgan defendants believe that the claims against them are without merit and intend to defend against them vigorously. Marie Snyder, et al v. City of Fallon, United States Department of the Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District Court, District of Nevada). On July 9, 2002, we were served with a purported Complaint for Class Action in which the plaintiffs, on behalf of themselves and others similarly situated, assert that a leukemia cluster has developed in the City of Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to unspecified "environmental carcinogens" at unspecified times in an unspecified manner and are therefore "suffering a significantly increased fear of serious disease." The plaintiffs seek a certification of a class of all persons in Nevada who have lived for at least three months of their first ten years of life in the City of Fallon between the years 1992 and the present who have not been diagnosed with leukemia. The Complaint purports to assert causes of action for nuisance and "knowing concealment, suppression, or omission of material facts" against all defendants, and seeks relief in the form of "a court-supervised trust fund, paid for by defendants, jointly and severally, to finance a medical monitoring program to deliver services [to members of the purported class] that include, but are not limited to, testing, preventative screening and surveillance for conditions resulting from, or which can potentially result from exposure to environmental carcinogens," incidental damages, and attorneys' fees and costs. We responded to the Complaint with a Motion to Dismiss on the grounds that it fails to state a claim against us upon which relief can be granted. This motion is currently pending before the court. Based on the information available to date and our preliminary investigation, we believe that the claims against us are without merit and intend to defend against them vigorously. Although no assurances can be given, we believe that we have meritorious defenses to all of these actions, that, to the extent an assessment of the matter is possible, we have established an adequate reserve to cover potential liability, and that these matters will not have a material adverse effect on our business, financial position or results of operations. 20 Environmental Matters We are subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current or predecessor owners and operators of a site, without regard to fault or the legality of the original conduct. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental regulations, risks of additional costs and liabilities are inherent in pipeline and terminal operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies there under, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We are currently involved in the following governmental proceedings related to compliance with environmental regulations associated with our assets and have established a reserve to address the costs associated with the cleanup: o one cleanup ordered by the United States Environmental Protection Agency related to ground water contamination in the vicinity of SFPP's storage facilities and truck loading terminal at Sparks, Nevada; o several ground water hydrocarbon remediation efforts under administrative orders issued by the California Regional Water Quality Control Board and two other state agencies; o groundwater and soil remediation efforts under administrative orders issued by various regulatory agencies on those assets purchased from GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe Line LLC and Central Florida Pipeline LLC; and o a ground water remediation effort taking place between Chevron, Plantation Pipe Line Company and the Alabama Department of Environmental Management. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide. Furthermore, our review of assets related to Kinder Morgan Interstate Gas Transmission LLC indicates possible environmental impacts from petroleum and used oil releases into the soil and groundwater at nine sites. Additionally, our review of assets related to Kinder Morgan Texas Pipeline indicates possible environmental impacts from petroleum releases into the soil and groundwater at six sites. Further delineation and remediation of any environmental impacts from these matters will be conducted. Reserves have been established to address the closure of these issues. On October 2, 2001, the jury rendered a verdict in the case of Walter Chandler v. Plantation Pipe Line Company. The jury awarded the plaintiffs a total of $43.8 million. The judge reduced the award to $42.6 million due to a prior settlement with the plaintiffs by a third party. The verdict was divided with the following award of damages: o $0.3 million compensatory damages for property damage to the Evelyn Chandler Trust; o $4.1 million compensatory damages to Walter (Buster) Chandler; o $1.2 million compensatory damages to Clay Chandler; and o $37 million punitive damages. Plantation has filed post judgment motions and an appeal of the verdict. The appeal of this case will be directly heard by the Alabama Supreme Court. It is anticipated that a decision by the Alabama Supreme Court will be received within the next six to eight months. This case was filed in April 1997 by the landowner (Evelyn Chandler Trust) and two residents of the property (Buster Chandler and his son, Clay Chandler). The suit was filed against Chevron, Plantation and two individuals. The two individuals were later dismissed from the suit. Chevron settled with the plaintiffs in December 2000. The property and residences are directly across the street from the location of a former Chevron products terminal. The Plantation pipeline system traverses the Chevron terminal property. The suit alleges that gasoline released from the terminal and pipeline contaminated the groundwater under the plaintiffs' property. As noted above, a current remediation effort is taking place between Chevron, Plantation and Alabama Department of Environmental Management. In addition to the Chandler case, in 1999, other individuals living in close proximity to the Chandlers filed eight lawsuits against Plantation, Chevron and an environmental consulting firm, CH2MHill. These individuals live in a community called Greenridge, which is outside of Moundville, Alabama. The eight lawsuits were filed in and are currently pending in the circuit court of Hale County, Alabama. The Greenridge plaintiffs allege property damage from groundwater contaminated by petroleum hydrocarbons. The Greenridge plaintiffs also allege personal injuries from exposure to fumes from contaminated groundwater that discharges to the swamp near their houses. The eight lawsuits were consolidated into one trial that was scheduled for December 2002 but has been continued. A new trial date has not been set but is anticipated during 2003. Plantation believes that the ultimate resolution of the Greenridge cases will not have a material adverse effect on its business, financial position or results of operations. 21 Although no assurance can be given, we believe that the ultimate resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position or results of operations. We have recorded a total reserve for environmental claims in the amount of $59.7 million at September 30, 2002. As of September 30, 2002, we were not able to reasonably estimate when the eventual settlements of these claims will occur. Other We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position or results of operations. In addition, since many of our assets are subject to regulation, we are subject to potential future challenges to our rates and to changes in applicable rules and regulations that may have an adverse effect on our business, financial position or results of operations. 4. Two-for-One Common Unit Split On July 18, 2001, Kinder Morgan Management, LLC, the delegate of our general partner, approved a two-for-one unit split of its outstanding shares and our outstanding common units representing limited partner interests in us. The common unit split entitled our common unitholders to one additional common unit for each common unit held. Our partnership agreement provides that when a split of our common units occurs, a unit split on our class B units and our i-units will be effected to adjust proportionately the number of our class B units and i-units. The two-for-one split occurred on August 31, 2001 to unitholders of record on August 17, 2001. All references to the number of Kinder Morgan Management, LLC shares, the number of our limited partner units and per unit amounts in our consolidated financial statements and related notes, have been restated to reflect the effect of the split for all periods presented. 5. Distributions On August 14, 2002, we paid a cash distribution for the quarterly period ended June 30, 2002, of $0.61 per unit to our common unitholders and to our class B unitholders. Kinder Morgan Management, LLC, our sole i-unitholder, received 619,585 additional i-units based on the $0.61 cash distribution per common unit. The distributions were declared on July 17, 2002, payable to unitholders of record as of July 31, 2002. On October 16, 2002, we declared a cash distribution for the quarterly period ended September 30, 2002, of $0.61 per unit. The distribution will be paid on or before November 14, 2002, to unitholders of record as of October 31, 2002. Our common unitholders and class B unitholders will receive cash. Our sole i-unitholder will receive a distribution in the form of additional i-units based on the $0.61 distribution per common unit. The number of i-units distributed will be 937,658. For each outstanding i-unit that Kinder Morgan Management, LLC holds, a fraction of an i-unit will be issued. The fraction is determined by dividing: o the cash amount distributed per common unit by o the average of Kinder Morgan Management's shares' closing market prices from October 15-28, 2002, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange. 6. Intangibles Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 141 "Business Combinations" and Statement of Financial Accounting Standards No. 142 "Goodwill and Other Intangible Assets". These accounting pronouncements require that we prospectively cease amortization of all intangible assets having indefinite useful economic lives. Such assets, including goodwill, are not to be amortized until their lives are determined to be finite. A recognized intangible asset with an indefinite useful life should be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We completed this initial transition impairment test in June 2002 and determined that our goodwill was not impaired as of January 1, 2002. 22 Our intangible assets include goodwill, lease value, contracts and agreements. All of our intangible assets having definite lives are being amortized on a straight-line basis over their estimated useful lives. SFAS Nos. 141 and 142 also require that we disclose the following information related to our intangible assets still subject to amortization and our goodwill (in thousands): Sept. 30, Dec. 31, 2002 2001 --------- --------- Goodwill $ 662,636 $ 566,633 Accumulated amortization (19,899) (19,899) --------- --------- Goodwill, net 642,737 546,734 --------- --------- Lease value 6,124 6,124 Contracts and other 10,767 10,739 Accumulated amortization (335) (200) --------- --------- Other intangibles, net 16,556 16,663 --------- --------- Total intangibles, net $ 659,293 $ 563,397 ========= ========= Changes in the carrying amount of goodwill for the nine months ended September 30, 2002 are summarized as follows (in thousands): Products Natural Gas CO2 Pipelines Pipelines Pipelines Terminals Total --------- --------- --------- --------- ----- Balance at Dec. 31, 2001 $ 262,765 $ 87,452 $ 46,101 $ 150,416 $546,734 Goodwill acquired 417 -- -- -- 417 Goodwill dispositions, -- -- -- -- -- net Impairment losses -- -- -- -- -- --------- --------- --------- --------- --------- Balance at Mar. 31, 2002 $ 263,182 $ 87,452 $ 46,101 $ 150,416 $ 547,151 ========= ========= ========= ========= ========= Goodwill acquired -- 83,262 -- 5,320 88,582 Goodwill dispositions, -- -- -- -- -- net Impairment losses -- -- -- -- -- --------- --------- --------- --------- --------- Balance at June 30, 2002 $ 263,182 $ 170,714 $ 46,101 $ 155,736 $ 635,733 ========= ========= ========= ========= ========= Goodwill acquired -- 3,432 -- 3,572 7,004 Goodwill dispositions, -- -- -- -- -- net Impairment losses -- -- -- -- -- --------- --------- --------- --------- --------- Balance at Sept. 30, 2002 $ 263,182 $ 174,146 $ 46,101 $ 159,308 $ 642,737 ========= ========= ========= ========= ========= Amortization expense on intangibles, including amortization of excess intangible costs of equity investments, consists of the following (in thousands): Three Months Ended Sept. 30, Nine Months Ended Sept. 30, 2002 2001 2002 2001 --------- --------- --------- --------- Goodwill $ -- $ 3,646 $ -- $ 9,613 Lease value 35 1,161 105 3,954 Contracts and other 10 10 30 30 -------- -------- -------- -------- $ 45 $ 4,817 $ 135 $ 13,597 ======== ======== ======== ======== Our weighted average amortization period for our intangible assets is approximately 42 years. The following table shows the estimated amortization expense for these assets for each of the five succeeding fiscal years (in thousands): 2003 $180 2004 $180 2005 $180 2006 $180 2007 $180 Had SFAS No. 142 been in effect prior to January 1, 2002, our reported limited partners' interest in net income and net income per unit would have been as follows (in thousands, except per unit amounts): 23 Three Months Ended Nine Months Ended Sept. 30, Sept. 30, Sept. 30, Sept. 30, 2002 2001 2002 2001 ---- ---- ---- ---- Reported limited partners' interest in net income $ 87,800 $ 60,968 $ 246,722 $ 174,633 Add: limited partners' interest in goodwill amortization -- 3,609 -- 9,516 -------- -------- --------- --------- Adjusted limited partners' interest in net income $ 87,800 $ 64,577 $ 246,722 $ 184,149 ======== ======== ========= ========= Basic limited partners' net income per unit: Reported net income $ 0.50 $ 0.37 $ 1.46 $ 1.16 Goodwill amortization -- 0.02 -- 0.06 ------ ------ ------ ------ Adjusted net income $ 0.50 $ 0.39 $ 1.46 $ 1.22 Diluted limited partners' net income per unit: Reported net income $ 0.50 $ 0.37 $ 1.46 $ 1.16 Goodwill amortization -- 0.02 -- 0.06 ------ ------ ------ ------ Adjusted net income $ 0.50 $ 0.39 $ 1.46 $ 1.22 ====== ====== ====== ====== 7. Debt Our debt and credit facilities as of September 30, 2002, consisted primarily of: o a $750 million unsecured 364-day credit facility due October 23, 2002 (subsequently replaced October 16, 2002 by a $494 million unsecured 364-day credit facility due October 14, 2003); o a $300 million unsecured five-year credit facility due September 29, 2004 (subsequently replaced October 16, 2002 by a $411.7 million unsecured three-year credit facility due October 15, 2005); o $79.5 million of Series F First Mortgage Notes due December 2004 (our subsidiary, SFPP, L.P. is the obligor on the notes); o $200 million of 8.00% Senior Notes due March 15, 2005; o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal District Revenue Bonds due March 15, 2006 (our subsidiary, International Marine Terminals, is the obligor on the bonds); o $250 million of 5.35% Senior Notes due August 15, 2007; o $30 million of 7.84% Senior Notes, with a final maturity of July 2008 (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes); o $250 million of 6.30% Senior Notes due February 1, 2009; o $250 million of 7.50% Senior Notes due November 1, 2010; o $700 million of 6.75% Senior Notes due March 15, 2011; o $450 million of 7.125% Senior Notes due March 15, 2012; o $25 million of New Jersey Economic Development Revenue Refunding Bonds due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is the obligor on the bonds); o $87.9 million of Industrial Revenue Bonds with final maturities ranging from September 2019 to December 2024 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is the obligor on the bonds); o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B", is the obligor on the bonds); o $300 million of 7.40% Senior Notes due March 15, 2031; o $300 million of 7.75% Senior Notes due March 15, 2032; o $500 million of 7.30% Senior Notes due August 15, 2033; and o a $1.05 billion short-term commercial paper program. None of our debt or credit facilities are subject to payment acceleration as a result of any change to our credit ratings. However, the margin that we pay with respect to LIBOR based borrowings under our credit facilities is tied to our credit ratings. On August 6, 2002, Kinder Morgan Management, LLC issued in a public offering, an additional 12,478,900 of its shares, including 478,900 shares upon exercise by the underwriters of an over-allotment option, at a price of $27.50 per share, less commissions and underwriting expenses. The net proceeds from the offering were used to buy i-units from us. After commissions and underwriting expenses, we received net proceeds of approximately $331.2 million for the issuance of 12,478,900 i-units. We used the proceeds from the i-unit issuance to reduce the borrowings under our commercial paper program. 24 Our outstanding short-term debt at September 30, 2002, consisted of: o $132.1 million of commercial paper borrowings; o $42.5 million under the SFPP, L.P. 10.7% First Mortgage Notes; and o $5.0 million under the Central Florida Pipeline LLC Notes. We intend and have the ability to refinance our $179.6 million of short- term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated balance sheet. We do not anticipate any liquidity problems. Our average interest rate for outstanding borrowings during the third quarter of 2002 was approximately 5.00% per annum. For additional information regarding our debt facilities, see Note 9 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2001. Credit Facilities On June 30, 2002, we had three existing bank credit facilities: o a $750 million unsecured 364-day credit facility due October 23, 2002; o a $200 million unsecured 364-day credit facility due February 20, 2003; and o a $300 million unsecured five-year credit facility due September 29, 2004. No borrowings were outstanding under our three credit facilities at June 30, 2002. In August 2002, upon the completion of our i-unit equity sale, we terminated, under the terms of the agreement, our $200 million unsecured 364-day credit facility that was due February 20, 2003. At September 30, 2002, no borrowings were outstanding under our remaining two credit facilities. On October 16, 2002, we announced that we had successfully renegotiated our bank credit facilities by replacing our $750 million unsecured 364-day credit facility due October 23, 2002 and our $300 million unsecured five-year credit facility due September 29, 2004 with two new credit facilities. The new facilities include: o a $494.0 million unsecured 364-day credit facility due October 14, 2003; and o a $411.7 million unsecured three-year credit facility due October 15, 2005. The amount available for borrowing under our credit facilities is reduced by a $23.7 million letter of credit that supports Kinder Morgan Operating L.P. "B"'s tax-exempt bonds and by our outstanding commercial paper borrowings. Furthermore, in addition to the borrowing capacity of this $905.7 million, we may close on additional commitments during the fourth quarter of 2002. Our new credit facilities are with a syndicate of financial institutions. Wachovia Bank, National Association is the administrative agent under both credit facilities. The terms of our two new credit facilities are substantially similar to the terms of our previous credit facilities. However, our prior credit facilities limited debt as a multiple of EBITDA (earnings before interest, taxes and depreciation expenses) for the prior four quarters to an amount not greater than 4.0. Our new facilities have increased the limit of that multiple to an amount not greater than 5.0. Interest on the two credit facilities accrues at our option at a floating rate equal to either: o the administrative agent's base rate (but not less than the Federal Funds Rate, plus 0.5%); or o LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt. Our new three-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate. Senior Notes Under an indenture dated August 19, 2002, and a First Supplemental Indenture dated August 23, 2002, we completed a private placement of $750 million in debt securities to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933. The indenture is a contract between us and Wachovia Bank, National Association, which acts as trustee. The notes represent additional unsecured obligations of ours and rank equally with all of our unsecured and unsubordinated debt. The notes consist of $500 million in principal amount of 7.30% 25 Senior Notes due August 15, 2033 and $250 million in principal amount of 5.35% Senior Notes due August 15, 2007, unless sooner redeemed. The notes are not entitled to the benefits of a sinking fund. Although only $500 million aggregate principal amount of the 7.30% notes and $250 million aggregate principal amount of the 5.35% notes were originally issued, so long as no Event of Default under the indenture has occurred and is continuing, we may issue and sell additional notes of either or both series and with the same terms, without the consent of holders of either series of the notes. Any additional notes of a series, together with the previously issued notes of that series, will constitute a single series of notes under the indenture. Interest on each series of notes is payable semi-annually in arrears on February 15 and August 15 of each year. The notes are redeemable, at our option, at any time at a price equal to 100% of their principal amount plus accrued and unpaid interest plus a make-whole premium, if any. In no event will the redemption price ever be less than 100% of the principal amount of the notes plus accrued interest to the redemption date. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $494.7 million for the 7.30% notes and $248.3 million for the 5.35% notes. The proceeds were used to reduce the borrowings under our commercial paper program. At the closing of the offering, we entered into a registration rights agreement with the initial purchasers pursuant to which we agreed, for the benefit of the holders of the notes, at our cost, to make an offer to exchange the original notes for new notes that are substantially identical to the terms of the original notes of the same series, except that the exchange notes will be freely transferable and issued free of any covenants regarding exchange and registration rights. Specifically, we agreed, at our cost, o within 120 days after the date of original issuance of the original notes, to file an exchange offer registration statement with the SEC with respect to the exchange offers for the exchange notes; o to use our reasonable efforts to cause the exchange offer registration statement to be declared effective under the Securities Act of 1933 within 210 days after the date of original issuance of the original notes; and o to keep the exchange offers open for not less than 30 days, or longer if required by applicable law. If we do not accomplish these or certain other actions with respect to the exchange offer by certain specified dates, the interest rate on the original notes will be increased until we accomplish those actions. The exchange offer commenced on October 18, 2002 and is scheduled to expire on November 18, 2002, unless extended. We do not anticipate that we will pay any additional interest on the notes. At September 30, 2002, our unamortized liability balance due on the various series of our senior notes was as follows (in millions): 8.0% senior notes due March 15, 2005 $ 199.8 5.35% senior notes due August 15, 2007 249.8 6.3% senior notes due February 1, 2009 249.5 7.5% senior notes due November 1, 2010 248.7 6.75% senior notes due March 15, 2011 698.3 7.125% senior notes due March 15, 2012 448.0 7.4% senior notes due March 15, 2031 299.3 7.75% senior notes due March 15, 2032 298.5 7.3% senior notes due August 15, 2033 499.0 ----- Total $3,190.9 ======== Interest Rate Swaps In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. As of September 30, 2002, we have entered into interest rate swap agreements with a notional principal amount of $1.95 billion for the purpose of hedging the interest rate risk associated with our fixed and floating rate debt obligations. These interest rate swaps have been designated as fair value hedges as defined by SFAS No. 133. These swaps also meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the "shortcut" method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. At September 30, 2002, we recognized an asset of 26 $157.5 million for the net fair value of our swap agreements and we included this amount with Deferred charges and other assets on the accompanying balance sheet. At December 31, 2001, we recognized a liability of $5.4 million for the net fair value of our swap agreements and we included this amount with Other Long-Term Liabilities and Deferred Credits on the accompanying balance sheet. For more information on our risk management activities, see Note 10. Commercial Paper Program As of June 30, 2002, our commercial paper program provided for the issuance of up to $1.25 billion of commercial paper. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facilities. On August 6, 2002, in conjunction with our issuance of additional i-units and as previously agreed upon under the terms of our credit facilities, we reduced our commercial paper program to provide for the issuance of up to $1.05 billion of commercial paper. As of September 30, 2002, we had $132.1 million of commercial paper outstanding with an average interest rate of 2.09%. Trailblazer Pipeline Company Debt At June 30, 2002, the outstanding balance under Trailblazer's $85.2 million two-year revolving credit facility was $31.0 million. The revolving credit facility was to expire on June 29, 2003, however, in late July 2002, we paid the $31.0 million outstanding balance under Trailblazer's revolving credit facility and terminated the facility. Kinder Morgan Operating L.P. "B" Debt The $23.7 million principal amount of tax-exempt bonds due 2024 were issued by the Jackson-Union Counties Regional Port District. These bonds bear interest at a weekly floating market rate. During the third quarter of 2002, the weighted-average interest rate on these bonds was 1.37% per annum, and at September 30, 2002, the interest rate was 1.70%. We have an outstanding letter of credit issued under our credit facilities that supports our tax-exempt bonds. The letter of credit reduces the amount available for borrowing under our credit facilities. International Marine Terminals Debt As of February 1, 2002, we own a 66 2/3% interest in International Marine Terminals (IMT) partnership (see Note 2). The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. The bonds mature on March 15, 2006. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, we agreed to guarantee the obligations of IMT in proportion to our ownership interest. Our obligation is approximately $30.3 million for principal, plus interest and other fees. Cortez Pipeline Company Debt Pursuant to a certain Throughput and Deficiency Agreement, the owners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline Company - 13% owner) are required, on a percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The Throughput and Deficiency Agreement contractually supports the borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the owners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including cash deficiencies relating to the repayment of principal and interest on borrowings by Cortez Capital Corporation. Parent companies of the respective Cortez Pipeline Company owners further severally guarantee, on a percentage basis, the obligations of the Cortez Pipeline Company owners under the Throughput and Deficiency Agreement. Due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital Corporation. Shell Oil Company shares our guaranty obligations jointly and severally through December 31, 2006 for Cortez Capital Corporation's debt programs in place as of April 1, 2000. 27 At September 30, 2002, the debt facilities of Cortez Capital Corporation consisted of: o a $175 million committed revolving credit facility due December 26, 2002; o $115.7 million of Series D notes due May 15, 2013; and o a $175 million short-term commercial paper program. At September 30, 2002, Cortez Capital Corporation had $141.5 million of commercial paper outstanding with an interest rate of 1.825%, the average interest rate on the series D notes was 6.9322% and there were no borrowings under the credit facility. 8. Partners' Capital At September 30, 2002, our partners' capital consisted of 129,936,018 common units, 5,313,400 class B units and 44,716,390 i-units. Together, these 179,965,808 units represent the limited partners' interest and an effective 98% economic interest in the Partnership, exclusive of our general partner's incentive distribution. Our common unit total consisted of 116,980,283 units held by third parties, 11,231,735 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. Our class B units were held entirely by Kinder Morgan, Inc. and our i-units were held entirely by Kinder Morgan Management, LLC. Our general partner has an effective 2% interest in the Partnership, excluding the general partner's incentive distribution. At December 31, 2001, our Partners' capital consisted of 129,855,018 common units, 5,313,400 class B units and 30,636,363 i-units. Our total common units outstanding consisted of 110,071,392 units held by third parties, 18,059,626 units held by Kinder Morgan, Inc. and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. Our class B units were held entirely by Kinder Morgan, Inc. and our i-units were held entirely by Kinder Morgan Management, LLC. Our class B units were issued in December 2000. The class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. We initially issued 29,750,000 i-units in May 2001. The i-units are a separate class of limited partner interests in us. All of our i-units are owned by Kinder Morgan Management, LLC and are not publicly traded. In accordance with its limited liability company agreement, Kinder Morgan Management's activities are restricted to being a limited partner in, and controlling and managing the business and affairs of, the Partnership, our operating partnerships and our subsidiaries. On August 6, 2002, Kinder Morgan Management, LLC issued in a public offering, an additional 12,478,900 of its shares, including 478,900 shares upon exercise by the underwriters of an over-allotment option, at a price of $27.50 per share, less commissions and underwriting expenses. The net proceeds from the offering were used to buy additional i-units from us. After commissions and underwriting expenses, we received net proceeds of approximately $331.2 million for the issuance of 12,478,900 i-units. We used the proceeds from the i-unit issuance to reduce the debt we incurred in our acquisition of Kinder Morgan Tejas during the first quarter of 2002. Through the combined effect of the provisions in our partnership agreement and the provisions of Kinder Morgan Management, LLC's limited liability company agreement, the number of outstanding Kinder Morgan Management, LLC shares and the number of i-units will at all times be equal. Furthermore, under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. The number of i-units we distribute to Kinder Morgan Management, LLC is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to Kinder Morgan Management, LLC. The fraction of an i-unit paid per i-unit owned by Kinder Morgan Management, LLC will have the same value as the cash payment on the common unit. Based on the preceding, Kinder Morgan Management, LLC received a distribution of 619,585 i-units on August 14, 2002. These additional i-units distributed were based on the $0.61 per unit distributed to our common unitholders on that date. For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. 28 Incentive distributions allocated to our general partner are determined by the amount that quarterly distributions to unitholders exceed certain specified target levels. Our distribution of $0.61 per unit paid on August 14, 2002 for the second quarter of 2002 required an incentive distribution to our general partner of $64.4 million. Our distribution of $0.525 per unit paid on August 14, 2001 for the second quarter of 2001 required an incentive distribution to our general partner of $50.1 million. The increased incentive distribution to our general partner paid for the second quarter of 2002 over the distribution paid for the second quarter of 2001 reflects the increase in the amount distributed per unit as well as the issuance of additional units. Our declared distribution for the third quarter of 2002 of $0.61 per unit will result in an incentive distribution to our general partner of $69.5 million. This compares to our distribution of $0.55 per unit and incentive distribution to our general partner of $54.2 million for the third quarter of 2001. 9. Comprehensive Income Statement of Financial Accounting Standards No. 130, "Accounting for Comprehensive Income", requires that enterprises report a total for comprehensive income. For each of the nine months ended September 30, 2002 and 2001, the only difference between our net income and our comprehensive income was the unrealized gain or loss on derivatives utilized for hedging purposes. For more information on our hedging activities, see Note 10. Our total comprehensive income is as follows (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2002 2001 2002 2001 -------- -------- -------- -------- Net income $158,180 $115,792 $444,130 $321,685 Cumulative effect transition adjustment -- -- -- (22,797) Change in fair value of derivatives used for hedging purposes (15,680) 57,592 (97,536) 20,585 Reclassification of change in fair value of derivatives to net income 3,4422 15,390 9,386) 69,364 --------- -------- --------- --------- Comprehensive income $145,942 $188,774 $337,208 $388,837 ========= ======== ========= ========= 10. Risk Management Hedging Activities Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by Statement of Financial Accounting Standards No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No.133" and No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". SFAS No. 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, SFAS No. 133 allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. Our normal business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. Through Kinder Morgan, Inc., we use energy financial instruments to reduce our risk of changes in the prices of natural gas, natural gas liquids and crude oil markets. Our risk management activities are only used in order to protect our profit margins and our risk management policies prohibit us from engaging in speculative trading. Commodity-related activities of our risk management group are monitored by our Risk Management Committee, which is charged with the review and enforcement of our management's risk management policy. The fair value of these risk management instruments reflects the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. We have available market quotes for substantially all of the financial instruments that we use. Our Form 10-K for the year ended December 31, 2001 contains additional information about the risks we face and the hedging program we employ to mitigate those risks. 29 We recognized an insignificant loss during the third quarter of 2002 as a result of ineffectiveness of these hedges. For the third quarter of 2001, approximately $0.3 million was recognized as a loss as a result of ineffectiveness of these hedges. Approximately $0.5 million was recognized as a gain during the first nine months of 2002 as a result of ineffectiveness of these hedges, and for the first nine months of 2001, approximately $0.5 million was recognized as a loss as a result of ineffectiveness of these hedges. For all periods presented, all gains and losses were reported within the caption Operations and maintenance in the accompanying Consolidated Statements of Income. For each of the nine months ended September 30, 2002 and 2001, there was no component of the derivative instruments' gain or loss excluded from the assessment of hedge effectiveness. The gains and losses included in Accumulated other comprehensive income will be reclassified into earnings as the hedged sales and purchases take place. Approximately $37.3 million of the Accumulated other comprehensive loss balance of $43.1 million representing unrecognized net losses on derivative activities at September 30, 2002 is expected to be reclassified into earnings during the next twelve months. During the nine months ended September 30, 2002, no gains or losses were reclassified into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions will no longer occur by the end of the originally specified time period. The differences between the current market value and the original physical contracts value associated with hedging activities are primarily reflected as Other current assets and Accrued other current liabilities in the accompanying consolidated balance sheets. At September 30, 2002, our balance of $62.7 million of Other current assets included approximately $45.5 million related to risk management hedging activities, and our balance of $209.6 million of Accrued other current liabilities included approximately $83.9 million related to risk management hedging activities. At December 31, 2001, our balance of $194.9 million of Other current assets included approximately $163.7 million related to risk management hedging activities, and our balance of $209.9 million of Accrued other current liabilities included approximately $117.8 million related to risk management hedging activities. At September 30, 2002, our balance of $241.2 million of Deferred charges and other assets included approximately $9.2 million related to risk management hedging activities, and our balance of $226.5 million of Other long-term liabilities and deferred credits included approximately $15.1 million related to risk management hedging activities. At December 31, 2001, our balance of $75.0 million of Deferred charges and other assets included approximately $22.0 million related to risk management hedging activities, and our balance of $246.5 million of Other long-term liabilities and deferred credits included approximately $4.7 million related to risk management hedging activities. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk. Interest Rate Swaps In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. As of September 30, 2002, we have entered into interest rate swap agreements with a notional principal amount of $1.95 billion for the purpose of hedging the interest rate risk associated with our fixed and floating rate debt obligations. A notional principal amount of $1.75 billion of these agreements effectively converts the interest expense associated with the following series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread: o $200 million principal amount of our 8.0% senior notes due March 15, 2005; o $200 million principal amount of our 5.35% senior notes due August 15, 2007; o $250 million principal amount of our 6.30% senior notes due February 1, 2009; o $200 million principal amount of our 7.125% senior notes due March 15, 2012; o $300 million principal amount of our 7.40% senior notes due March 15, 2031; o $200 million principal amount of our 7.75% senior notes due March 15, 2032; and o $400 million principal amount of our 7.30% senior notes due August 15, 2033. The swap agreements for our senior notes have termination dates that correspond to the maturity dates of such series. The swap agreements for our 7.40% senior notes contain mutual cash-out provisions at the then-current economic value every seven years. The swap agreements for our 7.125% senior notes contain cash-out provisions at the then-current economic value at March 15, 2009. The swap agreements for our 7.75% senior notes and our 30 7.30% senior notes contain mutual cash-out provisions at the then-current economic value every five years. As of December 31, 2001, we were party to interest rate swap agreements with a total notional principal amount of $900 million. We also maintain swap agreements that effectively convert the interest expense associated with $200 million of our floating rate debt to fixed rate. The maturity dates of these swap agreements range from September 2, 2003 to August 1, 2005. These interest rate swaps have been designated as fair value hedges as defined by SFAS No. 133. These swaps also meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the "shortcut" method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments or fixed rate payments under the swaps. Interest expense is accrued monthly and paid semi-annually. At September 30, 2002, we recognized an asset of $157.5 million for the net fair value of our swap agreements and we included this amount with Deferred charges and other assets on the accompanying balance sheet. At December 31, 2001, we recognized a liability of $5.4 million for the net fair value of our swap agreements and we included this amount with Other Long-Term Liabilities and Deferred Credits on the accompanying balance sheet. We are exposed to credit related losses in the event of nonperformance by counterparties to these interest rate swap agreements. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk. 11. Reportable Segments We divide our operations into four reportable business segments: o Products Pipelines; o Natural Gas Pipelines; o CO2 Pipelines; and o Terminals. We evaluate performance based on each segment's earnings, which exclude general and administrative expenses, third-party debt costs, interest income and expense and minority interest. Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies. Our Products Pipelines segment derives its revenues primarily from the transportation of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its revenues primarily from the gathering, transmission and storage of natural gas. Our CO2 Pipelines segment derives its revenues primarily from the marketing and transportation of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields and from the production of crude oil from fields in the Permian Basin of West Texas. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and chemicals. Financial information by segment follows (in thousands):
Three Months Ended September 30, Nine Months Ended September 30, 2002 2001 2002 2001 -------- -------- -------- -------- Revenues Products Pipelines $146,277 $ 137,828 $ 426,736 $ 465,702 Natural Gas Pipelines 829,614 382,656 2,168,117 1,588,165 CO2 Pipelines 38,191 29,145 104,731 90,390 Terminals 107,238 88,915 315,737 258,687 ----------- --------- ---------- ---------- Total consolidated revenues $ 1,121,320 $ 638,544 $3,015,321 $2,402,944 =========== ========= ========== ==========
31
Three Months Ended September 30, Nine Months Ended September 30, 2002 2001 2002 2001 -------- -------- -------- -------- Operating income Products Pipelines $ 86,583 $ 76,078 $ 253,223 $ 225,337 Natural Gas Pipelines 65,855 41,478 182,761 121,716 CO2 Pipelines 17,914 13,601 44,400 44,636 Terminals 46,527 38,536 134,440 106,586 ----------- --------- ---------- ---------- Total segment operating income 216,879 169,693 614,824 498,275 Corporate administrative expenses (27,476) (24,801) (87,218) (76,436) ------------ ---------- ---------- ---------- Total consolidated operating income $ 189,403 $ 144,892 $ 527,606 $ 421,839 ============ ========== ========== =========== Earnings from equity investments, net of amortization of excess costs Products Pipelines $ 7,773 $ 5,800 $ 23,239 $ 16,981 Natural Gas Pipelines 5,621 5,295 17,580 15,745 CO2 Pipelines 8,021 7,551 25,423 23,764 Terminals 9 -- (38) ------------ ---------- ----------- ------------ Consolidated equity earnings, net of amortization $ 21,424 $ 18,646 $ 66,204 $ 56,490 ============ ========== ========== =========== Income taxes and Other, net - income (expense) Products Pipelines $ (2,675) $ (2,166) $ (8,430) $ (6,814) Natural Gas Pipelines (1) 15 18 18 CO2 Pipelines 6 53 96 146 Terminals (1,217) (2,313) (4,670) (5,942) ------------ ---------- ----------- ------------ Total consolidated income taxes and Other, net $ (3,887) $ (4,411) $ (12,986) $ (12,592) ============ ========== ========== =========== Segment earnings Products Pipelines $ 91,681 $ 79,712 $ 268,032 $ 235,504 Natural Gas Pipelines 71,475 46,788 200,359 137,479 CO2 Pipelines 25,941 21,205 69,919 68,546 Terminals 45,319 36,223 129,732 100,644 ------------ ---------- ----------- ------------ Total segment earnings 234,416 183,928 668,042 542,173 Interest and corporate administrative expenses (a) (76,236) (68,136) (223,912) (220,488) ------------ ---------- ----------- ------------ Total consolidated net income $ 158,180 $ 115,792 $ 444,130 $ 321,685 ============ ========== ========== =========== (a) Includes interest and debt expense, general and administrative expenses, minority interest expense, and other insignificant items.
Sept. 30, Dec. 31, 2002 2001 -------------- -------------- Assets Products Pipelines $ 3,107,709 $ 3,095,899 Natural Gas Pipelines 3,027,467 2,058,836 CO2 Pipelines 572,052 503,565 Terminals 1,079,744 990,760 -------------- -------------- Total segment assets 7,786,972 6,649,060 Corporate assets (a) 318,613 83,606 -------------- -------------- Total consolidated assets $ 8,105,585 $ 6,732,666 ============== ============== (a)Includes cash, cash equivalents and certain unallocable deferred charges. 12. New Accounting Pronouncements Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations", issued in July 2001 by the Financial Accounting Standards Board, requires companies to record a liability relating to the retirement and removal of assets used in their business. The liability is initially recorded at its fair value, and the relative asset value is increased by the same amount. 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 have not yet quantified the impacts of adopting this Statement on our financial position or results of operations. In April 2002, the Financial Accounting Standards Board issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This Statement eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent, in accordance with the current GAAP criteria for extraordinary classification. In addition, SFAS No. 145 eliminates an inconsistency in lease accounting by requiring that 32 modifications of capital leases that result in reclassification as operating leases be accounted for consistent with sale-leaseback accounting rules. This Statement also contains other nonsubstantive corrections to authoritative accounting literature. The changes related to debt extinguishment will be effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting will be effective for transactions occurring after May 15, 2002. Adoption of this Statement will not have any immediate effect on our consolidated financial statements. We will apply this guidance prospectively. In June 2002, the Financial Accounting Standards Board issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally Emerging Issues Task Force Issue No. 94-3. We will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of the company's commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. 33 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. Results of Operations Third Quarter 2002 Compared With Third Quarter 2001 For the quarter ended September 30, 2002, our operating results represented the most profitable quarter in the history of the Partnership. Total consolidated net income for the quarter was a record $158.2 million ($0.50 per diluted unit), a 37% increase from the $115.8 million ($0.37 per diluted unit) in net income reported for the third quarter of 2001. Revenues for the third quarter of 2002 were a record $1,121.3 million, compared with revenues of $638.5 million in the same year-earlier period. Third quarter 2002 operating income was a record $189.4 million, compared with $144.9 million in the third quarter of 2001. Operating expenses, consisting of our combined cost of sales, fuel, power and operating and maintenance expenses, were $847.3 million in the third quarter of 2002, compared with $422.0 million in the same period a year ago. Operating income for the three months ended September 30, 2002, was $189.4 million, an increase of 31% compared with the $144.9 million in operating income reported in the same period last year. Our third quarter results demonstrate balanced growth across our business portfolio as all four of our business segments reported quarter-to-quarter increases in earnings, operating income and revenues. The increases were driven by volume growth from most of our assets, by the acquisitions of pipeline and terminal businesses that we made since the end of the third quarter of 2001 and by the expansion and capital improvement projects we have completed. The largest of these was the January 31, 2002 purchase of Kinder Morgan Tejas. Kinder Morgan Tejas' operations include a 3,400-mile intrastate natural gas pipeline system that has good access to natural gas supply basins and provides a strategic, complementary fit with our other natural gas pipeline assets in Texas, particularly Kinder Morgan Texas Pipeline. Third quarter earnings from equity investments, net of amortization of excess costs, were $21.4 million in 2002 versus $18.6 million in 2001. In addition, on October 16, 2002, we declared, for the second consecutive quarter, a record cash distribution of $0.61 per unit (an annualized rate of $2.44). This third quarter 2002 distribution is up 11% from the $0.55 per unit distribution made for the third quarter of 2001. Products Pipelines Our Products Pipelines segment reported earnings of $91.7 million on revenues of $146.3 million in the third quarter of 2002. In the third quarter of 2001, the segment reported earnings of $79.7 million on revenues of $137.8 million. Of the $12 million (15%) increase in quarter-to-quarter earnings, $11.1 million was associated with internal growth including higher earnings from our CALNEV pipeline, our Pacific operations, our 44.8% ownership interest in the Cochin Pipeline System and higher net equity earnings from our 51% ownership interest in Plantation Pipe Line Company. The remaining $0.9 million increase in segment earnings was associated with the acquisition of our additional 10% ownership interest in Cochin, effective December 31, 2001. CALNEV's earnings were up $3.2 million for the quarter, primarily due to lower fuel and power costs and slightly higher delivery volumes. Our Pacific operations reported a $2.8 million increase in earnings and a $4.1 million increase in revenues, mainly driven by both a 3% increase in average tariff rates and a 2% increase in mainline delivery volumes. Revenues and earnings from our proportionate ownership of the Cochin Pipeline system increased $1.9 million and $1.5 million, respectively, in the third quarter of 2002, when compared to the same quarter last year. Most of the increases were due to higher volumes and tariffs, however, a small portion ($0.9 million) of the earnings increase was the result of the additional 10% ownership interest we purchased effective December 31, 2001. The aggregate refined petroleum products delivery volumes on all of the segment's pipelines combined increased 2% in the third quarter of 2002 compared to the third quarter of 2001. Gasoline deliveries alone were up 4%, and jet fuel deliveries have continued to improve in each successive quarter of 2002 and are beginning to return to their pre-September 11, 2001 levels. Combined operating expenses for our Products Pipelines segment were $38.4 million in the third quarter of 2002 versus $41.1 million in the third quarter of 2001. The $2.7 million decrease (7%) was primarily due to significantly lower fuel and power expenses on our entire West Coast operations, most notably Pacific, CALNEV and our West Coast product terminal businesses. In addition, segment amortization expenses were lower in the third quarter of 2002 compared to the third quarter of 2001 by $1.6 million, due to the cessation of goodwill amortization beginning on January 1, 2002. 34 Earnings from our Products Pipelines' equity investments, net of amortization of excess costs, were $7.8 million in the third quarter of 2002 versus $5.8 million in the same quarter of 2001. The $2.0 million increase (34%) was mainly related to higher equity earnings from our 51% ownership interest in Plantation Pipe Line Company. Although Plantation's third quarter delivery volumes did not match the record-setting level reached in the second quarter of 2002, its volumes were almost 4% higher than last year's third quarter delivery volumes, and its operating results continued to show strong demand for refined petroleum products throughout the southeastern United States. Natural Gas Pipelines Our Natural Gas Pipelines segment reported earnings of $71.5 million on revenues of $829.6 million in the third quarter of 2002. In the third quarter of 2001, the segment reported earnings of $46.8 million on revenues of $382.7 million. The segment's operating expenses totaled $747.9 million in the third quarter of 2002 and $330.5 million in the third quarter of 2001. All of the amounts for the third quarter of 2002 include the results of Kinder Morgan Tejas, which we purchased on January 31, 2002. Since our acquisition of Kinder Morgan Tejas, we have closely integrated our Texas intrastate natural gas pipeline operations, taking advantage of the mutual business being carried on by our Kinder Morgan Tejas and Kinder Morgan Texas Pipeline systems. Combined, these businesses accounted for a $13.6 million increase in segment earnings and a $448.2 million increase in segment revenues, when compared to last year's third quarter. In addition, Trailblazer Pipeline Company reported a $10.5 million increase in quarter-to-quarter revenues and a $12.3 million increase in quarter-to-quarter earnings. The increases resulted from higher contract demand volumes on the recently expanded pipeline and from higher gas imbalance recoveries. Offsetting the overall increases in segment earnings and revenues was a $1.6 million decrease in earnings from Kinder Morgan Interstate Gas Transmission, primarily due to higher fuel costs, and a $12.4 million decrease in revenues earned by our Casper and Douglas natural gas gathering and processing systems. The revenue decrease was primarily related to a decline in gas prices in and around the Rocky Mountain region since the end of the third quarter of 2001. However, the revenue decrease had little impact on Casper and Douglas' earnings due to declines in costs, discussed below. The segment's $417.4 million increase in combined operating expenses in the third quarter of 2002 compared to the third quarter of 2001 included a $430.0 million increase from intrastate gas operations. The increase resulted from our acquisition of Kinder Morgan Tejas as well as increases in gas volumes purchased and a rise in the costs of purchased natural gas for both Kinder Morgan Texas Pipeline and Kinder Morgan Tejas. Offsetting the segment's overall increase in operating expenses, Casper and Douglas reported a $12.4 million decrease in operating expenses. The decrease was mostly due to the lower gas prices' effects on its gas gathering and processing operations. Earnings from our Natural Gas Pipelines' equity investments, net of amortization of excess costs, were essentially flat for the quarter. The segment reported $5.6 million in net equity earnings for the third quarter of 2002 versus $5.3 million for the same prior year period. The slight $0.3 million increase in equity earnings was mainly due to higher earnings from the segment's 50% ownership interest in Coyote Gas Treating, LLC. CO2 Pipelines Our CO2 Pipelines segment reported a $4.7 million (22%) increase in earnings in the third quarter of 2002, when compared to the third quarter of 2001. For the quarter ended September 30, 2002, CO2 Pipelines earned $25.9 million on revenues of $38.2 million. Combined operating expenses totaled $10.6 million for the current quarter. For the third quarter last year, our CO2 Pipelines segment reported earnings of $21.2 million, revenues of $29.1 million and combined operating expenses of $9.2 million. The period-to-period increases were primarily driven by increases in oil production volumes from the SACROC Unit and increases in carbon dioxide delivery volumes, partially offset by lower pricing on carbon dioxide sales and lower prices resulting from our long-term hedging program. The overall increase in segment earnings was partially offset by higher depreciation, depletion and amortization charges. Non-cash depreciation charges were up $2.8 million, mainly as a result of higher production volumes and additional capital investments. In April 2002, we announced a $160 million capital investment project consisting of a new carbon dioxide pipeline and additional infrastructure to support our carbon dioxide flooding program at the SACROC Unit. We anticipate beginning construction on the pipeline during the fourth quarter of 2002, and the estimated completion date is mid-2003. In the third quarter of 2002, our CO2 Pipelines segment reported $8.0 million in equity earnings, net of amortization of excess costs. The amount represents a 5% increase from the $7.6 million in equity earnings in the third quarter of 2001. The increase resulted from higher earnings from the segment's 50% ownership interest in 35 Cortez Pipeline Company mainly due to lower average debt balances and lower average borrowing rates, partially offset by lower carbon dioxide delivery volumes. Higher overall segment earnings were also offset slightly by a $0.5 million increase in taxes, other than income taxes, primarily the result of higher production taxes. Terminals Our Terminals segment, including both our bulk and liquids terminal businesses, reported earnings of $45.3 million, revenues of $107.2 million and operating expenses of $50.4 million in the third quarter of 2002. This compares to earnings of $36.2 million, revenues of $88.9 million and operating expenses of $41.3 million in the third quarter of 2001. A significant portion of the increases in our Terminals' operating results was due to key acquisitions we have made since the third quarter of 2001, including: o the terminal businesses we acquired from The Boswell Oil Company, effective August 31, 2001; o the terminal businesses we acquired from an affiliate of Stolt-Nielsen, Inc. in November 2001; o Laser Materials Services LLC, acquired effective January 1, 2002; o a 66 2/3% interest in International Marine Terminals Partnership - a 33 1/3% interest acquired effective January 1, 2002 and an additional 33 1/3% interest acquired effective February 1, 2002; o the Milwaukee bagging operations, acquired effective May 1, 2002; and o the Owensboro Gateway Terminal, acquired effective September 1, 2002. Due to the acquisitions of these businesses, our third quarter 2002 results include an additional $18.6 million in revenues, $11.2 million in combined operating expenses and $6.0 million in segment earnings. The remaining $3.1 million period-to-period increase in segment earnings was driven primarily by internal growth at our liquids terminals. The increase in revenues was slightly offset by a $0.3 million period-to-period decrease primarily related to lower engineering services. Excluding acquisitions, liquids terminals saw revenues increase $3.4 million (8%) and earnings increase $2.0 million (9%) in the third quarter of 2002, when compared to last year's third quarter. This increase was primarily due to a 5% increase in lease tank capacity as well as increased utilization and throughput on our existing assets in Houston, Texas and Carteret, New Jersey. Although quarter-to-quarter revenues from all bulk terminal operations owned during both quarters were down in 2002, primarily due to a drop in engineering services and lower bulk tonnage volumes, earnings were higher. The increase in earnings resulted from lower operating expenses due to the decreased volumes, and lower income tax expenses as a result of favorable tax planning. Segment Operating Statistics Operating statistics for the third quarter of 2002 and 2001 are as follows: Three Months Ended Sept. 30, 2002 Sept. 30, 2001 -------------- -------------- Products Pipelines Gasoline 120.7 115.9 Diesel 39.4 40.3 Jet Fuel 29.3 29.4 ------- ------- Total Refined Product Volumes (MBbl) 189.4 185.6 Natural gas liquids 10.6 10.0 ------- ------- Total Delivery Volumes (MBbl) (1) 200.0 195.6 Natural Gas Pipelines Transport Volumes (Bcf) (2) 306.4 263.5 CO2 Pipelines Delivery Volumes (Bcf) (3) 103.7 88.3 SACROC Oil Production (MMBbl) 1.2 0.8 Terminals Bulk Terminals Transload Tonnage (MMtons) (4) 14.2 15.8 Liquids Terminals Leaseable Capacity (MMBbl) 35.0 33.4 Utilization % 97% 95% 36 Note: Historical pro forma for acquired assets. (1) Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress and Heartland pipeline volumes. (2) Includes Kinder Morgan Interstate Gas Transmission, Kinder Morgan Texas Pipeline, Kinder Morgan Tejas and Trailblazer pipeline volumes. (3) Includes Cortez, Central Basin and Canyon Reef Carriers pipeline volumes. (4) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate terminal throughputs. Other Items not attributable to any segment include general and administrative expenses, interest income and expense and minority interest. Together, these items totaled $76.2 million in the third quarter of 2002 and $68.1 million in the third quarter of 2001. Our general and administrative expenses totaled $27.5 million in the third quarter of 2002 compared with $24.8 million in the third quarter of 2001. The quarter-to-quarter increase in general and administrative expenses primarily relates to additional employee benefit accruals made in September 2002. Our total interest expense, net of interest income, was $46.4 million in the third quarter of 2002 and $41.0 million in the third quarter of 2001. The $5.4 million increase (13%) in net interest charges was due to higher average borrowings during the third quarter of 2002 compared with the same period in 2001, partially offset by lower average interest rates during the third quarter of 2002. Nine Months Ended September 30, 2002 Compared With Nine Months Ended September 30, 2001 Net income for the nine months ended September 30, 2002 was $444.1 million ($1.46 per diluted unit) compared with net income of $321.7 million ($1.16 per diluted unit) in the first nine months of 2001. The 38% increase in earnings for the comparable January through September nine-month periods is in line with the 37% increase in earnings for the comparable third quarter periods. We reported total revenues of $3,015.3 million for the first nine months of 2002, compared with $2,402.9 million for the first nine months of 2001. Our operating expenses for the nine-month period ended September 30, 2002, were $2,233.2 million, and for the nine-month period ended September 30, 2001, were $1,767.7 million. Operating income for the nine months ended September 30, 2002, was $527.6 million, an increase of 25% compared with the $421.8 million in operating income reported in the same year-earlier period. Our equity earnings from investments, less amortization of excess costs, were $66.2 million in the first nine months of 2002 versus $56.5 million in the same period last year. Products Pipelines Products Pipelines reported earnings of $268.0 million on revenues of $426.7 million for the first nine months of 2002. These amounts compare with earnings of $235.5 million on revenues of $465.7 million for the same period of 2001. The $39.0 million (8%) decrease in period-to-period segment revenues includes a reduction of $67.4 million in transmix revenues resulting primarily from our long-term transmix processing agreement with Duke Energy Merchants. During the first quarter of 2001, we entered into a 10-year agreement with Duke Energy Merchants to process transmix on a fee basis only. Under the agreement, Duke Energy Merchants is responsible for procurement of the transmix and sale of the products after processing. This agreement allows us to eliminate commodity price exposure in our transmix operations. The overall decrease in segment revenues was partly offset by a $13.3 million increase in revenues earned by our CALNEV pipeline and by a $8.6 million increase in revenues earned from our investment in the Cochin Pipeline System. The increases reflect our acquisitions of CALNEV on March 30, 2001 from GATX Corporation, and our acquisition of an additional 10% interest in Cochin (bringing our total interest to 44.8%) effective December 31, 2001. Revenues and earnings from Cochin also increased during the nine-month period of 2002 due to higher volumes and tariffs. Revenues from our Pacific operations increased $6.9 million (3%), primarily as a result of a matching 3% increase in average tariff rates. Combined operating expenses for our Products Pipelines segment were $110.6 million in the first nine-months of 2002 versus $179.3 million in the same period last year. The $68.7 million reduction (38%) in expenses was primarily due to our agreement with Duke Energy Merchants, which reduced our cost of products sold by approximately $68.6 million. Excluding cost of sales, the segment's combined fuel, power and operating and maintenance charges were essentially flat for the comparable nine-month periods. Lower operating and maintenance expenses, primarily due to efficiencies achieved at our West Coast terminals since we acquired them from GATX, were offset by higher fuel and power expenses on our Pacific operations' pipelines. Earnings from our Products Pipelines' equity investments, net of amortization of excess costs, were $23.2 million in the first nine-months of 2002 versus $17.0 million in the same period of 2001. The $6.2 million increase 37 (36%) was mainly related to higher equity earnings from our 51% ownership interest in Plantation Pipe Line Company. Plantation reported higher earnings for the first nine months of 2002 compared to the same nine-month period of 2001. Its revenues were higher due to increased delivery volumes, its operating expenses were lower due to lower power costs, and its interest expenses were lower due to lower average borrowing rates. Natural Gas Pipelines Our Natural Gas Pipelines segment reported earnings of $200.4 million on revenues of $2,168.1 million in the first nine months of 2002. In the same 2001 period, the segment reported earnings of $137.5 million on revenues of $1,588.2 million. The increase in revenues and earnings for the first nine months of 2002 over the previous year was primarily driven by our acquisition of Kinder Morgan Tejas on January 31, 2002, as well as strong growth in the Trailblazer Pipeline Company. The $579.9 million overall increase in year-over-year segment revenues includes $627.3 million in higher revenues from our combined Texas intrastate systems, which buy, sell and transport natural gas primarily within the state of Texas. Higher revenues attributed to our Tejas acquisition were partially offset by a decrease in gas sale prices since the end of the third quarter of 2001. Excluding Kinder Morgan Tejas and Kinder Morgan Texas Pipeline, segment revenues decreased $47.3 million in the comparable nine-month periods. The drop in segment revenues includes a $42.6 million decrease from our Casper and Douglas gas gathering and processing system, primarily due to an overall drop in gas prices since the end of the third quarter of 2001, most significantly in the first six months of 2002. Revenues from Kinder Morgan Interstate Gas Transmission decreased $21.2 million, primarily due to less operational gas sales and lower fuel recovery rates in 2002. Partially offsetting this decrease in segment revenues was a $16.5 million increase in revenues earned by the Trailblazer Pipeline Company. Trailblazer's natural gas transport revenue increased primarily as a result of the completed pipeline expansion project. In May 2002, Trailblazer completed a $59 million expansion project that increased transportation capacity on the pipeline by approximately 60%. For the first nine months of 2002, Trailblazer's natural gas transport volumes increased 17%, when compared to the same period a year-ago. The segment's operating expenses totaled $1,937.9 million in the first nine months of 2002 and $1,435.1 million in the same year-ago period. The $502.8 million increase resulted primarily from the inclusion of newly acquired Kinder Morgan Tejas, partially offset by lower purchased gas costs. Casper and Douglas reported a $40.8 million decrease in expenses, also primarily driven by lower gas purchase costs. Kinder Morgan Interstate Gas Transmission reported a $11.2 million decrease in operating expenses, mostly due to lower fuel costs, less operational gas sales and favorable gas imbalance settlements. Earnings from our Natural Gas Pipelines' equity investments, net of amortization of excess costs, were $17.6 million for the first nine months of 2002 versus $15.7 million for the same prior year period. The $1.9 million increase (12%) in equity earnings was mainly due to higher earnings from the segment's 49% interest in the Red Cedar Gathering Company. CO2 Pipelines Our CO2 Pipelines segment reported earnings of $69.9 million on revenues of $104.7 million in the first nine months of 2002. The segment reported earnings of $68.5 million on revenues of $90.4 million in the same nine-month period of 2001. Combined operating expenses totaled $33.4 million for the first nine months of 2002 versus $27.0 million in the same period of 2001. The $14.3 million (16%) increase in segment revenues was driven by higher oil production volumes produced at the segment's SACROC Unit. However, the segment's overall net earnings increased only slightly, $1.4 million (2%), mainly due to the higher production volumes, partially offset by an $8.7 million (69%) increase in non-cash depreciation and depletion charges. Depreciation charges were up as a result of the higher production volumes, the capital expenditures and acquisitions made since the end of the third quarter of 2001, and a change to a higher depreciation rate. During the first nine months of 2002, our CO2 Pipelines reported $25.4 million in equity earnings, net of amortization of excess costs. This compares to $23.8 million during the same period of 2001. The $1.6 million increase (7%) was due to higher returns from the segment's equity interest in Cortez Pipeline Company, partly offset by lower returns from its 15% equity investment in MKM Partners, L.P., an oil and gas joint venture with Marathon Oil Company that began January 1, 2001. 38 Terminals Our Terminals segment reported earnings of $129.7 million, revenues of $315.7 million and operating expenses of $151.4 million in the first nine months of 2002. These results compare to earnings of $100.6 million, revenues of $258.7 million and operating expenses of $126.4 million in the comparable period of 2001. The increases in segment operating results were mainly the result of terminal acquisitions we have made since the beginning of 2001 and increased throughput at our liquids terminal facilities. Our acquisitions included the businesses described above in our quarterly discussion and analysis, as well as our purchase of Pinney Dock & Transport LLC, effective March 1, 2001, and our purchase of certain bulk terminal businesses from Koninklijke Vopak N.V., effective July 10, 2001. Due to the inclusion of these businesses, we realized incremental revenues of $71.5 million, operating expenses of $43.5 million and earnings of $23.0 million in the first nine months of 2002, over the comparable period of 2001. Excluding engineering services, revenues from bulk terminals, coal facilities and liquids terminals owned during both nine-month periods were relatively flat, but combined operating expenses were down 5% compared to 2001, mainly due to lower bulk tonnage volumes. Period-to-period bulk transload volumes, for all bulk terminals owned at September 30, 2002, decreased 5% compared to last year. The decline was primarily due to lower terminal transfers of coal and salt tonnage. At our liquids terminals, expansion projects, higher utilization rates and higher throughput contributed to a $4.4 million increase in earnings and a $4.6 million increase in revenues. Our leaseable capacity increased by 5% and at the same time our capacity leased increased from 95% to 97% over the same nine-month periods. The increased capacity reflects the expansion projects and related leases at our Carteret Terminal in New York Harbor and our Pasadena Terminal on the Houston, Texas Ship Channel. The overall increase in segment earnings, revenues and expenses were partially offset by a year-over-year decline in engineering services. Segment Operating Statistics Operating statistics for the first nine months of 2002 and 2001 are as follows: Nine Months Ended Sept. 30, 2002 Sept. 30, 2001 -------------- -------------- Products Pipelines Gasoline 350.5 331.0 Diesel 115.6 122.6 Jet Fuel 83.9 90.7 ------ ------ Total Refined Product Volumes (MBbl) 550.0 544.3 Natural gas liquids 30.4 31.7 ------ ------ Total Delivery Volumes (MBbl) (1) 580.4 576.0 Natural Gas Pipelines Transport Volumes (Bcf) (2) 808.7 728.3 CO2 Pipelines Delivery Volumes (Bcf) (3) 326.3 280.2 SACROC Oil Production (MMBbl) 3.3 2.4 Terminals Bulk Terminals Transload Tonnage (MMtons) (4) 41.9 44.0 Liquids Terminals Leaseable Capacity (MMBbl) 35.0 33.4 Utilization % 97% 95% Note: Historical pro forma for acquired assets. (1) Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress and Heartland pipeline volumes. (2) Includes Kinder Morgan Interstate Gas Transmission, Kinder Morgan Texas Pipeline, Kinder Morgan Tejas and Trailblazer pipeline volumes. (3) Includes Cortez, Central Basin and Canyon Reef Carriers pipeline volumes. (4) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate terminal throughputs. Other Items not attributable to any segment include general and administrative expenses, interest income and expense and minority interest. General and administrative expenses were $87.2 million for the nine-months ended September 30, 2002, and $76.4 million for the nine-months ended September 30, 2001. The increase was mainly a 39 result of higher administrative costs and spending associated with the new acquisitions and investments we made since September 30, 2001. Our total interest expense, net of interest income, was $129.2 million in the firs nine months of 2002, compared with $136.1 million in the same year-earlier period. The $6.9 million (5%) decrease in net interest items reflects the decrease in average borrowing rates that have occurred since September 30, 2001. The favorable change in net financing charges was partially offset by higher average borrowings. During the first nine months of 2002, we issued $1.5 billion in principal amount of senior notes and we retired a maturing amount of $200 million in principal amount of senior notes. During the first nine months of 2001, we closed a public offering of $1.0 billion in principal amount of senior notes. Financial Condition The following table illustrates the sources of our invested capital. In addition to our results of operations, these balances are affected by our financing activities as discussed below (dollars in thousands): Sept. 30, 2002 Dec. 31, 2001 -------------- ------------- Long-term debt, less market value of interest rate swaps $ 3,611,061 $ 2,237,015 Minority interest 41,927 65,236 Partners' capital 3,406,826 3,159,034 ----------- ----------- Total capitalization 7,059,814 5,461,285 Short-term debt, less cash and cash equivalents (62,380) 497,417 ----------- ----------- Total invested capital $ 6,997,434 $ 5,958,702 =========== =========== Capitalization: - --------------- Long-term debt, less market value of interest rate swaps 51.1% 41.0% Minority interest 0.6% 1.2% Partners' capital 48.3% 57.8% Invested Capital: - ----------------- Total debt, less cash, cash equivalents and market value of interest rate swaps 50.7% 45.9% Partners' capital and minority interest 49.3% 54.1% Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements (other than distributions to our common unitholders, class B unitholders and general partner) through borrowings under our credit facilities, issuing short-term commercial paper, long-term notes or additional common units or issuing additional i-units to Kinder Morgan Management, LLC. In general, we expect to fund: o cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; o expansion capital expenditures and working capital deficits with cash retained as a result of paying quarterly distributions on i-units in additional i-units, additional borrowings, the issuance of additional common units or the issuance of additional i-units to Kinder Morgan Management, LLC; o interest payments from cash flows from operating activities; and o debt principal payments with additional borrowings as such debt principal payments become due or by the issuance of additional common units or the issuance of additional i-units to Kinder Morgan Management, LLC. As a master limited partnership, our common units are attractive primarily to individual investors. Individual investors represent a small segment of the total equity capital market. We believe institutional investors prefer shares of Kinder Morgan Management, LLC over our common units due to tax and other regulatory considerations. Thus, Kinder Morgan Management, LLC makes purchases of i-units issued by us with the proceeds from the sale of Kinder Morgan Management, LLC shares to institutions, which may not wish to invest in us. At September 30, 2002, our current commitments for capital expenditures were approximately $23.0 million. This amount has been committed primarily for the purchase of plant and equipment and is based on the payments we 40 expect to need for our 2002 sustaining capital expenditure plan. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. Some of our customers are experiencing severe financial problems that have had a significant impact on their creditworthiness. We are working to implement, to the extent allowable under applicable laws and regulations, prepayments and other security requirements such as letters of credit to enhance our credit position relating to amounts owed from these customers. We cannot assure that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business. Operating Activities Net cash provided by operating activities was $546.3 million for the nine-months ended September 30, 2002, versus $404.4 million in the comparable period of 2001. The period-to-period increase of $141.9 million in cash flow from operations resulted chiefly from a $139.0 million increase in cash earnings from across our business portfolio. Distributions from equity investments increased $8.1 million due to higher returns from our investments in Plantation Pipe Line Company and Cortez Pipeline Company. Offsetting the overall increase in cash provided by operating activities were slightly lower cash inflows relative to net changes in working capital items, primarily due to less favorable settlements of product inventory as a result of the transmix processing agreement we entered into with Duke Energy Merchants in 2001. Investing Activities Net cash used in investing activities was $1,218.4 million for the nine month period ended September 30, 2002, compared to $1,632.9 million in the comparable 2001 period. The $414.5 million decrease in funds utilized in investing activities is primarily attributable to higher expenditures made for strategic acquisitions in the 2001 period. For the nine months ended September 30, 2002, our acquisition outlays totaled $864.3 million, including $723.2 million for Kinder Morgan Tejas and $80.1 million for the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company. For the nine months ended September 30, 2001, our asset acquisitions totaled $1,453.2 million, including $982.7 million used to acquire the GATX pipelines and terminal businesses and $359.1 million used to acquire natural gas pipeline assets formerly leased and operated by Kinder Morgan Texas Pipeline, L.P. Offsetting the overall decline in funds used in investing activities was a $163.8 million increase in funds used for capital expenditures in the first nine months of 2002 compared to the same period in 2001. Including expansion and maintenance projects, our capital expenditures were $342.6 million in the first nine months of 2002. We spent $178.8 million for capital expenditures in the same year-ago period. The increase was due primarily to continued investment in our Natural Gas Pipelines, Terminals and CO2 Pipelines business segments. We continue to expand and grow our existing businesses and have current projects in place that will significantly add storage and throughput capacity to our terminaling, natural gas transmission and carbon dioxide flooding operations. Our sustaining capital expenditures were $52.3 million for the first nine months of 2002 compared to $40.5 million for the first nine months of 2001. Financing Activities Net cash provided by financing activities amounted to $671.7 million for the nine months ended September 30, 2002. The decrease of $581.8 million from the comparable 2001 period was mainly the result of lower cash inflows from equity financing activities. In May 2001, we received $996.9 million as proceeds from our initial sale of 29,750,000 million i-units to Kinder Morgan Management, LLC. In August 2002, we raised $331.2 million from our sale of an additional 12,478,900 i-units to Kinder Morgan Management, LLC. The overall decrease in funds provided by our financing activities also resulted from a $85.5 million increase in distributions to our partners. Distributions to all partners increased to $426.7 million in the first nine months of 2002 compared to $341.2 million in the same year-ago period. The increase in distributions was due to: o an increase in the per unit cash distributions paid; o an increase in the number of units outstanding; and o an increase in the general partner incentive distributions, which resulted from both increased cash distributions per unit and an increase in the number of common units and i-units outstanding. The overall decrease in funds provided by financing activities was partly offset by a $181.2 million decrease in overall debt financing activities. During the first nine months of each of the years 2001 and 2002, we purchased the pipeline and terminal businesses we acquired primarily with borrowings under our commercial paper program. We then raised funds by completing public and private debt offerings of senior notes and by issuing additional i-units. We then used the proceeds from these debt and equity issuances to reduce our borrowings under our commercial paper program. During the first nine months of 2002, we closed a public offering of $750 million in principal amount of senior notes, completed a private placement of $750 million in principal amount of senior notes to qualified institutional buyers and retired a maturing amount of $200 million in principal amount of senior notes. In comparison, during the first nine months of 2001, we closed a public offering of $1.0 billion in principal amount 41 of senior notes. On August 14, 2002, we paid a quarterly distribution of $0.61 per unit for the second quarter of 2002, 16% greater than the $0.525 distribution paid for the second quarter of 2001. We paid this distribution in cash to our common unitholders and to our class B unitholders. Kinder Morgan Management, LLC, our sole i-unitholder, received additional i-units based on the $0.61 cash distribution per common unit. For each outstanding i-unit that Kinder Morgan Management, LLC held, a fraction of an i-unit was issued. The fraction was determined by dividing: o the cash amount distributed per common unit by o the average of Kinder Morgan Management's shares' closing market prices for the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange. On October 16, 2002, we declared a cash distribution for the quarterly period ended September 30, 2002, of $0.61 per unit. The distribution will be paid on or before November 14, 2002, to unitholders of record as of October 31, 2002. Our common unitholders and class B unitholders will receive cash. Kinder Morgan Management, LLC, our sole i-unitholder will receive a distribution in the form of additional i-units based on the $0.61 distribution per common unit. We believe that future operating results will continue to support similar levels of quarterly cash and i-unit distributions, however, no assurance can be given that future distributions will continue at such levels. Partnership Distributions Our partnership agreement requires that we distribute 100% of available cash as defined in our partnership agreement to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of our cash receipts, including cash received by our operating partnerships, less cash disbursements and net additions to reserves (including any reserves required under debt instruments for future principal and interest payments) and amounts payable to the former general partner of SFPP, L.P. in respect of its remaining 0.5% interest in SFPP. Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to Kinder Morgan Management, LLC, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When Kinder Morgan Management, LLC determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Typically, our general partner and owners of our common units and class B units receive distributions in cash, while Kinder Morgan Management, LLC, the sole owner of our i-units, receives distributions in additional i-units. For each outstanding i-unit, a fraction of an i-unit will be issued. The fraction is calculated by dividing the amount of cash being distributed per common unit by the average closing price of Kinder Morgan Management's shares over the ten consecutive trading days preceding the date on which the shares begin to trade ex-dividend under the rules of the New York Stock Exchange. The cash equivalent of distributions of i-units will be treated as if it had actually been distributed for purposes of determining the distributions to our general partner. We will not distribute cash to i-unit owners but will retain the cash for use in our business. Available cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets. Available cash for each quarter is distributed: o first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter; o second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter; 42 o third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and o fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and class B units in cash and to owners of i-units in the equivalent number of i-units, and 50% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. The general partner's incentive distribution for the distribution that we declared for the third quarter of 2002 was $69.5 million. The general partner's incentive distribution for the distribution that we declared for the third quarter of 2001 was $54.2 million. The general partner's incentive distribution that we paid during the third quarter of 2002 to our general partner (for the second quarter of 2002) was $64.4 million. The general partner's incentive distribution that we paid during the third quarter of 2001 to our general partner (for the second quarter of 2001) was $50.1 million. All partnership distributions we declare for the fourth quarter of each year are declared and paid in the first quarter of the following year. Information Regarding Forward-Looking Statements This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," "will," or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of our operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include: o price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, coal and other bulk materials and chemicals in the United States; economic activity, weather, alternative energy sources, conservation and technological advances may affect price trends and demand; o changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission; o our ability to integrate any acquired operations into our existing operations; o our ability to acquire new businesses and assets and to make expansions to our facilities; o difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to our terminals; o our ability to successfully identify and close acquisitions and make cost-saving changes in operations; o shut-downs or cutbacks at major refineries, petrochemical or chemical plants, utilities, military bases or other businesses that use or supply our services; o changes in laws or regulations, third party relations and approvals, decisions of courts, regulators and governmental bodies may adversely affect our business or our ability to compete; o our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities; o our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences; o interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes; o acts of sabotage, terrorism or other similar acts causing damage greater than our insurance coverage; o the condition of the capital markets and equity markets in the United States; o the political and economic stability of the oil producing nations of the world; o national, international, regional and local economic, competitive and regulatory conditions and developments; o the ability to achieve cost savings and revenue growth; o rates of inflation; o interest rates; o the pace of deregulation of retail natural gas and electricity; 43 o the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products, and o the timing and success of business development efforts. You should not put undue reliance on any forward-looking statements. See Items 1 and 2 "Business and Properties - Risk Factors" of our annual report filed on Form 10-K for the year ended December 31, 2001, for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in our 2001 Form 10-K report. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Item 3. Quantitative and Qualitative Disclosures About Market Risk. There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2001, in Item 7a of our 2001 Form 10-K report. For more information on our risk management activities, see Note 10 to our consolidated financial Statements included elsewhere in this report. Item 4. Controls and Procedures. Within the 90-day period prior to the filing of this report, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-14(c) under the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective. No significant changes were made in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation. 44 PART II. OTHER INFORMATION Item 1. Legal Proceedings. See Part I, Item 1, Note 3 to our consolidated financial statements entitled "Litigation and Other Contingencies", 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. Risk Factors Set forth below are two updated risk factors relating to our business. For additional risk factors about us, see our Form 10-K for the year ended December 31, 2001 filed with the Securities and Exchange Commission. PENDING FEDERAL ENERGY REGULATORY COMMISSION AND CALIFORNIA PUBLIC UTILITIES COMMISSION PROCEEDINGS SEEK SUBSTANTIAL REFUNDS AND REDUCTIONS IN TARIFF RATES ON SOME OF OUR PIPELINES. If the proceedings are determined adversely, they could have a material adverse impact on us. Regulators and shippers on our pipelines have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. In 1992, and from 1995 through 2001, some shippers on our pipelines filed complaints with the Federal Energy Regulatory Commission and California Public Utilities Commission that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariffs rates on our Pacific operations' pipeline system. The FERC complaints, separately docketed in two different proceedings, predominantly attacked the interstate pipeline tariff rates of our Pacific operations' pipeline system, contending that the rates were not just and reasonable under the Interstate Commerce Act and should not be entitled to "grandfathered" status under the Energy Policy Act. Complaining shippers seek substantial reparations for alleged overcharges during the years in question and request prospective rate reductions on each of the challenged facilities. Hearings on the second of these two proceedings began in October 2001, and an initial decision by the administrative law judge is expected in the fourth quarter of 2002. The complaints filed before the CPUC challenge the rates charged for intrastate transportation of refined petroleum products through the Pacific operations' pipeline system in California. After the CPUC dismissed the initial complaint and subsequently granted a limited rehearing on April 10, 2000, the complainants filed a new complaint with the CPUC asserting the intrastate rates were not just and reasonable. We currently believe the FERC complaints seek approximately $197 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $45 million. We currently believe the CPUC complaints seek approximately $15 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $31 million. These amounts are the amounts we currently believe the complainants are seeking. Please see Note 3 to the accompanying financial statements for additional information regarding these complaints. Amounts, if any, ultimately owed will be impacted by the passage of time and the application of interest. Decisions regarding these complaints could negatively impact our cash flow. Additional challenges to tariff rates could be filed with the FERC and CPUC in the future. PROPOSED RULEMAKING BY THE FEDERAL ENERGY REGULATORY COMMISSION OR OTHER REGULATORY AGENCIES HAVING JURISDICTION COULD ADVERSELY IMPACT OUR INCOME AND OPERATIONS. For example, on September 27, 2001, FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10. The proposed rule would expand FERC's current standards of conduct to include a regulated transmission provider and all of its energy affiliates. It is not known whether FERC will issue a final rule in this docket and, if it does, whether as a result we could incur increased costs and increased difficulty in our operations. Generally speaking, new regulations or different interpretations of existing 45 regulations applicable to our assets could have a negative impact on our business, financial condition and results of operations. THE DISTRESSED FINANCIAL CONDITION OF SOME OF OUR CUSTOMERS COULD HAVE AN ADVERSE IMPACT ON US IN THE EVENT THESE CUSTOMERS ARE UNABLE TO PAY US FOR THE SERVICES WE PROVIDE. Some of our customers are experiencing severe financial problems. The bankruptcy of one or more of them, or some other similar proceeding or liquidity constraint might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. INCREASED REGULATORY REQUIREMENTS RELATING TO THE INTEGRITY OF OUR PIPELINES WILL REQUIRE US TO SPEND ADDITIONAL MONEY TO COMPLY WITH THESE REQUIREMENTS. Through our regulated pipeline subsidiaries, we are subject to extensive laws and regulations related to pipeline integrity. Compliance with existing regulations requires significant capital expenditures. Additional laws and regulations that may be enacted in the future could significantly increase the amount of these expenditures. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits 4.1* -- Form of Indenture dated August 19, 2002 between Kinder Morgan Energy Partners and Wachovia Bank, National Association, as Trustee (incorporated by reference from Exhibit 4.1 of Kinder Morgan Energy Partners, L.P.'s Registration Statement on Form S-4 (Registration No. 333-100346) filed with the Securities and Exchange Commission on October 4, 2002). 4.2* -- Form of First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners and Wachovia Bank, National Association, as Trustee (incorporated by reference from Exhibit 4.2 of Kinder Morgan Energy Partners, L.P.'s Registration Statement on Form S-4 (Registration No. 333-100346) filed with the Securities and Exchange Commission on October 4, 2002). 4.3* -- Form of 5.35% Note and Form of 7.30% Note (contained in the Indenture filed as Exhibit 4.1). 4.4* -- Form of Registration Rights Agreement dated August 19, 2002 among Kinder Morgan Energy Partners, Salomon Smith Barney Inc., J.P. Morgan Securities Inc., Wachovia Securities, Inc., RBC Dominion Securities Corporation, SunTrust Capital Markets, Inc., Banc One Capital Markets, Inc., and Credit Lyonnais Securities (USA) Inc. (incorporated by reference from Exhibit 4.4 of Kinder Morgan Energy Partners, L.P.'s Registration Statement on Form S-4 (Registration No. 333-100346) filed with the Securities and Exchange Commission on October 4, 2002). 4.5* -- Form of Registration Rights Agreement dated August 23, 2002 between Kinder Morgan Energy Partners and J.P. Morgan Securities Inc. (incorporated by reference from Exhibit 4.5 of Kinder Morgan Energy Partners, L.P.'s Registration Statement on Form S-4 (Registration No. 333-100346) filed with the Securities and Exchange Commission on October 4, 2002). 4.6 -- Certain instruments with respect to long-term debt of the Partnership and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of the Partnership and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. ss.229.601. The Partnership hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request. 11 -- Statement re: computation of per share earnings. 99.1 -- Chief Executive Officer Certification. 99.2 -- Chief Financial Officer Certification. - --------------------- * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. (b) Reports on Form 8-K Current report dated July 8, 2002 on Form 8-K was filed on July 8, 2002, pursuant to Items 7 and 9 of that form. We provided notice that we expected to exceed our consensus earnings estimate of $0.43 per unit for the second quarter of 2002, and that we were comfortable with and expected to meet or exceed our annual consensus earnings of $1.82 per unit. A copy of the press release was filed as an exhibit pursuant to Item 7. Current report dated July 23, 2002 on Form 8-K was filed on July 23, 2002, pursuant to Items 5 and 7 of that form. We reported that a special meeting of shareholders of Kinder Morgan Management, LLC was held on July 23, 2002, for the purpose of considering and voting upon a proposal to eliminate the exchange feature of Kinder Morgan Management's shares by amending its limited liability company agreement. Approximately 90 % of those who voted approved the proposal to eliminate the exchange feature. The amendment to Kinder Morgan Management, LLC's limited liability company agreement eliminating the exchange feature was effective at the close of business July 23, 2002. A copy of the press release was filed as an exhibit pursuant to Item 7. Current report dated August 8, 2002 on Form 8-K was filed on August 9, 2002, pursuant to Items 7 and 9 of that form. On August 8, 2002, the Chairman and Chief Executive Officer and Vice president and Chief Financial Officer of Kinder Morgan Management, LLC, the delegate of Kinder Morgan, G.P., Inc., our general partner, executed certifications in connection with our Form 10-Q for the period ending June 30, 2002 pursuant to the Sarbanes-Oxley Act of 2002. Copies of such certifications were filed as exhibits pursuant to Item 7. Current report dated August 14, 2002 on Form 8-K was filed on August 14, 2002, pursuant to Item 9 of that form. We provided notice that we, along with Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and Kinder Morgan Management, LLC, a subsidiary of our general partner that manages and controls our business and affairs, intended to make presentations on August 14, 2002 at the UBS Warburg Equity Investor Tour to investors, analysts and others to address various strategic and financial issues relating to the business plans and objectives of us, Kinder Morgan, Inc. and Kinder Morgan Management, LLC. Notice was also given that prior to the meeting, interested parties would be able to view the materials presented at the meetings by visiting Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com/investor_relations/presentations/. Current report dated August 26, 2002 on Form 8-K was filed on August 26, 2002, pursuant to Item 7 of that form. We filed, as exhibits pursuant to Item 7, the consolidated balance sheets as of June 30, 2002 and December 31, 2001, of Kinder Morgan G.P., Inc., our general partner and a wholly-owned subsidiary of Kinder Morgan, Inc. Current report dated September 4, 2002 on Form 8-K was filed on September 4, 2002, pursuant to Item 9 of that form. We provided notice that we, along with Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and Kinder Morgan Management, LLC, a subsidiary of our general partner that manages and controls our business and affairs, intended to make presentations on September 4, 2002 at the Lehman Brothers' 2002 CEO Energy/Power Conference to investors, analysts and others to address various strategic and financial issues relating to the business plans and objectives of us, Kinder Morgan, Inc. and Kinder Morgan Management, LLC. Notice was 46 also given that prior to the meeting, interested parties would be able to view the materials presented at the meetings by visiting Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com/investor_relations/presentations/. Interested parties would also be able to access the presentations by audio webcast, both live and on-demand. Live webcast presentations could be accessed at: http://customer.ibeam.com/lehm003/090302a_byRFD/, by choosing the webcast link and completing the registration page. The on-demand webcast (replay) for the presentations would be available for three months, and could also be accessed at: http://customer.ibeam.com/lehm003/090302a_byRFD/. Current report dated September 17, 2002 on Form 8-K was filed on September 18, 2002, pursuant to Item 9 of that form. We provided notice that we, along with Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and Kinder Morgan Management, LLC, a subsidiary of our general partner that manages and controls our business and affairs, intended to make presentations on September 19, 2002 at the Global Power & Gas Leaders Conference to investors, analysts and others to address various strategic and financial issues relating to the business plans and objectives of us, Kinder Morgan, Inc. and Kinder Morgan Management, LLC. Notice was also given that prior to the meeting, interested parties would be able to view the materials presented at the meetings by visiting Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com/investor_relations/presentations/. Interested parties would also be able to access the presentations by audio webcast, both live and on-demand. Live webcast presentations could be accessed at: http://twst.com/econf/mm/merrill3/morgan.html, by choosing the webcast link and completing the registration page. The on-demand webcast (replay) for the presentations would be available for fourteen days, and could also be accessed at: http://twst.com/econf/mm/merrill3/morgan.html. 47 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. KINDER MORGAN ENERGY PARTNERS, L.P. (A Delaware limited partnership) By: KINDER MORGAN G.P., INC., its General Partner By: KINDER MORGAN MANAGEMENT, LLC, its Delegate /s/ C. Park Shaper ------------------------------ C. Park Shaper Vice President, Treasurer and Chief Financial Officer (Duly Authorized Officer and Principal Financial and Accounting Officer) Date: November 13, 2002 48 CERTIFICATIONS I, Richard D. Kinder, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy Partners, L.P.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ Richard D. Kinder ------------------------------ Richard D. Kinder Chairman and Chief Executive Officer Date: November 13, 2002 49 I, C. Park Shaper, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy Partners, L.P.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ C. Park Shaper ------------------------------ C. Park Shaper Vice President, Treasurer and Chief Financial Officer Date: November 13, 2002 50 EX-11 3 km-ex11_488264.txt COMPUTATION OF EPS KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES EXHIBIT 11 - STATEMENT RE: COMPUTATION OF PER SHARE EARNINGS (Dollars In Thousands) FOR THE QUARTER ENDED September 30, 2002 2001 ================================================================================ Weighted-average number of limited partners units on which limited partners' net income per unit is based: Basic 174,780,924 165,063,961 Add-Incremental units under common unit option plan 151,083 212,566 - -------------------------------------------------------------------------------- Assuming dilution 174,932,007 165,276,527 ================================================================================ Net income $ 158,180 $ 115,792 Less: General Partner's interest in Net Income (70,380) (54,824) - -------------------------------------------------------------------------------- Limited Partners' interest in Net Income $ 87,800 $ 60,968 ================================================================================ Limited Partners' Net Income per unit: Basic $ .50 $ .37 Diluted $ .50 $ .37 FOR THE NINE MONTHS ENDED September 30, 2002 2001 ================================================================================ Weighted-average number of limited partners units on which limited partners' net income per unit is based: Basic 169,171,439 149,971,087 Add-Incremental units under common unit option plan 173,449 205,592 - -------------------------------------------------------------------------------- Assuming dilution 169,344,888 150,176,679 ================================================================================ Net income $ 444,130 $ 321,685 Less: General Partner's interest in Net Income (197,408) (147,052) - -------------------------------------------------------------------------------- Limited Partners' interest in Net Income $ 246,722 $ 174,633 ================================================================================ Limited Partners' Net Income per unit: Basic $ 1.46 $ 1.16 Diluted $ 1.46 $ 1.16 EX-99.1 4 km-ex991_488263.txt CEO CERTIFICATION CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Kinder Morgan Energy Partners, L.P. (the "Company") on Form 10-Q for the quarterly period ending September 30, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: November 13, 2002 /s/ Richard D. Kinder ------------------------------------------------ Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC, the delegate of Kinder Morgan G.P., Inc., the General Partner of Kinder Morgan Energy Partners, L.P. EX-99.2 5 km-ex992_488261.txt CFO CERTIFICATION CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Kinder Morgan Energy Partners, L.P. (the "Company") on Form 10-Q for the quarterly period ending September 30, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: November 13, 2002 /s/ C. Park Shaper ----------------------------------------------- C. Park Shaper Vice President and Chief Financial Officer of Kinder Morgan Management, LLC, the delegate of Kinder Morgan G.P., Inc., the General Partner of Kinder Morgan Energy Partners, L.P. -----END PRIVACY-ENHANCED MESSAGE-----