UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 F O R M 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 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 129,908,018 common units outstanding at May 3, 2002. 1 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 Months Ended March 31, 2002 and 2001....................... 3 Consolidated Balance Sheets-March 31, 2002 and December 31, 2001................................... 4 Consolidated Statements of Cash Flows-Three Months Ended March 31, 2002 and 2001....................... 5 Notes to Consolidated Financial Statements.......... 6-27 Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations................... Results of Operations............................... 28 Financial Condition................................. 30 Information Regarding Forward-Looking Statements.... 33 Item 3: Quantitative and Qualitative Disclosures About Market Risk........................................... 34 PART II. OTHER INFORMATION Item 1: Legal Proceedings..................................... 35 Item 2: Changes in Securities and Use of Proceeds............. 35 Item 3: Defaults Upon Senior Securities....................... 35 Item 4: Submission of Matters to a Vote of Security Holders... 35 Item 5: Other Information..................................... 35 Item 6: Exhibits and Reports on Form 8-K...................... 35 Signature............................................. 37 2 PART I. FINANCIAL INFORMATION Item 1. Financial Statements. (Unaudited) KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Thousands Except Per Unit Amounts) (Unaudited) Three Months Ended March 31, 2002 2001 ---------- ---------- Revenues Natural gas sales $463,274 $635,750 Services 261,209 238,743 Product sales and other 78,582 154,152 ---------- ----------- 803,065 1,028,645 ---------- ----------- Costs and Expenses Gas purchases and other costs of sales 448,093 707,714 Operations and maintenance 87,291 95,005 Fuel and power 18,384 15,242 Depreciation and amortization 41,326 30,075 General and administrative 26,347 28,585 Taxes, other than income taxes 15,768 13,673 ---------- ------------ 637,209 890,294 ---------- ------------ Operating Income 165,856 138,351 Other Income (Expense) Earnings from equity investments 23,271 21,203 Amortization of excess cost of (1,394) (2,253) equity investments Interest, net (39,022) (49,807) Other, net (50) 274 Minority Interest (2,827) (3,002) ----------- ------------ Income Before Income Taxes 145,834 104,766 Income Taxes 4,401 3,099 ----------- ------------ Net Income $ 141,433 $ 101,667 =========== ============ General Partner's interest in Net $ 61,794 $ 41,622 Income Limited Partners' interest in Net 79,639 60,045 Income ----------- ------------ Net Income $ 141,433 $ 101,667 =========== ============ Basic and Diluted Limited Partners' $ 0.48 $ 0.44 =========== ============ Net Income per Unit Weighted Average Number of Units used in Computation of Limited Partners' Net Income per Unit Basic 166,049 135,036 =========== ============= Diluted 166,246 135,222 =========== ============= Additional per Unit information Declared Distribution $ 0.590 $ 0.525 =========== ============ 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) March 31, December 31, 2002 2001 --------- ------------ ASSETS Current Assets Cash and cash equivalents $ 29,266 $ 62,802 Accounts and notes receivable Trade 279,409 215,860 Related parties 18,427 52,607 Inventories Products 1,048 2,197 Materials and supplies 6,549 6,212 Gas imbalances 77,546 15,265 Gas in underground storage 7,436 18,214 Other current assets 91,268 194,886 ----------- ---------- 510,949 568,043 ----------- ---------- Property, Plant and Equipment, net 5,892,435 5,082,612 Investments 453,080 440,518 Notes receivable 3,030 3,095 Intangibles, net 563,742 563,397 Deferred charges and other assets 71,971 75,001 ----------- ---------- TOTAL ASSETS $7,495,207 $6,732,666 =========== ========== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Trade $ 129,115 $ 111,853 Related parties 68,528 9,235 Current portion of long-term debt 538,582 560,219 Accrued interest 19,195 34,099 Deferred revenues 2,664 2,786 Gas imbalances 97,388 34,660 Accrued other liabilities 190,426 209,852 ----------- ---------- 1,045,898 962,704 ----------- ---------- Long-Term Liabilities and Deferred Credits Long-term debt 2,959,661 2,231,574 Deferred revenues 28,657 29,110 Deferred income taxes 38,544 38,544 Other 277,761 246,464 ----------- ---------- 3,304,623 2,545,692 ----------- ---------- Commitments and Contingencies Minority Interest 64,480 65,236 ----------- ---------- Partners' Capital Common Units 1,886,229 1,894,677 Class B Units 125,376 125,750 i-Units 1,034,947 1,020,153 General Partner 61,123 54,628 Accumulated other comprehensive income (loss) (27,469) 63,826 ----------- ---------- 3,080,206 3,159,034 ----------- ---------- TOTAL LIABILITIES AND PARTNERS' CAPITAL $7,495,207 $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) Three Months Ended March 31, 2002 2001 ---------- ---------- Cash Flows From Operating Activities Net income $141,433 $101,667 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 41,326 30,075 Amortization of excess cost of equity investments 1,394 2,253 Earnings from equity investments (23,271) (21,203) Distributions from equity investments 6,177 10,521 Changes in components of working capital 58,998 (9,424) Other, net (3,486) 23,933 ---------- ---------- Net Cash Provided by Operating Activities 222,571 137,822 ---------- ---------- Cash Flows From Investing Activities Acquisitions of assets (758,340) (1,015,594) Additions to property, plant and equipment for expansion and maintenance (91,038) (39,881) projects Sale of investments, property, plant and equipment, net of removal costs (363) 8,047 Contributions to equity investments (291) (1,244) Other 758 (3,148) ---------- ------------ Net Cash Used in Investing Activities (849,274) (1,051,820) ---------- ------------ Cash Flows From Financing Activities Issuance of debt 1,800,337 3,067,734 Payment of debt (1,075,591) (1,849,301) Debt issue costs (60) (6,989) Distributions to partners: Common units (71,424) (61,011) Class B units (2,922) -- General Partner (55,300) (33,398) Minority interest (2,651) (2,274) Other, net 778 (325) ----------- ------------ Net Cash Provided by Financing Activities 593,167 1,114,436 ----------- ------------ Increase in Cash and Cash Equivalents (33,536) 200,438 Cash and Cash Equivalents, beginning of period 62,802 59,319 ----------- ------------ Cash and Cash Equivalents, end of period $29,266 $ 259,757 =========== ============ Noncash Investing and Financing Activities: Assets acquired by the assumption of liabilities 105,597 $259,634 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. Critical Accounting Policies and Estimates Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of our financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect: o the amounts we report for assets and liabilities; o our disclosure of contingent assets and liabilities at the date of the financial statements; and o the amounts we report for revenues and expenses during the reporting period. Therefore, the reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, provisions for uncollectible accounts receivable, exposures under contractual indemnifications and various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. In addition, we are subject to litigation as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. These revisions are reflected in our income in the period in which they are reasonably determinable. 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. 6 2. Acquisitions and Joint Ventures During the first quarter 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 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 $9.1 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 expands our growing bulk terminal operations and is part of our Terminals business segment. At March 31, 2002, we allocated our purchase price to property, plant and equipment. In the second quarter of 2002, we plan on making our final allocation to assets acquired and liabilities assumed. Our purchase price and our estimated allocation to assets acquired and liabilities assumed is as follows (in thousands): Purchase price: Cash paid, including transaction costs $ 9,101 Debt assumed 357 Liabilities assumed 2,967 ------- Total purchase price $12,425 ======= Allocation of purchase price: Current assets $ 879 Property, plant and equipment 11,546 ------- $12,425 ======= 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. 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 and we include IMT as part of our Terminals business segment. At March 31, 2002, we allocated our purchase price to property, plant and equipment. In the second quarter of 2002, we plan on making our final allocation to assets acquired and liabilities assumed. Our purchase price and our estimated allocation to assets acquired and liabilities assumed is as follows (in thousands): 7 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 $687.2 million and the assumption of approximately $103.8 million of liabilities. The acquisition cost will be modified by purchase price adjustments in the second quarter of 2002. Tejas Gas, LLC is primarily comprised 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, among other things, the final purchase price adjustments. Our estimated allocation to assets acquired and liabilities assumed is as follows (in thousands): Purchase price: Cash paid, including transaction costs $ 687,208 Liabilities assumed 103,787 ---------- Total purchase price $ 790,995 ========== Allocation of purchase price: Current assets $ 96,108 Property, plant and equipment 694,887 ---------- $ 790,995 ========== Pro Forma Information The following summarized unaudited Pro Forma Consolidated Income Statement information for the three months ended March 31, 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 Three Months Ended March 31, 2002 2001 ---- ---- (Unaudited) Revenues $1,044,811 $1,951,897 Operating Income 171,499 162,755 Net Income 141,028 126,586 Basic and diluted Limited Partners' Net Income per unit $ 0.48 $ 0.43 Acquisitions Subsequent to March 31, 2002 On December 12, 2001, we announced that we had signed a definitive agreement to acquire the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68 million in cash. The transaction closed on May 6, 2002. Following the acquisition, 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. At March 31, 2002, we allocated this payment to property, 8 plant and equipment. 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 the CALNEV pipeline and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings 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. 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; 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. 9 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 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 10 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. 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. 154-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 11 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. On November 7, 2001, the FERC issued an order ruling on the petitions for rehearing of Opinion No. 435-B. The Commission 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 Commission 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 Commission'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 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 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. SFPP submitted its compliance filing and tariffs implementing Opinion No. 435-B and the Commission's November 7, 2001 order on November 20, 2001. 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 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. Motions to intervene and protest the December 14, 2001 corrected submissions were filed by Navajo, ARCO and Mobil. 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 Commission clarify whether 12 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 Commission to stay that requirement pending judicial review. On April 8, 2002, SFPP filed a petition for review of the Commission's February 15, 2002 Order in the U.S. Court of Appeals for the District of Columbia Circuit. On April 9, 2002, the Court of Appeals consolidated that petition with the consolidated petitions for review of the Commission's prior orders and directed the parties "to file motions to govern future proceedings" by May 9, 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 Commission 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. 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. 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 13 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 latter half 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. Indexing protests. In June 2001, ARCO, Tosco, and Ultramar protested SFPP's adjustment to its interstate rates in compliance with the Commission's indexing regulations. Following submissions by the protestants and SFPP, the Commission issued an order in September 2001 dismissing the protests and finding that SFPP had complied with the Commission's indexing regulations. We are not able to predict with certainty the final outcome of the FERC proceedings, 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. Indexing protests. In June 2001, CALNEV filed to adjust its interstate rates upward pursuant to the FERC's indexing regulations. ARCO, ExxonMobil, Ultramar Diamond Shamrock and Ultramar, Inc. protested this adjustment. FERC accepted and suspended the rate adjustment and permitted it to go into effect subject to refund. In September 2001, following submission by CALNEV of its Form No. 6 annual report and further submissions by ARCO and CALNEV, the Commission dismissed the protests, finding that CALNEV's rate adjustment comported with the Commission's indexing regulations. OR01-08. In August 2001, ARCO filed a complaint against CALNEV's interstate rates alleging that they were unjust and unreasonable. Tosco and Ultramar filed interventions and subsequently filed complaints. In October 2001, the Commission set this claim for investigation and hearing. The matter was first referred to a settlement judge. On November 14, 2001, CALNEV filed a motion for rehearing or, in the alternative, clarification of the Commission's October 2001 order. CALNEV asserted that the Commission should have dismissed ARCO's complaint because it did not meet the standards of the Commission's regulations or, in the alternative, that the Commission should clarify the standards of pleading and proof applicable to ARCO's complaint. Settlement negotiations commenced in January 2002. In April 2002, CALNEV and the complainants were able to reach a mutually agreeable resolution of the disputed claims, and a settlement agreement was executed. Under the terms of the settlement agreement, the parties have filed a joint motion for dismissal of the pending complaints and termination of the proceeding. The parties are awaiting commission action on these motions. 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. 14 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. We believe that the resolution of such matters will not have a material 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 is accruing amounts for payment of the rental for the subject rights-of-way consistent with our expectations of the ultimate outcome of the proceeding. We expect this matter to go to trial during the second quarter of 2002. 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 Commission. 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. KMIGT currently expects that it may not have a fully compliant Order 637 tariff approved and in effect until sometime in the second or third quarter of 2002. 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. 15 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 Commission'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 Commission's decision to allow forward-hauls and backhauls to the same point. Finally, the D.C. Circuit held that several aspects of the Commission's segmentation policy and its policy on discounting at alternate points were not ripe for review. 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. Most of the tariff provisions will have an effective date of January 1, 2002, with the exception of language related to scheduling and segmentation, which will become effective at a future date dependent on when KMIGT's Order No. 637 provisions go into effect. 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. The Proposed Rulemaking is awaiting further Commission 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. 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 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 16 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. As of the date of this disclosure no written judgment has been entered. 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. 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. Defendants have sought an extension of time to answer, and have not yet responded to the Petition. There are no further pretrial proceedings at this time. Quinque Operating Company, et al. v. Gas Pipelines, et al. ----------------------------------------------------------- Cause No. 99-1390-CM, United States District Court for the District of Kansas. This action was originally filed 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. The plaintiffs in the case seek to have the Court certify the case as a class action. The plaintiffs are natural gas producers and fee royalty owners who allege that they have been subject to systematic mismeasurement of natural gas by the defendants for more than 25 years. Among other things, the plaintiffs allege a conspiracy among the pipeline industry to under-measure natural gas and have asserted joint and several liability against the defendants. Subsequently, one of the defendants removed the action to Kansas Federal District Court. 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, styled as United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the United States District Court, District of Colorado, because of common factual questions. On April 10, 2000, the Multidistrict Litigation 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. A case management conference recently occurred in State Court in Stevens County, and a briefing schedule was established for preliminary matters. Personal jurisdiction discovery has commenced. Merits discovery has not commenced. Recently, the defendants filed a motion to dismiss on grounds other than personal jurisdiction and a motion to dismiss for lack of personal jurisdiction for non-resident defendants. Although no assurances can be given, we believe that we have meritorious defenses to all of these actions, that 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. 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 thereunder, 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: o one cleanup ordered by the United States Environmental Protection Agency related to ground water 17 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; and 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. 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. Review of assets related to Kinder Morgan Interstate Gas Transmission LLC includes the environmental impacts from petroleum and used oil releases to the soil and groundwater at nine sites. Additionally, review of assets related to Kinder Morgan Texas Pipeline includes the environmental impacts from petroleum releases to the soil and groundwater at six sites. Further delineation and remediation of these impacts 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 verdict was divided with the following award of damages: o $0.3 million compensatory damages for property damage to the Evelyn Chandler Trust; o $5 million compensatory damages to Walter (Buster) Chandler; o $1.5 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 twelve to eighteen 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. A current remediation effort is taking place between Chevron, Plantation and Alabama Department of Environmental Management. 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 $72.6 million at March 31, 2002. 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. 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. 18 5. Distributions On February 14, 2002, we paid a cash distribution for the quarterly period ended December 31, 2001, of $0.55 per unit 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 $0.55 cash distribution per common unit. The distributions were declared on January 16, 2002, payable to unitholders of record as of January 31, 2002. On April 17, 2002, we declared a cash distribution for the quarterly period ended March 31, 2002, of $0.59 per unit. The distribution will be paid on or before May 15, 2002, to unitholders of record as of April 30, 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 $0.59 distribution per common unit. The number of i-units distributed will be 527,572. 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 April 12-25, 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, however, 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. As of March 31, 2002, we have not completed a transitional test for goodwill impairment. We intend to complete this test during the second quarter of 2002. 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): March 31, December 31, 2002 2001 ---------- ------------- Goodwill $567,050 $566,633 Accumulated amortization (19,899) (19,899) ---------- ----------- Goodwill, net 547,151 546,734 ---------- ----------- Lease value 6,124 6,124 Contracts and other 10,712 10,739 Accumulated amortization (245) (200) ----------- ------------ Other intangibles, net 16,591 16,663 ----------- ------------ Total intangibles, net $563,742 $563,397 =========== ============ Changes in the carrying amount of goodwill for the quarter ended March 31, 2002 are summarized as follows (in thousands): Natural Products Gas CO2 Pipelines Pipeline Pipeline 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 ======== ======= ======= ======== ======== 19 Amortization expense consists of the following (in thousands): Three Months Ended March 31, ----------------- 2002 2001 ----------------- Goodwill $ -- $2,582 Lease value 35 1,397 Contracts and other 10 138 ------ ------ $ 45 $4,117 ====== ====== 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): Three Months Ended March 31, ----------------- 2002 2001 ------- ------- Reported limited partners' interest in net income $ 79,639 $ 60,045 Add: limited partners' interest in goodwill amortization -- 2,557 ------- ------- Adjusted limited partners' interest in net income $ 79,539 $ 62,602 ======== ======== Basic limited partners' net income per unit: Reported net income $ 0.48 $ 0.44 Goodwill amortization -- 0.02 -------- -------- Adjusted net income $ 0.48 $ 0.46 ======== ======== Diluted limited partners' net income per unit: Reported net income $ 0.48 $ 0.44 Goodwill amortization -- 0.02 --------- -------- Adjusted net income $ 0.48 $ 0.46 ======== ======== 7. Debt Our debt and credit facilities as of March 31, 2002, consist primarily of: o an $85.2 million unsecured two-year credit facility due June 29, 2003 (Trailblazer Pipeline Company is the obligor on the facility); 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; o a $300 million unsecured five-year credit facility due September 29, 2004; o $200 million of 8.00% Senior Notes due March 15, 2005; 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 $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal District Revenue Bonds due March 15, 2006 (assumed as part of our IMT acquisition, see Note 2.); 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 $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; 20 o $300 million of 7.75% Senior Notes due March 15, 2032; o $79.6 million of Series F First Mortgage Notes due December 2004 (our subsidiary, SFPP, L.P. is the obligor on the notes); 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 $35 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); and o a $1.25 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. Our short-term debt at March 31, 2002, consisted of: o $763.9 million of commercial paper borrowings; o $42.5 million under the SFPP, L.P. 10.7% First Mortgage Notes; o $5.0 million under the Central Florida Pipeline LLC Notes; and o $3.5 million in other borrowings. We intend and have the ability to refinance $276.3 million of our short-term debt on a long-term basis under our unsecured five-year credit facility. We do not anticipate any liquidity problems. Our average interest rate for outstanding borrowings during the first quarter of 2002 was approximately 5.172% per annum. For additional information regarding our debt facilities, see Note 9 to our consolidated financial statements included in our Form 10-K for the year ended December 31, 2001. Credit Facilities On December 31, 2001, we had two credit facilities with a syndicate of financial institutions. They consisted of a $300 million unsecured five-year credit facility expiring on September 29, 2004 and a $750 million unsecured 364-day credit facility expiring on October 23, 2002. There were no borrowings under either credit facility at December 31, 2001 or during the first quarter of 2002. On February 21, 2002, we obtained a third unsecured 364-day credit facility, in the amount of $750 million, expiring on February 20, 2003. The credit facility was used to support the increase in our commercial paper program to $1.8 billion for our acquisition of Tejas Gas, LLC. The terms of this credit facility are substantially similar to the terms of our other two credit facilities. Upon issuance of additional senior notes in March 2002, this short-term credit facility was reduced to $200 million. As of March 31, 2002, no borrowings were outstanding under this credit facility. Our three credit facilities are with a syndicate of financial institutions. First Union National Bank is the administrative agent under our five-year credit facility and our 364-day facility that expires on October 23, 2002. JPMorgan Chase Bank is the administrative agent under our 364-day facility that expires on February 20, 2003. Interest on these three credit facilities accrues at our option at a floating rate equal to either: o the applicable 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 five-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate. The amount available for borrowing under our five-year credit facility is reduced by a $23.7 million letter of credit that supports Kinder Morgan Operating L.P. "B"'s tax-exempt bonds and our outstanding commercial paper borrowings. Senior Notes On March 14, 2002, we closed a public offering of $750 million in principal amount of senior notes, consisting of $450 million in principal amount of 7.125% senior notes due March 15, 2012 at a price to the public of 99.535% per note, and $300 million in principal amount of 7.75% senior notes due March 15, 2032 at a price to the public of 21 99.492% per note. The terms of these notes are substantially similar to the terms of our other senior notes. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $445.0 million for the 7.125% notes and $295.9 million for the 7.75% notes. We used the proceeds to reduce our outstanding balance on our commercial paper borrowings. On March 22, 2002, we paid $200 million to retire the principal amount of our Floating Rate senior notes that matured on that date. We borrowed the necessary funds under our commercial paper program. At March 31, 2002, our unamortized liability balance due on the various series of our senior notes were as follows (in millions): 8.0% senior notes due March 15, 2005 $ 199.8 6.30% senior notes due February 1, 2009 249.4 7.5% senior notes due November 1, 2010 248.6 6.75% senior notes due March 15, 2011 698.2 7.125% senior notes due March 15, 2012 447.9 7.40% senior notes due March 15, 2031 299.3 7.75% senior notes due March 15, 2032 298.5 -------- Total $2,441.7 ======== Commercial Paper Program As of December 31, 2001, we had $590.5 million of commercial paper outstanding with an interest rate of 2.6585%. On February 21, 2002, our commercial paper program increased to provide for the issuance of up to $1.8 billion of commercial paper. We entered into a $750 million unsecured 364-day credit facility to support this increase in our commercial paper program, and we used the program's increase in available funds to close on the Tejas acquisition. After the issuance of additional senior notes on March 14, 2002, we reduced our commercial paper program to $1.25 billion. As of March 31, 2002, we had $763.9 million of commercial paper outstanding with an interest rate of 2.455%. Trailblazer Pipeline Company Debt At March 31, 2002, the outstanding balance under Trailblazer's $85.2 million two-year revolving credit facility was $60.0 million. The revolving credit facility expires on June 29, 2003, and had a weighted average interest rate of 2.77% at March 31, 2002, which reflects LIBOR plus a margin of 0.875%. Pursuant to the terms of the revolving credit facility, Trailblazer partnership distributions are restricted by certain financial covenants. 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 first quarter of 2002, the weighted-average interest rate on these bonds was 1.29% per annum, and at March 31, 2002, the interest rate was 1.51%. 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. Cortez Pipeline Company Debt Pursuant to a certain Throughput and Deficiency Agreement, the owners of Cortez Pipeline Company are required to contribute capital to Cortez in the event of a cash deficiency. The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the owners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including cash deficiencies relating to the repayment of principal and interest. Their respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement. Due to our indirect ownership of Cortez through KMCO2, 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's debt programs in place as of April 1, 2000. At March 31, 2002, the debt facilities of Cortez Capital Corporation consisted of: o a $127 million uncommitted 364-day revolving credit facility; 22 <page> o a $48 million committed 364-day revolving credit facility; o $136.4 million of Series D notes; and o a $175 million short-term commercial paper program. At March 31, 2002, Cortez had $138 million of commercial paper outstanding with an interest rate of 1.83%, the average interest rate on the series D notes was 6.8579% and there were no borrowings under the credit facilities. 8. Partners' Capital At March 31, 2002, our partners' capital consisted of 129,893,618 common units, 5,313,400 class B units and 31,090,333 i-units. Together, these 166,297,351 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 110,178,342 units held by third parties, 17,991,276 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 common unit total 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 and our i-units were initially issued in May 2001. The i-units are a separate class of limited partner interest in the Partnership. All of the i-units are owned by Kinder Morgan Management, LLC and are not publicly traded. 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 agree 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. Typically, if 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 453,970 i-units on February 14, 2002. These additional i-units distributed were based on the $0.55 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 allocated to our general partner are determined by the amount that quarterly distributions to unitholders exceed certain specified target levels. Our distribution of $0.55 per unit paid on February 14, 2002 for the fourth quarter of 2001 required an incentive distribution to our general partner of $54.4 million. Our distribution of $0.475 per unit paid on February 14, 2001 for the fourth quarter of 2000 required an incentive distribution to our general partner of $32.8 million. The increased incentive distribution to our general partner paid for the fourth quarter of 2001 over the distribution paid for the fourth quarter of 2000 reflects the increase in the amount distributed per unit as well as the issuance of additional units. Our declared distribution for the first quarter of 2002 of $0.59 per unit will result in an incentive distribution to our general partner of $61.0 million. This compares to our distribution of $0.525 per unit and incentive distribution to our general partner of $41.0 million for the first 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 quarters ended March 31, 2002 and 2001, the only difference between our net income and our comprehensive income was the unrealized gain or loss on 23 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 Three Months Ended Ended March 31, 2002 March 31, 2001 -------------- ------------- Net income $ 141,433 $ 101,667 Cumulative effect transition adjustment -- (22,797) Change in fair value of derivatives used for hedging purposes (66,936) (20,209) Reclassification of change in fair value of derivatives to net income (24,359) 40,258 ----------- ---------- Comprehensive income $ 50,138 $ 98,919 =========== ========== 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 and associated transportation, natural gas liquids, crude oil and carbon dioxide. Through Kinder Morgan, Inc., we use energy financial instruments to reduce our risk of price changes in the spot and fixed price 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. Approximately $0.8 million was recognized in earnings as a gain during the first quarter of 2002 as a result of ineffectiveness of these hedges, which amount is reported within the caption Operations and maintenance in the accompanying Consolidated Statements of Income. For the first quarter of 2001, approximately $0.3 million was recognized in earnings as a loss as a result of ineffectiveness of these hedges. For each of the quarters ended March 31, 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 $21.7 million of the Accumulated other comprehensive income balance of $27.5 million representing unrecognized net losses on derivative activities at March 31, 2002 is expected to be reclassified into earnings during the next twelve months. During the quarter ended March 31, 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 March 31, 2002, our balance of $91.3 million of other current assets includes approximately $60.7 million related to risk management activities, and our balance of $190.4 million of accrued other current liabilities includes approximately $83.0 million related to risk management activities. At 24 <page> December 31, 2001, our balance of $194.9 million of other current assets includes approximately $163.7 million related to risk management activities, and our balance of $209.9 million of accrued other current liabilities includes approximately $117.8 million related to risk management activities. The remaining differences between the current market value and the original physical contracts value associated with hedging activities are reflected as deferred charges or deferred credits in the accompanying consolidated balance sheets. 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 March 31, 2002, we have entered into interest rate swap agreements with a notional principal amount of $1.3 billion for the purpose of hedging the interest rate risk associated with our fixed rate debt obligations. These agreements effectively convert 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 8.0% senior notes due March 15, 2005; o 6.30% senior notes due February 1, 2009; o 7.125% senior notes due March 15, 2012; o 7.40% senior notes due March 15, 2031; and o 7.75% senior notes due March 15, 2032. 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 7.75% 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. These 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 will 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 will record interest expense equal to the variable rate payments, which will be accrued monthly and paid semi-annually. At March 31, 2002, we recognized a liability of $23.9 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. At December 31, 2001, we recognized a liability of $5.4 million for the net fair value of our swap agreements. We are exposed to credit related losses in the event of nonperformance by counterparties to these interest rate swap agreements, but, given their existing credit ratings, we do not expect any counterparties to fail to met their obligations. 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 and transmission 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. Our Terminals segment derives its revenues primarily from the 25 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 March 31, 2002 2001 -------- ---------- Revenues Products Pipelines $134,818 $ 190,693 Natural Gas Pipelines 537,557 726,285 CO2 Pipelines 32,124 29,102 Terminals 98,566 82,565 -------- ----------- Total consolidated revenues $803,065 $ 1,028,645 ======== =========== Operating income Products Pipelines $ 77,542 $ 67,035 Natural Gas Pipelines 61,474 53,386 CO2 Pipelines 12,524 14,452 Terminals 40,663 32,063 -------- ----------- Total segment operating income 192,203 166,936 Corporate administrative expenses (26,347) (28,585) -------- ----------- Total consolidated operating Income $165,856 $ 138,351 ======== =========== Earnings from equity investments, net of amortization of excess costs Products Pipelines $ 7,180 $ 4,915 Natural Gas Pipelines 6,056 5,276 CO2 Pipelines 8,641 8,759 Terminals -- -- -------- ----------- Consolidated equity earnings, net $ 21,877 $ 18,950 of amortization ======== =========== Income taxes and Other, net - income (expense) Products Pipelines $ (2,775) $ (2,102) Natural Gas Pipelines 5 10 CO2 Pipelines 94 251 Terminals (1,775) (984) --------- ------------ Total consolidated income taxes $ (4,451) $ (2,825) and Other, net ========= ============ Segment Earnings Products Pipelines $ 81,947 $ 69,848 Natural Gas Pipelines 67,535 58,672 CO2 Pipelines 21,259 23,462 Terminals 38,888 31,079 -------- ----------- Total segment earnings 209,629 183,061 Interest and corporate (68,196) (81,394) administrative expenses (a) --------- ----------- Total consolidated net income $141,433 $ 101,667 (a) Includes interest expense, ======== ============ general and administrative expenses, minority interest and other insignificant items. Mar. 31, Dec. 31, 2002 2001 ---------- ---------- Assets Products Pipelines $3,160,609 $3,095,899 Natural Gas Pipelines 2,752,323 2,058,836 CO2 Pipelines 510,009 503,565 Terminals 1,016,511 990,760 ---------- ---------- Total segment assets 7,439,452 6,649,060 Corporate assets (a) 55,755 83,606 ---------- ---------- Total consolidated assets $7,495,207 $6,732,666 ========== ========== (a) Includes cash, cash equivalents and certain unallocable deferred charges 26 12. New Accounting Pronouncements Statement of Financial Accounting Standards No. 141 "Business Combinations" supercedes Accounting Principles Board Opinion No. 16 and requires that all transactions fitting the description of a business combination be accounted for using the purchase method and prohibits the use of the pooling of interests for all business combinations initiated after June 30, 2001. The Statement also modifies the accounting for the excess of fair value of net assets acquired as well as intangible assets acquired in a business combination. The provisions of this statement apply to all business combinations initiated after June 30, 2001, and all business combinations accounted for by the purchase method that are completed after July 1, 2001. This Statement requires disclosure of the primary reasons for a business combination and the allocation of the purchase price paid to the assets acquired and liabilities assumed by major balance sheet caption. We adopted SFAS No. 141 on January 1, 2002. Refer to Note 2 for more detail about our acquisitions. Statement of Financial Accounting Standards No. 142 "Goodwill and Other Intangible Assets" supercedes Accounting Principles Board Opinion No. 17 and requires that goodwill no longer be amortized but should be tested, at least on an annual basis, for impairment. A benchmark assessment of potential impairment must also be completed within six months of adopting SFAS No. 142. We intend to make our initial assessment during the second quarter of 2002. After the first six months, goodwill will be tested for impairment annually. SFAS No. 142 applies to any goodwill acquired in a business combination completed after June 30, 2001. Other intangible assets are to be amortized over their useful life and reviewed for impairment in accordance with the provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of". An intangible asset with an indefinite useful life can no longer be amortized until its useful life becomes determinable. This Statement requires disclosure of information about goodwill and other intangible assets in the years subsequent to their acquisition that was not previously required. Required disclosures include information about the changes in the carrying amount of goodwill from period to period and the carrying amount of intangible assets by major intangible asset class. After June 30, 2001, we completed two acquisitions, our Boswell and Stolt-Nielsen acquisitions, which resulted in the recognition of goodwill. We adopted SFAS No. 142 on January 1, 2002, and we expect that SFAS No. 142 will not have a material impact on our business, financial position or results of operations. With the adoption of SFAS No. 142, goodwill of approximately $547.2 million at March 31, 2002 is no longer subject to amortization over its estimated useful life. 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 discounted to its present 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 do not expect that SFAS No. 143 will have a material impact on our business, financial position or results of operations. Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" retains the requirements of SFAS 121, mentioned above; however, this statement requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell it. Furthermore, the scope of discontinued operations is expanded to include all components of an entity with operations of the entity in a disposal transaction. We adopted SFAS No. 144 on January 1, 2002 and the adoption has not had a material impact on our business, financial position or results of operations. 27 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. Results of Operations First Quarter 2002 Compared With First Quarter 2001 Our first quarter results continued to reflect solid returns from both our existing assets and our recently acquired assets, including the operating results of Kinder Morgan Tejas, which was acquired effective January 31, 2002. The acquisition of Kinder Morgan Tejas was one of our largest acquisitions since our current management took control of our general partner in February 1997, and the inclusion of Kinder Morgan Tejas' operating results in the first quarter of 2002 operating results helped us to reach record levels of quarterly operating income and net income. 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. By combining these intrastate pipeline systems, we expect to recognize operational synergies, increase transportation capacity, improve reliability and create additional services for our customer base. Our net income was $141.4 million ($0.48 per diluted unit) on revenues of $803.1 million in the first quarter of 2002, compared to net income of $101.7 million ($0.44 per diluted unit) on revenues of $1,028.6 million in the first quarter of 2001. Total consolidated operating income was $165.9 million in the first quarter of 2002 versus $138.4 million in the same period last year. Our operating expenses, consisting of gas purchases and other cost of sales, fuel, power and operating and maintenance expenses were $553.8 million in the first quarter of 2002 compared with $818.0 million in the same period a year ago. First quarter earnings from equity investments, net of amortization of excess costs, were $21.9 million in 2002 versus $19.0 million in 2001. In addition, we declared a record cash distribution of $0.59 per unit for the first quarter of 2002 (an annualized rate of $2.36). Our first quarter 2002 distribution is up 12% from the $0.525 per unit distribution made for the first quarter of 2001. Products Pipelines Our Products Pipelines segment reported earnings of $81.9 million on revenues of $134.8 million in the first quarter of 2002. In the first quarter of 2001, the segment reported earnings of $69.8 million on revenues of $190.7 million. The $55.9 million (29%) decrease in quarter-to-quarter segment revenues includes a reduction of $68.1 million in transmix revenues resulting from the Duke contract as described below and a reduction of $1.7 million in operating reimbursements from Plantation Pipe Line Company. 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 $11.6 million in revenues earned by CALNEV Pipe Line LLC and an increase of $1.6 million in revenues earned from our ownership interest in the Cochin Pipeline System. The increases reflect our acquisitions of CALNEV on March 30, 2001 from GATX Corporation and an additional 10% interest in Cochin (bringing our total interest to 44.8%) effective December 31, 2001. Revenues from our Pacific operations increased $1.4 million (2%) primarily as a result of higher average tariff rates, partially offset by lower non-transportation revenues. Combined operating expenses for our Products Pipelines segment were $35.5 million in the first quarter of 2002 versus $103.8 million in the first quarter of 2001. The reduction in expenses was primarily due to our agreement with Duke Energy Merchants, which largely reduced our cost of products sold. Lower accrued operating and maintenance expenses on the Central Florida Pipeline and at our West Coast liquids terminal businesses, both acquired from GATX Corporation on January 1, 2001, also contributed to the decrease in segment operating expenses. The overall decrease in segment operating expenses was partially 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 $7.2 million in the first quarter of 2002 versus $4.9 million in the same quarter of 2001. The $2.3 million increase was mainly related to higher equity earnings from our 51% ownership interest in Plantation Pipe Line Company. Plantation reported higher revenues and lower operating and interest expenses during the first quarter of 2002 compared to the first quarter of 2001. 28 Natural Gas Pipelines Our Natural Gas Pipelines segment reported earnings of $67.5 million on revenues of $537.6 million in the first quarter of 2002. In the first quarter of 2001, the segment reported earnings of $58.7 million on revenues of $726.3 million. The $188.7 million decrease in segment revenues reflects a $394.7 million decline in revenues from the segment's Kinder Morgan Texas Pipeline system, primarily due to lower gas prices. Offsetting the overall decrease in segment revenues was the inclusion of $246.8 million of revenues earned by Kinder Morgan Tejas and a $3.6 million (9%) increase in natural gas transportation revenues earned by Kinder Morgan Texas Pipeline, Kinder Morgan Intrastate Gas Transmission and Trailblazer Pipeline Company, mainly the result of an 8% increase in transportation volumes. The segment's operating expenses totaled $461.3 million in the first quarter of 2002 and $662.1 million in the first quarter of 2001. The $200.8 million decrease in segment operating expenses primarily resulted from the drop in natural gas prices. KMTP reported a $404.4 million decrease in operating expenses, mostly consisting of lower gas purchase costs, and KMIGT reported an $11.5 million decrease in operating expenses, mostly due to lower fuel costs and less fuel lost and unaccounted for. The overall decrease in segment operating expenses was partially offset by the inclusion of $232.9 million in expenses from newly acquired Kinder Morgan Tejas, as well as by higher expenses on the Trailblazer Pipeline, mainly the result of favorable system imbalance settlements made in February 2001. For the two months ended March 31, 2002, Kinder Morgan Tejas reported earnings of $10.9 million. Furthermore, Earnings from equity investments, net of amortization of excess costs, were $6.1 million for the first quarter of 2002 versus $5.3 million for the same prior year period. The $0.8 million increase 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 $21.3 million on revenues of $32.1 million in the first quarter of 2002. Combined operating expenses totaled $10.8 million for the current quarter. For the same period last year, our CO2 Pipelines segment reported earnings of $23.5 million, revenues of $29.1 million and combined operating expenses of $8.5 million. The 10% increase in segment revenues was primarily due to increased oil production volumes from the SACROC Unit. The decline in segment earnings was primarily due to higher depreciation, depletion and amortization charges and to an increase in fuel and power expenses. Non-cash depreciation charges were up $3.4 million as a result of higher production volumes, the capital expenditures and acquisitions made since the end of the first quarter of 2001 and a change in the calculation of our depreciation rate. Higher fuel and power expenses were associated with higher energy prices and the increase in volumes. The segment reported $8.6 million of equity earnings, net of amortization of excess costs, in the first quarter of 2002 compared to $8.8 million in the first quarter of 2001. Equity earnings represent the returns from the segment's 50% ownership interest in Cortez Pipeline Company and from its 15% ownership interest in MKM Partners, L.P. Terminals Our Terminals segment, which includes both our bulk and liquid terminal businesses, reported earnings of $38.9 million, revenues of $98.6 million and operating expenses of $46.2 million in the first quarter of 2002. This compares to earnings of $31.1 million, revenues of $82.6 million and operating expenses of $43.5 million in the first quarter of 2001. The quarter-to-quarter increase in segment revenue was driven by key acquisitions we have made since March 2001, including: o Pinney Dock & Transport LLC, acquired effective March 1, 2001; o the terminal businesses we acquired from Koninklijke Vopak N.V., effective July 10, 2001; 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; and o a 66 2/3% interest in International Marine Terminals Partnership, 33 1/3% interest acquired effective January 1, 2002 and an additional 33 1/3% interest acquired effective February 1, 2002. In the first quarter of 2002, the acquisitions listed above generated revenues of $23.6 million. Revenues from our bulk terminals owned during both periods declined in the first quarter of 2002 due to a 5% decrease in transload volumes. The decline in volumes was attributable to the mild winter that reduced both coal and road salt tonnage. Revenues from our liquids terminals owned during both periods were relatively flat, given continued high levels of utilization (97%). In the future, we expect that these high utilization levels will result in expansion opportunities and/or higher prices. The $2.7 million increase in segment operating expenses in the first quarter of 29 2002 compared to the first quarter of 2001 was mainly the result of the $158.4 million in terminal acquisitions made since the first quarter of 2001, partially offset by lower engineering expenses. Segment Operating Statistics Operating statistics for the first three months of 2002 and 2001 are as follows: Three Months Ended March 31, March 31, 2002 2001 ---- ---- Products Pipelines Gasoline 108.2 100.8 Diesel 36.5 40.2 Jet Fuel 26.3 30.3 NGL's 11.1 11.2 ----- ----- Total Delivery Volumes (MBbl)(1) 182.1 182.5 Natural Gas Pipelines Transport Volumes (Bcf) (2) 214.6 208.1 CO2 Pipelines Delivery Volumes (Bcf) (3) 113.1 98.7 Terminals Bulk Terminals Transload Tonnage (MMtons)(4) 12.6 13.3 Liquids Terminals Leaseable Capacity (MMBbl) 34.5 30.9 Utilization % 97% 97% Note: Historical pro forma for acquired assets. (1) Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress and Heartland pipeline volumes. (2) Includes KMIGT, KMTP, KM 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 $68.2 million in the first quarter of 2002 versus $81.4 million in the first quarter of 2001. Our general and administrative expenses totaled $26.4 million in the first quarter of 2002 compared with $28.6 million in the first quarter of 2001. The quarter-to-quarter decrease in general and administrative expenses was mainly due to reduced expense relating to the pipeline and terminal businesses that we acquired from GATX Corporation in 2001. In addition, during the first quarter of 2001, we incurred additional administrative expenses related to natural gas and products pipeline assets. We acquired additional natural gas pipeline assets from Kinder Morgan, Inc. on December 31, 2000 and we began assuming Plantation Pipe Line Company's operations on December 21, 2000. We continue to manage aggressively our infrastructure expense and to focus on our productivity and expense controls. Our total interest expense, net of interest income, was $39.0 million in the first quarter of 2002 and $49.8 million in the first quarter of 2001. The decrease of $10.8 million was primarily due to lower average interest rates during the first quarter of 2002 compared with the same period in 2001, partially offset by slightly higher average borrowings. During the first quarter of 2002, we closed a public offering of $750 million in principal amount of senior notes and retired a maturing amount of $200 million 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): 30 March 31, 2002 Dec. 31, 2001 -------------- ------------- Long-term debt $2,959,661 $2,231,574 Minority interests 64,480 65,236 Partners' capital 3,080,206 3,159,034 -------------- ------------- Total capitalization 6,104,347 5,455,844 Short-term debt, less cash and cash equivalents 509,316 497,417 -------------- ------------- Total invested capital $ 6,613,663 $5,953,261 ============== ============= Capitalization: Long-term debt 48.5% 40.9% Minority interests 1.0% 1.2% Partners' capital 50.5% 57.9% Invested Capital: Total debt 52.5% 45.8% Partners' capital and minority interests 47.5% 54.2% 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 or issuing short-term commercial paper, long-term notes, additional common units or additional i-units to Kinder Morgan Management. In general, we expect to fund: o future cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; o expansion capital expenditures and working capital deficits through additional borrowings or issuance of additional common units or additional i-units to Kinder Morgan Management; o interest payments from cash flows from operating activities; and o debt principal payments with additional borrowings as they become due or by issuance of additional common units or additional i-units to Kinder Morgan Management. At March 31, 2002, our current commitments for capital expenditures were approximately $66.0 million. This amount has been committed primarily for the purchase of plant and equipment and is based on the payments we expect to need for our 2002 sustaining capital expenditure plan. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. Operating Activities Net cash provided by operating activities was $222.6 million for the three months ended March 31, 2002, versus $137.8 million in the comparable period of 2001. The period-to-period increase in cash flow from operations was the result of higher cash inflows relative to net changes in current operating liabilities as well as higher cash earnings from our business portfolio. Higher cash inflows from net settlements of transportation imbalances with shippers on our natural gas pipelines and gathering lines, and the additional operating cash flows generated from our CALNEV and Kinder Morgan Tejas acquisitions accounted for most of the increase. The overall increase in operating cash flows was partially offset by lower cash flows relative to net settlement of hedging assets and liabilities. Investing Activities Net cash used in investing activities was $849.3 million for the three months ended March 31, 2002, compared to $1,051.8 million in the comparable 2001 period. The $202.5 million decrease in funds utilized in investing activities primarily relates to the difference between the $700.9 million used to acquire Kinder Morgan Tejas in the first quarter of 2002, versus the $979.2 million used to purchase pipeline and terminal businesses from GATX Corporation in the first quarter of 2001. Offsetting the overall decline in funds used in investing activities was a $51.1 million increase in funds used for capital expenditures in the first quarter of 2002 compared to the first quarter of 2001. Including expansion and maintenance projects, our capital expenditures were $91.0 million in the first quarter of 2002. We spent $39.9 million for capital expenditures in the same year-ago period. The increase was driven primarily by continued investment in our Natural Gas Pipelines and Terminals business segments. Specifically, the increase relates to our previously announced construction of a $70 million, 86-mile, 30-inch natural 31 gas pipeline in Texas as well as an ongoing expansion project at our Carteret, New Jersey liquids terminal. Our sustaining capital expenditures were $13.2 million for the first quarter of 2002 compared to $16.3 million for the first quarter of 2001. Financing Activities Net cash provided by financing activities amounted to $593.2 million for the three months ended March 31, 2002. The decrease of $521.3 million from the comparable 2001 period was mainly the result of a $493.7 million decrease in funds from overall debt financing activities. The decrease reflects higher net debt issuance in the first quarter of 2001, as well as the payment of our maturing $200 million in principal amount of Floating Rate senior notes in March 2002. In March 2002, we completed a public offering of $750 million in principal amount of senior notes, resulting in a net cash inflow of approximately $740.8 million net of discounts and issuing costs. We used the proceeds to reduce our borrowings under our commercial paper program. In the first quarter of 2001, we completed a public offering of $1.0 billion in principal amount of senior notes, resulting in a net cash inflow of approximately $990 million net of discounts and issuing costs. We used the $990 million to pay for our acquisition of Pinney Dock & Transport LLC and to reduce our outstanding balance on our credit facilities and commercial paper borrowings. The overall decrease in funds provided by our financing activities also resulted from a $35.6 million increase in distributions to our partners. Distributions to all partners increased to $132.3 million in the first quarter of 2002 compared to $96.7 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. On February 14, 2002, we paid a quarterly distribution of $0.55 per unit for the fourth quarter of 2001, 16% greater than the $0.475 distribution paid for the fourth quarter of 2000. We paid this distribution in cash to our common unitholders and to our class B unitholders. Kinder Morgan Management, our sole i-unitholder, received additional i-units based on the $0.55 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 April 17, 2002, we declared a cash distribution for the quarterly period ended March 31, 2002, of $0.59 per unit. The distribution will be paid on or before May 15, 2002, to unitholders of record as of April 30, 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 $0.59 distribution per common unit. We believe that future operating results will continue to support similar levels of quarterly cash 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, 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 determines our quarterly 32 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, 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; 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 amount of cash being distributed. The general partner's incentive distribution for the distribution that we declared for the first quarter of 2002 was $61.0 million. The general partner's incentive distribution for the distribution that we declared for the first quarter of 2001 was $41.0 million. The general partner's incentive distribution that we paid to our general partner was $54.4 million during the first quarter of 2002 and $32.8 million during the first quarter of 2001. 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 within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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. The 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, which may be affected by consumer confidence, economic activity, political instability, weather, alternative energy sources, conservation and technological advances; 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 any difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to our terminals; 33 o our ability to successfully identify and close strategic 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 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; and o the political and economic stability of the oil producing nations of the world. 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. 34 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. None. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits 1.1 - Form of Underwriting Agreement dated March 11, 2002 between Kinder Morgan Energy Partners, L.P. and J.P. Morgan Securities Inc., First Union Securities, Inc., Banc One Capital Markets, Inc., BMO Nesbitt Burns Corp., Commerzbank Capital Markets Corp., Credit Lyonnais Securities (USA) Inc., Scotia Capital (USA) Inc. and Sun Trust Capital Markets, Inc. *2.1 - Purchase and Sale Agreement between Intergen (North America), Inc. and Kinder Morgan Energy Partners, L.P. dated December 15, 2001 (filed as Exhibit 2.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed March 15, 2002). *2.2 - First Supplement to Purchase and Sale Agreement between Intergen (North America), Inc. and Kinder Morgan Energy Partners, L.P. dated February 28, 2002 (filed as Exhibit 2.2 to Kindger Morgan Energy Partners, L.P. Form 8-K filed March 15, 2002). 4.1 - Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032. 4.2 - Specimen of 7.125% Notes due March 15, 2012 in book-entry form. 4.3 - Specimen of 7.750% Notes due March 15, 2032 in book-entry form. 4.4 - 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. *10.1 - Retention Agreement dated January 17, 2002, by and between Kinder Morgan, Inc. and C. Park Shaper (incorporated by reference from Exhibit 10(l) of Kinder Morgan, Inc.'s Annual Report on Form 10-K for the period ending December 31, 2001). 10.2 - Form of Third Amendment to Credit Agreement dated as of February 19, 2002 among Kinder Morgan Energy Partners, L.P. and the lender parties thereto. 10.3 - Form of Bridge Credit Agreement dated as of February 21, 2002 among Kinder Morgan Energy Partners, L.P. and the lenders party thereto. 11 - Statement re: computation of per share earnings - --------------------- * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. 35 (b) Reports on Form 8-K Current report dated January 16, 2002 on Form 8-K was filed on January 16, 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 several presentations on January 17, 2002 at the 2002 Kinder Morgan Analyst Conference to 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 March 11, 2002 on Form 8-K was filed on March 12, 2002, pursuant to Item 7 of that form. We filed the Consolidated Balance Sheet at December 31, 2001, of Kinder Morgan G.P., Inc., our general partner and a wholly-owned subsidiary of Kinder Morgan, Inc. as an exhibit pursuant to Item 7 of that form. Current report dated March 15, 2002 on Form 8-K was filed on March 15, 2002, pursuant to Items 2 and 7 of that form. We provided notice that on February 28, 2002, Kinder Morgan Operating L.P. "A", one of our operating partnerships, completed the acquisition of all the membership interests of Tejas Gas, LLC from InterGen (North America), Inc. The acquisition was effective as of January 31, 2002 and in consideration for the sale, we paid a base purchase price of approximately $684.5 million and assumed debt and other liabilities of approximately $71 million, net of working capital assets. We filed the following documents as exhibits pursuant to Item 7: o Purchase and Sale Agreement between InterGen (North America), Inc. and ourselves dated December 15, 2001; o First Supplement to Purchase and Sale Agreement between InterGen (North America), Inc. and ourselves dated February 28, 2002; and o Press release announcing the acquisition of Tejas Gas from InterGen (North America), Inc. issued February 28, 2002. 36 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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 By: /s/ C. Park Shaper ------------------------------ C. Park Shaper Vice President, Treasurer and Chief Financial Officer Date: May 10, 2002