10-Q 1 km-form10q_601101v3.txt FORM 10-Q 9/30/03 F O R M 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 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 134,721,558 common units outstanding at October 31, 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 and Nine Months Ended September 30, 2003 and 2002...................................... 3 Consolidated Balance Sheets - September 30, 2003 and December 31, 2002............................................................. 4 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2003 and 2002...................................... 5 Notes to Consolidated Financial Statements....................... 6 Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations............................................. 41 Results of Operations............................................ 41 Financial Condition.............................................. 52 Information Regarding Forward-Looking Statements................. 56 Item 3: Quantitative and Qualitative Disclosures About Market Risk........ 58 Item 4: Controls and Procedures........................................... 58 ` PART II. OTHER INFORMATION Item 1: Legal Proceedings................................................. 59 Item 2: Changes in Securities and Use of Proceeds......................... 59 Item 3: Defaults Upon Senior Securities................................... 59 Item 4: Submission of Matters to a Vote of Security Holders............... 59 Item 5: Other Information................................................. 59 Item 6: Exhibits and Reports on Form 8-K.................................. 59 Signatures........................................................ 61 2 PART I. FINANCIAL INFORMATION Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Thousands Except Per Unit Amounts) (Unaudited) Three Months Ended Sept. 30, Nine Months Ended Sept. 30, ---------------------------- --------------------------- 2003 2002 2003 2002 ---------- ---------- ---------- ---------- Revenues Natural gas sales............................................ $1,209,888 $ 740,377 $3,827,246 $1,932,774 Services..................................................... 344,826 357,111 1,026,655 960,399 Product sales and other...................................... 96,128 23,832 250,226 122,148 ---------- ---------- ---------- ---------- 1,650,842 1,121,320 5,104,127 3,015,321 ---------- ---------- ---------- ---------- Costs and Expenses Gas purchases and other costs of sales....................... 1,212,200 729,773 3,822,989 1,890,342 Operations and maintenance................................... 98,089 92,644 293,763 278,399 Fuel and power............................................... 29,476 24,932 78,393 64,463 Depreciation, depletion and amortization..................... 55,031 42,546 158,594 126,495 General and administrative................................... 35,547 27,476 104,383 87,218 Taxes, other than income taxes............................... 15,534 14,546 46,326 40,798 ---------- ---------- ---------- ---------- 1,445,877 931,917 4,504,448 2,487,715 ---------- ---------- ---------- ---------- Operating Income............................................... 204,965 189,403 599,679 527,606 Other Income (Expense) Earnings from equity investments............................. 20,841 22,818 67,764 70,386 Amortization of excess cost of equity investments............ (1,394) (1,394) (4,182) (4,182) Interest, net................................................ (44,714) (46,350) (134,535) (129,236) Other, net................................................... 972 232 2,757 617 Minority Interest.............................................. (2,591) (2,410) (6,930) (7,458) ---------- ---------- ---------- ---------- Income Before Income Taxes and Cumulative Effect of a Change in Accounting Principle........................................ 178,079 162,299 524,553 457,733 Income Taxes................................................... (3,903) (4,119) (14,407) (13,603) ---------- ---------- ---------- ---------- Income Before Cumulative Effect of a Change in Accounting 174,176 158,180 510,146 444,130 Principle....................................................... Cumulative effect adjustment from change in accounting for asset retirement obligations...................................... - - 3,465 - ---------- ---------- ---------- ---------- Net Income..................................................... $ 174,176 $ 158,180 $ 513,611 $ 444,130 ========== ========== ========== ========== Calculation of Limited Partners' interest in Net Income: Income Before Cumulative Effect of a Change in Accounting $ 174,176 $ 158,180 $ 510,146 $ 444,130 Principle....................................................... Less: General Partner's interest............................... (82,727) (70,380) (239,682) (197,408) ---------- ---------- ---------- ---------- Limited Partners' interest..................................... 91,449 87,800 270,464 246,722 Add: Limited Partners' interest in Change in Accounting Principle - - 3,430 - ---------- ---------- ---------- ---------- Limited Partners' interest in Net Income....................... $ 91,449 $ 87,800 $ 273,894 $ 246,722 ========== ========== ========== ========== Basic and Diluted Limited Partners' Net Income per Unit: Income Before Cumulative Effect of a Change in Accounting $ 0.49 $ 0.50 $ 1.47 $ 1.46 Principle....................................................... Cumulative effect adjustment from change in accounting for asset retirement obligations...................................... - - 0.02 - ---------- ---------- ---------- ---------- Net Income..................................................... $ 0.49 $ 0.50 $ 1.49 $ 1.46 ========== ========== ========== ========== Weighted average number of units used in computation of Limited Partners' Net Income per unit: Basic.......................................................... 187,813 174,781 184,285 169,171 ========== ========== ========== ========== Diluted........................................................ 187,912 174,932 184,400 169,345 ========== ========== ========== ========== The accompanying notes are an integral part of these consolidated financial statements.
3 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Thousands) (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ Assets Current Assets Cash and cash equivalents................ $ 42,445 $ 41,088 Accounts and notes receivable Trade.................................. 534,632 457,583 Related parties........................ 17,653 17,907 Inventories Products............................... 3,923 4,722 Materials and supplies................. 9,835 7,094 Gas imbalances........................... 40,102 25,488 Gas in underground storage............... 3,988 11,029 Other current assets..................... 30,624 104,479 ------------ ------------ 683,202 669,390 Property, Plant and Equipment, net.......... 6,632,302 6,244,242 Investments................................. 406,378 451,374 Notes receivable............................ 2,870 3,823 Goodwill.................................... 729,510 716,610 Other intangibles, net...................... 17,253 17,324 Deferred charges and other assets........... 209,282 250,813 ------------ ------------ Total Assets................................ $ 8,680,797 $ 8,353,576 ============ ============ Liabilities and Partners' Capital Current Liabilities Accounts payable Trade.................................. $ 428,109 $ 373,368 Related parties........................ 355 43,742 Current portion of long-term debt........ 86,240 - Accrued interest......................... 21,028 52,500 Deferred revenues........................ 7,201 4,914 Gas imbalances........................... 50,382 40,092 Accrued other current liabilities........ 204,091 298,711 ------------ ------------ 797,406 813,327 ------------ ------------ Long-Term Liabilities and Deferred Credits Long-term debt, outstanding.............. 3,855,803 3,659,533 Market value of interest rate swaps...... 140,903 166,956 ------------ ------------ 3,996,706 3,826,489 Deferred revenues........................ 23,504 25,740 Deferred income taxes.................... 31,705 30,262 Other long-term liabilities and deferred credits.................................. 217,964 199,796 ------------ ------------ 4,269,879 4,082,287 ------------ ------------ Commitments and Contingencies (Note 3) Minority Interest........................... 44,144 42,033 ------------ ------------ Partners' Capital Common Units............................. 1,963,611 1,844,553 Class B Units............................ 121,360 123,635 i-Units.................................. 1,490,659 1,420,898 General Partner.......................... 80,631 72,100 Accumulated other comprehensive loss..... (86,893) (45,257) ------------ ------------ 3,569,368 3,415,929 ------------ ------------ Total Liabilities and Partners' Capital..... $ 8,680,797 $ 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 (Increase/(Decrease) in Cash and Cash Equivalents In Thousands) (Unaudited) Nine Months Ended Sept. 30, ------------------------------- 2003 2002 ----------- ---------- Cash Flows From Operating Activities Net income............................................... $ 513,611 $ 444,130 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, depletion and amortization............. 158,594 126,495 Amortization of excess cost of equity investments.... 4,182 4,182 Earnings from equity investments..................... (67,764) (70,386) Distributions from equity investments................ 61,084 58,920 Changes in components of working capital............. (107,284) (2,521) FERC rate reparations and refunds.................... (44,944) -- Other, net........................................... (6,760) (14,551) ----------- ---------- Net Cash Provided by Operating Activities................ 507,254 546,269 ----------- ---------- Cash Flows From Investing Activities Acquisitions of assets............................... (40,714) (864,311) Acquisitions of investments.......................... (10,000) -- Additions to property, plant and equipment for expansio and maintenance projects.......................... (413,228) (342,562) Sale of investments, property, plant and equipment, net of removal costs.............................. 2,118 1,710 Contributions to equity investments.................. (11,210) (14,481) Other................................................ 8,904 1,289 ----------- ---------- Net Cash Used in Investing Activities.................... (464,130) (1,218,355) ----------- ---------- Cash Flows From Financing Activities Issuance of debt..................................... 3,162,365 3,205,414 Payment of debt...................................... (2,880,518) (2,432,731) Debt issue costs..................................... (1,119) (14,180) Proceeds from issuance of common units............... 175,336 1,464 Proceeds from issuance of i-units.................... - 331,159 Contributions from General Partner................... 1,764 3,353 Distributions to partners: Common units..................................... (252,011) (227,327) Class B units.................................... (10,175) (9,298) General Partner.................................. (231,186) (182,742) Minority interest................................ (7,345) (7,365) Other, net........................................... 1,122 3,917 ----------- ---------- Net Cash (Used in)/Provided by Financing Activities...... (41,767) 671,664 ----------- ---------- Increase/(Decrease) in Cash and Cash Equivalents......... 1,357 (422) Cash and Cash Equivalents, beginning of period........... 41,088 62,802 ----------- ---------- Cash and Cash Equivalents, end of period................. $ 42,445 $ 62,380 =========== ========== Noncash Investing and Financing Activities: Assets acquired by the assumption of liabilities $ 1,978 $ 153,430
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. and its consolidated subsidiaries. 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. On January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" and we reclassified to goodwill from investments the $140.3 million of total unamortized excess cost over underlying fair value of net assets accounted for under the equity method. However, pursuant to SFAS No. 142, this amount, referred to as equity method goodwill, should continue to be recognized in accordance with Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." According to APB No. 18, equity method goodwill should not be treated as being separable from the related investment and should not be tested for impairment under SFAS No. 142, but rather, tested under APB No. 18. The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is "other than temporary." Accordingly, we have elected to reverse our original reclassification of the $140.3 million of equity method goodwill as of January 1, 2002 from our investments to our goodwill. Compared to the amounts previously reported in our Annual Report on Form 10-K for the year ended December 31, 2002, this reversal has resulted in an increase to "Investments" and a decrease in "Goodwill" in the amount of $140.3 million on our consolidated balance sheet as of December 31, 2002. 6 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 SFAS No. 143, "Accounting for Asset Retirement Obligations." For more information on our asset retirement obligations, see Note 4. 2. Acquisitions and Joint Ventures During the first nine 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 allocation of assets and liabilities may be adjusted to reflect the final determined amounts during a short period of time following the acquisition. The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date. 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 terminal 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 consolidated 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 expanded our growing Terminals business segment and complements certain of our existing terminal facilities. In our final analysis, it was considered reasonable to allocate a portion of our purchase price to goodwill given the substance of this transaction, in particular the synergies, and we include its operations in our Terminals business segment. Our allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands): 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 ======== MKM Partners, L.P. On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil Corporation to dissolve MKM Partners, L.P., a joint venture we formed on January 1, 2001 with subsidiaries of Marathon Oil Company. The joint venture assets consisted of a 12.75% interest in the SACROC oil field unit and a 49.9% interest in the Yates Field 7 unit, both of which are in the Permian Basin of West Texas. The MKM joint venture was owned 85% by subsidiaries of Marathon Oil Company and 15% by Kinder Morgan CO2 Company, L.P. It was dissolved effective June 30, 2003, and the net assets were distributed to creditors and partners in accordance with its partnership agreement. Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership interest in the SACROC unit for $23.3 million and the assumption of $1.9 million of liabilities. The SACROC unit is one of the largest and oldest oil fields in the United States using carbon dioxide flooding technology. This transaction increased our ownership interest in the SACROC unit to approximately 97%. Our allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.... $ 23,302 Liabilities assumed....................... 1,905 -------- Total purchase price...................... $ 25,207 ======== Allocation of purchase price: Property, plant and equipment............. $ 25,207 -------- $ 25,207 ======== IC Terminal Holdings Company Effective September 1, 2002, we acquired all of the shares of the capital stock of IC Terminal Holdings Company from the Canadian National Railroad. Our purchase price was $17.7 million, consisting of $17.4 million and the assumption of $0.3 million in liabilities. The total purchase price decreased $0.2 million in the third quarter of 2003 primarily due to adjustments in the amount of working capital items assumed on the acquisition date. The acquisition included the former ICOM marine terminal in St. Gabriel, Louisiana. The St. Gabriel facility has 400,000 barrels of liquids storage capacity and a related pipeline network that serves one of the fastest growing petrochemical production areas in the country. The acquisition further expanded our terminal businesses along the Mississippi River. The acquired terminal is referred to as the Kinder Morgan St. Gabriel terminal, and we include its operations in our Terminals business segment. Our allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.............................. $ 17,372 Liabilities assumed................ 326 -------- Total purchase price............... $ 17,698 ======== Allocation of purchase price: Current assets..................... $ 46 Property, plant and equipment...... 14,303 Investment in ICPT, LLC............ 1,785 Non-current note receivable........ 1,350 Deferred charges and other assets.. 214 -------- $ 17,698 ======== Owensboro Gateway Terminal Effective September 1, 2002, we acquired the Lanham River Terminal near Owensboro, Kentucky and related equipment for $7.7 million. In September 2002, we paid approximately $7.2 million and established a $0.5 million purchase price retention liability to be paid at the later of: (i) one year following the acquisition, or (ii) the day we received consent to the assignment of a contract between the seller and the New York Mercantile Exchange, Inc. We paid the $0.5 million liability in September 2003. The facility is one of the nation's largest storage and handling points for bulk aluminum. The terminal also handles a variety of other bulk products, including petroleum coke, lime and de-icing salt. The terminal is situated on a 92-acre site along the Ohio River, and the purchase expands our presence along the river, complementing our existing facilities located near Cincinnati, Ohio and Moundsville, West Virginia. We refer to the acquired terminal as our Owensboro Gateway Terminal and we include its operations in our Terminals business segment. 8 Our allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs............................. $ 7,640 Liabilities assumed................ 11 -------- Total purchase price............... $ 7,651 ======== Allocation of purchase price: Current assets..................... $ 42 Property, plant and equipment...... 4,265 Intangibles-agreements............. 54 Goodwill........................... 3,290 -------- $ 7,651 ======== The $3.3 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. Red Cedar Gas Gathering Company Effective August 1, 2003, we acquired reversionary interests in the Red Cedar Gas Gathering Company held by the Southern Ute Indian Tribe. Our purchase price was $10.0 million. The 4% reversionary interests were held by the Southern Ute Indian Tribe and were scheduled to take effect September 1, 2004 and September 1, 2009. With the elimination of these reversions, our ownership interest in Red Cedar will be maintained at 49% in the future. Our allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs............................ $ 10,000 -------- Total purchase price............... $ 10,000 ======== Allocation of purchase price: Investments........................ $ 10,000 -------- $ 10,000 ======== Pro Forma Information The following summarized unaudited pro forma consolidated income statement information for the nine months ended September 30, 2003 and 2002, assumes that 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 Nine Months Ended September 30, ---------------------------- 2003 2002 ---- ---- (Unaudited) Revenues................................................................... $ 5,112,861 $ 3,288,941 Operating Income........................................................... 603,034 544,095 Income Before Cumulative Effect of a Change in Accounting Principle........ 513,344 462,014 Net Income................................................................. $ 516,809 $ 462,014 Basic and diluted Limited Partners' Net Income per unit: Income Before Cumulative Effect of a Change in Accounting Principle..... $ 1.48 $ 1.42 Net Income.............................................................. $ 1.50 $ 1.42
9 Acquisitions Subsequent to September 30, 2003 Shell Products Terminals Effective October 1, 2003, we acquired five refined petroleum products terminals in the western United States for approximately $20.0 million from Shell Oil Products U.S. Following our acquisition, we plan to invest an additional $8.0 million in the facilities. The terminals are located in Colton and Mission Valley, California; Phoenix and Tucson, Arizona; and Reno, Nevada. Combined, the terminals have 28 storage tanks with total capacity of approximately 700,000 barrels for gasoline, diesel fuel and jet fuel. As part of the transaction, Shell has entered into a long-term contract to store products in the terminals. The acquisition enhances our Pacific operations and complements our existing West Coast Terminals. The acquired operations will be included as part of our Pacific operations and our Products Pipelines business segment. This acquisition had no effect on our consolidated financial statements during the periods covered by these financial statements. Our allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs............................. $ 20,022 -------- Total purchase price............... $ 20,022 ======== Allocation of purchase price: Property, plant and equipment...... $ 20,022 -------- $ 20,022 ======== Yates Field Unit and Carbon Dioxide Assets Effective November 1, 2003, we acquired certain assets in the Permian Basin of West Texas for approximately $227.5 million from a subsidiary of Marathon Oil Corporation. The assets acquired consisted of the following: o Marathon's approximate 42.5% interest in the Yates oil field unit for approximately $212.5 million. We previously owned a 7.5% ownership interest in the Yates field unit and we will now become operator of the field; o Marathon's 100% interest in the crude oil gathering system surrounding the Yates field for approximately $13.0 million; and o Marathon Carbon Dioxide Transportation Company for approximately $2.0 million. Marathon Carbon Dioxide Transportation Company owns a 65% ownership interest in the Pecos Carbon Dioxide Pipeline Company, which owns a 25-mile carbon dioxide pipeline. We previously owned a 4.27% ownership interest in the Pecos Carbon Dioxide Pipeline Company. 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 10 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." If SFPP rates previously "grandfathered" under the Energy Policy Act lose their "grandfathered" status and 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. On June 24, 2003, a non-binding, phase one initial decision was issued by an administrative law judge hearing a FERC case on the rates charged by SFPP on the interstate portion of its pipelines (see OR96-2 section below for further discussion). In his phase one initial decision, the administrative law judge recommended that the FERC "ungrandfather" SFPP's interstate rates and found most of SFPP's rates at issue to be unjust and unreasonable. The administrative law judge has indicated that a phase two initial decision will address prospective rates and whether reparations are necessary. Initial decisions have no force or effect and must be reviewed by the FERC. The FERC is not obliged to follow any of the administrative law judge's findings and can accept or reject this initial decision in whole or in part. In addition, as stated above, the facts are complex, the rules and regulations in this area are vague and little precedent exists. If the FERC ultimately finds that these rates should be "ungrandfathered" and are unjust and unreasonable, they could be lowered prospectively and complaining shippers could be entitled to reparations for prior periods. Resolution of this matter by the FERC is not expected before late 2004. 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. As the length of time from the filing of the complaints increases, the amounts sought by complainants in tariff reparations will likewise increase until a determination of reparations owed is made by the FERC. 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. The administrative law judge's initial decision does not change our estimate of what the complainants seek. Furthermore, 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, results of operations or cash flows. OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a consolidated proceeding that began in September 1992 and includes a number of shipper complaints against certain rates and practices on SFPP's East Line (from El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson Station in Carson, California. The complainants in the case are El Paso Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company, Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.), Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco Corporation (now part of ConocoPhillips Company). The FERC has ruled that the complainants have the burden of proof in those proceedings. A FERC administrative law judge held hearings in 1996, and issued an initial decision in September 1997. The initial decision held that all but one of SFPP's West Line rates were "grandfathered" under the Energy Policy Act of 1992 and therefore deemed to be just and reasonable; it further held that complainants had failed to prove "changed circumstances" with respect to those rates and that they therefore could not be challenged in the Docket No. OR92-8 et al. proceedings, either for the past or prospectively. However, the initial decision also made rulings generally adverse to SFPP on certain cost of service issues relating to the evaluation of East Line rates, which are not "grandfathered" under the Energy Policy Act. Those issues included the capital structure to be used in computing SFPP's "starting rate base," the level of income tax allowance SFPP may include in rates and the recovery of civil and regulatory litigation expenses and certain pipeline reconditioning costs incurred by SFPP. The initial decision also held SFPP's Watson Station gathering enhancement service was subject to FERC jurisdiction and ordered SFPP 11 to file a tariff for that service. The FERC subsequently reviewed the initial decision, and issued a series of orders in which it adopted certain rulings made by the administrative law judge, changed others and modified a number of its own rulings on rehearing. Those orders began in January 1999, with FERC Opinion No. 435, and continued through June 2003. The FERC affirmed that all but one of SFPP's West Line rates are "grandfathered" and that complainants had failed to satisfy the threshold burden of demonstrating "changed circumstances" necessary to challenge those rates. The FERC further held that the one West Line rate that was not grandfathered did not need to be reduced. The FERC consequently dismissed all complaints against the West Line rates in Docket Nos. OR92-8 et al. without any requirement that SFPP reduce, or pay any reparations for, any West Line rate. The FERC initially modified the initial decision's ruling regarding the capital structure to be used in computing SFPP's "starting rate base" to be more favorable to SFPP, but later reversed that ruling. The FERC also made certain modifications to the calculation of the income tax allowance and other cost of service components, generally to SFPP's disadvantage. On multiple occasions, the FERC required SFPP to file revised East Line rates based on rulings made in the FERC's various orders. SFPP was also directed to submit compliance filings showing the calculation of the revised rates, the potential reparations for each complainant and in some cases potential refunds to shippers. SFPP filed such revised East Line rates and compliance filings in March 1999, July 2000, November 2001 (revised December 2001), October 2002 and February 2003 (revised March 2003). Most of those filings were protested by particular SFPP shippers. The FERC has held that certain of the rates SFPP filed at the FERC's directive should be reduced retroactively and/or be subject to refund; SFPP has challenged the FERC's authority to impose such requirements in this context. While the FERC initially permitted SFPP to recover certain of its litigation, pipeline reconditioning and environmental costs, either through a surcharge on prospective rates or as an offset to potential reparations, it ultimately limited recovery in such a way that SFPP was not able to make any such surcharge or take any such offset. Similarly, the FERC initially ruled that SFPP would not owe reparations to any complainant for any period prior to the date on which that party's complaint was filed, but ultimately held that each complainant could recover reparations for a period extending two years prior to the filing of its complaint (except for Navajo, which was limited to one month of pre-complaint reparations under a settlement agreement with SFPP's predecessor). The FERC also ultimately held that SFPP was not required to pay reparations or refunds for Watson Station gathering enhancement fees charged prior to filing a FERC tariff for that service. In April 2003, SFPP paid complainants and other shippers reparations and/or refunds as required by FERC's orders. In August 2003, SFPP paid shippers an additional refund as required by FERC's most recent order in the Docket No. OR92-8 et al. proceedings. As of September 30, 2003, we have made payments of $44.9 million in 2003 for reparations and refunds under order from the FERC. Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond Shamrock (now part of Valero Energy Corporation) filed petitions for review of FERC's Docket OR92-8 et al. orders in the United States Court of Appeals for the District of Columbia Circuit. Certain of those petitions were dismissed by the Court of Appeals as premature, and the remaining petitions were held in abeyance pending completion of agency action. However, in December 2002, the Court of Appeals returned to its active docket all petitions to review the FERC's orders in the case through November 2001 and severed petitions regarding later FERC orders. The severed orders were held in abeyance for later consideration. Briefing in the Court of Appeals was completed in August 2003. The Court of Appeals has designated the case as "complex" under its case management plan and has set oral argument for November 12, 2003. 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. Several other West Line shippers filed similar complaints and/or motions to intervene. 12 Following a hearing in March 1997, a FERC administrative law 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 pre-existing 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 set a hearing to determine whether SFPP possessed market power in the origin market. Following a hearing on December 21, 2000, an administrative law judge found that SFPP possessed market power over the Sepulveda origin market. On February 28, 2003, the FERC issued an order upholding that decision. SFPP filed a request for rehearing of that order on March 31, 2003. The FERC denied SFPP's request for rehearing on July 9, 2003. As part of its February 28, 2003 order denying SFPP's application for market-based ratemaking authority, the FERC remanded to the ongoing litigation in Docket No. OR96-2, et al. the question of whether SFPP's current rate for service on the Sepulveda line is just and reasonable. That issue is currently pending before the administrative law judge in the Docket No. OR96-2, et al. proceeding. The procedural schedule in this remanded matter is currently suspended pending issuance of the phase two initial decision in the Docket No. OR96-2, et al. proceeding (see below). OR96-2; 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. The FERC accepted the complaints and consolidated them into one proceeding (Docket No. OR96-2, et al.), but held 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. 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. These complaints were consolidated 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. A FERC administrative law judge issued his initial decision on June 24, 2003. The initial decision found that, for the years at issue, the complainants had shown substantially changed circumstances for rates on SFPP's West, North and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson Station and thus found that those rates should not be "grandfathered" under the Energy Policy Act of 1992. The initial decision also found that most of SFPP's rates at issue were unjust and unreasonable. The initial decision indicated that a phase two initial decision will address prospective rates and whether reparations are necessary. Issuance of the phase two initial decision is expected sometime in the fourth quarter of 2003 or the first quarter of 2004. SFPP has filed a brief on exceptions to the FERC that contests the findings in the initial decision. SFPP's opponents have responded to SFPP's brief. Resolution of this matter by the FERC is not expected before late 2004. 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 13 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 May 23, 2003, the FERC denied Chevron's rehearing request and on July 1, 2003, Chevron filed an appeal of this denial at the U.S. Court of Appeals for the District of Columbia Circuit, which appeal is currently pending. On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition on the basis that Chevron lacks standing to bring its appeal and that the case is not ripe for review. Chevron answered on September 10, 2003. SFPP's motion is pending before the Court. Chevron continues to participate in the OR96-2 proceeding as an intervenor. OR03-5 proceedings. On June 30, 2003, Chevron filed another complaint against SFPP - substantially similar to its previous complaint - and moved to consolidate the complaint with the OR96-2 proceeding. This complaint was docketed as Docket No. OR03-5. Chevron requested that this new complaint be treated as if it were an amendment to its complaint in Docket No. 02-4, which was previously dismissed by the FERC. By this request, Chevron sought to, in effect, back-date its complaint, and claim for reparations, to February 2002. SFPP answered Chevron's complaint on July 22, 2003, opposing Chevron's requests for consolidation and for the back-dating of its complaint. At its October 22, 2003 meeting, the FERC accepted Chevron's complaint, but held it in abeyance pending the outcome of the Docket No. OR96-2, et al. proceeding. The FERC denied Chevron's request for consolidating and for back-dating. 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 resolution of these submitted matters is anticipated within the second quarter of 2004. The CPUC subsequently 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 required SFPP to submit cost data for 2001, 2002, and 2003, and 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 14 transportation rates, will be the subject of evidentiary hearings to be conducted in December 2003 and are expected to be resolved by the CPUC by the second quarter of 2004. 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, results of operations or cash flows. 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. Certain 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, where a procedural schedule was established. The technical conference on non-rate issues was held on February 6, 2003. Those issues include: - capacity award procedures; - credit procedures; - imbalance penalties; and - 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. On May 23, 2003, FERC issued an order deciding non-rate tariff issues and denying rehearing of its prior order. In the May 23, 2003 order, FERC: - accepted Trailblazer's proposed capacity award procedures with very limited changes; - accepted Trailblazer's credit procedures subject to very extensive changes, consistent with numerous recent orders involving other pipelines; - accepted a compromise agreed to by Trailblazer and the active parties under which existing shippers must match competing bids in the right of first refusal process for up to 10 years (in lieu of the current 5 years); and - accepted Trailblazer's withdrawal of daily imbalance charges. The referenced order did the following: - allowed shortened notice periods for suspension of service, but required at least 30 days notice for service termination; 15 - limited prepayments and any other assurance of future performance, such as a letter of credit, to three months of service charges except for new facilities; - required the pipeline to pay interest on prepayments or allow those funds to go into an interest-bearing escrow account; and - required much more specificity about credit criteria and procedures in tariff provisions. Certain shippers have sought rehearing of the May 23, 2003 order. Trailblazer made its compliance filing on June 20, 2003. Under the May 23, 2003 order, these tariff changes are effective as of May 23, 2003, except that Trailblazer has filed to make the revised credit procedures effective August 15, 2003. With respect to the on-going rate review phase of the case, direct testimony was filed by FERC Staff and Indicated Shippers on May 22, 2003 and cross-answering testimony was filed by Indicated Shippers on June 19, 2003. Trailblazer's answering testimony was filed on July 29, 2003. On September 22, 2003, Trailblazer filed an offer of settlement with the FERC. Under the settlement, if approved by the FERC, Trailblazer's rate would be reduced effective January 1, 2004, from about $0.12 to $0.09 per dekatherm of natural gas, and Trailblazer would file a new rate case to be effective January 1, 2010. We do not expect the settlement to have a material effect on our consolidated revenues in 2004 or in subsequent periods. Based on the comments, this settlement is supported or not opposed by all participants including the FERC staff, except for certain members of the Indicated Shippers group (Marathon, BP), referred to hereafter as contesting parties. On October 3, 2003, the presiding administrative law judge certified the settlement to the FERC and severed the contesting parties. The contesting parties filed rebuttal testimony on September 22, 2003. The trial took place from October 8-10, 2003, and involved only Trailblazer and the contesting parties. The FERC staff did not participate. Initial and reply briefs are due on November 21, 2003 and December 19, 2003, respectively. 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 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. On May 22, 2003, KMIGT received an Order on Rehearing and Compliance Filing (May 2003 Order) from the FERC, addressing KMIGT's November 19, 2001 filed request for rehearing and filing to comply with the directives of the October 19, 2001 Order. The May 2003 Order granted in part and denied in part KMIGT's request for rehearing, and directed KMIGT to file certain revised tariff sheets consistent with the May 2003 Order's directives. On June 20, 2003, KMIGT submitted its compliance filing reflecting revised tariff sheets in accordance with the 16 FERC's directives. Consistent with the May 2003 Order, KMIGT's compliance filing reflected tariff sheets with proposed effective dates of June 1, 2003 and December 1, 2003. Those sheets with a proposed effective date of December 1, 2003 concern tariff provisions necessitating computer system modifications. The June 20, 2003 compliance filing is pending FERC action. KMIGT is preparing for full implementation of Order 637 on December 1, 2003. The evaluation of the full impact of implementation of Order 637 on the KMIGT system is ongoing. We believe that these matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. Separately, numerous petitioners, including KMIGT, have filed appeals in respect 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: - 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; - 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 - 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: - segmentation; - scheduling for capacity release transactions; - receipt and delivery point rights; - treatment of system imbalances; - operational flow orders; - penalty revenue crediting; and - right of first refusal language. 17 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 rights of first refusal, but 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 made those modifications in a further compliance filing on May 16, 2003. Certain shippers have filed a limited protest regarding that compliance filing. That filing is pending FERC action. Under the FERC orders, limited aspects of Trailblazer's plan (revenue crediting) were effective as of May 1, 2003, and the entire plan is expected to be effective as of December 1, 2003. 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, results of operations or cash flows. 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. On June 26, 2003, FERC issued an interim rule to be effective August 7, 2003, under which regulated companies are required to document cash management arrangements and transactions. The interim rule does not include a proposed rule that would have required regulated companies, as a prerequisite to participation in cash management programs, to maintain a proprietary capital ratio of 30% and an investment grade credit rating. On October 22, 2003, the FERC issued its final rule amending its regulations effective November 2003 which, among other things, requires FERC-regulated entities to file their cash management agreements with the FERC and to notify the FERC within 45 days after the end of the quarter when their proprietary capital ratio drops below 30%, and when it subsequently returns to or exceeds 30%. We believe that these matters, as finally adopted, will not have a material adverse effect on our business, financial position, results of operations or cash flows. Other Regulatory On July 25, 2003, the FERC issued a Modification to Policy Statement stating that FERC regulated natural gas pipelines will, on a prospective basis, no longer be permitted to use gas basis differentials to price negotiated rate transactions. Effectively, we will no longer be permitted to use commodity price indices to structure transactions on our FERC regulated natural gas pipelines. Negotiated rates based on commodity price indices in existing contracts will be permitted to remain in effect until the end of the contract period for which such rates were negotiated. Price indexed contracts currently constitute an insignificant portion of our negotiated contracts on our FERC regulated natural gas pipelines; consequently, we do not believe that this Modification to Policy Statement will have a material impact on our business, financial position, results of operations or cash flows. 18 In addition to the matters described above, we may face additional challenges to our rates in the future. Shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. In addition, since many of our assets are subject to regulation, we are subject to potential future changes in applicable rules and regulations that may have an adverse effect on our business, financial position, results of operations or cash flows. Southern Pacific Transportation Company Easements SFPP, L.P. 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). In the second quarter of 2003, the trial court set the rent at approximately $5.0 million per year as of January 1, 1994. SPTC has appealed the matter to the California Court of Appeals. 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 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: - common law fraud; - fraudulent concealment; and - 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. 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 19 Court review and overturn the decision of the 10th Circuit Court of Appeals. On June 9, 2003, the United States Supreme Court denied the Writ of Certiorari. On July 16, 2003, the settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson, and Ainsworth cases became final. 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. 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. On June 12, 2003, plaintiff served discovery requests on certain defendants. On July 11, 2003, defendants moved to stay any responses to such discovery. Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating Company et al. v. Gas Pipelines, et al.) Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999, three plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a purported nationwide class action in the Stevens County, Kansas District Court against some 250 natural gas pipelines and many of their affiliates. The District Court is located in Hugoton, Kansas. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. The Petition (recently amended) alleges a conspiracy to underpay royalties, taxes and producer payments by the defendants' undermeasurement of the volume and heating content of natural gas produced from nonfederal lands for more than twenty-five years. The named plaintiffs purport to adequately represent the interests of unnamed plaintiffs in this action who are comprised of the nation's gas producers, State taxing agencies and royalty, working and overriding owners. The plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees from the defendants, jointly and severally. This action was originally filed on May 28, 1999 in Kansas State Court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. Subsequently, one of the defendants removed the action to Kansas Federal District Court and the case was styled as Quinque Operating Company, et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the District of Kansas. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claim Act cases referred to below, because of common factual questions. On April 10, 2000, the MDL Panel ordered that this case be consolidated with the Grynberg federal False Claims Act cases 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. 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. On July 8, 2003, a hearing was held on the motion to amend the complaint. On July 28, 2003, the Court granted leave to amend the complaint. The amended complaint does not list us or any of our affiliates as defendants. Additionally, a new complaint was filed and that complaint does not list us or any of our affiliates as defendants. We will continue to monitor these matters. 20 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 Claims Act. On May 7, 2003, Grynberg sought leave to file a Third Amended Complaint, which adds allegations of undermeasurement related to CO2 production. Defendants have filed briefs opposing leave to amend. 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 tortious 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. 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. The parties have engaged in some discovery and depositions. At this stage of discovery, we believe that our actions were justified and defensible under applicable Texas law and that the decision not to renew the underlying gas sales agreements was made unilaterally by persons acting on behalf of Entex. The plaintiffs have moved for summary judgment asking the court to declare that a fiduciary relationship existed for purposes of Sweatman's claims. We have moved for summary judgment on the grounds that: - there is no cause-in-fact of the gas sales nonrenewals attributable to us; and - the defense of legal justification applies to the claims for tortuous interference. 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 21 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"); 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 I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation,; Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court, State of Nevada, County of Washoe) ("Galaz II); Frankie Sue Galaz, et al v. The United States of America, the City of Fallon, Exxon Mobil Corporation,; Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District Court, District of Nevada)("Galaz III) 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 resulting from, or which can potentially result from exposure to environmental carcinogens," incidental damages, and attorneys' fees and costs. 22 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 I 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 I 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. Plaintiffs have filed a Notice of Appeal to the United States Court of Appeals for the 9th Circuit, which appeal is currently pending. On June 20, 2003, plaintiffs filed an additional Complaint for Class Action (the "Galaz II" matter) asserting the same claims in Nevada State trial court on behalf of the same purported class against virtually the same defendants, including us (and excluding the United States Department of the Navy). On September 30, 2003, the Kinder Morgan defendants filed a Motion to Dismiss the Galaz II Complaint along with a Motion for Sanctions, which motions are currently pending. On October 4, 2003, plaintiffs' counsel agreed in writing to dismiss the Galaz II matter, but had not done so as of October 30, 2003. Also on June 20, 2003, the plaintiffs in the Galaz matters filed yet another Complaint for Class Action in the United States District Court for the District of Nevada (the "Galaz III" matter) asserting the same claims in United States District Court for the District of Nevada on behalf of the same purported class against virtually the same defendants, including us. The Kinder Morgan defendants filed a Motion to Dismiss the Galaz III matter on August 15, 2003, which Motion is currently pending. On October 3, 2003, the plaintiffs filed a Motion for Withdrawal of Class Action, which voluntarily drops the class action allegations from the matter and seeks to have the case proceed on behalf of the Galaz family only. Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe) ("Jernee"). On May 30, 2003, a separate group of plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against us and several Kinder Morgan related entities and individuals and additional unrelated defendants ("Jernee"). Plaintiffs in the Jernee matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing "harmful substances and emissions and gases" to damage "the environment and health of human beings." Plaintiffs claim that "Adam Jernee's death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins." Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified special, general and punitive damages. The Kinder Morgan defendants are currently preparing Motions to Dismiss the Jernee matter. Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326 (Second Judicial District Court, State of Nevada, County of Washoe) ("Sands"). On August 28, 2003, a separate group of plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court against us and several Kinder Morgan related entities and individuals and additional unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing "harmful substances and emissions and gases" to damage "the environment and health of human beings." Plaintiffs claim that Stephanie Suzanne Sands' death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins. Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified special, general and punitive damages. The Kinder Morgan defendants 23 have not yet been formally served with a copy of the complaint. Based on the information available to date, our own preliminary investigation, and the positive results of investigations conducted by State and Federal agencies, we believe that the claims against us in the Snyder matter, the three Galaz matters, the Jernee matter and the Sands matter are without merit and intend to defend against them vigorously. 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. A settlement has been reached between most of the plaintiffs and Plantation. It is anticipated that the settlement will be completed by the end of November 2003. Plantation believes that the ultimate resolution of these Marion County, Mississippi cases will not have a material effect on its business, financial position, results of operations or cash flows. 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. We filed our answer to the Complaint on June 27, 2003, in which we denied ExxonMobil's claims and allegations as well as included counterclaims against ExxonMobil. 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 as a responsible party 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, if any, 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 24 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 economic 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. On June 23, 2003, plaintiff filed a Fourth Amended Petition that reduced its total claim for economic damages to $30.0 million. On October 5, 2003, plaintiff filed a Fifth Amended Petition that purported to add a cause of action for embezzlement. On October 15, 2003, plaintiff filed its Tenth Supplemental Responses to Requests for Disclosure that restated its alleged economic damages for the period of November 1987 through September 2003 as approximately $37.1 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, results of operations or cash flows. 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: - 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; - several ground water hydrocarbon remediation efforts under administrative orders issued by the California Regional Water Quality Control Board and two other state agencies; - 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 - 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 25 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, results of operations or cash flows. As of September 30, 2003, we have recorded a total reserve for environmental claims in the amount of $40.3 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, results of operations or cash flows. 4. Change in Accounting for Asset Retirement Obligations In August 2001, the Financial Accounting Standards Board issued SFAS 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: - a liability for any existing asset retirement obligations adjusted for cumulative accretion to the date of adoption; - an asset retirement cost capitalized as an increase to the carrying amount of the associated long-lived asset; and - 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 26 applying SFAS No. 143 as a change in accounting principle as described in Accounting Principles Board Opinion 20, "Accounting Changes." The cumulative effect adjustment resulted 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 September 30, 2003, we have recognized asset retirement obligations in the aggregate amount of $13.6 million relating to these requirements at existing sites within our CO2 Pipelines segment. In our Natural Gas Pipelines business segment, if we were to 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 September 30, 2003, we have recognized asset retirement obligations in the aggregate amount of $3.0 million relating to the businesses within our Natural Gas Pipelines segment. We have included $0.8 million of our total $16.6 million asset retirement obligations as of September 30, 2003 with "Accrued other current liabilities" in the accompanying consolidated balance sheet and the remaining $15.8 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 nine months ended September 30, 2003 is as follows (in thousands): Balance at December 31, 2002........ $ - Cumulative effect transition 14,125 adjustment.......................... Liabilities incurred................ 2,199 Liabilities settled................. (582) Accretion expense................... 654 Revisions in estimated cash flows... 208 --------- Balance at September 30, 2003....... $ 16,604 ========= Pro Forma Information Had the provisions of SFAS No. 143 been in effect prior to January 1, 2003, our net income and associated per unit amounts, and the amount of our liability for asset retirement obligations, would have been as follows (in thousands, except per unit amounts):
Pro Forma Pro Forma Three Months Ended Nine Months Ended ------------------ ----------------- Sept. 30, Sept. 30, Sept. 30, Sept. 30, 2003 2002 2003 2002 ---- ---- ---- ---- Reported income before cumulative effect of a change in accounting principle.................................. $174,176 $158,180 $510,146 $444,130 Adjustments from change in accounting for asset retirement obligations................................ -- (288) -- (874) -------- -------- -------- -------- Adjusted income before cumulative effect of a change in accounting principle..................................... $174,176 $157,892 $510,146 $443,256 ======== ======== ======== ======== Reported income before cumulative effect of a change in accounting principle per unit (fully diluted)............ $ 0.49 $ 0.50 $ 1.47 $ 1.46 ======== ======== ======== ======== Adjusted income before cumulative effect of a change in accounting principle per unit (fully diluted)............ $ 0.49 $ 0.50 $ 1.47 $ 1.45 ======== ======== ======== ========
27
Dec. 31, Sept. 30, Dec. 31, 2002 2002 2001 ---- ---- ---- Liability for asset retirement obligations............. $14,125 $14,041 $14,345
5. Distributions On August 14, 2003, we paid a cash distribution of $0.65 per unit to our common unitholders and to our class B unitholders for the quarterly period ended June 30, 2003. KMR, our sole i-unitholder, received 811,878 additional i-units based on the $0.65 cash distribution per common unit. The distributions were declared on July 16, 2003, payable to unitholders of record as of July 31, 2003. On October 15, 2003, we declared a cash distribution of $0.66 per unit for the quarterly period ended September 30, 2003. The distribution will be paid on or before November 14, 2003, to unitholders of record as of October 31, 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 $0.66 distribution per common unit. The number of i-units distributed will be 811,625. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.016844) will be issued. The fraction was determined by dividing: - $0.66, the cash amount distributed per common unit by - $39.184, the average of KMR's limited liability shares' closing market prices from October 15-28, 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 SFAS No. 141, "Business Combinations" and SFAS 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 have selected an impairment measurement test date of January 1 of each year and we have determined that our goodwill was not impaired as of January 1, 2003. Under ABP No. 18, any premium paid by an investor, which is analogous to goodwill, must also be identified. Under prior rules, excess cost over underlying fair value of net assets accounted for under the equity method, referred to as equity method goodwill, would have been amortized, however, under SFAS No. 142, equity method goodwill is not subject to amortization but rather to impairment testing pursuant to ABP No. 18. This test requires equity method investors to continue to assess impairment of investments in investees by considering whether declines in the fair values of those investments, versus carrying values, may be other than temporary in nature. As of December 31, 2002 and September 30, 2003, we have reported $140.3 million in equity method goodwill within the caption "Investments" in the accompanying consolidated balance sheets. 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. Following is information related to our intangible assets still subject to amortization and our goodwill (in thousands): 28 Sept. 30, Dec. 31, 2003 2002 ----------- ----------- Goodwill Gross carrying amount......... $ 743,652 $ 730,752 Accumulated amortization...... (14,142) (14,142) ----------- ----------- Net carrying amount........... 729,510 716,610 ----------- ----------- Lease value Gross carrying amount......... 6,592 $ 6,592 Accumulated amortization...... (853) (748) ----------- ----------- Net carrying amount........... 5,739 5,844 ----------- ----------- Contracts and other Gross carrying amount......... 11,801 $ 11,719 Accumulated amortization...... (287) (239) ----------- ----------- Net carrying amount........... 11,514 11,480 ----------- ----------- Total intangibles, net........... $ 746,763 $ 733,934 =========== =========== Changes in the carrying amount of goodwill for the nine months ended September 30, 2003 are summarized as follows (in thousands):
Products Natural Gas CO2 Pipelines Pipelines Pipelines Terminals Total ----------- ----------- ----------- ----------- ----------- Balance at Dec. 31, 2002...... $ 263,182 $ 253,358 $ 46,101 $ 153,969 $ 716,610 Goodwill acquired............. -- -- -- 12,900 12,900 Goodwill dispositions, net.... -- -- -- -- -- Impairment losses............. -- -- -- -- -- ----------- ----------- ----------- ----------- ----------- Balance at Sept. 30, 2003..... $ 263,182 $ 253,358 $ 46,101 $ 166,869 $ 729,510 =========== =========== =========== =========== ===========
Amortization expense on intangibles consists of the following (in thousands):
Three Months Ended Sept. 30, Nine Months Ended Sept. 30, ---------------------------- --------------------------- 2003 2002 2003 2002 ----------- ------------ ------------ ---------- Lease value............ $ 35 $ 35 $ 105 $ 105 Contracts and other.... 17 10 48 30 ----------- ------------ ------------ ---------- $ 52 $ 45 $ 153 $ 135 =========== =========== =========== ===========
The weighted average amortization period for our intangible assets is approximately 41 years. Our estimated amortization expense for these assets for each of the next five fiscal years is $0.2 million. 7. Debt Our outstanding short-term debt as of September 30, 2003 was $513.8 million. The balance consisted of: - $506.9 million of commercial paper borrowings; - $5 million under the Central Florida Pipeline LLC Notes; and - $1.9 million in other borrowings. As of September 30, 2003, we intend and have the ability to refinance $427.6 million of our short-term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, such amount has 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 4.346% during the third quarter of 2003 and 4.864% during the third quarter of 2002. 29 Credit Facilities As of September 30, 2003, we had two credit facilities: - a $570 million unsecured 364-day credit facility due October 14, 2003 (subsequently replaced October 14, 2003 by a $570 million unsecured 364-day credit facility due October 12, 2004); and - a $480 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. There were no borrowings under either credit facility at December 31, 2002 or at September 30, 2003. 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. Interest on the two credit facilities accrues at our option at a floating rate equal to either: - the administrative agent's base rate (but not less than the Federal Funds Rate, plus 0.5%); or - LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt. The amount available for borrowing under our credit facilities is reduced by: - a $23.7 million letter of credit that supports Kinder Morgan Operating L.P. "B"'s tax-exempt bonds; - 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 located at Fernandina Beach, Florida); - a $0.2 million letter of credit entered into on June 4, 2002 that supports a workers' compensation insurance policy; - a $0.5 million letter of credit entered into on March 31, 2003 that supports an engineering contract; and - 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. Our $570 million unsecured 364-day credit facility expired October 14, 2003. On that date, we obtained a new $570 million unsecured 364-day credit facility due October 12, 2004. The terms of this credit facility are substantially similar to the terms of the expired facility. Interest Rate Swaps In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. As of September 30, 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. 30 Commercial Paper Program As of December 31, 2002, our commercial paper program provided for the issuance of up to $1.05 billion of commercial paper. As of September 30, 2003, we had $506.9 million of commercial paper outstanding with an average interest rate of 1.1745%. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facilities. Central Florida Pipeline LLC Debt Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As part of our purchase price, we assumed an aggregate principal amount of $40.0 million of Senior Notes originally issued to a syndicate of eight insurance companies. The Senior Notes have a fixed annual interest rate of 7.84% with repayments in annual installments of $5.0 million beginning July 23, 2001. The final payment is due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of each year. At December 31, 2002, Central Florida's outstanding balance under the Senior Notes was $30.0 million. In July 2003, we made an annual repayment of $5.0 million and at September 30, 2003, Central Florida's outstanding balance under the Senior Notes was $25.0 million. 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. 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 September 30, 2003, the debt facilities of Cortez Capital Corporation consisted of: - $95 million of Series D notes due May 15, 2013; - a $175 million short-term commercial paper program; and - a $175 million committed revolving credit facility due December 26, 2003 (to support the above-mentioned $175 million commercial paper program). As of September 30, 2003, Cortez Capital Corporation had $140.4 million of commercial paper outstanding with an interest rate of 1.11%. During the third quarter of 2003, the average interest rate on the Series D notes was 7.0389%. As of September 30, 2003, there were no borrowings under the credit facility. 31 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 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 September 30, 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 under joint and several liability. The principal is to be repaid in seven equal installments beginning on October 31, 2004 and ending on October 31, 2010. The $55 million is outstanding as of September 30, 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 LLC, the operator of the port facilities. In July 2002, we acquired Nassau Terminals LLC 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 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. Thomas Bannigan, C. Park Shaper and James Street and Ms. Deborah Macdonald. Each of these 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. To date, we have made no payment with respect to these lines of credit. As of October 31, 2003, each line of credit was either terminated or refinanced without a guarantee from us. We have no further guaranteed obligations with respect to any borrowings by our officers. 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 September 30, 2003. KMI would be obligated to perform under this guarantee only if we and/or our assets were unable to satisfy our obligations. 32 8. Partners' Capital As of September 30, 2003, our partners' capital consisted of: - 134,712,958 common units; - 5,313,400 Class B units; and - 48,184,840 i-units. Together, these 188,211,198 units represent our limited partners' interest and an effective 98% economic interest in us, exclusive of our general partner's incentive distribution rights. Our general partner has an effective 2% interest in us, excluding its incentive distribution rights. As of September 30, 2003, our common unit total consisted of 121,757,223 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: - 129,943,218 common units; - 5,313,400 Class B units; and - 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. In June 2003, we issued in a public offering an additional 4,600,000 of our common units, including 600,000 units upon exercise by the underwriters of an over-allotment option, at a price of $39.35 per share, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $173.3 million for the issuance of these common units. We used the proceeds to reduce the borrowings under our commercial paper program. 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 cash to the holders of our i-units but will retain the cash 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 33 preceding, KMR received a distribution of 811,878 i-units in August 2003. These additional i-units distributed were based on the $0.65 per unit distributed to our common unitholders on August 14, 2003. 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 $0.65 per unit paid on August 14, 2003 for the second quarter of 2003 required an incentive distribution to our general partner of $79.6 million. Our distribution of $0.61 per unit paid on August 14, 2002 for the second quarter of 2002 required an incentive distribution to our general partner of $64.4 million. The increased incentive distribution to our general partner paid for the second quarter of 2003 over the distribution paid for the second quarter of 2002 reflects the increase in the amount distributed per unit as well as the issuance of additional units. Our declared distribution for the third quarter of 2003 of $0.66 per unit will result in an incentive distribution to our general partner of approximately $81.8 million. This compares to our distribution of $0.61 per unit and incentive distribution to our general partner of approximately $69.5 million for the third quarter of 2002. 9. Comprehensive Income SFAS No. 130, "Accounting for Comprehensive Income," requires that enterprises report a total for comprehensive income. For each of the nine months ended September 30, 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 10. Our total comprehensive income is as follows (in thousands):
Three Months Ended Nine Months Ended Sept. 30, Sept. 30, 2003 2002 2003 2002 -------- -------- -------- -------- Net income.......................................................... $174,176 $158,180 $513,611 $444,130 Change in fair value of derivatives used for hedging purposes....... (35,508) (15,680) (108,682) (97,536) Reclassification of change in fair value of derivatives to net income 15,798 3,442 67,046 (9,386) -------- -------- -------- -------- Comprehensive income................................................ $154,466 $145,942 $471,975 $337,208 ======== ======== ======== ========
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. The energy risk management products that we use include: - commodity futures and options contracts; - fixed-price swaps; and 34 - 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: - pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; - pre-existing or anticipated physical carbon dioxide sales that have pricing tied to crude oil prices; - natural gas purchases; and - 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. Certain of our business activities expose us to foreign currency fluctuations. However, we do not believe the risks associated with changes in foreign currency will have a material adverse effect on our business, financial position, results of operations or cash flows. Accordingly, as of September 30, 2003, no financial instruments were used to limit the effects of foreign exchange rate fluctuations on our financial results. 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 by us 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 (loss)" in the accompanying consolidated balance sheets are reclassified into earnings as the hedged sales and purchases take place. Approximately $40.9 million of the Accumulated other comprehensive loss balance of $86.9 million representing unrecognized net losses on derivative activities as of September 30, 2003 is expected to be reclassified into earnings during the next twelve months. During the nine months ended September 30, 2003, we reclassified $67.0 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. During the nine months ended September 30, 2003, no gains or losses were reclassified into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions will no longer occur by the end of the originally specified time period. We recognized a gain of $0.2 million during the third quarter of 2003 and no gain or loss during the third quarter of 2002 as a result of hedge ineffectiveness. We recognized a gain of $0.6 million during the first nine months of 2003 and a gain of $0.5 million during the first nine months of 2002 as a result of hedge ineffectiveness. All of 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 nine months ended September 30, 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 September 30, 2003, the balance in "Other current assets" on our consolidated balance sheet included $20.4 million related to risk management hedging activities, and the balance in "Accrued other current liabilities" included $61.6 million related to risk management hedging activities. As of December 31, 2002, the balance in "Other current assets" on our consolidated balance sheet included $57.9 million 35 related to risk management hedging activities, and the balance in "Accrued other current liabilities" included $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 September 30, 2003, the balance in "Deferred charges and other assets" included $2.5 million related to risk management hedging activities, and the balance in "Other long-term liabilities and deferred credits" included $49.0 million related to risk management hedging activities. As of December 31, 2002, the balance in "Deferred charges and other assets" included $5.7 million related to risk management hedging activities, and the balance in "Other long-term liabilities and deferred credits" included $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 September 30, 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 September 30, 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: - $200 million principal amount of our 8.0% senior notes due March 15, 2005; - $200 million principal amount of our 5.35% senior notes due August 15, 2007; - $250 million principal amount of our 6.30% senior notes due February 1, 2009; - $200 million principal amount of our 7.125% senior notes due March 15, 2012; - $300 million principal amount of our 7.40% senior notes due March 15, 2031; - $200 million principal amount of our 7.75% senior notes due March 15, 2032; and - $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 September 30, 2003, the maximum length of time over which we have hedged a portion of 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. 36 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 September 30, 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 October 1, 2003 to September 1, 2005. Prior to March 2002, this swap was designated a hedge of our $200 million Floating Rate Senior Notes, which were retired (repaid) 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 September 30, 2003, we recognized an asset of $149.2 million and a liability of $8.3 million for the $140.9 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: - Products Pipelines; - Natural Gas Pipelines; - CO2 Pipelines; and - Terminals. We evaluate performance principally 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 37 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 Sept. 30, Nine Months Ended Sept. 30, ---------------------------- ---------------------------- 2003 2002 2003 2002 ------------- ------------- ------------- ------------- Revenues Products Pipelines................................. $ 145,874 $ 146,277 $ 435,575 $ 426,736 Natural Gas Pipelines.............................. 1,321,651 829,614 4,143,765 2,168,117 CO2 Pipelines...................................... 66,577 38,191 169,664 104,731 Terminals.......................................... 116,740 107,238 355,123 315,737 ------------- ------------- ------------- ------------- Total consolidated revenues........................ $ 1,650,842 $ 1,121,320 $ 5,104,127 $ 3,015,321 ============= ============= ============= ============= Operating expenses (a) Products Pipelines................................. $ 42,784 $ 43,608 $ 124,450 $ 125,383 Natural Gas Pipelines.............................. 1,234,149 752,270 3,887,905 1,949,963 CO2 Pipelines...................................... 21,372 12,772 54,175 38,944 Terminals.......................................... 56,994 53,245 174,941 159,712 ------------- ------------- ------------- ------------- Total consolidated operating expenses.............. $ 1,355,299 $ 861,895 $ 4,241,471 $ 2,274,002 ============= ============= ============= ============= (a) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. Depreciation, depletion and amortization Products Pipelines................................. $ 16,827 $ 16,086 $ 50,110 $ 48,130 Natural Gas Pipelines.............................. 13,777 11,489 40,006 35,393 CO2 Pipelines...................................... 15,298 7,505 41,341 21,387 Terminals.......................................... 9,129 7,466 27,137 21,585 ------------- ------------- ------------- ------------- Total consol. depreciation, depletion and amortiz.. $ 55,031 $ 42,546 $ 158,594 $ 126,495 ============= ============= ============= ============= Earnings from equity investments Products Pipelines................................. $ 6,989 $ 8,592 $ 22,619 $ 25,700 Natural Gas Pipelines.............................. 5,877 5,691 18,260 17,788 CO2 Pipelines...................................... 7,978 8,526 26,848 26,936 Terminals.......................................... (3) 9 37 (38) ------------- ------------- ------------- ------------- Total consolidated equity earnings................. $ 20,841 $ 22,818 $ 67,764 $ 70,386 ============= ============= ============= ============= Amortization of excess cost of equity investments Products Pipelines................................. $ 819 $ 819 $ 2,461 $ 2,461 Natural Gas Pipelines.............................. 70 70 208 208 CO2 Pipelines...................................... 505 505 1,513 1,513 Terminals.......................................... -- -- -- -- ------------- ------------- ------------- ------------- Total consol. amortization of excess cost of invests $ 1,394 $ 1,394 $ 4,182 $ 4,182 ============= ============= ============= ============= Income taxes and Other, net - income (expense) Products Pipelines................................. $ (2,135) $ (2,675) $ (6,591) $ (8,430) Natural Gas Pipelines.............................. (180) (1) (488) 18 CO2 Pipelines...................................... (62) 6 (77) 96 Terminals.......................................... (554) (1,217) (4,494) (4,670) ------------- ------------- ------------- ------------- Total consolidated income taxes and other, net..... $ (2,931) $ (3,887) $ (11,650) $ (12,986) ============= ============= ============= =============
38
Three Months Ended Sept. 30, Nine Months Ended Sept. 30, ---------------------------- ---------------------------- 2003 2002 2003 2002 ------------- ------------- ------------- ------------- Operating income Products Pipelines................................. $ 86,263 $ 86,583 $ 261,015 $ 253,223 Natural Gas Pipelines.............................. 73,725 65,855 215,854 182,761 CO2 Pipelines...................................... 29,907 17,914 74,148 44,400 Terminals.......................................... 50,617 46,527 153,045 134,440 ------------- ------------- ------------- ------------- Total segment operating income (a) ................ 240,512 216,879 704,062 614,824 Corporate administrative expenses.................. (35,547) (27,476) (104,383) (87,218) ------------- ------------- ------------- ------------- Total consolidated operating income................ $ 204,965 $ 189,403 $ 599,679 $ 527,606 ============= ============= ============= ============= (a) Represents amounts reported above as revenues, less operating expenses and depreciation, depletion and amortization. Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments Products Pipelines................................. $ 107,944 $ 108,586 $ 327,153 $ 318,623 Natural Gas Pipelines.............................. 93,199 83,034 273,632 235,960 CO2 Pipelines...................................... 53,121 33,951 142,260 92,819 Terminals.......................................... 59,189 52,785 175,725 151,317 ------------- ------------- ------------- ------------- Total segment earnings before DD&A (a)............. 313,453 278,356 918,770 798,719 Total consol. depreciation, depletion and amortiz.. (55,031) (42,546) (158,594) (126,495) Total consol. amortization of excess cost of invests (1,394) (1,394) (4,182) (4,182) Interest and corporate administrative expenses (b). (82,852) (76,236) (242,383) (223,912) ------------- ------------- ------------- ------------- Total consolidated net income ..................... $ 174,176 $ 158,180 $ 513,611 $ 444,130 ============= ============= ============= ============= (a) Represents amounts reported above as revenues, earnings from equity investments and income taxes and other, net, less operating expenses. (b) Includes interest and debt expense, general and administrative expenses, minority interest expense and cumulative effect adjustment from a change in accounting principle (2003 only). Segment earnings Products Pipelines................................. $ 90,298 $ 91,681 $ 274,582 $ 268,032 Natural Gas Pipelines.............................. 79,352 71,475 233,418 200,359 CO2 Pipelines...................................... 37,318 25,941 99,406 69,919 Terminals.......................................... 50,060 45,319 148,588 129,732 ------------- ------------- ------------- ------------- Total segment earnings (a)......................... 257,028 234,416 755,994 668,042 Interest and corporate administrative expenses..... (82,852) (76,236) (242,383) (223,912) ------------- ------------- ------------- ------------- Total consolidated net income...................... $ 174,176 $ 158,180 $ 513,611 $ 444,130 ============= ============= ============= ============= (a) Represents amounts reported above as revenues, earnings from equity investments and income taxes and other, net, less operating expenses, depreciation, depletion and amortization and amortization of excess cost of equity investments.
Sept. 30, Dec. 31, 2003 2002 ------------- ------------- Assets Products Pipelines..................... $ 3,125,940 $ 3,088,799 Natural Gas Pipelines.................. 3,183,172 3,121,674 CO2 Pipelines.......................... 838,209 613,980 Terminals.............................. 1,317,308 1,165,096 ------------- ------------- Total segment assets................... 8,464,629 7,989,549 Corporate assets (a)................... 216,168 364,027 ------------- ------------- Total consolidated assets.............. $ 8,680,797 $ 8,353,576 ============= ============= (a) Includes cash, cash equivalents and certain unallocable deferred charges. 12. New Accounting Pronouncements In January 2003, the Financial Accounting Standards Board issued Interpretation (FIN) No. 46, "Consolidation of Variable Interest Entities". This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", provides guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as variable interest entities (VIE). FIN No. 46 is the guidance that determines: 39 - whether consolidation is required under the "controlling financial interest" model of ARB No. 51 or other existing authoritative guidance; or - whether the variable-interest model under FIN No. 46 should be used to account for existing and new entities. All entities, other than those excluded from the scope of FIN No. 46, must first decide whether an entity is a VIE. If an entity meets FIN No. 46's criteria for VIE status, FIN No. 46 is applicable. Otherwise, existing authoritative guidance for consolidation should be applied. FIN No. 46 also provides guidance for identifying the enterprise that will consolidate a VIE, which is the enterprise that is exposed to the majority of an entity's risks (defined as expected losses) or receives the majority of the benefits from an entity's activities (defined as expected residual returns). That enterprise is referred to as the "primary beneficiary" of the VIE, and FIN No. 46 requires that the primary beneficiary and all other enterprises that hold a significant variable interest in a VIE make new disclosure in their financial statements. Pursuant to FIN No. 46, an entity is considered a VIE if any of the following factors are present: - the equity investment in the entity is insufficient to finance the operations of that entity without additional subordinated financial support from other parties; - the equity investors of the entity lack decision-making rights; - an equity investor holds voting rights that are disproportionately low in relation to the actual economics of the investor's relationship with the entity, and substantially all of the entity's activities involve or are conducted on behalf of that investor; - other parties protect the equity investors from expected losses; - parties, other than the equity holders, hold the right to receive the entity's expected residual returns, or the equity investors' rights to expected residual returns is capped. Therefore, some common structures, such as limited partnerships, joint ventures, trusts, and vendor-financing arrangements, may, in certain instances, qualify as VIEs under FIN No. 46's criteria. In addition, FIN No. 46 requires that, upon meeting certain criteria, portions of a legal entity must be evaluated as separate VIEs, apart from the larger entity. In October 2003, the FASB deferred the latest date by which all public entities must apply FIN No. 46, to the first reporting period ending after December 15, 2003. This broader deferral applies to all VIEs and potential VIEs, both financial and non-financial in nature. However, the deferral only applies to VIEs that existed prior to February 1, 2003. The requirements of FIN No. 46 applied immediately to VIEs created after January 31, 2003, and those situations were not subject to the deferral. Pursuant to the deferral, public companies must complete their evaluations of VIEs that existed prior to February 1, 2003, and the consolidation of those for which they are the primary beneficiary for financial statements issued for the first period ending after December 15, 2003. For calendar year companies, consolidation of previously existing VIEs will be required in their December 31, 2003 financial statements. We continue to evaluate the effect from the adoption of this Statement on our consolidated financial statements. 40 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. Results of Operations Throughout the following discussion and analysis, we refer to (i) revenues, (ii) costs and expenses, (iii) operating income, (iv) earnings from equity investments, net of amortization of excess cost, and (v) earnings. Costs and expenses include (i) natural gas purchases and other costs of sales, (ii) operations and maintenance expenses, (iii) fuel and power expenses, (iv) depreciation, depletion and amortization, (v) general and administrative expenses, and (vi) taxes, other than income taxes. Our operating income represents revenues less costs and expenses. Our earnings represent (i) operating income, (ii) earnings from equity investments, net of amortization of excess cost, (iii) interest income and expense, (iv) other income and expense items, net, (v) minority interest, and (vi) income taxes. We do not attribute general and administrative expenses, interest income and expense or minority interest to any of our reportable business segments. For more detailed segment information, please refer to Note 11 to our Consolidated Financial Statements, entitled "Reportable Segments" included elsewhere in this report. Third Quarter 2003 Compared With Third Quarter 2002 Total consolidated net income for the third quarter of 2003 was $174.2 million ($0.49 per diluted unit), up10% from the $158.2 million ($0.50 per diluted unit) of net income reported for the third quarter of 2002. The $16.0 million quarter-to-quarter increase in earnings demonstrates continued strong demand for services across our portfolio of pipeline and terminal businesses. Moving forward, we will continue to focus on increasing the utilization of existing assets and investing in new infrastructure to help meet growing energy demand across the United States. Revenues for the third quarter of 2003 totaled $1,650.8 million, compared with revenues of $1,121.3 million for the same period last year. Costs and expenses were $1,445.8 million in the third quarter of 2003, compared with $931.9 million in the same period a year ago. Our third quarter 2003 operating income was $205.0 million, 8% over the $189.4 million in operating income earned during the third quarter of 2002. During the third quarter, earnings and revenues grew in each of our four reportable business segments except Products Pipelines, where both earnings and revenues were essentially flat. The increase in our overall net income was primarily driven by higher earnings from our CO2 Pipelines and Natural Gas Pipelines business segments. The increase was mainly due to strong internal growth of operations since the start of the third quarter of 2002, primarily the result of higher oil sales volumes and increased natural gas transportation, storage and sales activity. Third quarter equity earnings, net of amortization of excess costs, from investments accounted for under the equity method of accounting were $19.4 million in the third quarter of 2003 and $21.4 million in the third quarter of 2002. Our equity earnings predominantly consist of returns on our investments in Plantation Pipe Line Company, Cortez Pipeline Company and the Red Cedar Gathering Company. The $2.0 million (9%) decrease in equity earnings, net of amortization of excess costs, was primarily due to our acquisition of MKM Partners, L.P.'s 12.75% ownership interest in the SACROC oil field unit on June 1, 2003, and the subsequent dissolution of MKM Partners, L.P. on June 30, 2003. MKM Partners, L.P. was an oil and gas joint venture formed on January 1, 2001 and owned 85% by subsidiaries of Marathon Oil Company and 15% by Kinder Morgan CO2 Company, L.P. Prior to the dissolution of the joint venture, we accounted for our investment in MKM Partners, L.P. under the equity method of accounting. On October 15, 2003, we declared a record quarterly cash distribution of $0.66 per unit (an annualized rate of $2.64) for the third quarter of 2003. This distribution is 8% higher than the $0.61 per unit distribution we made for the third quarter of 2002. It will be paid on November 14, 2003 to unitholders of record on October 31, 2003. Products Pipelines Our Products Pipelines segment's third quarter 2003 results were consistent with the results reported through the first six months of the year and with the third quarter results from 2002. The segment earned $90.3 million on revenues of $145.9 million in the third quarter of 2003. In the third quarter of 2002, Products Pipelines reported earnings of $91.7 million on revenues of $146.3 million. The segment's costs and expenses totaled $59.6 million in 41 the third quarter of 2003 and $59.7 million in the third quarter of 2002. Operating income for the quarters ended September 30, 2003 and 2002 were $86.3 million and $86.6 million, respectively. Earnings from our Products Pipelines' equity investments, net of amortization of excess costs, were $6.2 million in the third quarter of 2003 and $7.8 million in the third quarter of 2002. Income tax expense decreased to $2.3 million in the third quarter of 2003 from $2.9 million in the same period of 2002. Third quarter 2003 earnings increases from our Transmix operations, Central Florida pipeline, Pacific operations and North System were offset by declines in earnings from our ownership interest in the Cochin pipeline system, our Cypress products pipeline, our investment in Plantation Pipe Line Company and our West Coast Terminals. Cochin's earnings and revenues were negatively impacted by a pipeline rupture and fire in July 2003 that led to the shut down of the system for 29 days during the third quarter. In addition, the system was operated at less than maximum pressure for the balance of the quarter. Both the $1.4 million (2%) and $0.4 million (0%) decreases in quarter-to-quarter segment earnings and revenues were significantly impacted by a $3.2 million (80%) drop in earnings and a $3.1 million (41%) drop in revenues from our 44.8% interest in Cochin. Overall, total segment delivery volumes decreased 2% in the third quarter of 2003 compared to the same quarter of 2002. Gasoline delivery volumes were down 4% due to continued refinery problems in the Southeast and the continuing process of converting from methyl tertiary-butyl ether (MTBE) to ethanol in the State of California. MTBE-blended gasoline is being replaced by an ethanol blend and since ethanol is not shipped in our pipelines, we realize a small reduction in California gasoline volumes; however, higher fees we earn from ethanol-related services at our terminals positively contribute to our earnings. In addition, for the second consecutive quarter in 2003, declines in jet fuel delivery volumes were more than offset by increases in delivered diesel volumes. Operations at our transmix facilities, where we process and separate pipeline transmix into pipeline-quality gasoline and light distillate products on a fee basis, reported increases of $1.3 million (33%) in earnings and $1.2 million (19%) in revenues primarily due to a 22% increase in the volume of transmix processed. Central Florida reported third quarter 2003 increases in earnings and revenues of $0.7 million (16%) and $0.6 million (7%), respectively, over the third quarter of 2002, mainly due to an almost 8% increase in delivery volumes related to customer additions. On our Pacific operations, earnings increased $0.6 million (1%) and revenues were flat in the third quarter of 2003, when compared to the same quarter last year. The earnings increase was primarily due to lower maintenance expenses. Revenues were flat across both quarters as decreases in mainline delivery volume revenues were offset by increases in non-transportation terminal revenues, as the market continued to transition to ethanol, which cannot be shipped through our pipelines but is blended at our terminals. We also profited from a $0.4 million (19%) increase in earnings and a $0.5 million (7%) increase in revenues from our North System pipeline. Throughput deliveries on the pipeline dropped 8% compared to third quarter 2002, but we benefited from an almost 17% increase in average tariff rates as a result of an increased Cost of Service tariff agreement filed with the Federal Energy Regulatory Commission in May 2003. In addition to the negative impact of Cochin's results, referred to above, partially offsetting the segment's overall increases in earnings and revenues were a $0.4 million (34%) decrease in earnings and a $0.4 million (22%) decrease in revenues from our Cypress pipeline. Cypress' lower earnings resulted from the drop in revenues, due to customers catching up on liquids volumes earned but not delivered in prior periods, and to lower throughput volumes. On July 30, 2003, we experienced a rupture on our Pacific operations' Tucson to Phoenix line. Through a combination of increased deliveries on our Los Angeles to Phoenix line and terminal modifications at our Tucson terminal that allowed volumes of Phoenix-grade gasoline to be trucked into Phoenix, we were able to deliver most of the volumes into the Phoenix area which normally flow through the ruptured line. The 8-inch line resumed service on August 24, 2003. The impact of the rupture on our results of operations for the quarter was not material. Our longer term plan to ensure adequate capacity into the Phoenix market is to: - replace 4,600 feet of 8-inch pipe on the damaged line (which was completed on September 12, 2003); - construct approximately four miles of new 12-inch pipe in Phoenix from Star Pass Boulevard to West Weymouth Avenue to replace existing 8-inch pipe (estimated completion date is December 15th, 2003); and 42 - construct about seven miles of new 12-inch pipe from Starr Pass Boulevard to our Tucson terminal to replace existing 8-inch pipe (estimated completion date is February 1, 2004). The segment's costs and expenses were flat for the third quarters of 2003 and 2002, and the $1.6 million (21%) decrease in equity earnings, net of amortization, was mainly due to lower earnings from our investment in Plantation Pipe Line Company. The decrease was driven by a 6% decrease in quarter-to-quarter delivery volumes on the Plantation system, primarily due to various refinery shut-downs in the third quarter of 2003 and to a loss of some supply and delivery contracts to competing pipelines. The $0.6 million (21%) decrease in income tax expense was directly related to Plantation's lower pre-tax income. Natural Gas Pipelines Our Natural Gas Pipelines segment again reported strong quarterly results. The segment reported earnings of $79.4 million on revenues of $1,321.7 million in the third quarter of 2003. In the third quarter of 2002, the segment reported earnings of $71.5 million on revenues of $829.6 million. The segment's costs and expenses were $1,248.0 million in the third quarter of 2003 and $763.7 million in the third quarter of 2002. Operating income for each of the two quarters ended September 30, 2003 and 2002 was $73.7 million and $65.9 million, respectively. Earnings from our Natural Gas Pipelines' equity investments, net of amortization of excess costs, were $5.8 million in the third quarter of 2003 versus $5.6 million in the same quarter last year. The segment also recognized income tax expense of $0.7 million in the third quarter of 2003. The segment's $7.9 million (11%) increase in earnings in the third quarter of 2003 compared to the third quarter of 2002 was primarily attributable to growth in the operations of our Texas intrastate natural gas pipeline group. The group's earnings in the third quarter of 2003 exceeded last year's third quarter amount by $15.2 million, more than offsetting a $7.2 million decrease in quarter-to-quarter earnings from our two Rocky Mountain natural gas pipeline systems: Kinder Morgan Interstate Gas Transmission and Trailblazer Pipeline Company. The earnings increase on our intrastate pipeline systems was driven by increases in natural gas sales, transportation and storage activities, primarily related to long-term contracts signed with BP in August 2002. Our intrastate group reported a 6% increase in natural gas sales volumes in the third quarter of 2003 compared to the third quarter of 2002. In 2003, we benefited from the inclusion of a full quarter of results from our Kinder Morgan North Texas and Mier-Monterrey Mexico pipeline systems, both included as part of the intrastate pipeline group. These two pipelines reported combined earnings of $4.4 million, revenues of $6.3 million and costs and expenses of $1.2 million in the third quarter of 2003. The North Texas pipeline was completed and placed in service in August 2002, and the Mier-Monterrey pipeline was completed in placed in service in March 2003. The earnings decrease on our Rocky Mountain pipeline systems was primarily due to the timing of favorable settlements of operational gas balancing agreements in the third quarter of 2002. Increases in sales volumes and prices of natural gas since the end of the third quarter of 2002 have driven the quarter-to-quarter increase in segment revenues, but the higher gas prices have likewise increased our natural gas purchase costs, thereby offsetting some of the growth in revenues from natural gas sales. The segment's service and other revenues, including transportation and storage services, increased $23.8 million (27%), primarily due to incremental demand fee revenues associated with gas transportation agreements. In total, segment transport volumes were up nearly 9% in the third quarter of 2003 compared to the third quarter of 2002. As described above, the segment's overall increase in costs and expenses was mostly due to the higher gas purchase costs incurred by our intrastate gas pipeline group as a result of the increase in gas prices since the end of the third quarter of 2002. Non-cash depreciation and amortization expenses were also higher by $2.3 million (20%) in the third quarter of 2003 versus the third quarter of 2002. The increase was due to recent capital expenditures made within our intrastate pipeline operations, including the new capital assets related to the start-up of the North Texas and Mier-Monterrey pipelines. The $0.2 million (4%) increase in equity earnings was primarily due to higher earnings from the segment's 25% ownership interest in Thunder Creek Gas Services, LLC, mainly due to higher gas gathering revenues. The segment's $0.7 million in income tax expense in the third quarter of 2003 was related to the earnings from the start-up of our Mier-Monterrey pipeline. 43 CO2 Pipelines Since the end of the third quarter of 2002, we have profited from both increased drilling activity and a higher ownership interest (effective June 1, 2003) in the operations of the SACROC oil field unit in the Permian Basin of West Texas. The CO2 Pipelines segment reported record earnings of $37.3 million on revenues of $66.6 million in the third quarter of 2003. This compares to earnings of $25.9 million on revenues of $38.2 million in the third quarter of 2002. Costs and expenses totaled $36.7 million in the third quarter of 2003 and $20.3 million in the third quarter of 2002. Operating income for each of the quarters ended September 30, 2003 and 2002 was $29.9 million and $17.9 million, respectively. In addition, the segment reported $7.5 million in equity earnings, net of amortization of excess costs, in the quarter ended September 30, 2003. Equity earnings, net of amortization, totaled $8.0 million in the third quarter of 2002. The $11.4 million (44%) increase in quarter-to-quarter segment earnings was primarily attributable to the $28.4 million (74%) increase in revenues, partially offset by higher depreciation, depletion and amortization expenses, and by higher operating, maintenance and fuel and power expenses. The segment's increase in revenues was mainly due to higher oil production volumes. Oil production at the SACROC unit averaged 20,900 barrels per day in the third quarter of 2003, a 55% increase in production over the same period last year. Production reached over 23,000 barrels per day at the end of September 2003, and we expect production to surpass 25,000 barrels per day by the end of the year. As mentioned above, effective June 1, 2003, we acquired MKM Partners, L.P.'s 12.75% ownership interest in the SACROC unit. We acquired this interest for $23.3 million and the assumption of $1.9 million of liabilities, and the acquisition increased our ownership interest in SACROC to approximately 97%. As a result of our oil reserve ownership interests, we are exposed to commodity price risk, but the risk is mitigated by our long-term hedging strategy that is intended to generate more stable realized prices. For the comparable quarters ended September 30, 2003 and 2002, we benefited from an approximate 4% increase in our realized weighted average price of oil per barrel (from $22.54 per barrel in third quarter 2002 to $23.50 per barrel in third quarter 2003). For more information on our hedging activities, see Note 10 to our Consolidated Financial Statements, included elsewhere in this report. Additionally, the segment benefited from a $4.0 million adjustment to revenues due to favorable settlements of pending royalty litigation, and from slightly higher carbon dioxide transportation revenues due to an increase in carbon dioxide deliveries to all fields throughout West Texas. While carbon dioxide delivery volumes increased almost 24% in the third quarter of 2003 compared to the third quarter of 2002, a significant proportion (63%) of the quarter-to-quarter increase in carbon dioxide delivery volumes resulted from the inclusion of deliveries from our Centerline pipeline, which began operations in May 2003. The Centerline Pipeline consists of approximately 113 miles of 16-inch pipe located in the Permian Basin between Denver City, Texas and Snyder, Texas, and primarily transports carbon dioxide to the SACROC oil field unit. We do not recognize profits on carbon dioxide sales to ourselves. The overall increase in segment earnings was partially offset by higher depreciation, depletion and amortization charges and by higher operating and maintenance expenses. Non-cash depletion and depreciation-related charges were up $7.8 million (104%), a result of the higher production volumes (as depletion expense is calculated on a per unit production basis), a higher per barrel depletion rate and additional capital investments made since the end of the third quarter of 2002. Operating, maintenance, and fuel and power expenses increased $7.7 million (77%), principally the result of the increase in oil production volumes. The segment's $7.5 million of equity earnings in the third quarter of 2003 represents earnings from its 50% ownership interest in Cortez Pipeline Company. Equity earnings realized in the third quarter of 2002 consisted of $5.9 million from the segment's equity interest in Cortez and $2.1 million from its previous 15% ownership interest in MKM Partners, L.P. Effective June 30, 2003, MKM Partners, L.P. was dissolved. The $1.6 million (27%) increase in equity earnings from Cortez was driven by an almost 14% increase in carbon dioxide delivery volumes due to the increased demand for carbon dioxide in West Texas. 44 Terminals Our Terminals segment, including both our bulk and liquids terminal businesses, reported earnings of $50.1 million on revenues of $116.7 million in the third quarter of 2003. In the same quarter last year, the segment earned $45.3 million on revenues of $107.2 million. Costs and expenses for each of the quarters ended September 30, 2003 and 2002 were $66.1 million and $60.7 million, respectively. Operating income for each of the quarters ended September 30, 2003 and 2002 was $50.6 million and $46.5 million, respectively. Both our dry bulk and liquids terminal operations reported quarter-to-quarter increases in earnings, revenues and operating income. Terminal operations acquired on or after September 1, 2002 accounted for $2.6 million of the $4.8 million increase in segment earnings. These acquisitions included: - the Owensboro Gateway Terminal, acquired effective September 1, 2002; - the St. Gabriel Terminal, acquired effective September 1, 2002; - the purchase of four floating cranes at our bulk terminal facility in Port Sulphur, Louisiana in December 2002; and - the bulk terminal businesses acquired from M.J. Rudolph Corporation, effective January 1, 2003. The above acquisitions contributed an incremental $6.9 million of revenues and $4.3 million of costs and expenses to the third quarter of 2003 compared to the third quarter of 2002. Excluding these acquisitions, terminal earnings increased $2.2 million and revenues increased $2.6 million in the third quarter of 2003, compared to the third quarter of 2002. A $2.1 million (3%) increase in liquids terminal revenues accounted for the majority of the change in segment earnings and revenues. The revenue increase was primarily due to an increase in refined petroleum imports to the United States and to expansion projects that have increased the leaseable capacity at some of our largest liquids terminals. Expansion projects undertaken since the end of the third quarter of 2002, including the work done at our Carteret, New Jersey and Pasadena, Texas terminals, have increased our liquids terminals' leaseable capacity by almost 3% over the third quarter of 2002, more than offsetting a slight (1.5%) drop in our overall utilization percentage. Over half of the decline in utilization was associated with tank maintenance. Revenues at our Carteret terminal accounted for $1.3 million of this increase, primarily due to the construction of five 100,000 barrel petroleum products storage tanks since the end of the third quarter of 2002 and to escalations in annual contract provisions. In our dry-bulk businesses, excluding the acquisitions above, revenues were essentially flat, as decreases in revenues from our two largest coal terminals were virtually offset by increases in revenues from other coal terminals, petroleum coke and other bulk tonnage transfers, and dock services. The segment's overall decrease in coal revenues was related to decreases in coal tonnage handled at our Grand Rivers, Kentucky and Cora, Illinois coal terminals. As we anticipated and discussed in our Annual Report on Form 10-K for the year ended December 31, 2002, these terminals experienced a drop in contract volumes handled for the Tennessee Valley Authority due to the fact that the TVA has diverted some of its business to new competing coal terminals that have come on-line since the end of the third quarter of 2002. Third quarter costs and expenses from all terminals owned during both years totaled $61.6 million in the third quarter of 2003, compared with $60.5 million in the comparable period of 2002. The $1.1 million (2%) increase in costs and expenses was mainly due to higher depreciation expense associated with ongoing capital improvements at selected terminal sites. Segment Operating Statistics Operating statistics for the third quarter of 2003 and 2002 are as follows (historical pro forma for acquired assets): 45 Three Months Ended Sept. 30, 2003 Sept. 30, 2002 Products Pipelines Gasoline (MMBbl)......................... 115.8 120.7 Diesel (MMBbl)........................... 42.0 38.6 Jet Fuel (MMBbl)......................... 28.4 30.0 ------ ------ Total Refined Product Volumes (MMBbl).... 186.2 189.3 Natural Gas Liquids (MMBbl).............. 9.4 10.6 ------ ------ Total Delivery Volumes (MMBbl) (1)....... 195.6 199.9 Natural Gas Pipelines (2) Transport Volumes (Bcf) ................. 333.1 306.8 Sales Volumes (Bcf) ..................... 242.9 228.1 CO2 Pipelines Delivery Volumes (Bcf) (3)............... 129.2 104.4 SACROC Oil Production (MBbl/d) .......... 20.9 13.5 Realized Weighted Average Oil Price per Bbl (4)................................. $23.50 $22.54 Terminals Bulk Terminals Transload Tonnage (MMtons) (5)........ 13.3 14.6 Liquids Terminals Leaseable Capacity (MMBbl)............ 36.0 35.0 Liquids Utilization %................. 95.5% 97.0% 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 Intrastate group and Trailblazer pipeline volumes. (3) Includes Cortez, Central Basin, Canyon Reef Carriers and Centerline pipeline volumes. (4) Includes all partnership crude oil properties. (5) 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. Together, these items totaled $82.9 million in the third quarter of 2003 and $76.2 million in the third quarter of 2002. Our general and administrative expenses totaled $35.6 million in the third quarter of 2003 compared with $27.5 million in the third quarter of 2002. The $8.1 million (29%) quarter-to-quarter increase in general and administrative expenses was principally due to higher legal expenses, employee benefit and pension costs and overall corporate and worker-related insurance expenses. Total interest expense, net of interest income, was $44.7 million in the third quarter of 2003 versus $46.3 million in the same quarter of 2002. The $1.6 million (3%) quarter-to-quarter decrease in net interest charges was due to lower average borrowing rates during the third quarter of 2003 compared with the same quarterly period last year. Minority interest remained relatively flat in the third quarter of each year, totaling $2.6 million in the third quarter of 2003 versus $2.4 million in the third quarter of 2002. The $0.2 million (8%) quarterly increase in 2003 over 2002 was chiefly due to higher net income realized by International Marine Terminals, a Louisiana partnership owned 66 2/3% and controlled by us. Nine Months Ended September 30, 2003 Compared With Nine Months Ended September 30, 2002 For the nine months ended September 30, 2003, our income before a benefit from a change in accounting principle was $510.1 million ($1.47 per diluted unit). This amount is 15% greater than our reported net income of $444.1 million ($1.46 per diluted unit) for the same nine month period of 2002. In 2003, we benefited from a cumulative effect adjustment of $3.5 million related to a change in accounting for asset retirement obligations 46 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, our net income for the nine month period ended September 30, 2003 totaled $513.6 million ($1.49 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. We reported total revenues of $5,104.1 million for the first nine months of 2003, compared with $3,015.3 million in revenues for the first nine months of 2002. Our costs and expenses were $4,504.4 million for the nine month period ended September 30, 2003, and $2,487.7 million for the comparable period of 2002. Operating income for the nine months ended September 30, 2003, was $599.7 million, 14% over the $527.6 million in operating income reported for the nine months ended September 30, 2002. Equity earnings from investments, less amortization of excess costs, were $63.6 million in the first nine months of 2003 versus $66.2 million in the same period last year. For the comparative nine month periods of 2003 and 2002, all four of our business segments reported increases in earnings, operating income and revenues. The increases were driven by both internal growth, resulting from our ongoing expansion and capital improvement projects, including our Trailblazer pipeline expansion and Mier-Monterrey pipeline construction, and by acquisitions, including natural gas operations, terminal businesses and additional ownership interests in oil producing field units. The most significant of these actions was our January 31, 2002 purchase of Kinder Morgan Tejas and the subsequent integration of its operations into our pre-existing natural gas businesses. Kinder Morgan Tejas' natural gas operations include a 3,400-mile Texas intrastate natural gas pipeline system and the subsequent integration of its operations with our other natural gas pipeline assets in Texas, particularly Kinder Morgan Texas Pipeline and Kinder Morgan North Texas Pipeline, have improved our overall results. Products Pipelines Our Products Pipelines segment reported earnings of $274.6 million on revenues of $435.6 million in the first nine months of 2003. In the same nine month period last year, the segment reported earnings of $268.0 million on revenues of $426.7 million. Costs and expenses totaled $174.6 million in the first nine months of 2003 and $173.5 million in the first nine months of 2002. Operating income for each of the nine month periods ended September 30, 2003 and 2002 was $261.0 million and $253.2 million, respectively. Earnings from our Products Pipelines' equity investments, net of amortization of excess costs, were $20.2 million in the first nine month period of 2003 versus $23.2 million in the comparable period of 2002. Currency translation gains contributed to a $0.8 million increase in other income items, and income tax expense dropped $1.0 million in the first nine months of 2003 from the same prior year period. The $6.6 million (2%) increase in segment earnings and the $8.9 million (2%) increase in segment revenues resulted from returns on assets owned over both nine month periods, primarily driven by earnings from deliveries of natural gas liquids on our North System pipeline, terminal services on our Pacific operations and CALNEV pipeline, processing operations at our pipeline transmix facilities and deliveries of refined petroleum products on our Central Florida pipeline. Partially offsetting the positive overall changes in segment earnings and revenues were decreases in earnings and revenues from our proportionate share of the Cochin pipeline and our Cypress pipeline, as well as lower earnings from our equity investment in the Plantation Pipe Line Company. Earnings from our North System were up $3.6 million (47%) and revenues were up $4.2 million (17%) in the first nine months of 2003, compared to the same period of 2002. As described above in our quarterly discussion and analysis, the increases were mostly due to higher revenues associated with higher average tariff rates in the 2003 period. Throughput volumes on the North System matched last year's totals due to cold weather in the Midwest during the first quarter of 2003 and overall strong propane demand. Combined earnings and revenues from our Pacific operations and CALNEV pipeline increased $5.2 million (3%) and $6.6 million (3%), respectively. The increases were primarily the result of increased ethanol blending operations and higher revenues from CALNEV delivery volumes, due to an almost 6% increase in average tariff rates driven by an increase in transportation of longer-haul, higher margin barrels. Earnings from our transmix operations increased $2.6 million (21%) in the first nine months of 2003, when compared to the same period a year earlier. The increase was the result of a $2.5 million (12%) increase in transmix processing revenues, due to a similar increase in transmix processing volumes. Our transmix processing activities are primarily performed on a "for fee" basis pursuant to a long-term contract expiring 47 in 2010. Finally, earnings and revenues from our Central Florida pipeline in the first nine months of 2003 increased $2.3 million (15%) and $1.3 million (5%), respectively, from the same period in 2002. The revenue increase was primarily due to an almost 3% increase in transport volumes due to the addition of new customers, and the earnings increase resulted from higher revenues and favorable adjustments to operating expenses made in the second quarter of 2003. Partially offsetting the segment's period-to-period overall increases in earnings and revenues were decreased earnings and revenues from the Cochin pipeline system. Cochin's earnings decreased $5.3 million (40%) in the first nine months of 2003, when compared to the same nine months of 2002. The decrease was mainly due to a $6.3 million (26%) decrease in revenues, the result of both lower delivery volumes associated with decreased propane production in western Canada and a pipeline rupture and fire in July 2003, as referred to above in our quarterly discussion and analysis. Additionally, earnings from our Cypress pipeline were down $0.7 million (23%) in the comparable nine month periods of 2003 and 2002. The decrease was the result of a corresponding $0.7 million (14%) decrease in revenues, mainly the result of customers catching up on liquids volumes earned but not delivered in prior periods. The segment's costs and expenses were essentially even across both nine month periods. The $1.1 million (1%) increase in the segment's costs and expenses was mostly due to higher depreciation charges and higher property tax expenses, both related to capital investments made since the end of the third quarter of 2002. The $3.0 million (13%) decrease in equity earnings and the $1.0 million (11%) decrease in income tax expenses related to lower returns from our investment in Plantation Pipe Line Company. Plantation's product transport delivery volumes were down 6% in the nine months ended September 30, 2003 compared to the same time period of 2002, when Plantation enjoyed record throughput. As discussed above in our quarterly discussion and analysis, the decrease was primarily due to various refinery shut-downs in the third quarter of 2003 and to a loss of certain supply and delivery contracts to competing pipelines. The decrease in income tax expense was directly related to Plantation's lower income. Natural Gas Pipelines Our Natural Gas Pipelines segment reported earnings of $233.4 million on revenues of $4,143.8 million in the first nine months of 2003. In the first nine months of 2002, the segment reported earnings of $200.4 million on revenues of $2,168.1 million. The segment's costs and expenses were $3,927.9 million in the first nine months of 2003 and $1,985.3 million in same period of 2002. Operating income for each of the nine months ended September 30, 2003 and 2002 was $215.9 million and $182.8 million, respectively. Earnings from our Natural Gas Pipelines' equity investments, net of amortization of excess costs, were $18.1 million in the nine month period ended September 30, 2003 and $17.6 million in the same period a year ago. The segment also recognized income tax expense of $1.5 million in the first nine months of 2003, and no income tax expense in the comparable period of 2002. The largest portion of our overall increase in consolidated net income in the comparable nine month periods of 2003 and 2002 came from the increase in earnings from our Natural Gas Pipelines segment. The increase was primarily the result of our January 31, 2002 acquisition of Kinder Morgan Tejas and the subsequent integration of Kinder Morgan Tejas with our Kinder Morgan Texas Pipeline system, North Texas pipeline, and Mier-Monterrey pipeline. Together, the four operations comprise our Texas intrastate natural gas pipeline group. The acquisition, construction and subsequent integration of all of our natural gas pipeline assets in and around the State of Texas has produced a very strategic intrastate pipeline business combination. The segment's $33.0 million (16%) increase in earnings in the first nine months of 2003 compared to the first nine months of 2002 was attributable primarily to internal growth from this intrastate pipeline group. The intrastate pipeline group accounted for approximately $28.1 million of the total period-to-period increase in segment earnings. Our North Texas and Mier-Monterrey pipeline systems, both placed in service since the end of the second quarter of 2002, reported combined earnings of $9.3 million, revenues of $13.3 million and costs and expenses of $2.7 million in the first nine months of 2003. Also, during 2003, we received a full nine-month benefit from the expansion of our Trailblazer pipeline system. Trailblazer's $59 million expansion project was completed in May 2002, and in the first nine months of 2003, Trailblazer reported a $4.1 million (14%) increase in earnings and a $9.3 million (25%) 48 increase in revenues, compared to the first nine months of 2002. The increases in earnings and revenues resulted from both an 18% increase in transport volumes and a 7% increase in average tariff rates in the 2003 period over the 2002 period. Overall, the segment's significant increases in period-to-period revenues and costs and expenses related primarily to higher natural gas prices since the end of the third quarter of 2002. Both Kinder Morgan Tejas and Kinder Morgan Texas Pipeline purchase and sell significant volumes of natural gas, which is 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. This purchase and sale activity results in considerably higher revenues and cost of sales expense compared to the interstate natural gas pipeline systems of Kinder Morgan Interstate Gas Transmission 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. In addition to the increase in period-to-period segment costs and expenses attributable to higher gas purchase costs, the segment reported higher depreciation and amortization charges and higher operating and maintenance expenses, including fuel and power costs. Depreciation expenses totaled $40.0 million, up 13% from the $35.4 million reported in the first nine months of 2002. The increase was due to the additional capital investments we have made since the end of the third quarter of 2002 and to an additional month of depreciation for Kinder Morgan Tejas. The increase in operating, maintenance and fuel and power expenses were attributable to an increase in natural gas transmission volumes. By entering into new long-term transportation, storage and sales contracts with customers like BP and Pemex, and by extending certain existing contracts with other customers, the segment increased total natural gas transport volumes by 12% in the first nine months of 2003, compared to the first nine months of 2002. Earnings from our Natural Gas Pipelines' equity investments, net of amortization of excess costs, were relatively stable across both nine month periods of 2003 and 2002. The $0.5 million (3%) increase in 2003 over 2002 was mainly related to higher equity earnings from the segment's 25% ownership interest in Thunder Creek Gas Services, LLC. Thunder Creek had higher income primarily as a result of higher revenues associated with an increase in gas gathering volumes. The segment's $1.5 million income tax expense in the nine month period of 2003 was principally related to the operations of our Mier-Monterrey pipeline, which was placed in service in March 2003. CO2 Pipelines Our CO2 Pipelines segment reported earnings of $99.4 million on revenues of $169.7 million in the first nine months of 2003. In the same prior year period, the segment reported earnings of $69.9 million on revenues of $104.7 million. Costs and expenses totaled $95.6 million in the first nine months of 2003 versus $60.3 million in the comparable period of 2002. Operating income for each of the nine months ended September 30, 2003 and 2002 was $74.1 million and $44.4 million, respectively. Equity earnings, net of amortization of excess costs, were essentially flat across both nine month periods. The segment reported $25.3 million in equity earnings for the nine months ended September 30, 2003 and $25.4 million in the comparable period of 2002. The period-to-period increases in revenues and costs and expenses were chiefly due to the higher production volumes and our increased ownership interest in the SACROC oil field unit, as referred to above in our quarterly discussion and analysis. The segment benefited from period-to-period increases of 56% in oil production volumes from the SACROC unit and 7% in the average hedged price of oil per barrel. The segment reported an overall 3% increase in carbon dioxide delivery volumes, including deliveries made by the Centerline carbon dioxide pipeline, which began operations in May 2003. The $35.3 million (59%) increase in the segment's costs and expenses primarily related to higher depreciation, depletion and amortization charges, higher fuel and power expenses, and higher operating and maintenance expenses. Non-cash depletion and depreciation-related charges were up $20.0 million (93%), primarily due to capital investments and acquisitions of property interests since the end of the third quarter of 2002, as well as a higher per barrel depletion rate. Fuel and power expenses were up $6.2 million (48%) and operating and maintenance expenses were up $5.2 million (27%), both primarily the result of expanded oil field operations and acquired interests. 49 Although the segment's overall equity earnings were essentially unchanged across both nine month periods, we realized a $0.7 million (4%) increase in equity earnings from our investment in Cortez Pipeline Company, mainly due to lower average debt balances and slightly lower borrowing rates. The increase from Cortez was offset by a $0.8 million decrease in equity earnings from our previous 15% interest in MKM Partners, L.P. Equity earnings from MKM Partners, L.P. was lower during 2003 due to the fact that we acquired the partnership's 12.75% ownership interest in the SACROC unit effective June 1, 2003, and the partnership was dissolved effective June 30, 2003. Terminals Our Terminals segment reported earnings of $148.6 million on revenues of $355.1 million in the first nine months of 2003. In the same period last year, the segment earned $129.7 million on revenues of $315.7 million. Costs and expenses for each of the nine months ended September 30, 2003 and 2002 were $202.1 million and $181.3 million, respectively. Operating income for each of the nine months ended September 30, 2003 and 2002 was $153.0 million and $134.4 million, respectively. The increases in segment operating results were driven by the terminal acquisitions we have made since the beginning of 2002 and by internal growth at certain existing terminals. Our terminal acquisitions include the businesses described above in our quarterly discussion and analysis as well as the acquisition of our Milwaukee bagging operations, effective May 1, 2002. These terminal acquisitions accounted for $11.7 million of the $18.9 million period-to-period increase in segment earnings. Combined, the acquired terminal operations accounted for incremental revenues, costs and expenses and operating income of $28.2 million, $16.4 million and $11.8 million, respectively. Earnings from all liquids terminals owned during the same nine month period of both years increased $10.3 million (12%) in 2003 compared to 2002. Revenues from these liquids terminal operations increased $11.8 million (7%) and costs and expenses increased $2.5 million (3%) in the first nine months of 2003, compared to the same period last year. The increases were primarily due to the expansion projects and higher petroleum product storage and transfer activities at some of our largest liquids terminals as described above in our quarterly discussion and analysis. Our Houston terminal complex, located in Pasadena and Galena Park, Texas along the Houston Ship Channel, along with our Carteret, New Jersey terminal on the New York Harbor and our Argo terminal near Chicago all reported higher earnings in the first nine months of 2003 when compared to the same period last year. Expansion projects have increased our liquids terminals' leaseable capacity by almost 3% in the nine month period ended September 30, 2003 compared to the same period in 2002, more than offsetting the slight 1% drop in our overall utilization percentage. The $2.5 million period-to-period increase in costs and expenses includes a $2.0 million increase in non-cash depreciation expense, the result of our ongoing capital spending and investment projects. For all bulk terminal businesses owned during the first nine month period of both years, earnings decreased $3.1 million (7%) in 2003 compared to 2002. Revenues were flat across both time periods as decreases in revenues from coal transloading operations and engineering services were offset by increases in revenues from other bulk tonnage transfers and dock services. Costs and expenses increased $1.9 million (2%) in the first nine months of 2003, when compared to the same period of 2002. The increase was primarily due to higher depreciation expense associated with bulk terminal capital spending made since the end of September 2002, largely related to capital improvements made in cement handling operations at our Shipyard River terminal in Charleston, South Carolina. Segment Operating Statistics Operating statistics for the first nine months of 2003 and 2002 are as follows (historical pro forma for acquired assets): 50 Nine Months Ended ------------------------------- Sept. 30, 2003 Sept. 30, 2002 -------------- -------------- Products Pipelines Gasoline (MMBbl)......................... 335.8 350.5 Diesel (MMBbl)........................... 119.1 113.1 Jet Fuel (MMBbl)......................... 82.1 86.2 ------ ------ Total Refined Product Volumes (MMBbl).... 537.0 549.8 Natural Gas Liquids (MMBbl).............. 30.6 30.5 ------ ------ Total Delivery Volumes (MMBbl) (1)....... 567.6 580.3 Natural Gas Pipelines (2) Transport Volumes (Bcf) ................. 935.7 832.9 Sales Volumes (Bcf) (3).................. 677.8 679.0 CO2 Pipelines Delivery Volumes (Bcf) (4)............... 336.1 326.8 SACROC Oil Production (MBbl/d) .......... 19.2 12.3 Realized Weighted Average Oil Price per Bbl (5)................................. $ 24.09 $ 22.46 Terminals Bulk Terminals Transload Tonnage (MMtons) (6)........ 42.4 44.3 Liquids Terminals Leaseable Capacity (MMBbl)............ 36.0 35.0 Liquids Utilization %................. 96.0% 97.0% 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 Intrastate group and Trailblazer pipeline volumes. (3) First quarter 2002 includes sales volumes under prior management, which may not be comparable. (4) Includes Cortez, Central Basin, Canyon Reef Carriers and Centerline pipeline volumes. (5) Includes all partnership crude oil properties. (6) 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 nine months of 2003, the negative impact of these items was partially offset by a $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 $242.4 million in the first nine month period of 2003 and $223.9 million in the same prior year period. Our general and administrative expenses totaled $104.4 million in the first nine months of 2003 compared with $87.2 million in the same period last year. The $17.2 million (20%) year-over-year increase in general and administrative expenses primarily related to higher legal fees, higher employee benefit and pension costs, and higher corporate and worker-related insurance expenses. Total interest expense, net of interest income, was $134.6 million in the first nine months of 2003 versus $129.2 million in the same year-ago period. The $5.4 million (4%) increase in period-to-period net interest charges was due to higher average borrowings during the first nine months of 2003, partially offset by lower average interest rates in the first nine months of 2003 compared with the same period last year. Minority interest totaled $6.9 million in the first nine months of 2003, compared to $7.5 million in the first nine months of 2002. The $0.6 million (8%) decrease resulted primarily from our May 2002 acquisition of the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company that we did not already own, thereby eliminating the minority interest relating to Trailblazer. 51 Financial Condition The following table illustrates the sources of our invested capital. In addition to our results of operations, these balances are affected by our financing activities as discussed below (dollars in thousands):
Sept. 30, 2003 Dec. 31, 2002 -------------- ------------- Long-term debt, excluding market value of interest rate swaps...... $ 3,855,803 $ 3,659,533 Minority interest.................................................. 44,144 42,033 Partners' capital.................................................. 3,569,368 3,415,929 ------------- ------------ Total capitalization............................................ 7,469,315 7,117,495 Short-term debt, less cash and cash equivalents.................... 43,795 (41,088) ------------- ------------ Total invested capital.......................................... $ 7,513,110 $ 7,076,407 ============= ============ Capitalization: -------------- Long-term debt, excluding market value of interest rate swaps.. 51.6% 51.4% Minority interest.............................................. 0.6% 0.6% Partners' capital.............................................. 47.8% 48.0% ----- ----- 100.0% 100.0% ===== ===== Invested Capital: ---------------- Total debt, less cash and cash equivalents and excluding market value of interest rate swaps.............................. 51.9% 51.1% Partners' capital and minority interest........................ 48.1% 48.9% ----- ----- 100.0% 100.0% ===== =====
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: - cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; - 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; - interest payments from cash flows from operating activities; and - 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 institutional investors. As of September 30, 2003, our current commitments for sustaining capital expenditures were approximately $32.5 million. This amount has been committed primarily for the purchase of plant and equipment and is based on the payments we expect to make as part of our 2003 sustaining capital expenditure plan. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. 52 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, tariffs 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 provide assurance 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, future results of operations or future cash flows. Operating Activities Net cash provided by operating activities was $507.3 million for the nine months ended September 30, 2003, versus $546.3 million in the comparable period of 2002. The period-to-period decrease of $39.0 million (7%) in cash flow from operations was primarily the result of a $104.8 million decrease in cash inflows relative to net changes in working capital items and payments of $44.9 million in 2003 for reparations and refunds under order from the Federal Energy Regulatory Commission. The decrease in funds generated by working capital was mainly due to higher settlements of related party payables during the first nine months of 2003, primarily associated with reimbursements to KMI for general and administrative services and for costs related to the construction of our Mier-Monterrey natural gas pipeline. The reparation and refund payment was mandated by the FERC as part of an East line settlement reached in 1999 between shippers and our Pacific operations pursuant to rates charged by our Pacific operations on the interstate portion of their products pipelines. For more information on our Pacific operations' regulatory proceedings, see Note 3 to the Consolidated Financial Statements included elsewhere in this report. These decreases in cash discussed above were partially offset by a $95.4 million increase in cash from overall higher partnership income, net of non-cash items including depreciation charges and undistributed earnings from equity investments. Also, we realized a $13.1 million increase in cash inflows during the first nine months of 2003 versus 2002 relative to changes in other non-current items, principally related to lower payments in 2003 on rate case issues, business development and project costs. Cash from investment distributions increased $2.2 million in 2003, primarily due to higher distributions from our 49% interest in the Red Cedar Gas Gathering Company. Investing Activities Net cash used in investing activities was $464.1 million for the nine month period ended September 30, 2003, compared to $1,218.4 million in the comparable 2002 period. The $754.3 million (62%) decrease in cash used in investing activities was primarily attributable to higher expenditures made for strategic acquisitions in the first nine months of 2002. For the nine months ended September 30, 2002, our acquisition outlays totaled $864.3 million, including $723.2 million for Kinder Morgan Tejas. For the nine months ended September 30, 2003, our acquisition payments totaled $50.7 million, including $23.3 million used to acquire an additional 12.75% ownership interest in the SACROC oil field unit in West Texas. Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership interest in the SACROC unit for $23.3 million in cash and the assumption of $1.9 million of liabilities. This transaction increased our ownership interest in the SACROC unit to approximately 97%. Additionally, in September 2003, we paid $10.0 million to acquire reversionary interests in the Red Cedar Gas Gathering Company. The 4% reversionary interests were held by the Southern Ute Indian Tribe and were scheduled to take effect September 1, 2004 and September 1, 2009. With the elimination of these reversions, our ownership interest in Red Cedar will be maintained at 49% in the future. For more information on our acquisitions, see Note 2 to the Consolidated Financial Statements included elsewhere in this report. Offsetting the period-to-period decreases in funds used in investing activities discussed above was a $70.7 million increase in funds used for capital expenditures. Including expansion and maintenance projects, our capital expenditures were $413.2 million in the first nine months of 2003 versus $342.5 million in the same year-ago period. The increase was mainly due to higher capital investment in our CO2 Pipelines and Products Pipelines business segments. Our sustaining capital expenditures were $62.4 million for the first nine months of 2003 compared to $52.3 million for the first nine months of 2002. 53 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 carbon dioxide flooding and terminaling operations. In October 2003, we started construction on our $30 million investment project that involves the construction of pipeline, compression and storage facilities to accommodate an additional six billion cubic feet of natural gas storage capacity at Kinder Morgan Interstate Gas Transmission's Cheyenne Market Center. The Cheyenne Market Center offers firm natural gas storage capabilities that will allow for the receipt, storage and subsequent re-delivery of natural gas supplies at applicable points located in the vicinity of the Cheyenne Hub in Weld County, Colorado and our Huntsman storage facility in Cheyenne County, Nebraska. Financing Activities Net cash used in financing activities amounted to $41.8 million for the nine months ended September 30, 2003. In the same nine month period last year, our financing activities provided $671.7 million. The $713.5 million decrease from the comparable 2002 period was primarily the result of a $490.8 million decrease in cash flows from overall debt financing activities and a $157.3 million decrease in cash flows from partnership equity issuances. Both decreases were related to our higher acquisition expenditures during 2002, as described above in our discussion of Investing Activities. We purchased the pipeline and terminal businesses primarily with borrowings under our commercial paper program. We then raised funds by completing public and private debt offerings of senior notes and by issuing additional i-units. We used the proceeds from these debt and equity issuances to reduce our borrowings under our commercial paper program. During the first nine months of 2002, we closed a public offering of $750 million in principal amount of senior notes, completed a private placement of $750 million in principal amount of senior notes to qualified institutional buyers and retired a maturing amount of $200 million in principal amount of senior notes. We also made payments of $55.0 million to retire the outstanding balance on our Trailblazer Pipeline Company's two-year revolving credit facility and used $458.4 million to reduce our commercial paper borrowings. During the first nine months of 2003, we have borrowed an additional $286.9 million under our commercial paper program and we have used these funds for our asset acquisitions, capital expansion projects and other partnership activities. The period-to-period decrease in cash flows from equity financing activities primarily relates to the difference in cash received from our June 2003 issuance of common units and our August 2002 issuance of i-units. In June 2003, we issued in a public offering, 4,600,000 of our common units at a price of $39.35 per share, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $173.3 million for the issuance of these common units. In August 2002, we issued 12,478,900 i-units to KMR at a price of $27.50 per share, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $331.2 million for the issuance of these i-units. We used the proceeds from each of these issuances to reduce the borrowings under our commercial paper program. The overall decrease in funds provided by our financing activities also resulted from a $74.0 million increase in distributions to our partners. Distribution to all partners increased to $500.7 million in the first nine months of 2003 compared to $426.7 million in the same year-earlier period. The increase in distributions was due to: - an increase in the per unit cash distributions paid; - an increase in the number of units outstanding; and - 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 August 14, 2003, we paid a quarterly distribution of $0.65 per unit for the second quarter of 2003, 7% greater than the $0.61 per unit distribution paid for the second quarter of 2002. We paid this distribution in cash to our common unitholders and to our class B unitholders. KMR, our sole i-unitholder, received 811,878 additional i-units based on the $0.65 cash distribution per common unit. For each outstanding i-unit that KMR held, a fraction (0.017138) of an i-unit was issued. The fraction was determined by dividing: 54 - $0.65, the cash amount distributed per common unit by - $37.927, 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. On October 15, 2003, we declared a cash distribution for the quarterly period ended September 30, 2003, of $0.66 per unit. The distribution will be paid on or before November 14, 2003, to unitholders of record as of October 31, 2003. Our common unitholders and Class B unitholders will receive cash. KMR, our sole i-unitholder, will receive a distribution in the form of additional i-units based on the $0.66 distribution per common unit. The number of i-units distributed will be 811,625. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.016844) will be issued. The fraction was determined by dividing: - $0.66, the cash amount distributed per common unit by - $39.184, the average of KMR's limited liability shares' closing market prices from October 15-28, 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. 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: 55 - 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; - 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; - 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 - 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. Our general partner's incentive distribution for the distribution that we declared for the third quarter of 2003 was $81.8 million. Our general partner's incentive distribution for the distribution that we declared for the third quarter of 2002 was $69.5 million. Our general partner's incentive distribution that we paid during the third quarter of 2003 to our general partner (for the second quarter of 2003) was $79.6 million. Our general partner's incentive distribution that we paid during the third quarter of 2002 to our general partner (for the second quarter of 2002) was $64.4 million. All partnership distributions we declare for the fourth quarter of each year are declared and paid in the first quarter of the following year. There have been no material changes in either certain contractural obligations or our obligations with respect to other entities which are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2002 in our 2002 Form 10-K report. 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: - price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, coal and other bulk materials and chemicals in the United States; - economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand; - changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission; - our ability to integrate any acquired operations into our existing operations; - our ability to acquire new businesses and assets and to make expansions to our facilities; - difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to our terminals or pipelines; 56 - our ability to successfully identify and close acquisitions and make cost-saving changes in operations; - shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use or supply our services; - 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; - 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; - 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; - interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes; - acts of nature, sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits; - the condition of the capital markets and equity markets in the United States; - the political and economic stability of the oil producing nations of the world; - national, international, regional and local economic, competitive and regulatory conditions and developments; - the ability to achieve cost savings and revenue growth; - rates of inflation; - interest rates; - the pace of deregulation of retail natural gas and electricity; - foreign exchange fluctuations; - the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products; and - 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. 57 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. As of the end of the quarter ended September 30, 2003, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 58 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. Corporate Governance In October 2003, the boards of directors of KMR and our general partner took a number of corporate governance actions, including: - establishing the position of Lead Director and electing Mr. Perry M. Waughtal to serve a one-year term in that position; - establishing a separate Nominating and Governance Committee; and - adopting a number of committee charters and policies intended to comply with the Sarbanes-Oxley Act of 2002 and other expected Securities and Exchange Commission and New York Stock Exchange requirements. 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. 31.1 -- Certification by CEO pursuant to Rule 13A-14 or 15D of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 -- Certification by CFO pursuant to Rule 13A-14 or 15D of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 59 32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. --------------------- (b) Reports on Form 8-K Current report dated August 4, 2003 on Form 8-K was furnished on August 5, 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 August 5, 2003 and August 6, 2003 at various meetings with investors, analysts and others to discuss the second quarter 2003 and second quarter year-to-date 2003 financial results, business plans and objectives of us, Kinder Morgan, Inc. and Kinder Morgan Management, LLC. Notice was also given that prior to the meeting, interested parties would be able to view the materials presented at the meetings by visiting Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com/ investor/presentations. Current report dated September 16, 2003 on Form 8-K was furnished on September 16, 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 September 17, 2003, at various meetings with investors, analysts and others, and on September 18, 2003, at the Merrill Lynch Power & Gas Leaders Conference, to discuss the second quarter 2003 and second quarter year-to-date 2003 financial results, business plans and objectives of us, Kinder Morgan, Inc. and Kinder Morgan Management, LLC. Notice was also given that prior to the meeting, interested parties would be able to view the materials presented at the meetings by visiting Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com/ investor/presentations. Current report dated October 21, 2003 on Form 8-K was furnished on October 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 discuss and answer questions related to our carbon dioxide business in a live webcast. Interested parties would be able to access the webcast by visiting: http://www.firstcallevents.com/ service/ajwz391859932gf12.html. The webcast began at 4:30 p.m. E.S.T on October 21, 2003, and is archived at Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com and at: http://www.prnewswire.com. 60 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: November ___, 2003 61