-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, BgkHr2VGbrx9J4kcPmjMG2qeyzr8I1ZEmAaqLU+G/GiYoLPI01eWgF+EKDAMPm4n c19RQ1Fr8uqdpataj4qGEQ== 0001014108-03-000061.txt : 20030515 0001014108-03-000061.hdr.sgml : 20030515 20030514173730 ACCESSION NUMBER: 0001014108-03-000061 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20030331 FILED AS OF DATE: 20030515 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KINDER MORGAN ENERGY PARTNERS L P CENTRAL INDEX KEY: 0000888228 STANDARD INDUSTRIAL CLASSIFICATION: PIPE LINES (NO NATURAL GAS) [4610] IRS NUMBER: 760380342 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-11234 FILM NUMBER: 03700392 BUSINESS ADDRESS: STREET 1: 370 VAN GORDON STREET CITY: LAKEWOOD STATE: CO ZIP: 80228 BUSINESS PHONE: 3039144752 MAIL ADDRESS: STREET 1: 370 VAN GORDON STREET STREET 2: 2600 GRAND AVENUE CITY: LAKEWOOD STATE: CO ZIP: 80228-8304 FORMER COMPANY: FORMER CONFORMED NAME: ENRON LIQUIDS PIPELINE L P DATE OF NAME CHANGE: 19970304 10-Q 1 km-form10q_539417.txt FORM 10-Q F O R M 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2003 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 Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ] The Registrant had 130,033,218 common units outstanding at April 30, 2003. 1 KINDER MORGAN ENERGY PARTNERS, L.P. TABLE OF CONTENTS Page Number PART I. FINANCIAL INFORMATION Item 1: Financial Statements (Unaudited)......................... 3 Consolidated Statements of Income - Three Months Ended 3 March 31, 2003 and 2002................................ Consolidated Balance Sheets - March 31, 2003 and 4 December 31, 2002...................................... Consolidated Statements of Cash Flows - Three Months 5 Ended March 31, 2003 and 2002.......................... Notes to Consolidated Financial Statements............. 6 Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations...................... 44 Results of Operations.................................. 44 Financial Condition.................................... 48 Information Regarding Forward-Looking Statements....... 52 Item 3: Quantitative and Qualitative Disclosures About Market Risk..................................................... 53 Item 4: Controls and Procedures.................................. 53 PART II. OTHER INFORMATION Item 1: Legal Proceedings........................................ 54 Item 2: Changes in Securities and Use of Proceeds................ 54 Item 3: Defaults Upon Senior Securities.......................... 54 Item 4: Submission of Matters to a Vote of Security Holders...... 54 Item 5: Other Information........................................ 54 Item 6: Exhibits and Reports on Form 8-K......................... 54 Signatures............................................... 56 Certifications........................................... 57 2 PART I. FINANCIAL INFORMATION Item 1. Financial Statements. KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Thousands Except Per Unit Amounts) (Unaudited) Three Months Ended March 31, 2003 2002 ------------- ---------- Revenues Natural gas sales.................................. $ 1,378,288 $ 469,868 Services........................................... 334,941 295,243 Product sales and other............................ 75,609 37,954 --------- --------- 1,788,838 803,065 --------- --------- Costs and Expenses Gas purchases and other costs of sales............. 1,375,414 448,093 Operations and maintenance......................... 93,899 87,291 Fuel and power..................................... 25,138 18,384 Depreciation and amortization...................... 49,805 41,326 General and administrative......................... 34,679 29,532 Taxes, other than income taxes..................... 14,751 12,583 --------- --------- 1,593,686 637,209 --------- --------- Operating Income..................................... 195,152 165,856 Other Income (Expense) Earnings from equity investments................... 24,305 23,271 Amortization of excess cost of equity investments.. (1,394) (1,394) Interest, net...................................... (44,925) (39,022) Other, net......................................... 277 (50) Minority Interest.................................... (2,214) (2,827) --------- --------- Income Before Income Taxes and Cumulative Effect of . a Change in Accounting Principle.................. 171,201 145,834 Income Taxes......................................... (4,188) (4,401) ---------- ---------- Income Before Cumulative Effect of a Change in Accounting Principle.............................. 167,013 141,433 Cumulative effect adjustment from change in accounting for asset retirement obligations.................. 3,465 - --------- --------- Net Income........................................... $ 170,478 $ 141,433 ========= ========= Calculation of Limited Partners' interest in Net Income: Income Before Cumulative Effect of a Change in Accounting Principle............................. $ 167,013 $ 141,433 Less: General Partner's interest.................... (76,425) (61,794) ---------- ---------- Limited Partners' interest.......................... 90,588 79,639 Add: Limited Partners' interest in Change in Accounting Principle............................. 3,430 - --------- --------- Limited Partners' interest in Net Income............ $ 94,018 $ 79,639 ========= ========= Basic and Diluted Limited Partners' Net Income per Unit: Income Before Cumulative Effect of a Change in Accounting Principle............................. $ 0.50 $ 0.48 Cumulative effect adjustment from change in accounting for asset retirement obligations...... 0.02 - ---------- --------- Net Income.......................................... $ 0.52 $ 0.48 ========== ========= Weighted average number of units used in computation of Limited Partners' Net Income per unit: Basic............................................... 181,377 166,049 ========== ========= Diluted............................................. 181,510 166,246 ========== ========= 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, 2003 2002 ----------- -------- ASSETS Current Assets Cash and cash equivalents.......................... $ 36,881 $ 41,088 Accounts and notes receivable Trade............................................ 763,094 457,583 Related parties.................................. 21,664 17,907 Inventories Products......................................... 3,392 4,722 Materials and supplies........................... 8,965 7,094 Gas imbalances..................................... 51,280 25,488 Gas in underground storage......................... 3,707 11,029 Other current assets............................... 78,820 104,479 ---------- ---------- 967,803 669,390 ---------- ---------- Property, Plant and Equipment, net.................... 6,381,802 6,244,242 Investments........................................... 320,835 311,044 Notes receivable...................................... 2,673 3,823 Goodwill.............................................. 869,840 856,940 Other intangibles, net................................ 17,356 17,324 Deferred charges and other assets..................... 241,925 250,813 ---------- ---------- TOTAL ASSETS.......................................... $8,802,234 $8,353,576 ========== ========== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Trade............................................ $ 657,489 $ 373,368 Related parties.................................. 7,946 43,742 Current portion of long-term debt.................. 14,520 - Accrued interest................................... 20,152 52,500 Deferred revenues.................................. 5,620 4,914 Gas imbalances..................................... 51,870 40,092 Accrued other current liabilities.................. 358,511 298,711 ---------- ---------- 1,116,108 813,327 ---------- ---------- Long-Term Liabilities and Deferred Credits Long-term debt, outstanding........................ 3,787,234 3,659,533 Market value of interest rate swaps................ 157,665 166,956 ---------- ---------- 3,944,899 3,826,489 Deferred revenues.................................. 23,143 25,740 Deferred income taxes.............................. 30,262 30,262 Other long-term liabilities and deferred credits... 220,292 199,796 ---------- ---------- 4,218,596 4,082,287 ---------- ---------- Commitments and Contingencies (Note 3) Minority Interest..................................... 41,976 42,033 ---------- ---------- Partners' Capital Common Units....................................... 1,831,477 1,844,553 Class B Units...................................... 123,068 123,635 i-Units............................................ 1,444,786 1,420,898 General Partner.................................... 74,919 72,100 Accumulated other comprehensive income (loss)...... (48,696) (45,257) ----------- ----------- 3,425,554 3,415,929 ----------- ----------- TOTAL LIABILITIES AND PARTNERS' CAPITAL............... $8,802,234 $8,353,576 =========== =========== 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, ----------------------------- 2003 2002 ------------ -------- Cash Flows From Operating Activities Net income..................................... $ 170,478 $141,433 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect adjustment from change in accounting for asset retirement obligations.............................. (3,465) -- Depreciation and amortization.............. 49,805 41,326 Amortization of excess cost of equity investments.............................. 1,394 1,394 Earnings from equity investments........... (24,305) (23,271) Distributions from equity investments...... 17,872 6,177 Changes in components of working capital... (37,079) 58,998 Other, net................................. (3,456) (3,486) ---------- --------- Net Cash Provided by Operating Activities...... 171,244 222,571 --------- -------- Cash Flows From Investing Activities Acquisitions of assets..................... (2,098) (758,340) Acquisitions of investments................ (3,500) -- Additions to property, plant and equipment for expansion and maintenance projects.. (145,831) (91,038) Sale of investments, property, plant and equipment, net of removal costs......... (823) (274) Contributions to equity investments........ (9,415) (291) Other...................................... 3,168 669 --------- -------- Net Cash Used in Investing Activities.......... (158,499) (849,274) --------- -------- Cash Flows From Financing Activities Issuance of debt........................... 955,365 1,800,337 Payment of debt............................ (813,365) (1,075,591) Debt issue costs........................... (287) (60) Proceeds from issuance of common units..... 780 680 Distributions to partners: Common units........................... (81,232) (71,424) Class B units.......................... (3,321) (2,922) General Partner........................ (73,641) (55,300) Minority interest...................... (2,236) (2,651) Other, net................................. 985 98 --------- -------- Net Cash (Used in)/Provided by Financing Activities..................................... (16,952) 593,167 --------- -------- Decrease in Cash and Cash Equivalents.......... (4,207) (33,536) Cash and Cash Equivalents, beginning of period. 41,088 62,802 --------- -------- Cash and Cash Equivalents, end of period....... $ 36,881 $ 29,266 ========= ======== Noncash Investing and Financing Activities: Assets acquired by the assumption of liabilities $ -- $105,597 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, 2002. Kinder Morgan, Inc. and Kinder Morgan Management, LLC Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware corporation, is the sole stockholder of our general partner, Kinder Morgan G.P., Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report. Kinder Morgan Management, LLC, a Delaware limited liability company, was formed on February 14, 2001. Our general partner owns all of Kinder Morgan Management, LLC's voting securities and, pursuant to a delegation of control agreement, our general partner delegated to Kinder Morgan Management, LLC, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control the business and affairs of us, our operating limited partnerships and their subsidiaries. Kinder Morgan Management, LLC cannot take certain specified actions without the approval of our general partner and its activities are limited to being a limited partner in, and managing and controlling the business and affairs of, us, our operating limited partnerships and their subsidiaries. Kinder Morgan Management, LLC is referred to as "KMR" in this report. Basis of Presentation Our consolidated financial statements include our accounts and those of our majority-owned and controlled subsidiaries and our operating partnerships. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior periods have been reclassified to conform to the current presentation. Net Income Per Unit We compute Basic Limited Partners' Net Income per Unit by dividing our limited partners' interest in net income by the weighted average number of units outstanding during the period. Diluted Limited Partners' Net Income per Unit reflects the potential dilution, by application of the treasury stock method, that could occur if options to issue units were exercised, which would result in the issuance of additional units that would then share in our net income. Asset Retirement Obligations As of January 1, 2003, we account for asset retirement obligations pursuant to Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." For more information on our asset retirement obligations, see Note 4. 6 2. Acquisitions and Joint Ventures During the first three months of 2003, we completed or made adjustments for the following significant acquisitions. Each of the acquisitions was accounted for under the purchase method and the assets acquired and liabilities assumed were recorded at their estimated fair market values as of the acquisition date. The preliminary amounts assigned to assets and liabilities may be adjusted during a short period of time following the acquisition. The results of operations from these acquisitions are included in the consolidated financial statements from the effective date of acquisition. 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 an aggregate consideration of approximately $881.5 million, consisting of $727.1 million in cash and the assumption of $154.4 million of liabilities. Tejas Gas, LLC consists primarily of a 3,400-mile natural gas intrastate pipeline system that extends from south Texas along the Mexico border and the Texas Gulf Coast to near the Louisiana border and north from near Houston to east Texas. The acquisition expanded 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 combination of these systems is part of our Texas intrastate natural gas pipeline group. Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.............. $ 727,094 Liabilities assumed................................. 154,455 --------- Total purchase price................................ $ 881,549 ========= Allocation of purchase price: Current assets...................................... $ 56,496 Property, plant and equipment, including cushion gas 674,147 Goodwill ........................................... 150,906 --------- $ 881,549 ========= Our allocation to assets acquired and liabilities assumed was based on an appraisal of fair market values. The $150.9 million of goodwill was assigned to our Natural Gas Pipelines business segment and the entire amount is expected to be deductible for tax purposes. Bulk Terminals from M.J. Rudolph Effective January 1, 2003, we acquired long-term lease contracts from New York-based M.J. Rudolph Corporation to operate four bulk facilities at major ports along the East Coast and in the southeastern United States. The acquisition also includes the purchase of certain assets that provide stevedoring services at these locations. The aggregate cost of the acquisition was approximately $31.3 million. On December 31, 2002, we paid $29.9 million for the Rudolph acquisition and this amount was included with Other current assets on our accompanying balance sheet. In the first quarter of 2003, we paid the remaining $1.4 million and we allocated our aggregate purchase price to the appropriate asset and liability accounts. The acquired operations serve various terminals located at the ports of New York and Baltimore, along the Delaware River in Camden, New Jersey, and in Tampa Bay, Florida. Combined, these facilities transload nearly four million tons annually of products such as fertilizer, iron ore and salt. The acquisition expands our growing Terminals business segment and complements certain of our existing terminal facilities and will be included in our Terminals business segment. Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands): 7 Purchase price: Cash paid, including transaction costs.... $ 31,337 Liabilities assumed....................... 6 -------- Total purchase price...................... $ 31,343 ======== Allocation of purchase price: Current assets............................ $ 84 Property, plant and equipment............. 18,250 Intangibles-agreements ................... 100 Deferred charges and other assets ........ 9 Goodwill ................................. 12,900 -------- $ 31,343 ======== The $12.9 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. Pro Forma Information The following summarized unaudited Pro Forma Consolidated Income Statement information for the three months ended March 31, 2003 and 2002, assumes all of the acquisitions we have made since January 1, 2002, including the ones listed above, had occurred as of January 1, 2002. 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, 2002 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, 2003 2002 ---- ---- (Unaudited) Revenues....................................... $1,788,838 $1,051,357 Operating Income............................... 195,152 174,155 Income Before Cumulative Effect of a Change in Accounting Principle......................... 167,013 149,845 Net Income..................................... 170,478 149,845 Basic and diluted Limited Partners' Net Income per unit: Income Before Cumulative Effect of a Change in Accounting Principle......................... $ 0.50 $ 0.50 Net Income..................................... $ 0.52 $ 0.50 3. Litigation and Other Contingencies Federal Energy Regulatory Commission Proceedings SFPP, L.P. SFPP, L.P., referred to herein as SFPP, is the subsidiary limited partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at the FERC involving shippers' complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services, on our Pacific operations' pipeline systems. Generally, the interstate rates on our Pacific operations' pipeline systems are "grandfathered" under the Energy Policy Act of 1992 unless "substantially changed circumstances" are found to exist. To the extent "substantially changed circumstances" are found to exist, our Pacific operations may be subject to substantial exposure under these FERC complaints. The complainants in the proceedings before the FERC 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." Given the relative newness of the grandfathering standard under the Energy Policy Act and limited precedent, we cannot predict how 8 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 prospective rate reductions and complainants may be entitled to reparations for periods from the date of their respective complaint to the date of the implementation of the new rates. We currently believe that these FERC complaints seek approximately $154 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $45 million. We are not able to predict with certainty the final outcome of the pending FERC proceedings involving SFPP, should they be carried through to their conclusion, or whether we can reach a settlement with some or all of the complainants. However, even if "substantially changed circumstances" are found to exist, we believe that the resolution of these FERC complaints will be for amounts substantially less than the amounts sought and that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations. 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. 9 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 FERC to modify various rulings made in the initial decision. On January 13, 1999, the FERC issued its Opinion No. 435, which affirmed certain of those rulings and reversed or modified others. With respect to SFPP's West Line, the FERC affirmed that all but one of the West Line rates are "grandfathered" as just and reasonable and that "changed circumstances" had not been shown to satisfy the complainants' threshold burden necessary to challenge those rates. The FERC further held that the rate stated in Tariff No. 18 did not require rate reduction. Accordingly, the FERC dismissed all complaints against the West Line rates without any requirement that SFPP reduce, or pay any reparations for, any West Line rate. With respect to the East Line rates, Opinion No. 435 made several changes in the initial decision's methodology for calculating the rate base. It held that the June 1985 capital structure of SFPP's parent company at that time, rather than SFPP's 1988 partnership capital structure, should be used to calculate the starting rate base and modified the accumulated deferred income tax and allowable cost of equity used to calculate the rate base. It also ruled that SFPP would not owe reparations to any complainant for any period prior to the date on which that complainant's complaint was filed, thus reducing by two years the potential reparations period claimed by most complainants. SFPP and certain complainants sought rehearing of Opinion No. 435 by the FERC. In addition, ARCO, RHC, Navajo, Chevron and SFPP filed petitions for review of Opinion No. 435 with the U.S. Court of Appeals for the District of Columbia Circuit, all of which were either dismissed as premature or held in abeyance pending FERC 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. 10 Opinion No. 435-A reaffirmed that SFPP may recover certain litigation costs incurred in defense of its rates (amortized over five years), but reversed a ruling that those expenses may include the costs of certain civil litigation with Navajo and El Paso. It also reversed a prior decision that litigation costs should be allocated between the East and West Lines based on throughput, and instead adopted SFPP's position that such expenses should be split equally between the two systems. As to reparations, Opinion No. 435-A held that no reparations would be awarded to West Line shippers and that only Navajo was eligible to recover reparations on the East Line. It reaffirmed that a 1989 settlement with SFPP barred Navajo from obtaining reparations prior to November 23, 1993, but allowed Navajo reparations for a one-month period prior to the filing of its December 23, 1993 complaint. Opinion No. 435-A also confirmed that FERC's indexing methodology should be used in determining rates for reparations purposes and made certain clarifications sought by Navajo. Opinion No. 435-A denied Chevron's request for modification of SFPP's prorationing policy. That policy required customers to demonstrate a need for additional capacity if a shortage of available pipeline space existed. SFPP's prorationing policy has since been changed to eliminate the "demonstrated need" test. Finally, Opinion No. 435-A directed SFPP to revise its initial compliance filings to reflect the modified rulings. It eliminated the refund obligation for the compliance tariff containing the Watson Station gathering enhancement fee, but required SFPP to pay refunds to the extent that the initial compliance tariff East Line rates exceeded the rates produced under Opinion No. 435-A. In June 2000, several parties filed requests for rehearing of rulings made in Opinion No. 435-A. Chevron and RHC both sought reconsideration of the FERC's ruling that only Navajo is entitled to reparations for East Line shipments. SFPP sought rehearing of the FERC's: o decision to require use of the December 1988 partnership capital structure for the period 1984-88 in computing the starting rate base; o elimination of civil litigation costs; o refusal to allow any recovery of civil litigation settlement payments; and o failure to provide any allowance for regulatory expenses in prospective rates. On July 17, 2000, SFPP submitted a compliance filing implementing the rulings made in Opinion No. 435-A, together with a calculation of reparations due to Navajo and refunds due to other East Line shippers. SFPP also filed a tariff stating revised East Line rates based on those rulings. 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 FERC'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 Diamond Shamrock ("UDS") is not eligible for reparations in the Docket No. OR92-8 et al. proceedings. 11 The FERC also changed prior rulings that had permitted SFPP to use certain litigation, environmental and pipeline rehabilitation costs that were not recovered through the prescribed rates to offset overearnings (and potential reparations) and to recover any such costs that remained by means of a surcharge to shippers. Opinion No. 435-B required SFPP to pay reparations to each complainant without any offset for unrecovered costs. It required SFPP to subtract from the total 1995-1998 supplemental costs allowed under Opinion No. 435-A any overearnings not paid out as reparations, and allowed SFPP to recover any remaining costs from shippers by means of a five-year surcharge beginning August 1, 2000. Opinion No. 435-B also ruled that SFPP would only be permitted to recover certain regulatory litigation costs through the surcharge, and that the surcharge could not include environmental or pipeline rehabilitation costs. Opinion No. 435-B directed SFPP to make additional changes in its revised compliance filing, including: o using a remaining useful life of 16.8 years in amortizing its starting rate base, instead of 20.6 years; o removing the starting rate base component from base rates as of August 1, 2001; o amortizing the accumulated deferred income tax balance beginning in 1992, rather than 1988; o listing the corporate unitholders that were the basis for the income tax allowance in its compliance filing and certifying that those companies are not Subchapter S corporations; and o "clearly" excluding civil litigation costs and explaining how it limited litigation costs to FERC-related expenses and assigned them to appropriate periods in making reparations calculations. On October 15, 2001, Chevron and RHC filed petitions for rehearing of Opinion No. 435-B. Chevron asked the FERC to clarify: o the period for which Chevron is entitled to reparations; and o whether East Line shippers that have received the benefit of FERC-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 FERC's rate index in order to have standing to challenge SFPP rates for those years in pending or subsequent proceedings. RHC's petition contended that Opinion No. 435-B should be modified on rehearing, to the extent it: o suggested that a "substantial divergence" standard applies to complaint proceedings challenging the total level of SFPP's East Line rates subsequent to the Docket No. OR92-8 et al. proceedings; o required a substantial divergence to be shown between SFPP's cost of service and the change in the FERC oil pipeline index in such subsequent complaint proceedings, rather than a substantial divergence between the cost of service and SFPP's revenues; and o permitted SFPP to recover 1993 rate case litigation expenses through a surcharge mechanism. ARCO, UDS 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 UDS 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 FERC held that Chevron's eligibility for reparations should be measured from August 3, 1993, rather than the September 23, 1992 date sought by Chevron. The FERC also clarified its prior ruling with respect to the "substantial divergence" test, holding that in order to be considered on the merits, complaints challenging the SFPP rates set by applying the FERC's indexing regulations to the 1994 cost of service derived under the Opinion No. 435 12 orders must demonstrate a substantial divergence between the indexed rates and the pipeline's actual cost of service. Finally, the FERC held that SFPP's 1993 regulatory costs should not be included in the surcharge for the recovery of supplemental costs. On November 20, 2001, SFPP submitted its compliance filing and tariffs implementing Opinion No. 435-B and the FERC's November 7, 2001 Order. Motions to intervene and protest were subsequently filed by ARCO, Mobil (which now submits filings under the name ExxonMobil), RHC, Navajo and Chevron, alleging that SFPP: o should have calculated the supplemental cost surcharge differently; o did not provide adequate information on the taxpaying status of its unitholders; and o failed to estimate potential reparations for ARCO. On December 7, 2001, Chevron filed a petition for rehearing of the FERC's November 7, 2001 Order. The petition requested the FERC to specify whether Chevron would be entitled to reparations for the two year period prior to the August 3, 1993 filing of its complaint. On December 10, 2001, SFPP filed a response to those claims. On December 14, 2001, SFPP filed a revised compliance filing and new tariff correcting an error that had resulted in understating the proper surcharge and tariff rates. On December 20, 2001, the FERC's Director of the Division of Tariffs and Rates Central issued two letter orders rejecting SFPP's November 20, 2001 and December 14, 2001 tariff filings because they were not made effective retroactive to August 1, 2000. On January 11, 2002, SFPP filed a request for rehearing of those orders by the FERC, on the ground that the FERC has no authority to require retroactive reductions of rates filed pursuant to its orders in complaint proceedings. On January 7, 2002, SFPP and RHC filed petitions for review of the FERC's November 7, 2001 Order in the U.S. Court of Appeals for the District of Columbia Circuit. On January 8, 2002, the court consolidated those petitions with the petitions for review of Opinion Nos. 435, 435-A and 435-B. On January 24, 2002, the court ordered the consolidated proceedings to be held in abeyance until the FERC acts on Chevron's request for rehearing of the November 7, 2001 Order. Motions to intervene and protest the December 14, 2001 corrected submissions were filed by Navajo, ARCO and ExxonMobil. UDS 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 FERC denied rehearing of the Director of the Division of Tariffs and Rates Central's letter orders. On February 21, 2002, SFPP filed a motion requesting that the FERC clarify whether it intended SFPP to file a retroactive tariff or simply make a compliance filing calculating the effects of Opinion No. 435-B back to August 1, 2000; in the event the order was clarified to require a retroactive tariff filing, SFPP asked the FERC to stay that requirement pending judicial review. On April 8, 2002, SFPP filed a petition for review of the FERC's February 15, 2002 Order in the U.S. Court of Appeals for the District of Columbia Circuit. BP West Coast Products, LLC (formerly ARCO), ExxonMobil, and Tosco filed motions to intervene in that proceeding. A motion to intervene was also filed by Valero Energy Corporation ("Valero Energy") (which had merged with UDS on December 31, 2001) and Valero Energy's newly acquired shipper subsidiary Ultramar Inc. On April 9, 2002, the Court of Appeals consolidated SFPP's petition with the petitions for review of the FERC's prior orders and directed the parties "to file motions to govern future proceedings" by May 9, 2002. Motions were filed by SFPP, RHC, Navajo, Chevron and the "Indicated Parties" (BP West Coast Products, ExxonMobil, Ultramar Inc., UDS and Tosco). The FERC requested that the Court of Appeals continue to hold the consolidated cases in abeyance pending the completion of proceedings before the agency on rehearing. 13 On June 25, 2002, the Court of Appeals granted the ExxonMobil and Valero Energy motions to intervene, and directed intervenors on the side of petitioners to notify the court of that status and provide a statement of issues to be raised. ExxonMobil filed a notice on July 2, 2002; Ultramar Inc. and Valero Energy on July 10, 2002. On July 12, 2002, SFPP responded to the ExxonMobil notice in order to urge the Court of Appeals not to rely on ExxonMobil's categorization of the issues and party alignments in allocating briefing. On May 31, 2002, SFPP filed FERC Tariff No. 70, which implemented the FERC's annual indexing adjustment. Motions to intervene and protest were filed by Navajo and Chevron, contesting any indexing adjustment to the litigation surcharge permitted by Opinion No. 435-B. On June 28, 2002, the FERC's Director of the Division of Tariffs and Rates rejected Tariff No. 70 on the ground that the surcharge should not be indexed. On July 2, 2002, SFPP filed FERC Tariff No. 73 to replace Tariff No. 70 in compliance with that decision, which resulted in an average reduction from Tariff No. 70 of approximately $.0002 per barrel. On September 26, 2002, the FERC issued an order ruling on the protests against SFPP's November 20, 2001 and December 14, 2001 compliance filings implementing Opinion No. 435-B and the November 7, 2001 Order. The FERC held that: o SFPP must measure supplemental costs against the total amount of reparations for the entire reparations period (as opposed to year-by-year); o SFPP will not be permitted to include in its supplemental costs (a) litigation expenses incurred during 1999 and 2000 or (b) payments made to Navajo and RHC to settle certain FERC litigation; o the tariff surcharge collected by SFPP for all shipments between August 1, 2000 and December 1, 2001 is subject to refund; and o in calculating its tax allowance, SFPP must exclude the ownership interest attributable to an entity that the FERC found to be a mutual fund. The FERC rejected the requests by Navajo, BP West Coast Products and ExxonMobil to extend the period for which they are entitled to reparations beyond the periods specified in prior orders. The September 26, 2002 Order also ruled on SFPP's request for clarification of the February 15, 2002 Order as to whether it was required to make a retroactive tariff filing or rather a compliance filing calculating the effects of Opinion No. 435-B beginning August 1, 2000. The FERC held that SFPP was required to file a tariff retroactive to August 1, 2000. The FERC did not rule on SFPP's alternative request for a stay. The FERC also ruled on Chevron's request for rehearing of the November 7, 2001 Order, clarifying that Chevron was eligible for reparations for shipments on the East Line for the two years prior to the filing of its complaint. On October 22, 2002, ExxonMobil filed a Request for Clarification or, in the Alternative, Rehearing of the September 26, 2002 Order. ExxonMobil requested that the FERC clarify that ExxonMobil was eligible for reparations for East Line rates. Following the September 26, 2002 Order, several parties filed motions to govern future proceedings with the U.S. Court of Appeals for the District of Columbia Circuit. BP West Coast Products and ExxonMobil (the "Indicated Parties") and Valero Energy, Ultramar Inc. and Tosco (the "Joint Parties") requested that the court return the petitions for review to its active docket but sever the docket involving compliance filing issues. The FERC filed a motion that did not take a definitive position on whether the petitions for review should continue to be held in abeyance, but noted that compliance filing issues were still pending before the FERC. SFPP, Chevron, Navajo and RHC filed responses to the motions to govern future proceedings. On December 6, 2002, the Court of Appeals granted the motion of the "Indicated Parties" and "Joint Parties" to return the petitions for review to the Court's active docket. The Court also severed the docket relating to compliance filing issues and directed the parties to submit a proposed briefing schedule and format. On January 6, 2003, SFPP and FERC filed a joint briefing proposal, and the shipper parties jointly filed a separate briefing proposal. 14 On October 18, 2002, Chevron filed a petition for review of Opinion Nos. 435, 435-A and 435-B in the U.S. Court of Appeals for the District of Columbia Circuit. The Court of Appeals consolidated that petition with the main docket on November 20, 2002. Tosco and BP West Coast Products moved to intervene in that docket, and those motions were granted on December 10, 2002. Petitions for review of the September 26, 2002 Order were filed in the U.S. Court of Appeals for the District of Columbia Circuit by Navajo, on October 24, 2002, and by SFPP, on November 8, 2002. The Court consolidated those petitions with the main docket on November 5, 2002 and November 12, 2002, respectively. Valero Marketing and Supply Company ("Valero Marketing and Supply") moved to intervene in both dockets and Tosco moved to intervene in the docket for the SFPP petition. On January 6, 2003, Valero Marketing and Supply filed a motion to substitute itself for UDS in the UDS petition for review of Opinion No. 435-B. On January 21, 2003, SFPP filed a response, stating that it did not object to the proposed substitution provided Valero Marketing and Supply was not permitted to create or enlarge any claim for damages. On January 24, 2003, ConocoPhillips filed a motion to substitute itself for Tosco in the consolidated dockets, and on January 27, 2003, filed a similar motion in the severed docket relating to compliance filing issues. On February 4, 2003, the Court of Appeals granted the ConocoPhillips motion for substitution. On October 25, 2002, SFPP filed Tariff No. 75 implementing changes required by the September 26, 2002 Order, and on October 28, 2002, SFPP submitted a compliance filing pursuant to that order. Valero Marketing and Supply filed a motion to intervene and protest regarding the compliance filing and tariff, and Tosco protested the compliance filing. Navajo Refining Company, L.P. moved to intervene in proceedings relating to the tariff, and Chevron and Equilon Enterprises LLC filed comments and related pleadings challenging the compliance filing and seeking additional relief. On January 29, 2003, the FERC issued an order accepting the October 28, 2002 compliance filing subject to the condition that SFPP recalculate gross reparations in determining its per barrel surcharge and submit a revised tariff reflecting that change within fifteen days of the order. The FERC rejected all other challenges to that compliance filing. On February 13, 2003, SFPP filed its revised compliance filing along with Tariff No. 81, implementing the provisions of the January 29, 2003 Order. No party protested that filing. Valero Marketing and Supply moved to intervene in the sub-docket related to Tariff No. 81 and Valero Marketing and Supply and Ultramar Inc. moved to intervene in the sub-docket related to the compliance filing. On February 24, 2003, the FERC modified the basis on which maximum allowable oil pipeline rates are adjusted for inflation, from the producer price index for finished goods minus one percent to the unadjusted producer price index for finished goods. On February 25, 2003, SFPP filed Tariff No. 82, which implemented that indexing change with respect to its prospective rates. Tariff No. 82 was protested by BP West Coast Products, Chevron, ExxonMobil, Valero Marketing and Supply, and ConocoPhillips Company, in Docket No. IS03-131. On March 28, 2003, the Commission denied the protests and accepted Tariff No. 82. On March 7, 2003, SFPP filed a revised compliance filing in Docket No. OR92-8, which adjusted the refund calculations in SFPP's October 28, 2002 compliance filing to account for the change in the oil pipeline pricing index as of July 1, 2001. On March 24, 2003, BP West Coast Products protested this revised compliance filing. On March 27, 2003, Navajo Refining Company, LP filed an answer to the BP West Coast Products protest in which it also challenged the adjustment to the refund calculation made in the revised compliance filing. On April 14, 2003, SFPP made reparation payments of $42.7 million and refund payments of $1.7 million as ordered by the Commission pursuant to SFPP's March 7, 2003 revised compliance filing. Petitions for review of the January 29, 2003 Order were filed by ConocoPhillips on February 6, 2003, SFPP on March 10, 2003 and Chevron on March 27, 2003. SFPP moved to intervene in the ConocoPhillips docket. ExxonMobil and BP West Coast Products moved to intervene in the SFPP docket. On March 7, 2003, the United States Court of Appeals for the District of Columbia Circuit severed from the main docket all dockets relating to petitions for review of the February 15, 2002, September 26, 2002, and January 29, 2003 Orders. The Court of Appeals ordered those dockets to be held in abeyance pending resolution of the main docket. The Court of Appeals also issued a briefing schedule for the main docket, with opening briefs due May 9, 2003 and final briefs due September 17, 2003. No date for oral argument was set, and the panel that will hear the 15 case has not yet been announced. The Court also granted the motion of Valero Marketing and Supply to substitute itself for UDS. Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC --------------------- Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject to FERC's jurisdiction under the Interstate Commerce Act, and, if so, claimed that the rate for that service was unlawful. Texaco sought to have its claims addressed in the OR92-8 proceeding discussed above. Several other West Line shippers filed similar complaints and/or motions to intervene. The FERC consolidated all of these filings into Docket No. 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. On February 28, 2003, the FERC issued an order upholding that decision. Because the FERC found that SFPP did not have market power over two of the three major customers at the Sepulveda origin market and because the third customer is now an affiliate of SFPP, SFPP filed a request for rehearing of that order on March 31, 2003, which 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. As part of its February 28, 2003 order denying SFPP's application for market-based ratemaking authority, the FERC remanded the proceeding to the ongoing litigation in Docket No. OR96-2, et al. for a determination of whether SFPP's current rate for service on the Sepulveda line is just and reasonable. OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar filed a ---------------------------------- complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates, claiming they were unjust and unreasonable and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of SFPP's interstate rates, raising claims against SFPP's East and West Line rates similar to those that have been at issue in Docket Nos. OR92-8, et al. discussed above, 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. 16 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, the FERC accepted these new complaints and consolidated them with the ongoing proceeding in Docket No. OR96-2, et al. A hearing in this consolidated proceeding was held from October 2001 to March 2002. An initial decision by the administrative law judge is expected in the second quarter of 2003. OR02-4 proceedings. ------------------ On February 11, 2002, Chevron, an intervenor in the OR96-2 proceeding, filed a complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate the complaint with the OR96-2 proceeding. On May 21, 2002, the FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a request for rehearing and on September 25, 2002, the FERC dismissed Chevron's rehearing request. In October 2002, Chevron filed a request for rehearing of the FERC's September 25, 2002 Order. On April 4, 2003, Chevron filed a motion for expedited consideration of its rehearing request. Its rehearing request remains pending. Chevron continues to participate in the OR96-2 proceeding as an intervenor. California Public Utilities Commission Proceeding ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission on April 7, 1997. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the State of California and requests prospective rate adjustments. On October 1, 1997, the complainants filed testimony seeking prospective rate reductions aggregating approximately $15 million per year. On August 6, 1998, the CPUC issued its decision dismissing the complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited rehearing of its August 1998 decision for the purpose of addressing the proper ratemaking treatment for partnership tax expenses, the calculation of environmental costs and the public utility status of SFPP's Sepulveda Line and its Watson Station gathering enhancement facilities. In pursuing these rehearing issues, complainants sought prospective rate reductions aggregating approximately $10 million per year. On March 16, 2000, SFPP filed an application with the CPUC seeking authority to justify its rates for intrastate transportation of refined petroleum products on competitive, market-based conditions rather than on traditional, cost-of-service analysis. On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC asserting that SFPP's California intrastate rates are not just and reasonable based on a 1998 test year and requesting the CPUC to reduce SFPP's rates prospectively. The amount of the reduction in SFPP rates sought by the complainants is not discernible from the complaint. The rehearing complaint was heard by the CPUC in October 2000 and the April 2000 complaint and SFPP's market-based application were heard by the CPUC in February 2001. All three matters stand submitted as of April 13, 2001, and a decision addressing the submitted matters is expected within three to four months. The CPUC has recently issued a resolution approving a 2001 request by SFPP to raise its California rates to reflect increased power costs. The resolution approving the requested rate increase also requires SFPP to submit cost data for 2001, 2002, and 2003 to assist the CPUC in determining whether SFPP's overall rates for California intrastate transportation services are reasonable. The resolution reserves the right to require refunds, from the date of issuance of the resolution, to the extent the CPUC's analysis of cost data to be submitted by SFPP demonstrates that SFPP's California jurisdictional rates are unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data required by the CPUC, which submittal was protested by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation, and Chevron Products Company. Issues raised by the protest, including the reasonableness of SFPP's existing intrastate transportation rates, will be the subject of evidentiary hearings and are expected to be resolved by the CPUC by the first quarter of 2004. 17 We currently believe the CPUC complaints seek approximately $15 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $31 million. There is no way to quantify the potential extent to which the CPUC could determine that SFPP's existing California rates are unreasonable or estimate the amount of dollars potentially subject to refund as a consequence of the CPUC resolution requiring the provision by SFPP of cost-of-service data. SFPP believes that submission of the required, representative cost data required by the CPUC will indicate that SFPP's existing rates for California intrastate services remain reasonable and that no refunds are justified. We believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations. Trailblazer Pipeline Company As required by its last rate case settlement, Trailblazer Pipeline Company made a general rate case filing at the FERC on November 29, 2002. The filing provides for a small rate decrease and also includes a number of non-rate tariff changes. By an order issued December 31, 2002, FERC effectively bifurcated the proceeding. The rate change was accepted to be effective on January 1, 2003, subject to refund and a hearing. Most of the non-rate tariff changes were suspended until June 1, 2003, subject to refund and a technical conference procedure. Trailblazer sought rehearing of the FERC order with respect to the refund condition on the rate decrease. On April 15, 2003, the FERC granted Trailblazer's rehearing request to remove the refund condition that had been imposed in the December 31, 2002 Order. The Intervenors have sought rehearing as to the FERC's acceptance of certain non-rate tariff provisions. A prehearing conference on the rate issues was held on January 16, 2003. A procedural schedule was established under which the hearing will commence on October 8, 2003, if the case is not settled. Discovery has commenced as to rate issues. The technical conference on non-rate issues was held on February 6, 2003. Those issues include: o capacity award procedures; o credit procedures; o imbalance penalties; and o the maximum length of bid terms considered for evaluation in the right of first refusal process. Comments on these issues as discussed at the technical conference were filed by parties in March 2003. An order on the technical conference issues is expected sometime during the second quarter of 2003. 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 the 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 the 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 the 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 the 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 18 into effect until further order of the FERC. KMIGT filed its compliance filing with the October 19, 2001 Order on November 19, 2001 and also filed a request for rehearing/clarification of the FERC's October 19, 2001 Order on November 19, 2001. Several parties protested the November 19, 2001 compliance filing. KMIGT filed responses to those protests on December 14, 2001. At this time, it is unknown when this proceeding will be finally resolved. The full impact of implementation of Order 637 on the KMIGT system is under evaluation. We believe that these matters will not have a material adverse effect on our business, financial position or results of operations. Separately, numerous petitioners, including KMIGT, have filed appeals of Order 637 in the D.C. Circuit, potentially raising a wide array of issues related to Order 637 compliance. Initial briefs were filed on April 6, 2001, addressing issues contested by industry participants. Oral arguments on the appeals were held before the court in December 2001. On April 5, 2002, the D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C. Circuit remanded the FERC's decision to impose a 5-year cap on bids that an existing shipper would have to match in the right of first refusal process. The D.C. Circuit also remanded the FERC's decision to allow forward-hauls and backhauls to the same point. Finally, the D.C. Circuit held that several aspects of the FERC's segmentation policy and its policy on discounting at alternate points were not ripe for review. The FERC requested comments from the industry with respect to the issues remanded by the D.C. Circuit. They were due July 30, 2002. On October 31, 2002, the FERC issued an order in response to the D.C. Circuit's remand of certain Order 637 issues. The order: o eliminated the requirement of a 5-year cap on bid terms that an existing shipper would have to match in the right of first refusal process, and found that no term matching cap is necessary given existing regulatory controls; o affirmed FERC's policy that a segmented transaction consisting of both a forwardhaul up to contract demand and a backhaul up to contract demand to the same point is permissible; and o accordingly required, under Section 5 of the Natural Gas Act, pipelines that the FERC had previously found must permit segmentation on their systems to file tariff revisions within 30 days to permit such segmented forwardhaul and backhaul transactions to the same point. On December 23, 2002, KMIGT filed revised tariff provisions (in a separate docket) in compliance with the October 31, 2002 Order concerning the elimination of the right of first refusal five-year term matching cap. In an order issued January 22, 2003, the FERC approved such revised tariff provisions to be effective January 23, 2003. Trailblazer Pipeline Company On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with the 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, the FERC issued its order on Trailblazer's Order No. 637 compliance filing. The FERC approved Trailblazer's proposed language regarding operational flow orders and the right of first refusal, but 19 required Trailblazer to make changes to its tariff related to the other issues listed above. On November 14, 2001, Trailblazer made its compliance filing pursuant to the FERC order of October 15, 2001 and also filed for rehearing of the October 15, 2001 order. On April 16, 2003, the FERC issued its order on Trailblazer's compliance filing and rehearing order. The FERC denied Trailblazer's requests for rehearing and approved the compliance filing subject to modifications that must be made within 30 days of the order. Trailblazer anticipates no adverse impact on its business as a result of the implementation of Order No. 637. Standards of Conduct Rulemaking On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10 in which it proposed new rules governing the interaction between an interstate natural gas pipeline and its affiliates. If adopted as proposed, the Notice of Proposed Rulemaking could be read to limit communications between KMIGT, Trailblazer and their respective affiliates. In addition, the Notice could be read to require separate staffing of KMIGT and its affiliates, and Trailblazer and its affiliates. Comments on the Notice of Proposed Rulemaking were due December 20, 2001. Numerous parties, including KMIGT, have filed comment on the Proposed Standards of Conduct Rulemaking. On May 21, 2002, the FERC held a technical conference dealing with the FERC's proposed changes in the Standard of Conduct Rulemaking. On June 28, 2002, KMIGT and numerous other parties filed additional written comments under a procedure adopted at the technical conference. The Proposed Rulemaking is awaiting further FERC action. We believe that these matters, as finally adopted, will not have a material adverse effect on our business, financial position or results of operations. The FERC also issued a Notice of Proposed Rulemaking in Docket No. RM02-14-000 in which it proposed new regulations for cash management practices, including establishing limits on the amount of funds that can be swept from a regulated subsidiary to a non-regulated parent company. Kinder Morgan Interstate Gas Transmission LLC filed comments on August 28, 2002. We believe that these matters, as finally adopted, will not have a material adverse effect on our business, financial position or results of operations. Southern Pacific Transportation Company Easements SFPP and Southern Pacific Transportation Company are engaged in a judicial reference proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by SPTC should be adjusted pursuant to existing contractual arrangements (Southern Pacific Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc., Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the State of California for the County of San Francisco, filed August 31, 1994). Although SFPP received a favorable ruling from the trial court in May 1997, in September 1999, the California Court of Appeals remanded the case back to the trial court for further proceeding. SFPP claims that the rent payable for each of the years 1994 through 2004 should be approximately $4.4 million and SPTC claims it should be approximately $15.0 million. We believe SPTC's position in this case is without merit and we have set aside reserves that we believe are adequate to address any reasonably foreseeable outcome of this matter. The trial of this matter ended in early March 2003 and we expect the judge's ruling sometime in the second quarter of 2003. 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, has been named as a defendant with several others in a series of lawsuits in the United States District Court in Denver, Colorado and certain state courts in Colorado and Texas. The plaintiffs include several private royalty, overriding royalty and working interest owners at the McElmo Dome (Leadville) Unit in southwestern Colorado. Plaintiffs in the Colorado state court action also are overriding royalty interest owners in the Doe Canyon Unit. Plaintiffs seek to also represent classes of claimants composed of all private and governmental royalty, overriding royalty and working interest owners, and governmental taxing authorities who have an interest in the carbon dioxide produced at the McElmo Dome Unit. Plaintiffs claim they and the members of any classes that might be certified have been damaged because the defendants have maintained a low price for carbon dioxide in the enhanced oil recovery market in the Permian Basin and maintained a high cost of pipeline 20 transportation from the McElmo Dome Unit to the Permian Basin. Plaintiffs claim breaches of contractual and potential fiduciary duties owed by defendants and also allege other theories of liability including: o common law fraud; o fraudulent concealment; and o negligent misrepresentation. In addition to actual or compensatory damages, certain plaintiffs are seeking punitive or trebled damages as well as declaratory judgment for various forms of relief, including the imposition of a constructive trust over the defendants' interests in the Cortez Pipeline and the Partnership. 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); Shell Western E&P Inc. v. Bailey, et al., No 98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et al. v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court, Denton County filed 12/22/99); First State Bank of Denton v. Mobil Oil Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County filed 3/29/01); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct. Montezuma County filed 3/21/98). At a hearing conducted in the United States District Court for the District of Colorado on April 8, 2002, the Court orally announced that it had approved the certification of proposed plaintiff classes and approved a proposed settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson, and Ainsworth cases. The Court entered a written order approving the Settlement on May 6, 2002. Plaintiffs counsel representing Shores, et al. appealed the court's decision to the 10th Circuit Court of Appeals. On December 26, 2002, the 10th Circuit Court of Appeals affirmed in all respects the District Court's Order approving settlement. Following the decision of the 10th Circuit, the plaintiffs and defendants jointly filed motions to abate the Shell Western E&P Inc., Shores and First State Bank of Denton cases in order to afford the parties time to discuss potential settlement of those matters. These Motions were granted on February 6, 2003. In the Celeste C. Grynberg case, the parties are currently engaged in discovery. On March 24, 2003, the plaintiffs' counsel in the Shores matter filed a Petition for Writ of Certiorari in the United States Supreme Court seeking to have the Court review and overturn the decision of the 10th Circuit Court of Appeals. RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et al. Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the First Supplemental Petition filed by RSM Production Corporation on behalf of the County of Zapata, State of Texas and Zapata County Independent School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15 other defendants, including two other Kinder Morgan affiliates. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. The Petition alleges that these taxing units relied on the reported volume and analyzed heating content of natural gas produced from the wells located within the appropriate taxing jurisdiction in order to properly assess the value of mineral interests in place. The suit further alleges that the defendants undermeasured the volume and heating content of that natural gas produced from privately owned wells in Zapata County, Texas. The Petition further alleges that the County and School District were deprived of ad valorem tax revenues as a result of the alleged undermeasurement of the natural gas by the defendants. On December 15, 2001, the defendants filed motions to transfer venue on jurisdictional grounds. There are no further pretrial proceedings at this time. Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating Company et al. v. Gas Pipelines, et al.) Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999, three plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a purported nationwide class action in the Stevens County, Kansas District Court against some 250 natural gas pipelines and many of their affiliates. The District Court is located in Hugoton, Kansas. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. The Petition (recently amended) alleges a conspiracy to underpay royalties, taxes and producer payments by the defendants' undermeasurement of the volume and heating content of natural gas produced from nonfederal lands 21 for more than twenty-five years. The named plaintiffs purport to adequately represent the interests of unnamed plaintiffs in this action who are comprised of the nation's gas producers, State taxing agencies and royalty, working and overriding owners. The plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees from the defendants, jointly and severally. This action was originally filed on May 28, 1999 in Kansas State Court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. Subsequently, one of the defendants removed the action to Kansas Federal District Court and the case was styled as Quinque Operating Company, et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the District of Kansas. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claim Act cases referred to below, because of common factual questions. On April 10, 2000, the MDL Panel ordered that this case be consolidated with the Grynberg federal False Claims Act cases discussed below. On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling remanding the case back to the State Court in Stevens County, Kansas. The Court in Kansas has issued a case management order addressing the initial phasing of the case. In this initial phase, the court will rule on motions to dismiss (jurisdiction and sufficiency of pleadings), and if the action is not dismissed, on class certification. Merits discovery has been stayed. Recently, the defendants filed a motion to dismiss on grounds other than personal jurisdiction, which was denied by the Court in August, 2002. The Motion to Dismiss for lack of Personal Jurisdiction of the nonresident defendants has been briefed and is pending. The current named plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and Stixon Petroleum, Inc. Quinque Operating Company has been dropped from the action as a named plaintiff. On April 10, 2003, the court issued its decision denying plaintiffs' motion for class certification. Plaintiffs have indicated they will move the Court for permission to amend the Complaint. United States of America, ex rel., Jack J. Grynberg v. K N Energy Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claim Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. The multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases, referred to as valuation claims. Judge Downes denied the defendant's motion to dismiss on May 18, 2001. The United States' motion to dismiss most of plaintiff's valuation claims has been granted by the court. Grynberg has appealed that dismissal to the 10th Circuit, which has requested briefing regarding its jurisdiction over that appeal. Discovery is now underway to determine issues related to the Court's subject matter jurisdiction arising out of the False Claim Act. Mel R. Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et al. On July 25, 2002, we were served with this suit for breach of contract, tortious interference with existing contractual relationships, conspiracy to commit tortuous interference and interference with prospective business relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and Paz Gas Corporation claim they are entitled to receive under an agreement with a subsidiary of ours acquired in the Tejas Gas acquisition. We have filed a motion to remove the case from venue in Dewitt County, Texas to Harris County, Texas, and our motion was denied in a venue hearing in November 2002. 22 In a Second Amended Original Petition, Sweatman and Paz assert new and distinct allegations against us, principally that we were a party to an alleged commercial bribery committed by us, Gulf Energy Marketing, and Intergen inasmuch as we, in our role as acquirer of Kinder Morgan Tejas, allegedly paid Intergen to not renew the underlying Entex contracts belonging to the Tejas/Paz joint venture. Moreover, new and distinct allegations of breach of fiduciary and bribery of a fiduciary are also raised in this amended petition for the first time. Based on the information available to date and our preliminary investigation, we believe this suit is without merit and we intend to defend it vigorously. Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy, Incorporated, Reliant Energy Resources Corp., Entex Gas Marketing Company, Kinder Morgan Texas Pipeline, L.P., Kinder Morgan Energy Partners, L.P., Houston Pipeline Company, L.P. and AEP Gas Marketing, L.L.C., No. 30875 (District Court, Wharton County Texas). On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan Energy Partners, L.P. were served with the above-entitled Complaint. A First Amended Complaint was served on October 23, 2002, adding additional defendants Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc., Kinder Morgan Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The First Amended Complaint purports to bring a class action on behalf of those Texas residents who purchased natural gas for residential purposes from the so-called "Reliant Defendants" in Texas at any time during the period encompassing "at least the last ten years." The Complaint alleges that Reliant Energy Resources Corp., by and through its affiliates, has artificially inflated the price charged to residential consumers for natural gas that it allegedly purchased from the non-Reliant defendants, including the above-listed Kinder Morgan entities. The Complaint further alleges that in exchange for Reliant Energy Resources Corp.'s purchase of natural gas at above market prices, the non-Reliant defendants, including the above-listed Kinder Morgan entities, sell natural gas to Entex Gas Marketing Company at prices substantially below market, which in turn sells such natural gas to commercial and industrial consumers and gas marketers at market price. The Complaint purports to assert claims for fraud, violations of the Texas Deceptive Trade Practices Act, and violations of the Texas Utility Code against some or all of the Defendants, and civil conspiracy against all of the defendants, and seeks relief in the form of, inter alia, actual, exemplary and statutory damages, civil penalties, interest, attorneys' fees and a constructive trust ab initio on any and all sums which allegedly represent overcharges by Reliant and Reliant Energy Resources Corp. On November 18, 2002, the Kinder Morgan defendants filed a Motion to Transfer Venue and, Subject Thereto, Original Answer to the First Amended Complaint. The parties are currently engaged in preliminary discovery. Based on the information available to date and our preliminary investigation, the Kinder Morgan defendants believe that the claims against them are without merit and intend to defend against them vigorously. Marie Snyder, et al v. City of Fallon, United States Department of the Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District Court, District of Nevada)("Snyder"); and Frankie Sue Galaz, et al v. United States of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No. cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz"). On July 9, 2002, we were served with a purported Complaint for Class Action in the Snyder case, in which the plaintiffs, on behalf of themselves and others similarly situated, assert that a leukemia cluster has developed in the City of Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to unspecified "environmental carcinogens" at unspecified times in an unspecified manner and are therefore "suffering a significantly increased fear of serious disease." The plaintiffs seek a certification of a class of all persons in Nevada who have lived for at least three months of their first ten years of life in the City of Fallon between the years 1992 and the present who have not been diagnosed with leukemia. The Complaint purports to assert causes of action for nuisance and "knowing concealment, suppression, or omission of material facts" against all defendants, and seeks relief in the form of "a court-supervised trust fund, paid for by defendants, jointly and severally, to finance a medical monitoring program to deliver services to members of the purported class that include, but are not limited to, testing, preventative screening and surveillance for conditions 23 resulting from, or which can potentially result from exposure to environmental carcinogens," incidental damages, and attorneys' fees and costs. The defendants responded to the Complaint by filing Motions to Dismiss on the grounds that it fails to state a claim upon which relief can be granted. On November 7, 2002, the United States District Court granted the Motion to Dismiss filed by the United States, and further dismissed all claims against the remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs filed a Motion for Reconsideration and Leave to Amend, which was denied by the Court on December 30, 2002. Plaintiffs have filed a Notice of Appeal to the United States Court of Appeals for the 9th Circuit, which appeal is currently pending. On December 3, 2002, plaintiffs filed an additional Complaint for Class Action in the Galaz matter asserting the same claims in the same Court on behalf of the same purported class against virtually the same defendants, including us. On February 10, 2003, the defendants filed Motions to Dismiss the Galaz Complaint on the grounds that it also fails to state a claim upon which relief can be granted. This motion to dismiss was granted as to all defendants on April 3, 2003. Based on the information available to date and our preliminary investigation, we believe that the claims against us in the Snyder and Galaz matters are without merit and intend to defend against them vigorously. Walter Chandler v. Plantation Pipe Line Company On October 2, 2001, the jury rendered a verdict against Plantation Pipe Line Company in the case of Walter Chandler v. Plantation Pipe Line Company. The jury awarded the plaintiffs a total of $43.8 million. The judge reduced the award to $42.6 million due to a prior settlement with the plaintiffs by a third party. This case was filed in April 1997 by the landowner (Evelyn Chandler Trust) and two residents of the property (Buster Chandler and his son, Clay Chandler). The suit was filed against Chevron, Plantation and two individuals. The two individuals were later dismissed from the suit. Chevron settled with the plaintiffs in December 2000. The property and residences are directly across the street from the location of a former Chevron products terminal. The Plantation pipeline system traverses the Chevron terminal property. The suit alleges that gasoline released from the terminal and pipeline contaminated the groundwater under the plaintiffs' property. As noted below, a current remediation effort is taking place among Chevron, Plantation and Alabama Department of Environmental Management. In addition to the Chandler case, in 1998 and 1999, other entities and individuals living in close proximity to the Chandlers filed lawsuits against Plantation, Chevron and an environmental consulting firm, CH2MHill, alleging property damage and personal injuries from groundwater contaminated with petroleum hydrocarbons. In February 2003, Plantation settled, through a confidential settlement, all of these lawsuits as well as the Chandler litigation. Plantation believes that the settlement of these lawsuits and the Chandler litigation will not have a material adverse effect on its business, financial position or results of operations. Marion County, Mississippi Litigation In 1968, Plantation discovered a release from its 12-inch pipeline in Marion County, Mississippi. The pipeline was immediately repaired. In 1998 and 1999, 62 lawsuits were filed on behalf of 263 plaintiffs in the Circuit Court of Marion County, Mississippi. The majority of the claims are based on alleged exposure from the 1968 release, including claims for property damage and personal injury. Plantation has resolved some of the lawsuits but lawsuits by 236 of the plaintiffs are still pending. Although a trial date has not been set for any of the remaining cases, it is anticipated that a trial on a portion of the lawsuits will be scheduled in 2003. Plantation believes that the ultimate resolution of these Marion County, Mississippi cases will not have a material effect on its business, financial position or results of operations. 24 Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, Inc. and ST Services, Inc. On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the Superior Court of New Jersey, Gloucester County. Our answer to the Complaint is due June 27, 2003. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, and owned currently by ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil performed an environmental site assessment of the terminal required prior to sale pursuant to state law. During the site assessment, ExxonMobil discovered items that required remediation and the New Jersey Department of Environmental Protection issued an order that required ExxonMobil to perform various remediation activities to remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is still remediating the site and has not been removed from the state's cleanup order; however, ExxonMobil claims that the remediation continues because of GATX Terminals' storage of a fuel additive, MTBE, at the terminal during GATX Terminals' ownership of the terminal. When GATX Terminals sold the terminal to ST Services, the parties indemnified one another for certain environmental matters. When GATX Terminals was sold to us, GATX Terminals' indemnification obligations to ST Services may have passed to us, consequently, at issue is any indemnification obligations we may owe to ST Services in respect to environmental remediation of MTBE at the terminal. The Complaint seeks any and all damages related to remediating MTBE at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit for remediating MTBE at the terminal. Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party in interest for Enron Helium Company, a division of Enron Corp., Enron Liquids Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th Judicial District Court, Harris County, Texas) On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original Petition and Application for Declaratory Relief against Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P., Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron Helium Company. Plaintiff added Enron Corp. as party in interest for Enron Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a Defendant. The claims against Enron Corp. were severed into a separate cause of action. Plaintiff's claims are based on a Gas Processing Agreement entered into on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company relating to gas produced in the Hugoton Field in Kansas and processed at the Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff also asserts claims relating to the Helium Extraction Agreement entered between Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated March 14, 1988. Plaintiff alleges that Defendants failed to deliver propane and to allocate plant products to Plaintiff as required by the Gas Processing Agreement and originally sought damages of approximately $5.9 million. Plaintiff filed its Third Amended Petition on February 25, 2003. In its Third Amended Petition, Plaintiff alleges claims for breach of the Gas Processing Agreement and the Helium Extraction Agreement, requests a declaratory judgment and asserts claims for fraud by silence/bad faith, fraudulent inducement of the 1997 Amendment to the Gas Processing Agreement, civil conspiracy, fraud, breach of a duty of good faith and fair dealing, negligent misrepresentation and conversion. As of April 7, 2003, Plaintiff alleged damages for the period November 1987 through March 1997 in the amount of $30.7 million. On May 2, 2003, Plaintiff added claims for the period April 1997 through February 2003 in the amount of $12.9 million. The parties are currently engaged in discovery. Based on the information available to date in our investigation, the Kinder Morgan Defendants believe that the claims against them are without merit and intend to defend against them vigorously. Although no assurances can be given, we believe that we have meritorious defenses to all of these actions, that, to the extent an assessment of the matter is possible, we have established an adequate reserve to cover potential liability, and that these matters will not have a material adverse effect on our business, financial position or results of operations. 25 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, terminal and carbon dioxide field and oil field 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 and have established a reserve to address the costs associated with the cleanup: o one cleanup ordered by the United States Environmental Protection Agency related to ground water contamination in the vicinity of SFPP's storage facilities and truck loading terminal at Sparks, Nevada; o several ground water hydrocarbon remediation efforts under administrative orders issued by the California Regional Water Quality Control Board and two other state agencies; o groundwater and soil remediation efforts under administrative orders issued by various regulatory agencies on those assets purchased from GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe Line LLC and Central Florida Pipeline LLC; and o a ground water remediation effort taking place between Chevron, Plantation Pipe Line Company and the Alabama Department of Environmental Management. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide. Furthermore, our review of assets related to Kinder Morgan Interstate Gas Transmission LLC indicates possible environmental impacts from petroleum and used oil releases into the soil and groundwater at nine sites. Additionally, our review of assets related to Kinder Morgan Texas Pipeline indicates possible environmental impacts from petroleum releases into the soil and groundwater at six sites. Further delineation and remediation of any environmental impacts from these matters will be conducted. Reserves have been established to address the closure of these issues. 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. As of March 31, 2003, we have recorded a total reserve for environmental claims in the amount of $46.6 million. However, we were not able to reasonably estimate when the eventual settlements of these claims will occur. Other We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position or results of operations. In addition to the matters described above, we may face additional challenges to our rates in the future. Shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. In addition, since many of our assets are subject to regulation, we are 26 subject to potential future changes in applicable rules and regulations that may have an adverse effect on our business, financial position or results of operations. 4. Change in Accounting for Asset Retirement Obligations In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The provisions of this Statement are effective for fiscal years beginning after June 15, 2002. We adopted SFAS No. 143 on January 1, 2003. SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. Its primary impact on us will be to change the method of accruing for oil production site restoration costs related to our CO2 Pipelines business segment. Prior to January 1, 2003, we accounted for asset retirement obligations in accordance with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." Under SFAS No. 143, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. Specifically, upon adoption of this Statement, an entity must recognize the following items in its balance sheet: o a liability for any existing asset retirement obligations adjusted for cumulative accretion to the date of adoption; o an asset retirement cost capitalized as an increase to the carrying amount of the associated long-lived asset; and o accumulated depreciation on that capitalized cost. Amounts resulting from initial application of this Statement shall be measured using current information, current assumptions and current interest rates. The amount recognized as an asset retirement cost shall be measured as of the date the asset retirement obligation was incurred. Cumulative accretion and accumulated depreciation shall be measured for the time period from the date the liability would have been recognized had the provisions of this Statement been in effect to the date of adoption of this Statement. The cumulative-effect adjustment for this change in accounting principle resulted in income of $3.5 million in the first quarter of 2003. Furthermore, as required by SFAS No. 143, we recognized the cumulative-effect of initially applying SFAS No. 143 as a change in accounting principle as described in Accounting Principles Board Opinion 20, "Accounting Changes." The cumulative-effect adjustment results from the difference between the amounts recognized in our consolidated balance sheet prior to the application of SFAS No. 143 and the net amount recognized in our consolidated balance sheet pursuant to SFAS No. 143. In our CO2 Pipelines business segment, we are required to plug and abandon oil wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of March 31, 2003, we have recognized asset retirement obligations in the aggregate amount of $11.3 million relating to these requirements at two existing sites within our CO2 Pipelines segment. In our Natural Gas Pipelines business segment, if we would cease providing utility services, we would be required to remove surface facilities from land belonging to our customers and others. Our Texas intrastate natural gas pipeline group has various condensate drip tanks and separators located throughout its natural gas pipeline systems, as well as inactive gas processing plants, laterals and gathering systems which are no longer integral to the overall mainline transmission systems, and asbestos-coated underground pipe, which is being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission system has compressor stations which are no longer active and other miscellaneous facilities, all of which have been officially abandoned. We believe we can reasonably estimate both the time and costs associated with the retirement of these facilities. As of March 31, 2003, we have recognized 27 asset retirement obligations in the aggregate amount of $2.8 million relating to the businesses within our Natural Gas Pipelines segment. We have included $0.8 million of our total $14.1 million asset retirement obligations as of March 31, 2003 with Accrued other current liabilities in the accompanying consolidated balance sheet and the remaining $13.3 million with Other long-term liabilities and deferred credits. No assets are legally restricted for purposes of settling our asset retirement obligations. A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for the quarter ended March 31, 2003 is as follows (in thousands): Balance at Dec. 31, 2002................... $ - Cumulative effect transition adjustment.... 14,125 Liabilities incurred....................... - Liabilities settled........................ (202) Accretion expense.......................... 171 Revisions in estimated cash flows.......... - ----------- Balance at Mar. 31, 2003................... $ 14,094 =========== Pro Forma Information If SFAS No. 143 had been applied as of January 1, 2002, our liability for asset retirement obligations would have been approximately $14.1 million at March 31, 2002 and December 31, 2002. The following table illustrates the Pro Forma impact on the carrying amounts of the obligations for each of the three months ended March 31, 2002 and March 31, 2003 as if SFAS No. 143 had been adopted on January 1, 2002 (in thousands): Three Months Three Months Ended Ended Mar. 31, 2003 Mar. 31, 2002 ------------- ------------- Balance at beginning of period....... $ 14,125 $14,344 Liabilities incurred................. -- -- Liabilities settled.................. (202) (437) Accretion expense.................... 171 233 Revisions in estimated cash flows.... -- -- --------- --------- Balance at end of period............. $ 14,094 $ 14,140 ========= ========= For each of the three months ended March 31, 2003 and 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, -------------------- 2003 2002 --------- -------- Reported limited partners' interest in net income $ 94,018 $ 79,639 Add: limited partners' interest in adjustments from change in accounting for asset retirement obligations -- (253) -------- -------- Adjusted limited partners' interest in net income $ 94,018 $ 79,386 ======== ======== Basic and diluted limited partners' net income per unit: Reported net income $ 0.52 $ 0.48 Adjs. from change in accounting for asset retirement obligations -- -- -------- -------- Adjusted net income $ 0.52 $ 0.48 ======== ======== 5. Distributions On February 14, 2003, we paid a cash distribution for the quarterly period ended December 31, 2002, of $0.625 per unit to our common unitholders and to our class B unitholders. KMR, our sole i-unitholder, received 858,981 additional i-units based on the $0.625 cash distribution per common unit. The distributions were declared on 28 January 15, 2003, payable to unitholders of record as of January 31, 2003. On April 16, 2003, we declared a cash distribution for the quarterly period ended March 31, 2003, of $0.64 per unit. The distribution will be paid on or before May 15, 2003, to unitholders of record as of April 30, 2003. Our common unitholders and class B unitholders will receive cash. KMR will receive a distribution in the form of additional i-units based on the $0.64 distribution per common unit. The number of i-units distributed will be 859,933. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.018488) will be issued. The fraction was determined by dividing: o $0.64, the cash amount distributed per common unit by o $34.617, the average of KMR's limited liability shares' closing market prices from April 11-25, 2003, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange. 6. Intangibles Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 141 "Business Combinations" and Statement of Financial Accounting Standards No. 142 "Goodwill and Other Intangible Assets." These accounting pronouncements require that we prospectively cease amortization of all intangible assets having indefinite useful economic lives. Such assets, including goodwill, are not to be amortized until their lives are determined to be finite. A recognized intangible asset with an indefinite useful life should be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We completed this initial transition impairment test in June 2002 and determined that our goodwill was not impaired as of January 1, 2002. We completed our second impairment test in early May 2003 and determined that our goodwill was not impaired as of January 1, 2003. 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): Mar. 31, Dec. 31, 2003 2002 --------- --------- Goodwill $869,840 $856,940 Lease value 6,124 6,124 Contracts and other 11,662 11,580 Accumulated amortization (430) (380) --------- --------- Other intangibles, net 17,356 17,324 --------- --------- Total intangibles, net $887,196 $874,264 ========= ========= Changes in the carrying amount of goodwill for the three months ended March 31, 2003 are summarized as follows (in thousands): Products Natural Gas CO2 Pipelines Pipelines Pipelines Terminals Total --------- ----------- --------- --------- ----- Balance at Dec. 31, 2002 $ 349,458 $ 307,412 $ 46,101 $ 153,969 $ 856,940 Goodwill acquired -- -- -- 12,900 12,900 Goodwill dispositions, net -- -- -- -- -- Impairment losses -- -- -- -- -- ------- ---------- ---------- ---------- ---------- Balance at Mar. 31, 2003 $ 349,458 $ 307,412 $ 46,101 $ 166,869 $ 869,840 ========= ========= ========= ========= ========= 29 Amortization expense on intangibles consists of the following (in thousands): Three Months Ended Mar. 31, 2003 2002 ------------ ----------- Goodwill $ -- $ -- Lease value 35 35 Contracts and other 15 10 ------------ ----------- $ 50 $ 45 ============ =========== Our weighted average amortization period for our intangible assets is approximately 41 years. The following table shows the estimated amortization expense for these assets for each of the five succeeding fiscal years (in thousands): 2004 $206 2005 $206 2006 $206 2007 $206 2008 $206 7. Debt Our debt and credit facilities as of March 31, 2003, consisted primarily of: o a $530 million unsecured 364-day credit facility due October 14, 2003; o a $445 million unsecured three-year credit facility due October 15, 2005; o $37.1 million of Series F First Mortgage Notes due December 2004 (our subsidiary, SFPP, L.P. is the obligor on the notes); o $200 million of 8.00% Senior Notes due March 15, 2005; o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal District Revenue Bonds due March 15, 2006 (our 66 2/3% owned subsidiary, International Marine Terminals, is the obligor on the bonds); o $250 million of 5.35% Senior Notes due August 15, 2007; o $30 million of 7.84% Senior Notes, with a final maturity of July 2008 (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes); o $250 million of 6.30% Senior Notes due February 1, 2009; o $250 million of 7.50% Senior Notes due November 1, 2010; o $700 million of 6.75% Senior Notes due March 15, 2011; o $450 million of 7.125% Senior Notes due March 15, 2012; o $25 million of New Jersey Economic Development Revenue Refunding Bonds due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is the obligor on the bonds); o $87.9 million of Industrial Revenue Bonds with final maturities ranging from September 2019 to December 2024 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is the obligor on the bonds); o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B," is the obligor on the bonds); 30 o $300 million of 7.40% Senior Notes due March 15, 2031; o $300 million of 7.75% Senior Notes due March 15, 2032; o $500 million of 7.30% Senior Notes due August 15, 2033; and o a $975 million short-term commercial paper program (supported by our credit facilities, the amount available for borrowing under our credit facilities is reduced by our outstanding commercial paper borrowings). None of our debt or credit facilities are subject to payment acceleration as a result of any change to our credit ratings. However, the margin that we pay with respect to LIBOR based borrowings under our credit facilities is tied to our credit ratings. Our outstanding short-term debt as of March 31, 2003 was $407.8 million. The balance consisted of: o $362 million of commercial paper borrowings; o $37.1 million under the SFPP, L.P. 10.7% First Mortgage Notes; o $5 million under the Central Florida Pipeline LLC Notes; and o $3.7 million in other borrowings. We intend and have the ability to refinance $393.3 million of our short-term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated balance sheet. Currently, we do not anticipate any liquidity problems. The weighted average interest rate on all of our borrowings was approximately 4.730% per annum during the first quarter of 2003 and 5.172% per annum during the first quarter of 2002. 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, 2002. Credit Facilities As of March 31, 2003, we had two credit facilities: o a $530 million unsecured 364-day credit facility due October 14, 2003; and o a $445 million unsecured three-year credit facility due October 15, 2005. Our credit facilities are with a syndicate of financial institutions. Wachovia Bank, National Association is the administrative agent under both credit facilities. The terms of our two credit facilities are substantially similar to the terms of our previous credit facilities. Interest on the two credit facilities accrues at our option at a floating rate equal to either: o the administrative agent's base rate (but not less than the Federal Funds Rate, plus 0.5%); or o LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt. There were no borrowings under either credit facility at December 31, 2002 or at March 31, 2003. The amount available for borrowing under our credit facilities is reduced by: o a $23.7 million letter of credit that supports Kinder Morgan Operating L.P. "B"'s tax-exempt bonds; o a $28 million letter of credit entered into on December 23, 2002 that supports Nassau County, Florida Ocean Highway and Port Authority tax exempt bonds (associated with the operations of our bulk terminal facility 31 located at Fernandina Beach, Florida); o a $0.2 million letter of credit entered into on June 4, 2002 that supports a workers' compensation insurance policy; o a $0.5 million letter of credit entered into on March 31, 2003 that supports an engineering contract; and o our outstanding commercial paper borrowings. Our three-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate. On May 5, 2003, we increased the borrowings available under our two credit facilities by $75 million as follows: o our $530 million unsecured 364-day credit facility was increased to $570 million; and o our $445 million unsecured three-year credit facility was increased to $480 million. Senior Notes As of March 31, 2003, our unamortized liability balance due on the various series of our senior notes was as follows (in millions): 8.0% senior notes due March 15, 2005 $ 199.8 5.35% senior notes due August 15, 2007 249.9 6.3% senior notes due February 1, 2009 249.5 7.5% senior notes due November 1, 2010 248.8 6.75% senior notes due March 15, 2011 698.4 7.125% senior notes due March 15, 2012 448.1 7.4% senior notes due March 15, 2031 299.3 7.75% senior notes due March 15, 2032 298.5 7.3% senior notes due August 15, 2033 499.0 ------- Total $3,191.3 ======== 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, 2003, we have entered into interest rate swap agreements with a notional principal amount of $1.95 billion for the purpose of hedging the interest rate risk associated with our fixed and variable rate debt obligations. The $1.95 billion notional principal amount of our interest rate swap agreements has not changed since December 31, 2002. These swaps meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the "shortcut" method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. For more information on our risk management activities, see Note 10. Commercial Paper Program As of December 31, 2002 and March 31, 2003, our commercial paper program provided for the issuance of up to $975 million of commercial paper. As of March 31, 2003, we had $362 million of commercial paper outstanding with an average interest rate of 1.429%. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facilities. 32 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 2003, the weighted-average interest rate on these bonds was 1.10% per annum, and as of March 31, 2003, the interest rate was 1.17%. We have an outstanding letter of credit issued under our credit facilities that supports our tax-exempt bonds. The letter of credit reduces the amount available for borrowing under our credit facilities. International Marine Terminals Debt We own a 66 2/3% interest in International Marine Terminals partnership. The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. The bonds mature on March 15, 2006. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, we agreed to guarantee the obligations of IMT in proportion to our ownership interest. Our obligation is approximately $30.3 million for principal, plus interest and other fees. Contingent Debt Cortez Pipeline Company Debt Pursuant to a certain Throughput and Deficiency Agreement, the owners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline Company - 13% owner) are required, on a percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The Throughput and Deficiency Agreement contractually supports the borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the owners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including cash deficiencies relating to the repayment of principal and interest on borrowings by Cortez Capital Corporation. Parent companies of the respective Cortez Pipeline Company owners further severally guarantee, on a percentage basis, the obligations of the Cortez Pipeline Company owners under the Throughput and Deficiency Agreement. Due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital Corporation. Shell Oil Company shares our guaranty obligations jointly and severally through December 31, 2006 for Cortez Capital Corporation's debt programs in place as of April 1, 2000. As of March 31, 2003, the debt facilities of Cortez Capital Corporation consisted of: o $115.7 million of Series D notes due May 15, 2013; o a $175 million short-term commercial paper program; and o a $175 million committed revolving credit facility due December 26, 2003 (to support the above-mentioned $175 million commercial paper program). As of March 31, 2003, Cortez Capital Corporation had $135.1 million of commercial paper outstanding with an interest rate of 1.30%, the average interest rate on the Series D notes was 6.9322% and there were no borrowings under the credit facility. Plantation Pipeline Company Debt On April 30, 1997, Plantation Pipeline Company entered into a $10 million, ten-year floating-rate term credit agreement. We, as an owner of Plantation Pipeline Company, severally guarantee this debt on a pro rata basis 33 equivalent to our respective 51% ownership interest. During 1999, this agreement was amended to reduce the maturity date by three years. The $10 million is outstanding as of March 31, 2003. Red Cedar Gas Gathering Company Debt In October 1998, Red Cedar Gas Gathering Company sold $55 million in aggregate principal amount of Senior Notes due October 31, 2010. The $55 million was sold in 10 different notes in varying amounts with identical terms. The Senior Notes are collateralized by a first priority lien on the ownership interests, including our 49% ownership interest, in Red Cedar Gas Gathering Company. The Senior Notes are also guaranteed by us and the other owner of Red Cedar Gas Gathering Company. The principal is to be repaid in seven equal installments beginning on October 31, 2004 and ending on October 31, 2009, with any remainder due October 31, 2010. The $55 million is outstanding as of March 31, 2003. Nassau County, Florida Ocean Highway and Port Authority Debt Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the State of Florida. During 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5 million for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. A letter of credit was issued as security for the Adjustable Demand Revenue Bonds and was guaranteed by the parent company of Nassau Terminals, Inc., the operator of the port facilities. In July 2002, we acquired Nassau Terminals, Inc. and became guarantor under the letter of credit agreement. In December 2002, we issued a $28 million letter of credit under our credit facilities and the former letter of credit guarantee was terminated. Certain Relationships and Related Transactions Retention Agreement Effective January 17, 2002, KMI entered into a retention agreement with C. Park Shaper, an officer of KMI, Kinder Morgan G.P., Inc. (our general partner) and its delegate, KMR. Pursuant to the terms of the agreement, Mr. Shaper obtained a $5 million personal loan guaranteed by KMI and us. Mr. Shaper was required to purchase and did purchase KMI common stock and our common units in the open market with the loan proceeds. If he voluntarily leaves KMI prior to the end of five years, then he must repay the entire loan. On the fifth anniversary date of the agreement, provided Mr. Shaper has continued to be employed by KMI and/or our general partner, then KMI and we will assume Mr. Shaper's obligations under the loan. The agreement contains provisions that address termination for cause, death, disability and change of control. It is expected that KMI's and our involvement in this loan will end in October 2003. Lines of Credit We have agreed to guarantee potential borrowings under lines of credit available from Wachovia Bank, National Association, formerly known as First Union National Bank, to Messrs. Joseph Listengart, Thomas Bannigan, Shaper and James Street and Ms. Deborah Macdonald. Each of these KMI officers is primarily liable for any borrowing on his or her line of credit, and if we make any payment with respect to an outstanding loan, the officer on behalf of whom payment is made must surrender a percentage of his or her options to purchase KMI common stock. Our current obligations under the guaranties, on an individual basis, generally do not exceed $1.0 million and such obligations, in the aggregate, do not exceed $1.9 million. Our obligations under these guaranties do not include our obligations in respect of the $5 million loan obtained by Mr. Shaper in connection with his retention agreement, referred to above. To date, we have made no payment with respect to these lines of credit. Further, our involvement in these lines of credit will expire in October 2003. 34 KMI Asset Contributions In conjunction with our acquisition of Natural Gas Pipelines assets from KMI on December 31, 1999 and 2000, KMI became a guarantor of approximately $522.7 million of our debt. This amount has not changed as of December 31, 2002 and March 31, 2003. KMI would be obligated to perform under this guarantee only if we and/or our assets were unable to satisfy our obligations. 8. Partners' Capital As of March 31, 2003, our partners' capital consisted of: o 129,989,818 common units; o 5,313,400 Class B units; and o 46,513,029 i-units. Together, these 181,816,247 units represent the limited partners' interest and an effective 98% economic interest in the Partnership, exclusive of our general partner's incentive distribution rights. Our general partner has an effective 2% interest in the Partnership, excluding its incentive distribution rights. As of March 31, 2003, our common unit total consisted of 117,034,083 units held by third parties, 11,231,735 units held by KMI and its consolidated affiliates (excluding our general partner); and 1,724,000 units held by our general partner. Our Class B units were held entirely by KMI and our i-units were held entirely by KMR. As of December 31, 2002, our Partners' capital consisted of: o 129,943,218 common units; o 5,313,400 Class B units; and o 45,654,048 i-units. Our total common units outstanding at December 31, 2002, consisted of 116,987,483 units held by third parties, 11,231,735 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. Our Class B units were held entirely by KMI and our i-units were held entirely by KMR. All of our Class B units were issued in December 2000. The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. We initially issued i-units in May 2001. The i-units are a separate class of limited partner interests in us. All of our i-units are owned by KMR and are not publicly traded. In accordance with its limited liability company agreement, KMR's activities are restricted to being a limited partner in, and controlling and managing the business and affairs of, the Partnership, our operating partnerships and our subsidiaries. Through the combined effect of the provisions in our partnership agreement and the provisions of KMR's limited liability company agreement, the number of outstanding KMR shares and the number of i-units will at all times be equal. Furthermore, under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have the same value as the cash payment on the common unit. 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 the related cash but will retain the cash 35 and use the cash in our business. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. Based on the preceding, KMR received a distribution of 858,981 i-units on February 14, 2003. These additional i-units distributed were based on the $0.625 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, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. 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 $0.625 per unit paid on February 14, 2003 for the fourth quarter of 2002 required an incentive distribution to our general partner of $72.5 million. 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. The increased incentive distribution to our general partner paid for the fourth quarter of 2002 over the distribution paid for the fourth quarter of 2001 reflects the increase in the amount distributed per unit as well as the issuance of additional units. Our declared distribution for the first quarter of 2003 of $0.64 per unit will result in an incentive distribution to our general partner of approximately $75.5 million. This compares to our distribution of $0.59 per unit and incentive distribution to our general partner of approximately $61.0 million for the first quarter of 2002. 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, 2003 and 2002, the only difference between our net income and our comprehensive income was the unrealized gain or loss on derivatives utilized for hedging purposes. For more information on our hedging activities, see Note 9. Our total comprehensive income is as follows (in thousands): Three Months Ended March 31, 2003 2002 -------- -------- Net income $170,478 $141,433 Change in fair value of derivatives used for hedging purposes (53,870) (66,936) Reclassification of change in fair value of derivatives to net income 50,431 (24,359) ------ -------- Comprehensive income $167,039 $50,138 ======== ======= 10.Risk Management Hedging Activities Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. Through KMI, we use energy financial instruments to reduce our risk of changes in the prices of natural gas, natural gas liquids and crude oil markets (and carbon dioxide to the extent contracts are tied to crude oil prices) as discussed below. 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. 36 The energy risk management products that we use include: o commodity futures and options contracts; o fixed-price swaps; and o basis swaps. Pursuant to our management's approved policy, we are to engage in these activities only as a hedging mechanism against price volatility associated with: o pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; o pre-existing or anticipated physical carbon dioxide sales that have pricing tied to crude oil prices; o natural gas purchases; and o system use and storage. 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. Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 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. However, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting requirements of SFAS No. 133 and is accounted for using traditional accrual accounting. 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 derivatives that hedge our commodity price risks involve our normal business activities, which include the sale of natural gas, natural gas liquids, oil and carbon dioxide, and these derivatives have been designated as cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. To be effective, changes in the value of the derivative or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged. The ineffective portion of the gain or loss is reported in earnings immediately. The gains and losses included in Accumulated other comprehensive income are reclassified into earnings as the hedged sales and purchases take place. Approximately $34.1 million of the Accumulated other comprehensive loss balance of $48.7 million representing unrecognized net losses on derivative activities as of March 31, 2003 is expected to be reclassified into earnings during the next twelve months. During the quarter ended March 31, 2003, we reclassified $50.4 million of accumulated other comprehensive income into earnings. This amount includes the balance of $45.3 million representing unrecognized net losses on derivative activities at December 31, 2002. In addition, we did not reclassify any gains or losses 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 37 time period. We recognized a gain of $0.2 million during the first quarter of 2003 and a gain of $0.8 million during the first quarter of 2002 as a result of ineffective hedges. These amounts are reported within the captions Gas purchases and other costs of sales and Operations and maintenance in the accompanying Consolidated Statements of Income. For each of the quarters ended March 31, 2003 and 2002, we did not exclude any component of the derivative instruments' gain or loss from the assessment of hedge effectiveness. The differences between the current market value and the original physical contracts value associated with our hedging activities are primarily reflected as Other current assets and Accrued other current liabilities in the accompanying consolidated balance sheets. As of March 31, 2003, our balance of $78.8 million of Other current assets included approximately $66.1 million related to risk management hedging activities, and our balance of $358.5 million of Accrued other current liabilities included approximately $100.9 million related to risk management hedging activities. As of December 31, 2002, our balance of $104.5 million of Other current assets included approximately $57.9 million related to risk management hedging activities, and our balance of $298.7 million of Accrued other current liabilities included approximately $101.3 million related to risk management hedging activities. The remaining differences between the current market value and the original physical contracts value associated with our hedging activities are reflected as deferred charges or deferred credits in the accompanying consolidated balance sheets. As of March 31, 2003, our balance of $241.9 million of Deferred charges and other assets included approximately $4.5 million related to risk management hedging activities, and our balance of $220.3 million of Other long-term liabilities and deferred credits included approximately $19.3 million related to risk management hedging activities. As of December 31, 2002, our balance of $250.8 million of Deferred charges and other assets included approximately $5.7 million related to risk management hedging activities, and our balance of $199.8 million of Other long-term liabilities and deferred credits included approximately $8.5 million related to risk management hedging activities. Our over-the-counter swaps and options are with a number of parties, who principally have investment grade credit ratings. We both owe money and are owed money under these financial instruments. Defaults by counterparties under over-the-counter swaps and options could expose us to additional commodity price risks in the event that we are unable to enter into replacement contracts for such swaps and options on substantially the same terms. Alternatively, we may need to pay significant amounts to the new counterparties to induce them to enter into replacement swaps and options on substantially the same terms. While we enter into derivative transactions principally 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 in the future. 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, 2003 and as of December 31, 2002, we were a party to interest rate swap agreements with a notional principal amount of $1.95 billion for the purpose of hedging the interest rate risk associated with our fixed and variable rate debt obligations. As of March 31, 2003, a notional principal amount of $1.75 billion of these agreements effectively converts the interest expense associated with the following series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread: o $200 million principal amount of our 8.0% senior notes due March 15, 2005; o $200 million principal amount of our 5.35% senior notes due August 15, 2007; o $250 million principal amount of our 6.30% senior notes due February 1, 2009; o $200 million principal amount of our 7.125% senior notes due March 15, 2012; 38 o $300 million principal amount of our 7.40% senior notes due March 15, 2031; o $200 million principal amount of our 7.75% senior notes due March 15, 2032; and o $400 million principal amount of our 7.30% senior notes due August 15, 2033. These swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes, therefore, as of March 31, 2003, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with interest rate risk is through August 2033. The swap agreements related to our 7.40% senior notes contain mutual cash-out provisions at the then-current economic value every seven years. The swap agreements related to our 7.125% senior notes contain cash-out provisions at the then-current economic value at March 15, 2009. The swap agreements related to our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out provisions at the then-current economic value every five years. These interest rate swaps have been designated as fair value hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge a recognized asset or liability's exposure to changes in their fair value as fair value hedges and the gain or loss on fair value hedges are to be recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The effect of that accounting is to reflect in earnings the extent to which the hedge is not effective in achieving offsetting changes in fair value. As of March 31, 2003, we also had swap agreements that effectively convert the interest expense associated with $200 million of our variable rate debt to fixed rate. The maturity dates of these swap agreements range from September 2, 2003 to September 1, 2005. In the prior year, this hedge was designated a fair value hedge on our $200 million Floating Rate Senior Notes, which were retired in March 2002. Subsequent to the repayment of our Floating Rate Senior Notes, the swaps were designated as a cash flow hedge of the risk associated with changes in the designated benchmark interest rate (in this case, one-month LIBOR) related to forecasted payments associated with interest on an aggregate of $200 million of our portfolio of commercial paper. Our interest rate swaps meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the "shortcut" method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments or fixed rate payments under the swaps. Interest expense is accrued monthly and paid semi-annually. As of March 31, 2003, we recognized an asset of $168.9 million and a liability of $11.2 million for the $157.7 million net fair value of our swap agreements, and we included these amounts with Deferred charges and other assets and Other long-term liabilities and deferred credits on the accompanying balance sheet. The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged was recognized as Market value of interest rate swaps on the accompanying balance sheet. As of December 31, 2002, we recognized an asset of $179.1 million and a liability of $12.1 million for the $167.0 million net fair value of our swap agreements, and we included these amounts with Deferred charges and other assets and Other long-term liabilities and deferred credits on the accompanying balance sheet and again, the offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged was recognized as Market value of interest rate swaps on the accompanying balance sheet. We are exposed to credit related losses in the event of nonperformance by counterparties to these interest rate swap agreements. While we enter into derivative transactions primarily with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk. 11.Reportable Segments We divide our operations into four reportable business segments: 39 o Products Pipelines; o Natural Gas Pipelines; o CO2 Pipelines; and o Terminals. We evaluate performance based on each segments' 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 and terminaling 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 transmission, storage, gathering and sale of natural gas. Our CO2 Pipelines segment derives its revenues primarily from the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields and from the production and sale of crude oil from fields in the Permian Basin of West Texas. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and chemicals. Financial information by segment follows (in thousands): Three Months Ended March 31, 2003 2002 ----------- ----------- Revenues Products Pipelines............................ $ 144,417 $ 134,818 Natural Gas Pipelines......................... 1,480,954 537,557 CO2 Pipelines................................. 48,456 32,124 Terminals..................................... 115,011 98,566 ----------- ----------- Total consolidated revenues................... $ 1,788,838 $ 803,065 =========== =========== Depreciation and amortization (a) Products Pipelines............................ $ 16,560 $ 15,996 Natural Gas Pipelines......................... 12,626 11,425 CO2 Pipelines................................. 11,762 6,989 Terminals..................................... 9,028 6,916 ----------- ----------- Total consolidated depreciation and amortization................................ $ 49,976 $ 41,326 =========== =========== (a) 2003 amounts include $171 of non-cash asset retirement obligation accretion expense, included within operations and maintenance expense in the accompanying consolidated statement of income. $169 of such expense is included in CO2 Pipelines' depreciation and amortization total and $2 is included in Natural Gas Pipelines' depreciation and amortization total. Operating income Products Pipelines............................ $ 86,671 $ 78,573 Natural Gas Pipelines......................... 72,796 61,507 CO2 Pipelines................................. 20,181 12,634 Terminals..................................... 50,183 42,674 ----------- ----------- Total segment operating income................ 229,831 195,388 Corporate administrative expenses............. (34,679) (29,532) ------------ ------------ Total consolidated operating income........... $ 195,152 $ 165,856 =========== =========== 40 Earnings from equity investments Products Pipelines............................ $ 8,043 $ 8,001 Natural Gas Pipelines......................... 6,224 6,125 CO2 Pipelines................................. 10,006 9,145 Terminals..................................... 32 - ----------- ----------- Total consolidated equity earnings............ $ 24,305 $ 23,271 =========== =========== Amortization of excess cost of equity investments Products Pipelines............................ $ 821 $ 821 Natural Gas Pipelines......................... 69 69 CO2 Pipelines................................. 504 504 Terminals..................................... - - ----------- ----------- Total consolidated amortization of excess cost of invests................................. $ 1,394 $ 1,394 =========== =========== Income taxes and Other, net - income (expense) Products Pipelines............................ $ (2,600) $ (2,775) Natural Gas Pipelines......................... (85) 5 CO2 Pipelines................................. 17 94 Terminals..................................... (1,243) (1,775) ------------ ------------ Total consolidated income taxes and Other, net $ (3,911) $ (4,451) ============ ============ Segment earnings Products Pipelines............................ $ 91,293 $ 82,978 Natural Gas Pipelines......................... 78,866 67,568 CO2 Pipelines................................. 29,700 21,369 Terminals..................................... 48,972 40,899 ----------- ----------- Total segment earnings........................ 248,831 212,814 Interest and corporate administrative expenses (a) ............................... (78,353) (71,381) ------------ ------------ Total consolidated net income................. $ 170,478 $ 141,433 =========== =========== (a) Includes interest and debt expense, general and administrative expenses, minority interest expense, cumulative effect adjustment from a change in accounting principle (2003 only) and other insignificant items. March 31, Dec. 31, 2003 2002 ----------- -------- Assets Products Pipelines............................ $ 3,056,164 $ 3,088,799 Natural Gas Pipelines......................... 3,476,175 3,121,674 CO2 Pipelines................................. 722,512 613,980 Terminals..................................... 1,302,494 1,165,096 ----------- ----------- Total segment assets.......................... 8,557,345 7,989,549 Corporate assets (a).......................... 244,889 364,027 ----------- ----------- Total consolidated assets..................... $ 8,802,234 $ 8,353,576 =========== =========== (a) Includes cash, cash equivalents and certain unallocable deferred charges. 12. New Accounting Pronouncements In April 2002, the Financial Accounting Standards Board issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This Statement eliminates the requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses are now classified as extraordinary items only if they are deemed to be unusual and infrequent, in accordance with the current GAAP criteria for extraordinary classification. In addition, SFAS No. 145 eliminates an inconsistency in lease accounting by requiring that modifications of capital leases that result in reclassification as operating leases be accounted for consistent with sale-leaseback accounting rules. This Statement also contains other nonsubstantive corrections to authoritative accounting literature. The changes related to debt extinguishment are effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting are effective for transactions occurring after May 15, 2002. Adoption of this Statement has not had any immediate effect on our consolidated financial statements. We will apply this guidance 41 prospectively. In June 2002, the Financial Accounting Standards Board issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally Emerging Issues Task Force Issue No. 94-3. We adopted the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of the company's commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. In November 2002, the Financial Accounting Standards Board issued Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation of Financial Accounting Standards Board Statements No. 5, 57 and 107, and rescission of FIN No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. This interpretation incorporates, without change, the guidance in FIN No. 34, "Disclosure of Indirect Guarantees of Indebtedness of Others," which is being superceded. The initial recognition and initial measurement provisions of FIN No. 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in this interpretation are effective for financial statements of interim or annual periods after December 15, 2002, and have been adopted. In December 2002, the Financial Accounting Standards Board issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." This amendment to SFAS No. 123, "Accounting for Stock-Based Compensation," provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The provisions of this statement are effective for financial statements of interim or annual periods after December 15, 2002. Adoption of this Statement has not had any immediate effect on our consolidated financial statements. On April 30 2003, the Financial Accounting Standards Board issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This Statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. The new guidance amends SFAS No. 133 for decisions made: o as part of the Derivatives Implementation Group process that effectively required amendments to SFAS No. 133; o in connection with other Board projects dealing with financial instruments; and o regarding implementation issues raised in relation to the application of the definition of a derivative, particularly regarding the meaning of an "underlying" and the characteristics of a derivative that contains financing components. The amendments set forth in SFAS No. 149 are intended to improve financial reporting by requiring that contracts with comparable characteristics be accounted for similarly. In particular, this Statement clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative as discussed in SFAS No. 133. In addition, it clarifies when a derivative contains a financing component that warrants special reporting in the statement of cash flows. SFAS No. 149 amends certain other existing pronouncements. These changes are intended to result in more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting. 42 The Statement is effective for contracts entered into or modified after June 30, 2003, except as stated below and for hedging relationships designated after June 30, 2003. We will apply this guidance prospectively. We have not yet quantified the impacts of adopting this Statement on our financial position or results of operations. We will continue to apply the provisions of this Statement that relate to SFAS No. 133 Implementation Issues that have been effective for fiscal quarters that began prior to June 15, 2003, in accordance with their respective effective dates. In addition, certain provisions relating to forward purchases or sales of "when-issued" securities or other securities that do not yet exist, will be applied to existing contracts as well as new contracts entered into after June 30, 2003. 43 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. Results of Operations First Quarter 2003 Compared With First Quarter 2002 For the quarter ended March 31, 2003, our operating results represented our most profitable quarter ever. Total consolidated net income before a change in accounting principle was a record $167.0 million ($0.50 per diluted unit), an 18% increase from the $141.4 million ($0.48 per diluted unit) in consolidated net income reported for the first quarter of 2002. Additionally, our 2003 first quarter results benefited from a cumulative-effect adjustment of $3.5 million related to a change in accounting for asset retirement obligations pursuant to our adoption of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. After the cumulative-effect adjustment, net income for the quarter totaled $170.5 million ($0.52 per diluted unit). For more information on this cumulative-effect adjustment from a change in accounting principle, see Note 4 to our Consolidated Financial Statements, included elsewhere in this report. Revenues for the first quarter of 2003 were a record $1,788.8 million, compared with revenues of $803.1 million in the same year-earlier period. The increase, primarily due to higher natural gas prices, was largely offset by similar increases in natural gas purchase costs. Our first quarter 2003 operating income was $195.2 million, the second-highest level ever attained and 18% over the $165.9 million in operating income earned during the first quarter of 2002. Operating expenses, excluding depreciation, depletion and amortization, general and administrative expenses and taxes, other than income taxes, were $1,494.5 million in the first quarter of 2003, compared with $553.8 million in the same period a year ago. Our first quarter results demonstrated balanced growth across our business portfolio as all four of our business segments reported quarter-to-quarter increases in earnings, operating income and revenues. The increases were driven primarily by internal growth, mainly resulting from our ongoing expansion and capital improvement projects within our CO2 Pipelines and Natural Gas Pipelines business segments, but also by the acquisitions of pipeline and terminal businesses that we have made since the beginning of the first quarter of 2002. The largest of these was the January 31, 2002 purchase of Kinder Morgan Tejas. Kinder Morgan Tejas' operations include a 3,400-mile Texas 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. First quarter earnings from our investments accounted for under the equity method of accounting, which include investments in Plantation Pipe Line Company, Cortez Pipeline Company and the Red Cedar Gathering Company, were up approximately 5% in the first quarter of 2003, compared to the same year ago period. Equity earnings, net of amortization of excess costs, were $22.9 million and $21.9 million for each of the first three months of 2003 and 2002, respectively. In addition, on April 16, 2003, we declared a record quarterly cash distribution of $0.64 per unit (an annualized rate of $2.56). This first quarter 2003 distribution will be paid on May 15, 2003, and is up 8% from the $0.59 per unit distribution we made for the first quarter of 2002. Furthermore, we expect to declare cash distributions of at least $2.63 per unit for 2003, and we expect to increase our quarterly cash distribution to at least $0.68 per unit (an annualized rate of $2.72) by the fourth quarter of 2003. However, no assurance can be given that we will be able to achieve this level of distributions. Products Pipelines Our Products Pipelines segment reported earnings of $91.3 million on revenues of $144.4 million in the first quarter of 2003. In the first quarter of 2002, the segment reported earnings of $83.0 million on revenues of $134.8 million. Operating income for each of the quarters ended March 31, 2003 and 2002 was $86.7 million and $78.6 million, respectively. The $8.3 million (10%) increase in quarter-to-quarter earnings resulted from internal growth, primarily driven by record earnings from our North System liquids pipeline and higher returns from terminal assets associated with our Pacific operations. The $9.6 million (7%) increase in overall segment revenues includes a $3.5 million increase in revenues from our North System, primarily due to a 17% increase in throughput volume and higher average tariff rates in the first quarter of 2003 compared to the same period last year. The throughput volume increase was due to 44 cold weather in the Midwest and strong propane demand. Revenues from our Pacific operations accounted for $2.0 million of the quarter-to-quarter increase in overall segment revenues. Although total delivery volumes on our Pacific operations were down slightly in the first quarter of 2003 compared to last year, average tariff rates remained relatively flat, and we benefited from higher terminal revenue as a result of increased ethanol blending operations. Revenues from our CALNEV pipeline increased $1.6 million in the first quarter of 2003 compared to the first quarter of 2002. CALNEV benefited from a slight (1%) increase in transport volumes and an almost 3% increase in average tariff rates. The segment's expenses, excluding depreciation charges and taxes, other than income taxes, increased a slight 1% in the first quarter of 2003, compared to the first quarter a year ago. Expenses totaled $36.0 million in the first quarter of 2003 and $35.5 million in the first quarter of 2002. The $0.5 million change was the result of higher operations and maintenance expenses, partially offset by lower fuel and power expenses. Earnings from our Products Pipelines' equity investments, net of amortization of excess costs, were $7.2 million in each of the first quarters of 2003 and 2002. The segment's equity earnings primarily relate to our 51% ownership interest in Plantation Pipe Line Company. Plantation's earnings in the first quarter of 2003 were essentially unchanged from its earnings in the first quarter of 2002. Lower pipeline revenues resulting from a decrease in delivery volumes were offset by higher non-transportation income items. Natural Gas Pipelines Our Natural Gas Pipelines segment reported earnings of $78.9 million on revenues of $1,481.0 million in the first quarter of 2003. In the first quarter of 2002, the segment reported earnings of $67.6 million on revenues of $537.6 million. The segment's expenses, excluding depreciation charges and taxes, other than income taxes, were $1,391.3 million in the first quarter of 2003 and $461.3 million in the first quarter of 2002. Operating income for each of the two quarters ended March 31, 2003 and 2002 was $72.8 million and $61.5 million, respectively. The segment's $11.3 million (17%) increase in earnings in the first quarter of 2003 compared to the first quarter of 2002 was primarily attributable to internal growth on our Kinder Morgan Interstate Gas Transmission and Trailblazer Pipeline Company natural gas pipeline systems. Together, these two Rocky Mountain natural gas pipeline systems accounted for $10.6 million of the quarter-to-quarter increase in segment earnings. The increase was primarily the result of higher operational sales of natural gas at higher margins as well as an increase in natural gas transport volumes. In May 2002, we completed a fully-subscribed, $59 million expansion project on our Trailblazer system that increased transportation capacity on the pipeline by approximately 60%. Earnings from our Texas intrastate natural gas pipeline group were up $0.9 million in the first quarter of 2003, compared to the same period last year, principally due to the contributions from our North Texas and Mier-Monterrey natural gas pipelines. In addition to the Kinder Morgan Tejas and Kinder Morgan Texas Pipeline systems, our Texas intrastate natural gas group now includes the Kinder Morgan North Texas pipeline, completed in August 2002, and the Mier-Monterrey pipeline, completed in March 2003. The North Texas pipeline is an 86-mile system that transports natural gas from an interconnect with KMI's Natural Gas Pipeline Company of America system in Lamar County, Texas to electric generating facilities within the State of Texas. FPL Energy has entered into a 30-year long-term, binding firm transportation contract with us for the full 325,000 dekatherms per day of natural gas capacity on the North Texas pipeline. The Mier-Monterrey pipeline stretches from south Texas to Monterrey, Mexico and can transport up to 375,000 dekatherms per day of natural gas. We have entered into a 15-year contract with Pemex Gas Y Petroquimica Basica, which has subscribed for all of the capacity on the pipeline. The pipeline connects to a 1,000-megawatt power plant complex and to the Pemex natural gas transportation system. The segment's significant increases in period-to-period revenues and expenses relate primarily to higher natural gas prices in the first quarter of 2003, and to our January 31, 2002 acquisition of Kinder Morgan Tejas. The acquisition and subsequent integration of its assets with our pre-existing natural gas pipeline assets in the State of Texas, particularly our KMTP system, has produced a strategic and complementary intrastate pipeline business combination. Both Kinder Morgan Tejas and KMTP purchase and sell significant volumes of natural gas, which is 45 transported through their pipeline systems. Our objective is to match purchases and sales in the aggregate, thus locking-in the equivalent of a transportation fee. The purchase and sale activity results in considerably higher revenues and operating expenses compared to the interstate natural gas pipeline systems of KMIGT and Trailblazer Pipeline Company. Both KMIGT and Trailblazer charge a transportation fee for gas transmission service but neither system has significant gas purchases and resales. The overall increase in segment earnings was partially offset by higher depreciation and amortization charges. Depreciation expenses totaled $12.6 million, up 11% from the $11.4 million reported in the first quarter of 2002. The increase was due to the additional capital investments we have made since the end of the first quarter of 2002 and to our acquisition of Kinder Morgan Tejas. Earnings from our Natural Gas Pipelines' equity investments, net of amortization of excess costs, were essentially flat for the first quarter of 2003 compared to the first quarter of 2002. The segment's equity investments, which include investments in Red Cedar, Thunder Creek Gas Services, LLC and Coyote Gas Treating, LLC, reported $6.2 million in net equity earnings for the first quarter of 2003 versus $6.1 million for the same prior year period. The slight $0.1 million increase in equity earnings was mainly due to higher earnings from the segment's 25% ownership interest in Thunder Creek. CO2 Pipelines Our CO2 Pipelines segment reported earnings of $29.7 million on revenues of $48.5 million in the first three months of 2003. The segment reported earnings of $21.4 million on revenues of $32.1 million in the same period of 2002. Expenses, excluding depreciation, depletion, amortization, and taxes, other than income taxes, totaled $14.5 million in the first quarter of 2003 versus $10.8 million in the first quarter of 2002. Operating income for each of the quarters ended March 31, 2003 and 2002 was $20.2 million and $12.6 million, respectively. The $8.3 million (39%) increase in period-to-period segment earnings was primarily attributable to the $16.4 million (51%) increase in revenues, partially offset by higher depreciation, depletion and operating expenses. The increase in revenues was mainly due to higher oil production volumes and higher average oil prices. The segment reported a 50% increase in oil production volumes from its SACROC Unit and benefited from an 8% increase in our realized weighted average hedged price of oil per barrel. The general increase in segment revenues was partially offset by lower carbon dioxide delivery volumes, primarily due to reduced deliveries from the McElmo Dome carbon dioxide Unit. The overall increase in segment earnings was partially offset by higher depreciation, depletion and amortization charges and by higher operations and maintenance expenses. Non-cash depletion and depreciation-related charges were up $4.6 million, mainly as a result of the higher production volumes and additional capital investments that we have made since the end of the first quarter of 2002. The $3.7 million period-to-period increase in expenses, excluding depreciation, depletion, amortization, and taxes, other than income taxes, was primarily due to the increase in oil production and to higher fuel and power expenses as a result of higher production volumes. In the first quarter of 2003, our CO2 Pipelines segment reported $9.5 million in equity earnings, net of amortization of excess costs. The amount represents a 10% increase from the $8.6 million in equity earnings in the first quarter of 2002. The increase resulted from higher earnings from the segment's 15% ownership interest in MKM Partners, L.P. MKM Partners, L.P., an oil and gas joint venture with Marathon Oil Company, had higher earnings due to higher average oil prices and higher production. Higher overall segment earnings were also offset slightly by a $0.4 million increase in taxes, other than income taxes, primarily the result of higher production taxes. Terminals Our Terminals segment, including both our bulk and liquids terminal businesses, reported earnings of $49.0 million on revenues of $115.0 million in the first quarter of 2003. In the first quarter of 2002, the segment earned $40.9 million on revenues of $98.6 million. Expenses, excluding depreciation and taxes, other than income taxes, for each of the quarters ended March 31, 2003 and 2002 were $52.7 million and $46.2 million, respectively. Operating income for each of the quarters ended March 31, 2003 and 2002 was $50.2 million and $42.7 million, respectively. 46 Excluding acquisitions, earnings increased $4.6 million and revenues increased $7.1 million for the first quarter of 2003 compared to the same prior year period. The favorable change was driven primarily by expansion projects that have increased utilization and leaseable capacity at certain terminals, most notably our Carteret, New Jersey and Harvey, Louisiana liquids terminals. Our total leaseable capacity for liquids products increased 3% in the first quarter of 2003 compared to the first quarter of 2002, and the increase resulted in a $4.3 million increase in segment earnings and a $4.9 million increase in revenues from liquids terminals that were owned in both periods. First quarter earnings from all bulk terminal operations owned during each year were essentially the same in 2003 versus 2002. Increases from an almost 4% increase in coal transload volumes at our Grand Rivers, Kentucky and Cora, Illinois coal terminals, as well as from strong fertilizer and soda ash exports from bulk terminal facilities located on the West Coast were offset by a quarter-to-quarter drop in engineering services. Key acquisitions of terminal businesses since the end of the first quarter of 2002 accounted for $3.5 million of the $8.1 million (20%) increase in segment earnings, and $9.3 million of the $16.4 million (17%) increase in segment revenues. These acquisitions included: o the Milwaukee Bagging Operations, acquired effective May 1, 2002; o the Owensboro Gateway Terminal, acquired effective September 1, 2002; o the St. Gabriel Terminal, acquired effective September 1, 2002; o the purchase of four floating cranes at our bulk terminal facility in Port Sulphur, Louisiana in December 2002; and o the bulk terminal businesses acquired from M.J. Rudolph Corporation, effective January 1, 2003. The above acquisitions accounted for $5.3 million in expenses, excluding depreciation and taxes, other than income taxes, in the first quarter of 2003. Segment Operating Statistics Operating statistics for the first three months of 2003 and 2002 are as follows: Three Months Ended March 31, 2003 March 31, 2002 -------------- -------------- Products Pipelines Gasoline (MMBbl)............................... 104.0 108.2 Diesel (MMBbl)................................. 36.0 35.5 Jet Fuel (MMBbl)............................... 26.6 27.3 --------- --------- Total Refined Product Volumes (MMBbl).......... 166.6 171.0 Natural Gas Liquids (MMBbl).................... 12.8 11.1 --------- --------- Total Delivery Volumes (MMBbl) (1)............. 179.4 182.1 Natural Gas Pipelines Transport Volumes (Bcf) (2).................... 260.4 242.4 CO2 Pipelines Delivery Volumes (Bcf) (3)..................... 102.3 113.1 SACROC Oil Production (MBbl/d) ................ 17.0 11.2 Realized Weighted Average Oil Price per Bbl.... $ 24.88 $ 22.98 Terminals Bulk Terminals Transload Tonnage (MMtons) (4).............. 14.0 14.2 Liquids Terminals Leaseable Capacity (MMBbl).................. 35.6 34.5 Utilization %............................... 96% 97% 47 Note: Historical pro forma for acquired assets. (1) Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress and Heartland pipeline volumes. (2) Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastates 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; excludes operatorship of LAXT bulk terminal. Other Items not attributable to any segment include general and administrative expenses, interest income and expense and minority interest. For the first quarter of 2003, these items were offset by the $3.5 million cumulative-effect adjustment related to our change in accounting for asset retirement obligations. Together, these items (including the cumulative-effect adjustment) totaled $78.4 million in the first quarter of 2003 and $71.4 million in the first quarter of 2002. Our general and administrative expenses totaled $34.7 million in the first quarter of 2003 compared with $29.5 million in the first quarter of 2002. The $5.2 million (18%) quarter-to-quarter increase in general and administrative expenses primarily related to higher employee benefit costs, higher labor and payroll tax expenses, and higher general expenses, mainly resulting from timing differences in the payment of general services, including legal fees. Our total interest expense, net of interest income, was $44.9 million in the first quarter of 2003 and $39.0 million in the first quarter of 2002. The $5.9 million (15%) increase in net interest charges was due to higher average borrowings during the first quarter of 2003 compared with the same period last year. The increase in period-to-period net interest charges was partially offset by lower average interest rates during the first quarter of 2003. Minority interest totaled $2.2 million in the first quarter of 2003, compared to $2.8 million in the first quarter of 2002. The $0.6 million (21%) decrease resulted primarily from our acquisition of an additional ownership interest in Trailblazer Pipeline Company. In May 2002, we acquired the remaining 33 1/3% ownership interest in Trailblazer that we did not already own, thereby eliminating the minority interest relating to Trailblazer Pipeline Company. 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): March 31, Dec. 31, 2003 2002 ----------- ----------- Long-term debt, excluding market value of interest rate swaps................................ $ 3,787,234 $ 3,659,533 Minority interest.................................... 41,976 42,033 Partners' capital.................................... 3,425,554 3,415,929 ___________ ___________ Total capitalization............................... 7,254,764 7,117,495 Short-term debt, less cash and cash equivalents...... (22,361) (41,088) ___________ ___________ Total invested capital............................. $ 7,232,403 $ 7,076,407 =========== =========== Capitalization: - -------------- Long-term debt, excluding market value of interest rate swaps....................................... 52.2% 51.4% Minority interest.................................. 0.6% 0.6% Partners' capital.................................. 47.2% 48.0% ------ ------ 100.0% 100.0% ====== ====== Invested Capital: - ---------------- Total debt, less cash and cash equivalents and excluding market value of interest rate swaps.... 52.1% 51.1% Partners' capital and minority interest............ 47.9% 48.9% ------ ------ 100.0% 100.0% ====== ====== 48 Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements (other than distributions to our common unitholders, Class B unitholders and general partner) through borrowings under our credit facilities, issuing short-term commercial paper, long-term notes or additional common units or issuing additional i-units to KMR. In general, we expect to fund: o cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; o expansion capital expenditures and working capital deficits with cash retained as a result of paying quarterly distributions on i-units in additional i-units, additional borrowings, the issuance of additional common units or the issuance of additional i-units to KMR; o interest payments from cash flows from operating activities; and o debt principal payments with additional borrowings as such debt principal payments become due or by the issuance of additional common units or the issuance of additional i-units to KMR. As a publicly traded limited partnership, our common units are attractive primarily to individual investors. Individual investors represent a small segment of the total equity capital market. We believe institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations. Thus, KMR makes purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutions. As of March 31, 2003, our current commitments for sustaining capital expenditures were approximately $77.8 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 2003 sustaining capital expenditure plan. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. Some of our customers are experiencing severe financial problems that have had a significant impact on their creditworthiness. We are working to implement, to the extent allowable under applicable contracts, laws and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these customers. We cannot assure that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position or future results of operations. Operating Activities Net cash provided by operating activities was $171.2 million for the three months ended March 31, 2003, versus $222.6 million in the comparable period of 2002. The period-to-period decrease of $51.4 million in cash flow from operations resulted chiefly from a $96.1 million decrease in cash inflows relative to net changes in working capital items. The unfavorable working capital change was primarily the result of timing differences in the collection on and payments of our accounts receivables and payables and from changes in customer prepayments of natural gas transportation revenues. Partially offsetting the decrease in cash inflows due to net changes in working capital items was a $33.3 million increase in cash earnings from across our business portfolio and an $11.7 million increase in the amount of distributions we received from our equity investments. The increase in equity investment distributions related to higher distributions from our 50% equity interest in Cortez Pipeline Company and from our 49% equity interest in the Red Cedar Gathering Company. Investing Activities Net cash used in investing activities was $158.5 million for the three month period ended March 31, 2003, compared to $849.3 million in the comparable 2002 period. The $690.8 million decrease in cash used in investing activities was primarily attributable to higher expenditures made for strategic acquisitions in the 2002 period. For 49 the three months ended March 31, 2002, our acquisition outlays totaled $758.3 million, including $700.9 million for Kinder Morgan Tejas. For the three months ended March 31, 2003, our asset acquisitions totaled $5.6 million, including $3.5 million used to acquire the remaining 50% ownership interest in ICPT, L.L.C., a small liquids pipeline limited liability company associated with our St. Gabriel liquids terminal business. Other investing activities accounted for $2.5 million of the overall decrease in cash used in investing activities in the first quarter of 2003 compared to the first quarter of 2002. The decrease related to higher cash inflows from changes in underground gas storage in the first quarter of 2003. Offsetting the overall period-to-period decrease in funds used in investing activities was a $54.8 million increase in funds used for capital expenditures and a $9.1 million increase in contributions to equity investments. Including expansion and maintenance projects, our capital expenditures were $145.8 million in the first three months of 2003 versus $91.0 million in the same year-ago period. The increase was mainly due to our continued investment in our Natural Gas Pipelines, Terminals and CO2 Pipelines business segments. We continue to expand and grow our existing businesses and have current projects in place that will significantly add storage and throughput capacity to our terminaling and carbon dioxide flooding operations. We plan to invest approximately $230 million in additional development at the SACROC Unit in the Permian Basin of West Texas during 2003. Our sustaining capital expenditures were $17.1 million for the first three months of 2003 compared to $13.2 million for the first three months of 2002. The increase in our contributions to equity investments related to an $8.4 million contribution to Plantation Pipe Line Company in the first quarter of 2003. Financing Activities Net cash used in financing activities amounted to $17.0 million for the three months ended March 31, 2003. In the comparable quarter of 2002, our financing activities provided $593.2 million. The decrease of $610.2 million from the comparable 2002 period was mainly the result of lower cash inflows from overall debt financing activities. The increase reflects higher net debt issuance in the first quarter of 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. In addition, net borrowings under our commercial paper program were higher during the first quarter of 2002 compared to the first quarter of 2003. The increase from net borrowings was partially offset by the payment of our maturing $200 million in principal amount of Floating Rate senior notes in March 2002. The overall decrease in funds provided by our financing activities also resulted from a $28.1 million increase in distributions to our partners. Distribution to all partners increased to $160.4 million in the first quarter of 2003 compared to $132.3 million in the first quarter of 2002. 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, 2003, we paid a quarterly distribution of $0.625 per unit for the fourth quarter of 2002, 14% greater than the $0.55 per unit distribution paid for the fourth quarter of 2001. We paid this distribution in cash to our common unitholders and to our class B unitholders. KMR, our sole i-unitholder, received 858,981 additional i-units based on the $0.625 cash distribution per common unit. For each outstanding i-unit that KMR held, a fraction (0.018815) of an i-unit was issued. The fraction was determined by dividing: o $0.625, the cash amount distributed per common unit by o $33.219, the average of KMR'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. 50 On April 16, 2003, we declared a cash distribution for the quarterly period ended March 31, 2003, of $0.64 per unit. The distribution will be paid on or before May 15, 2003, to unitholders of record as of April 30, 2003. Our common unitholders and Class B unitholders will receive cash. KMR, our sole i-unitholder, will receive a distribution of 0.018488 i-units for each outstanding i-unit held based on the $0.64 distribution per common unit. We believe that future operating results will continue to support similar levels of quarterly cash and i-unit distributions; however, no assurance can be given that future distributions will continue at such levels. Partnership Distributions Our partnership agreement requires that we distribute 100% of available cash, as defined in our partnership agreement, to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of our cash receipts, including cash received by our operating partnerships, less cash disbursements and net additions to reserves (including any reserves required under debt instruments for future principal and interest payments) and amounts payable to the former general partner of SFPP, L.P. in respect of its remaining 0.5% interest in SFPP. Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, 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 KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Typically, our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, 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 KMR'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 do not distribute cash to i-unit owners but 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 value of cash and i-units being distributed. The general partner's incentive distribution for 51 the distribution that we declared for the first quarter of 2003 was $75.5 million. 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 that we paid during the first quarter of 2003 to our general partner (for the fourth quarter of 2002) was $72.5 million. The general partner's incentive distribution that we paid during the first quarter of 2002 to our general partner (for the fourth quarter of 2001) was $54.4 million. All partnership distributions we declare for the fourth quarter of each year are declared and paid in the first quarter of the following year. Information Regarding Forward-Looking Statements This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," "will," or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of 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; o economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand; o changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission; o our ability to integrate any acquired operations into our existing operations; o our ability to acquire new businesses and assets and to make expansions to our facilities; o difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to our terminals or pipelines; o our ability to successfully identify and close acquisitions and make cost-saving changes in operations; o shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use or supply our services; o changes in laws or regulations, third party relations and approvals, decisions of courts, regulators and governmental bodies may adversely affect our business or our ability to compete; o our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities; o our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or 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; 52 o acts of nature, sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits; o the condition of the capital markets and equity markets in the United States; o the political and economic stability of the oil producing nations of the world; o national, international, regional and local economic, competitive and regulatory conditions and developments; o the ability to achieve cost savings and revenue growth; o rates of inflation; o interest rates; o the pace of deregulation of retail natural gas and electricity; o the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products; and o the timing and success of business development efforts. You should not put undue reliance on any forward-looking statements. See Items 1 and 2 "Business and Properties - Risk Factors" of our annual report filed on Form 10-K for the year ended December 31, 2002, 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 2002 Form 10-K report. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments. Our future results also could be adversely impacted by unfavorable results of litigation and the coming to fruition of contingencies referred to in Note 3 to our consolidated financial statements included elsewhere in this report. 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, 2002, in Item 7A of our 2002 Form 10-K report. For more information on our risk management activities, see Note 10 to our consolidated financial statements included elsewhere in this report. Item 4. Controls and Procedures. Within the 90-day period prior to the filing of this report, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-14(c) under the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective. No significant changes were made in our internal controls or in other factors that could significantly affect these disclosure controls and procedures subsequent to the date of their evaluation. 53 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 4.1 --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. 11 --Statement re: computation of per share earnings. 99.1--Chief Executive Officer Certification. 99.2--Chief Financial Officer Certification. - --------------------- (b) Reports on Form 8-K Current report dated January 15, 2003 on Form 8-K was furnished on January 16, 2003, pursuant to Items 7 and 9 of that form. In Item 9, we provided notice that on January 15, 2003, we issued a press release announcing record earnings in 2002 and an increase in our quarterly distribution to unitholders. Our 2002 net income totaled $608.4 million, up 38% over our 2001 net income of $442.3 million, and our cash distribution for the fourth quarter of 2002 was raised to $0.625 per common unit, up 14% over our fourth quarter 2001 cash distribution of $0.55 per common unit. A copy of the press release was filed in Item 7 as an exhibit pursuant to Item 9. Current report dated January 21, 2003 on Form 8-K was furnished on January 21, 2003, pursuant to Item 9 of that form. We provided notice that we, along with Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and Kinder Morgan Management, LLC, a subsidiary of our general partner that manages and controls our business and affairs, intended to make presentations on January 22, 2003 at the Kinder Morgan 2003 Analyst Conference to address the fiscal year 2002 results, the fiscal year 2003 outlook, and other business information about 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, 54 Inc.'s website at: http://www.kindermorgan.com/investor/presentations/. Interested parties would also be able to access the presentations by audio webcast, both live and on-demand. Live webcast presentations could be accessed at: http://www.videonewswire.com/event.asp?id=10577, by choosing the webcast link and completing the registration page. The on-demand webcast (replay) for the presentations would be available within 24 hours of the actual presentation, would remain available for 45 days, and could also be accessed at: http://www.videonewswire.comevent.asp?id=10577. Current Report dated May 5, 2003 on Form 8-K was filed on May 6, 2003, pursuant to Item 5 of that form. We reported that on May 2, 2003 we were notified by the staff of the SEC that the staff is conducting an informal investigation concerning our public disclosures regarding the allocation of purchase price between assets and goodwill in connection with our acquisition of the assets of Tejas Gas, LLC. The staff has not asserted that we acted improperly or illegally, and has indicated that the Commission has not issued a formal order. We have voluntarily agreed to cooperate fully with the staff's informal investigation. We believe that the informal investigation will not result in a material change to our financial statements. 55 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. KINDER MORGAN ENERGY PARTNERS, L.P. (A Delaware limited partnership) By: KINDER MORGAN G.P., INC., its General Partner By: KINDER MORGAN MANAGEMENT, LLC, its Delegate /s/ C. Park Shaper ------------------------------ C. Park Shaper Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc. (principal financial officer and principal accounting officer) Date: May 14, 2003 56 CERTIFICATIONS I, Richard D. Kinder, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy Partners, L.P.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ Richard D. Kinder ------------------------------ Richard D. Kinder Chairman and Chief Executive Officer Date: May 14, 2003 57 I, C. Park Shaper, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy Partners, L.P.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ C. Park Shaper ------------------------------ C. Park Shaper Vice President, Treasurer and Chief Financial Officer Date: May 14, 2003 58 EX-11 3 km-ex11_539418.txt COMPUTATION RE: EARNINGS PER UNIT KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES EXHIBIT 11 - STATEMENT RE: COMPUTATION OF PER SHARE EARNINGS (Dollars In Thousands Except Per Unit Amounts) FOR THE QUARTER ENDED MARCH 31, 2003 2002 =============================================================================== Weighted-average number of limited partners' units on which limited partners' net income per unit is based: Basic 181,376,635 166,048,877 Add: Incremental units under common unit option plan 133,591 197,088 - -------------------------------------------------------------------------------- Assuming dilution 181,510,226 166,245,965 ================================================================================ Income Before Cumulative Effect of a Change in Accounting Principle $ 167,013 $ 141,433 Add: Cumulative effect adjustment from change in accounting for asset retirement obligations 3,465 - - -------------------------------------------------------------------------------- Net Income $ 170,478 $ 141,433 - -------------------------------------------------------------------------------- Calculation of Limited Partners' interest in Net Income: - -------------------------------------------------------------------------------- Income Before Cumulative Effect of a Change in Accounting Principle $ 167,013 $ 141,433 - -------------------------------------------------------------------------------- Less: General Partner's interest (76,425) (61,794) - -------------------------------------------------------------------------------- Limited Partner's interest 90,588 79,639 - -------------------------------------------------------------------------------- Add: Limited Partner's interest in Change in Accounting Principle 3,430 - - -------------------------------------------------------------------------------- Limited Partners' interest in Net Income $ 94,018 $ 79,639 ================================================================================ Earnings per limited partner unit: Limited Partners' Income Before Cumulative Effect of a Change in Accounting Principle per unit Basic $ .50 $ .48 Diluted $ .50 $ .48 Limited Partners' Cumulative Effect of a Change in Accounting Principle per unit Basic $ .02 $ - Diluted $ .02 $ - Limited Partners' Net Income per unit Basic $ .52 $ .48 Diluted $ .52 $ .48 EX-99.1 4 km-ex991_539164.txt SARBANES-OXLEY CERTIFICATION CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Kinder Morgan Energy Partners, L.P. (the "Company") on Form 10-Q for the quarterly period ending March 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. A signed original of this written statement required by Section 906 has been provided to Kinder Morgan Energy Partners, L.P. and will be retained by Kinder Morgan Energy Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request. Dated: May 14, 2003 /s/ Richard D. Kinder -------------------------- Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC, the delegate of Kinder Morgan G.P., Inc., the General Partner of Kinder Morgan Energy Partners, L.P. EX-99.2 5 km-ex992_539166.txt SARBANES-OXLEY CERTIFICATION CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Kinder Morgan Energy Partners, L.P. (the "Company") on Form 10-Q for the quarterly period ending March 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. A signed original of this written statement required by Section 906 has been provided to Kinder Morgan Energy Partners, L.P. and will be retained by Kinder Morgan Energy Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request. Dated: May 14, 2003 /s/ C. Park Shaper ---------------------------------- C. Park Shaper Vice President and Chief Financial Officer of Kinder Morgan Management, LLC, the delegate of Kinder Morgan G.P., Inc., the General Partner of Kinder Morgan Energy Partners, L.P. -----END PRIVACY-ENHANCED MESSAGE-----