10-Q 1 km-form10q_7128584.txt F O R M 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2006 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X] The Registrant had 157,019,676 common units outstanding as of April 28, 2006. 1 KINDER MORGAN ENERGY PARTNERS, L.P. TABLE OF CONTENTS Page Number PART I. FINANCIAL INFORMATION Item 1: Financial Statements (Unaudited).................................. 3 Consolidated Statements of Income-Three Months Ended March 31, 2006 and 2005....................................... 3 Consolidated Balance Sheets - March 31, 2006 and December 31, 2005............................................. 4 Consolidated Statements of Cash Flows - Three Months Ended March 31, 2006 and 2005................................. 5 Notes to Consolidated Financial Statements...................... 6 Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations............................. 52 Critical Accounting Policies and Estimates...................... 52 Results of Operations........................................... 52 Financial Condition............................................. 65 Information Regarding Forward-Looking Statements................ 72 Item 3: Quantitative and Qualitative Disclosures About Market Risk........ 74 Item 4: Controls and Procedures........................................... 74 PART II. OTHER INFORMATION Item 1: Legal Proceedings................................................. 75 Item 1A: Risk Factors...................................................... 75 Item 2: Unregistered Sales of Equity Securities and Use of Proceeds....... 75 Item 3: Defaults Upon Senior Securities................................... 75 Item 4: Submission of Matters to a Vote of Security Holders............... 75 Item 5: Other Information................................................. 75 Item 6: Exhibits.......................................................... 75 Signature......................................................... 77 2 PART I. FINANCIAL INFORMATION Item 1. Financial Statements. KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Thousands Except Per Unit Amounts) (Unaudited) Three Months Ended March 31, ------------ --------------- 2006 2005 ---------- --------------- Revenues Natural gas sales................................... $1,691,392 $1,352,615 Services............................................ 509,502 443,425 Product sales and other............................. 190,707 175,892 ---------- ---------- 2,391,601 1,971,932 ---------- ---------- Costs and Expenses Gas purchases and other costs of sales.............. 1,677,231 1,337,770 Operations and maintenance.......................... 173,382 138,540 Fuel and power...................................... 50,923 41,940 Depreciation, depletion and amortization............ 92,721 85,027 General and administrative.......................... 60,883 73,852 Taxes, other than income taxes...................... 31,267 25,826 ---------- ---------- 2,086,407 1,702,955 ---------- ---------- Operating Income...................................... 305,194 268,977 Other Income (Expense) Earnings from equity investments.................... 24,721 26,072 Amortization of excess cost of equity investments... (1,414) (1,417) Interest, net....................................... (75,706) (58,727) Other, net.......................................... 1,775 (1,321) Minority Interest..................................... (2,370) (2,388) ---------- ---------- Income Before Income Taxes............................ 252,200 231,196 Income Taxes.......................................... (5,491) (7,575) ---------- ---------- Net Income............................................ $ 246,709 $ 223,621 -========= ========== General Partner's interest in Net Income.............. $ 129,528 $ 111,727 Limited Partners' interest in Net Income.............. 117,181 111,894 ---------- ---------- Net Income............................................ $ 246,709 $ 223,621 ========== ========== Basic and Diluted Limited Partners' Net Income per $ 0.53 $ 0.54 ========== ========== Unit.................................................. Weighted average number of units used in computation of Limited Partners' Net Income per unit: Basic................................................. 220,753 207,528 ========== ========== Diluted............................................... 221,080 207,584 ========== ========== Per unit cash distribution declared................... $ 0.81 $ 0.76 ========== ========== The accompanying notes are an integral part of these consolidated financial statements. 3 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Thousands) (Unaudited) March 31, December 31, --------- ------------ 2006 2005 ---- ---- ASSETS Current Assets Cash and cash equivalents........................ $ 32,636 $ 12,108 Restricted deposits.............................. 33,100 - Accounts, notes and interest receivable, net Trade......................................... 784,806 1,011,716 Related parties............................... 3,659 2,543 Inventories Products...................................... 15,367 18,820 Materials and supplies........................ 13,851 13,292 Gas imbalances Trade......................................... 13,781 18,220 Related parties............................... 3,111 - Gas in underground storage....................... 45,616 7,074 Other current assets............................. 93,177 131,451 ----------- ----------- 1,039,104 1,215,224 ----------- ----------- Property, Plant and Equipment, net................. 9,210,903 8,864,584 Investments........................................ 434,684 419,313 Notes receivable Trade............................................ 1,438 1,468 Related parties.................................. 92,003 109,006 Goodwill........................................... 798,959 798,959 Other intangibles, net............................. 216,588 217,020 Deferred charges and other assets.................. 227,572 297,888 ----------- ----------- Total Assets....................................... $12,021,251 $11,923,462 =========== =========== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Cash book overdrafts....................... $ 42,198 $ 30,408 Trade...................................... 681,252 996,174 Related parties............................ 5,370 16,676 Current portion of long-term debt............. - - Accrued interest.............................. 42,898 74,886 Accrued taxes................................. 40,862 23,536 Deferred revenues............................. 12,281 10,523 Gas imbalances Trade...................................... 13,189 22,948 Related parties............................ - 1,646 Accrued other current liabilities............. 643,703 632,088 ----------- ----------- 1,481,753 1,808,885 ----------- ----------- Long-Term Liabilities and Deferred Credits Long-term debt Outstanding................................ 5,704,920 5,220,887 Market value of interest rate swaps........ 10,239 98,469 ----------- ----------- 5,715,159 5,319,356 Deferred revenues............................. 5,846 6,735 Deferred income taxes......................... 70,632 70,343 Asset retirement obligations.................. 42,721 42,417 Other long-term liabilities and deferred credits 1,086,598 1,019,655 ----------- ----------- 6,920,956 6,458,506 ----------- ----------- Commitments and Contingencies (Note 3) Minority Interest............................... 131,087 42,331 ----------- ----------- Partners' Capital Common Units.................................. 2,638,137 2,680,352 Class B Units................................. 108,165 109,594 i-Units....................................... 1,814,526 1,783,570 General Partner............................... 122,021 119,898 Accumulated other comprehensive loss.......... (1,195,394) (1,079,674) ----------- ----------- 3,487,455 3,613,740 ----------- ----------- Total Liabilities and Partners' Capital......... $12,021,251 $11,923,462 =========== =========== 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) Three Months Ended March 31, ---------------------- 2006 2005 ---------- ---------- Cash Flows From Operating Activities Net income............................................ $ 246,709 $ 223,621 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization............ 92,721 85,027 Amortization of excess cost of equity investments... 1,414 1,417 Earnings from equity investments.................... (24,721) (26,072) Distributions from equity investments................. 22,378 13,386 Changes in components of working capital: Accounts receivable................................. 236,029 49,284 Other current assets................................ (22,329) (10,239) Inventories......................................... 2,898 (2,245) Accounts payable.................................... (326,208) (95,343) Accrued liabilities................................. (44,324) (12,429) Accrued taxes....................................... 17,397 15,636 Other, net............................................ (25,950) 17,464 ---------- ---------- Net Cash Provided by Operating Activities............... 176,014 259,507 ---------- ---------- Cash Flows From Investing Activities Acquisitions of assets................................ (240,000) (6,476) Additions to property, plant and equip. for expansion and maintenance projects.................... (193,663) (143,808) Sale of investments, property, plant and equipment, net of removal costs.................................. (272) 2,900 Investments in margin deposits........................ (33,100) (18,096) Contributions to equity investments................... (2) (18) Natural gas stored underground and natural gas liquids line-fill..................................... (9,833) (1,905) Other................................................. (2,988) (588) ---------- ---------- Net Cash Used in Investing Activities................... (479,858) (167,991) ---------- ---------- Cash Flows From Financing Activities Issuance of debt...................................... 1,148,000 1,327,433 Payment of debt....................................... (664,267) (1,182,630) Debt issue costs...................................... (450) (4,477) Increase (Decrease) in cash book overdrafts........... 11,789 (8,560) Proceeds from issuance of common units................ 83 1,167 Contributions from minority interest.................. 91,043 409 Distributions to partners: Common units........................................ (125,873) (109,191) Class B units....................................... (4,251) (3,932) General Partner..................................... (127,405) (107,585) Minority interest................................... (3,477) (2,761) Other, net............................................ (838) (1,389) ---------- ---------- Net Cash Provided by (Used in) Financing Activities..... 324,354 (91,516) ---------- ---------- Effect of exchange rate changes on cash and cash equivalents............................................. 18 -- ---------- ---------- Increase (Decrease) in Cash and Cash Equivalents........ 20,528 -- Cash and Cash Equivalents, beginning of period.......... 12,108 -- ---------- ---------- Cash and Cash Equivalents, end of period................ $ 32,636 $ -- ========== ========== Noncash Investing and Financing Activities: Contribution of net assets to partnership investments........................................... $ 17,003 $ -- Assets acquired by the assumption of liabilities...... $ -- $ 284 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 which are solely normal and recurring 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, 2005. Kinder Morgan, Inc., Kinder Morgan G.P., 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 our business and affairs, except that Kinder Morgan Management, LLC cannot take certain specified actions without the approval of our general partner. Under the delegation of control agreement, Kinder Morgan Management, LLC manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Furthermore, in accordance with its limited liability company agreement, Kinder Morgan Management, LLC's 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 operating partnerships and their majority-owned and controlled subsidiaries. All significant intercompany items have been eliminated in consolidation. 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 maximum potential dilution that could occur if units whose issuance depends on the market price of the units at a future date were considered outstanding, or if, by application of the treasury stock method, options to issue units were exercised, both of which would result in the issuance of additional units that would then share in our net income. 6 2. Acquisitions and Joint Ventures During the first three months of 2006, we completed the following acquisition. The acquisition was accounted for under the purchase method and the assets acquired were recorded at their estimated fair market values as of the acquisition date. The preliminary allocation of assets (and any liabilities assumed) may be adjusted to reflect the final determined amounts during a period of time following the acquisition. The results of operations from this acquisition are included in our consolidated financial statements from the acquisition date. Entrega Gas Pipeline LLC Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega Gas Pipeline LLC from EnCana Corporation for $240.0 million in cash. We contributed $160.0 million, which corresponded to our 66 2/3% ownership interest in Rockies Express Pipeline LLC. Sempra Energy holds the remaining 33 1/3% ownership interest and contributed $80.0 million. At the time of acquisition, Entegra Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas pipeline that will consist of two segments: (i) a 136-mile, 36-inch diameter pipeline that extends from the Meeker Hub in Rio Blanco County, Colorado to the Wamsutter Hub in Sweetwater County, Wyoming, and (ii) a 191-mile, 42-inch diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in Weld County, Colorado, where it will ultimately connect with our Rockies Express Pipeline, an interstate natural gas pipeline that, at the time of acquisition, was being developed by Rockies Express Pipeline LLC. In combination, the Entrega and Rockies Express pipelines have the potential to create a major new natural gas transmission pipeline that will provide seamless transportation of natural gas from Rocky Mountain production areas to Midwest and eastern Ohio markets. EnCana Corporation completed construction of the first segment of the Entrega Pipeline and interim service has begun. Under the terms of the purchase and sale agreement, we and Sempra will construct the second segment of the Entrega Pipeline, and construction is scheduled to begin this summer. It is anticipated that the entire Entrega system will be placed into service by January 1, 2007. In April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline LLC. Going forward, the entire pipeline system will be known as the Rockies Express Pipeline. Also in April 2006, we paid EnCana approximately $4.6 million in cash as consideration for purchase prince adjustments recognized in the second quarter of 2006. As of March 31, 2006, our allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.......... $ 240,000 Liabilities assumed............................. -- --------- Total purchase price............................ $ 240,000 ========= Allocation of purchase price: Current assets.................................. $ -- Property, plant and equipment................... 240,000 Deferred charges and other assets............... -- --------- $ 240,000 Pro Forma Information The following summarized unaudited pro forma consolidated income statement information for the three months ended March 31, 2006 and 2005, assumes that all of the acquisitions we have made and joint ventures we have entered into since January 1, 2005, including the one listed above, had occurred as of the beginning of the period presented. 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 and joint ventures as of January 1, 2005 or the results that will be attained in the future. Amounts presented below are in thousands, except for the per unit amounts: 7 Pro Forma Three Months Ended March 31, ---------------------------- 2006 2005 ------------ ------------- (Unaudited) Revenues.......................................... $ 2,398,260 $ 2,004,783 Operating Income.................................. 305,331 277,706 Net Income........................................ $ 245,656 $ 228,690 Basic Limited Partners' Net Income per unit....... $ 0.53 $ 0.56 Diluted Limited Partners' Net Income per unit..... $ 0.53 $ 0.56 Acquisitions Subsequent to March 31, 2006 Oil and Gas Properties On April 7, 2006, Kinder Morgan Production Company L.P. purchased various oil and gas properties from Journey Acquisition - I, L.P. and Journey 2000, L.P. The acquisition was made effective March 1, 2006. The properties are primarily located in the Permian Basin area of West Texas, produce approximately 850 barrels of oil equivalent per day net, and include some fields with enhanced oil recovery development potential near our current carbon dioxide operations. The acquired operations are included as part of our CO2 business segment. During the next several months, we will perform technical evaluations to confirm the carbon dioxide enhanced oil recovery potential and generate definitive plans to develop this potential if proven to be economic. The purchase price plus the anticipated investment to both further develop carbon dioxide enhanced oil recovery and construct a new carbon dioxide supply pipeline on all of the acquired properties is approximately $115 million. However, since we intend to divest in the near future those acquired properties that are not candidates for carbon dioxide enhanced oil recovery, our total investment is likely to be considerably less. April 2006 Terminal Assets In April 2006, we acquired terminal assets and operations from A&L Trucking, L.P. and U.S. Development Group in three separate transactions for an aggregate consideration of approximately $61.9 million, consisting of $61.6 million in cash and $0.3 million in assumed liabilities. The first transaction included the acquisition of equipment and infrastructure on the Houston Ship Channel that loads and stores steel products. The acquired assets complement our nearby bulk terminal facility purchased from General Stevedores, L.P. in July 2005. The second acquisition included the purchase of a rail terminal at the Port of Houston that handles both bulk and liquids products. The rail terminal complements our existing Texas petroleum coke terminal operations and maximizes the value of our existing deepwater terminal by providing customers with both rail and vessel transportation options for bulk products. Thirdly, we acquired the entire membership interest of Lomita Rail Terminal LLC, a limited liability company that owns a high-volume rail ethanol terminal in Carson, California. The terminal serves approximately 80% of the southern California demand for reformulated fuel blend ethanol with expandable offloading/distribution capacity, and the acquisition expanded our existing rail transloading operations. All of the acquired assets are included in our Terminals business segment. We will allocate our total purchase price to assets acquired and liabilities assumed in the second quarter of 2006, and we expect to assign approximately $17.6 million of goodwill to our Terminals business segment. 3. Litigation, Environmental and Other Contingencies Federal Energy Regulatory Commission Proceedings SFPP, L.P. SFPP, L.P., referred to in this report 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, including shippers' complaints regarding interstate rates on our Pacific operations' pipeline systems. 8 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 this proceeding. 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 "substantially changed circumstances" with respect to those rates and that the rates 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 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 "substantially 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. 9 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. We made aggregate payments of $44.9 million in 2003 for reparations and refunds pursuant to a FERC order. Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond Shamrock Corporation (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, and oral argument took place on November 12, 2003. On July 20, 2004, the Court of Appeals issued its opinion in BP West Coast Products, LLC v. Federal Energy Regulatory Commission, No. 99-1020, On Petitions for Review of Orders of the Federal Energy Regulatory Commission (Circuit opinion), addressing in part the tariffs of SFPP, L.P. Among other things, the court's opinion vacated the income tax allowance portion of the FERC opinion and the order allowing recovery in SFPP's rates for income taxes and remanded to the FERC this and other matters for further proceedings consistent with the court's opinion. In reviewing a series of FERC orders involving SFPP, the Court of Appeals held, among other things, that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its limited partnership interests owned by corporate partners. By its terms, the portion of the opinion addressing SFPP only pertained to SFPP, L.P. and was based on the record in that case. The Court of Appeals held that, in the context of the Docket No. OR92-8, et al. proceedings, all of SFPP's West Line rates were grandfathered other than the charge for use of SFPP's Watson Station gathering enhancement facility and the rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded that the FERC had a reasonable basis for concluding that the addition of a West Line origin point at East Hynes, California did not involve a new "rate" for purposes of the Energy Policy Act. It rejected arguments from West Line Shippers that certain protests and complaints had challenged West Line rates prior to the enactment of the Energy Policy Act. The Court of Appeals also held that complainants had failed to satisfy their burden of demonstrating substantially changed circumstances, and therefore could not challenge grandfathered West Line rates in the Docket No. OR92-8 et al. proceedings. It specifically rejected arguments that other shippers could "piggyback" on the special Energy Policy Act exception permitting Navajo to challenge grandfathered West Line rates, which Navajo had withdrawn under a settlement with SFPP. The court remanded to the FERC the changed circumstances issue "for further consideration" in light of the court's decision regarding SFPP's tax allowance. While, the FERC had previously held in the OR96-2 proceeding (discussed following) that the tax allowance policy should not be used as a stand-alone factor in determining when there have been substantially changed circumstances, the FERC's May 4, 2005 income tax allowance policy statement (discussed following) may affect how the FERC addresses the changed circumstances and other issues remanded by the court. The Court of Appeals upheld the FERC's rulings on most East Line rate issues; however, it found the FERC's reasoning inadequate on some issues, including the tax allowance. The Court of Appeals held the FERC had sufficient evidence to use SFPP's December 1988 stand-alone capital structure to calculate its starting rate base as of June 1985; however, it rejected SFPP arguments that would have resulted in a higher starting rate base. The Court of Appeals accepted the FERC's treatment of regulatory litigation costs, including the limitation of recoverable costs and their offset against "unclaimed reparations" - that is, reparations that could have been awarded to parties that did not seek them. The court also accepted the FERC's denial of any recovery for the costs of civil litigation by East Line shippers against SFPP based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix. However, the court did not find adequate support for the FERC's decision to allocate the limited litigation costs that SFPP was allowed to recover in its rates equally between the East Line and the West Line, and ordered the FERC to explain that decision further on remand. 10 The Court of Appeals held the FERC had failed to justify its decision to deny SFPP any recovery of funds spent to recondition pipe on the East Line, for which SFPP had spent nearly $6 million between 1995 and 1998. It concluded that the Commission's reasoning was inconsistent and incomplete, and remanded for further explanation, noting that "SFPP's shippers are presently enjoying the benefits of what appears to be an expensive pipeline reconditioning program without sharing in any of its costs." The Court of Appeals affirmed the FERC's rulings on reparations in all respects. It held the Arizona Grocery doctrine did not apply to orders requiring SFPP to file "interim" rates, and that "FERC only established a final rate at the completion of the OR92-8 proceedings." It held that the Energy Policy Act did not limit complainants' ability to seek reparations for up to two years prior to the filing of complaints against rates that are not grandfathered. It rejected SFPP's arguments that the FERC should not have used a "test period" to compute reparations that it should have offset years in which there were underrecoveries against those in which there were overrecoveries, and that it should have exercised its discretion against awarding any reparations in this case. The Court of Appeals also rejected: o Navajo's argument that its prior settlement with SFPP's predecessor did not limit its right to seek reparations; o Valero's argument that it should have been permitted to recover reparations in the Docket No. OR92-8 et al. proceedings rather than waiting to seek them, as appropriate, in the Docket No. OR96-2 et al. proceedings; o arguments that the former ARCO and Texaco had challenged East Line rates when they filed a complaint in January 1994 and should therefore be entitled to recover East Line reparations; and o Chevron's argument that its reparations period should begin two years before its September 1992 protest regarding the six-inch line reversal rather than its August 1993 complaint against East Line rates. On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips and ExxonMobil filed a petition for rehearing and rehearing en banc asking the Court of Appeals to reconsider its ruling that West Line rates were not subject to investigation at the time the Energy Policy Act was enacted. On September 3, 2004, SFPP filed a petition for rehearing asking the court to confirm that the FERC has the same discretion to address on remand the income tax allowance issue that administrative agencies normally have when their decisions are set aside by reviewing courts because they have failed to provide a reasoned basis for their conclusions. On October 4, 2004, the Court of Appeals denied both petitions without further comment. On November 2, 2004, the Court of Appeals issued its mandate remanding the Docket No. OR92-8 proceedings to the FERC. SFPP and shipper parties subsequently filed various pleadings with the FERC regarding the proper nature and scope of the remand proceedings. On December 2, 2004, the FERC issued a Notice of Inquiry and opened a new proceeding (Docket No. PL05-5) to consider how broadly the court's ruling on the tax allowance issue in BP West Coast Products, LLC, v. FERC should affect the range of entities the FERC regulates. The FERC sought comments on whether the court's ruling applies only to the specific facts of the SFPP proceeding, or also extends to other capital structures involving partnerships and other forms of ownership. Comments were filed by numerous parties, including our Rocky Mountain natural gas pipelines, in the first quarter of 2005. On May 4, 2005, the FERC adopted a policy statement in Docket No. PL05-5, providing that all entities owning public utility assets - oil and gas pipelines and electric utilities - would be permitted to include an income tax allowance in their cost-of-service rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. Any tax pass-through entity seeking an income tax allowance would have to establish that its partners or members have an actual or potential income tax obligation on the entity's public utility income. The FERC expressed the intent to implement its policy in individual cases as they arise. On December 17, 2004, the Court of Appeals issued orders directing that the petitions for review relating to FERC orders issued after November 2001 in OR92-8, which had previously been severed from the main Court of Appeals docket, should continue to be held in abeyance pending completion of the remand proceedings before the FERC. Petitions for review of orders issued in other FERC dockets have since been returned to the court's active docket (discussed further below in relation to the OR96-2 proceedings). 11 On January 3, 2005, SFPP filed a petition for a writ of certiorari asking the United States Supreme Court to review the Court of Appeals' ruling that the Arizona Grocery doctrine does not apply to "interim" rates, and that "FERC only established a final rate at the completion of the OR92-8 proceedings." BP West Coast Products and ExxonMobil also filed a petition for certiorari, on December 30, 2004, seeking review of the Court of Appeals' ruling that there was no pending investigation of West Line rates at the time of enactment of the Energy Policy Act (and thus that those rates remained grandfathered). On April 6, 2005, the Solicitor General filed a brief in opposition to both petitions on behalf of the FERC and United States, and Navajo, ConocoPhillips, Ultramar, Valero and Western Refining filed an opposition to SFPP's petition. SFPP filed a reply to those briefs on April 18, 2005. On May 16, 2005, the Supreme Court issued orders denying the petitions for certiorari filed by SFPP and by BP West Coast Products and ExxonMobil. On June 1, 2005, the FERC issued its Order on Remand and Rehearing, which addressed issues in both the OR92-8 and OR96-2 proceedings (discussed following). With respect to the OR92-8 proceedings, the June 1, 2005 order ruled on several issues that had been remanded by the Court of Appeals in BP West Coast Products. With respect to the income tax allowance, the FERC held that its May 4, 2005 policy statement would apply in the OR92-8 and OR96-2 proceedings and that SFPP "should be afforded an income tax allowance on all of its partnership interests to the extent that the owners of those interests had an actual or potential tax liability during the periods at issue." It directed SFPP and opposing parties to file briefs regarding the state of the existing record on those questions and the need for further proceedings. Those filings are described below in the discussion of the OR96-2 proceedings. The FERC held that SFPP's allowable regulatory litigation costs in the OR92-8 proceedings should be allocated between the East Line and the West Line based on the volumes carried by those lines during the relevant period. In doing so, it reversed its prior decision to allocate those costs between the two lines on a 50-50 basis. The FERC affirmed its prior decision to exclude SFPP's pipeline reconditioning costs from the cost of service in the OR92-8 proceedings, but stated that SFPP will have an opportunity to justify much of those reconditioning expenses in the OR96-2 proceedings. The FERC deferred further proceedings on the non-grandfathered West Line turbine fuel rate until completion of its review of the initial decision in phase two of the OR96-2 proceedings. The FERC held that SFPP's contract charge for use of the Watson Station gathering enhancement facilities was not grandfathered and required further proceedings before an administrative law judge to determine the reasonableness of that charge; those proceedings are currently in settlement negotiations before a FERC settlement judge. Petitions for review of the June 1, 2005 order by the United States Court of Appeals for the District of Columbia Circuit have been filed by SFPP, Navajo, Western Refining, BP West Coast Products, ExxonMobil, Chevron, ConocoPhillips, Ultramar and Valero. SFPP has moved to intervene in the review proceedings brought by the other parties. A briefing schedule has been set by the Court, with initial briefs due May 30, 2006 and final briefs filed October 11, 2006. On December 16, 2005, the FERC issued its Order on Initial Decision and on Certain Remanded Cost Issues, which provided further guidance regarding application of the FERC's income tax allowance policy in this case, which is discussed below in connection with the OR96-2 proceedings. The December 16, 2005 order required SFPP to submit a revised East Line cost of service filing following FERC's rulings regarding the income tax allowance and the ruling in its June 1, 2005 order regarding the allocation of litigation costs. SFPP is required to file interim East Line rates effective May 1, 2006 using the lower of the revised OR92-8 (1994 test year) or OR96-2 (1999 test year) rates, as adjusted for indexing through April 30, 2006. The December 16, 2005 order also required SFPP to calculate costs-of-service for West Line turbine fuel movements based on both a 1994 and 1999 test year and to file interim turbine fuel rates to be effective May 1, 2006, using the lower of the two test year rates as indexed through April 30, 2006. SFPP was further required to calculate estimated reparations for complaining shippers consistent with the order. As described further below, various parties filed requests for rehearing and petitions for review of the December 16, 2005 order. Sepulveda proceedings. In December 1995, Texaco filed a complaint at the FERC (Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipeline (Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject to the FERC's jurisdiction under the Interstate Commerce Act, and claimed that the rate 12 for that service was unlawful. Several other West Line shippers filed similar complaints and/or motions to intervene. In an August 1997 order, the FERC held that the movements on the Sepulveda pipeline were subject to its jurisdiction. On October 6, 1997, SFPP filed a tariff establishing the initial interstate rate for movements on the Sepulveda pipeline at 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. In December 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 pipeline is just and reasonable. Hearings in this proceeding were held in February and March 2005. SFPP asserted various defenses against the shippers' claims for reparations and refunds, including the existence of valid contracts with the shippers and grandfathering protection. In August 2005, the presiding administrative law judge issued an initial decision finding that for the period from 1993 to November 1997 (when the Sepulveda FERC tariff went into effect) the Sepulveda rate should have been lower. The administrative law judge recommended that SFPP pay reparations and refunds for alleged overcollections. SFPP filed in October 2005 a brief to the FERC taking exception to this and other portions of the initial decision. OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar Diamond Shamrock Corporation filed a complaint at the 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 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 SFPP's 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 Western 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 in June 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. On March 26, 2004, the FERC issued an order on the phase one initial decision. The FERC's phase one order reversed the initial decision by finding that SFPP's rates for its North and Oregon Lines should remain "grandfathered" and amended the initial decision by finding that SFPP's West Line rates (i) to Yuma, Tucson and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no longer be "grandfathered" and are not just and 13 reasonable. The FERC upheld these findings in its June 1, 2005 order, although it appears to have found substantially changed circumstances as to SFPP's West Line rates on a somewhat different basis than in the phase one order. The FERC's phase one order did not address prospective West Line rates and whether reparations were necessary. As discussed below, those issues have been addressed in the FERC's December 16, 2005 order on phase two issues. The FERC's phase one order also did not address the "grandfathered" status of the Watson Station fee, noting that it would address that issue once it was ruled on by the Court of Appeals in its review of the FERC's Opinion No. 435 orders; as noted above, the FERC held in its June 1, 2005 order that the Watson Station fee is not grandfathered. Several of the participants in the proceeding requested rehearing of the FERC's phase one order. The FERC denied those requests in its June 1, 2005 order. In addition, several participants, including SFPP, filed petitions with the United States Court of Appeals for the District of Columbia Circuit for review of the FERC's phase one order. On August 13, 2004, the FERC filed a motion to dismiss the pending petitions for review of the phase one order, which Petitioners, including SFPP, answered on August 30, 2004. On December 20, 2004, the Court of Appeals referred the FERC's motion to the merits panel and directed the parties to address the issues in that motion on brief, thus effectively dismissing the FERC's motion. In the same order, the Court of Appeals granted a motion to hold the petitions for review of the FERC's phase one order in abeyance and directed the parties to file motions to govern future proceeding 30 days after FERC disposition of the pending rehearing requests. In August 2005, the FERC and SFPP jointly moved that the Court of Appeals hold the petitions for review of the March 26, 2004 and June 1, 2005 orders in abeyance due to the pendency of further action before the FERC on income tax allowance issues. In December 2005, the Court of Appeals denied this motion and placed the petitions seeking review of the two orders on the active docket. The FERC's phase one order also held that SFPP failed to seek authorization for the accounting entries necessary to reflect in SFPP's books, and thus in its annual report to the FERC ("FERC Form 6"), the purchase price adjustment ("PPA") arising from our 1998 acquisition of SFPP. The phase one order directed SFPP to file for permission to reflect the PPA in its FERC Form 6 for the calendar year 1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP noted that it had previously requested such permission and that the FERC's regulations require an oil pipeline to include a PPA in its Form 6 without first seeking FERC permission to do so. Several parties protested SFPP's compliance filing. In its June 1, 2005 order, the FERC accepted SFPP's compliance filing. In the June 1, 2005 order, the FERC directed SFPP to file a brief addressing whether the records developed in the OR92-8 and OR96-2 cases were sufficient to determine SFPP's entitlement to include an income tax allowance in its rates under the FERC's new policy statement. On June 16, 2005, SFPP filed its brief reviewing the pertinent records in the pending cases and applicable law and demonstrating its entitlement to a full income tax allowance in its interstate rates. SFPP's opponents in the two cases filed reply briefs contesting SFPP's presentation. It is not possible to predict with certainty the ultimate resolution of this issue, particularly given the likelihood that the FERC's policy statement and its decision in these cases will be appealed to the federal courts. On September 9, 2004, the presiding administrative law judge in OR96-2 issued his initial decision in the phase two portion of this proceeding, recommending establishment of prospective rates and the calculation of reparations for complaining shippers with respect to the West Line and East Line, relying upon cost of service determinations generally unfavorable to SFPP. On December 16, 2005, the FERC issued an order addressing issues remanded by the Court of Appeals in the Docket No. OR92-8 proceeding (discussed above) and the phase two cost of service issues, including income tax allowance issues arising from the briefing directed by the FERC's June 1, 2005 order. The FERC directed SFPP to submit compliance filings and revised tariffs by February 28, 2006 (as extended to March 7, 2006) which were to address, in addition to the OR92-8 matters discussed above, the establishment of interim West Line rates based on a 1999 test year, indexed forward to a May 1, 2006 effective date and estimated reparations. The FERC also resolved favorably a number of methodological issues regarding the calculation of SFPP's income tax allowance under the May 2005 policy statement and, in its compliance filings, directed SFPP to submit further information establishing the amount of its income tax allowance for the years at issue in the OR92-8 and OR96-2 proceedings. SFPP and Navajo have filed requests for rehearing of the December 16, 2005 order. ExxonMobil, BP West Coast Products, Chevron, Ultramar, and ConocoPhillips have filed petitions for review of the December 16, 2005 order with the United States Court of Appeals for the District of Columbia Circuit. On February 13, 2006, the 14 FERC issued an order addressing the pending rehearing requests, granting the majority of SFPP's requested changes regarding reparations and methodological issues. SFPP, Navajo, and other parties have filed petitions for review of the December 16, 2005 and February 13, 2006 orders with the United States Court of Appeals for the District of Columbia Circuit. On March 7, 2006, SFPP filed its compliance filings and revised tariffs. Various shippers filed protests of the tariffs. On April 21, 2006, various parties submitted comments challenging aspects of the costs of service and rates reflected in the compliance filings and tariffs. On April 28, 2006, the FERC issued an order accepting SFPP's tariffs lowering its West Line and East Line rates in conformity with the FERC's December 2005 and February 2006 orders. On May 1, 2006, these lower tariff rates became effective. The FERC indicated that a subsequent order would address the issues raised in the comments. On May 1, 2006, SFPP filed reply comments. 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 final outcome will depend, in part, on the outcomes of the appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP, complaining shippers, and an intervenor. We estimated, as of December 31, 2003, that shippers' claims for reparations totaled approximately $154 million and that prospective rate reductions would have an aggregate average annual impact of approximately $45 million, with the reparations amount and interest increasing as the timing for implementation of rate reductions and the payment of reparations has extended (estimated at a quarterly increase of approximately $9 million). Based on the December 16, 2005 order, rate reductions will be implemented on May 1, 2006. We now assume that reparations and accrued interest thereon will be paid no earlier than the first quarter of 2007; however, the timing, and nature, of any rate reductions and reparations that may be ordered will likely be affected by the final disposition of the application of the FERC's new policy statement on income tax allowances to our Pacific operations in the FERC Docket Nos. OR92-8 and OR96-2 proceedings. In 2005, we recorded an accrual of $105.0 million for an expense attributable to an increase in our reserves related to our rate case liability. We had previously estimated the combined annual impact of the rate reductions and the payment of reparations sought by shippers would be approximately 15 cents of distributable cash flow per unit. Based on our review of the FERC's December 16, 2005 order and the FERC's February 13, 2006 order on rehearing, and subject to the ultimate resolution of these issues in our compliance filings and subsequent judicial appeals, we now expect the total annual impact will be less than 15 cents per unit. The actual, partial year impact on 2006 distributable cash flow per unit will likely be closer to 5 cents per unit. Chevron complaint OR02-4 and OR03-5 proceedings. On February 11, 2002, Chevron, an intervenor in the Docket No. OR96-2, et al. proceeding, filed a complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate the complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002, the FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a request for rehearing, which the FERC dismissed on September 25, 2002. In October 2002, Chevron filed a request for rehearing of the FERC's September 25, 2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron filed a petition for review of this denial at the U.S. Court of Appeals for the District of Columbia Circuit. On June 30, 2003, Chevron filed another complaint against SFPP (OR03-5) - substantially similar to its previous complaint - and moved to consolidate the complaint with the Docket No. OR96-2, et al. proceeding. Chevron requested that this new complaint be treated as if it were an amendment to its complaint in Docket No. OR02-4, 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. On October 28, 2003, 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 consolidation and for back-dating. On November 21, 2003, Chevron filed a petition for review of the FERC's October 28, 2003 order at the Court of Appeals for the District of Columbia Circuit. On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition for review in OR02-4 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 was pending, when the Court of Appeals, on December 8, 2003, granted Chevron's motion to hold the case in abeyance pending the outcome of the appeal of the Docket No. OR92-8, et al. proceeding. 15 On January 8, 2004, the Court of Appeals granted Chevron's motion to have its appeal of the FERC's decision in OR03-5 consolidated with Chevron's appeal of the FERC's decision in the OR02-4 proceeding. Following motions to dismiss by the FERC and SFPP, on December 10, 2004, the Court dismissed Chevron's petition for review in Docket No. OR03-5 and set Chevron's appeal of the FERC's orders in OR02-4 for briefing. On January 4, 2005, the Court granted Chevron's request to hold such briefing in abeyance until after final disposition of the OR96-2 proceeding. Chevron continues to participate in the Docket No. OR96-2 et al. proceeding as an intervenor. Airlines OR04-3 proceeding. On September 21, 2004, America West Airlines, Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental Airlines, Inc. (collectively, the "Airlines") filed a complaint against SFPP at the FERC. The Airlines' complaint alleges that the rates on SFPP's West Line and SFPP's charge for its gathering enhancement service at Watson Station are not just and reasonable. The Airlines seek rate reductions and reparations for two years prior to the filing of their complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company, L.P., and ChevronTexaco Products Company all filed timely motions to intervene in this proceeding. Valero Marketing and Supply Company filed a motion to intervene one day after the deadline. SFPP answered the Airlines' complaint on October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's answer and on November 12, 2004, SFPP replied to the Airlines' response. In March and June 2005, the Airlines filed motions seeking expedited action on their complaint, and in July 2005, the Airlines filed a motion seeking to sever issues related to the Watson Station gathering enhancement fee from the OR04-3 proceeding and consolidate them in the proceeding regarding the justness and reasonableness of that fee that the FERC docketed as part of the June 1, 2005 order. In August 2005, the FERC granted the Airlines' motion to sever and consolidate the Watson Station fee issues. OR05-4 and OR05-5 proceedings. On December 22, 2004, BP West Coast Products LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC, which the FERC docketed as OR05-4. The complaint alleges that SFPP's interstate rates are not just and reasonable, that certain rates found grandfathered by the FERC are not entitled to such status, and, if so entitled, that "substantially changed circumstances" have occurred, removing such protection. The complainants seek rate reductions and reparations for two years prior to the filing of their complaint and ask that the complaint be consolidated with the Airlines' complaint in the OR04-3 proceeding. ConocoPhillips Company, Navajo Refining Company, L.P., and Western Refining Company, L.P. all filed timely motions to intervene in this proceeding. SFPP answered the complaint on January 24, 2005. On December 29, 2004, ConocoPhillips filed a complaint against SFPP at the FERC, which the FERC docketed as OR05-5. The complaint alleges that SFPP's interstate rates are not just and reasonable, that certain rates found grandfathered by the FERC are not entitled to such status, and, if so entitled, that "substantially changed circumstances" have occurred, removing such protection. ConocoPhillips seeks rate reductions and reparations for two years prior to the filing of their complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, Navajo Refining Company, L.P., and Western Refining Company, L.P. all filed timely motions to intervene in this proceeding. SFPP answered the complaint on January 28, 2005. On February 25, 2005, the FERC consolidated the complaints in Docket Nos. OR05-4 and OR05-5 and held them in abeyance until after the conclusion of the various pending SFPP proceedings, deferring any ruling on the validity of the complaints. On March 28, 2005, BP West Coast and ExxonMobil requested rehearing of one aspect of the February 25, 2005 order; they argued that any tax allowance matters in these proceedings could not be decided in, or as a result of, the FERC's inquiry into income tax allowance in Docket No. PL05-5. On June 8, 2005, the FERC denied the request for rehearing. Consolidated Complaints. On February 13, 2006, the FERC consolidated the complaints in Docket Nos. OR03-5, OR04-3, OR05-4, and OR05-5 and set for hearing the portions of those complaints attacking SFPP's North Line and Oregon Line rates, which rates remain grandfathered under the Energy Policy Act of 1992. A procedural schedule, leading to hearing in early 2007, has been established in that consolidated proceeding. Contemporaneously, settlement negotiations, under the auspices of a FERC settlement judge are proceeding. The FERC also indicated in its order that it would address the remaining portions of these complaints in the context of its disposition of SFPP's compliance filings in the OR92-8/OR96-2 proceedings. North Line rate case, IS05-230 proceeding. In April 2005, SFPP filed to increase its North Line interstate rates to reflect increased costs, principally due to the installation of replacement pipe between Concord and Sacramento, 16 California. Under FERC regulations, SFPP was required to demonstrate that there was a substantial divergence between the revenues generated by its existing North Line rates and its increased costs. SFPP's rate increase was protested by various shippers and accepted subject to refund by the FERC. A hearing was held in January and February 2006, and the case has now been briefed to the administrative law judge. Trailblazer Pipeline Company On March 22, 2005, Marathon Oil Company filed a formal complaint with the FERC alleging that Trailblazer Pipeline Company violated the FERC's Negotiated Rate Policy Statement and the Natural Gas Act by failing to offer a recourse rate option for its Expansion 2002 capacity and by charging negotiated rates higher than the applicable recourse rates. Marathon requested that the FERC require Trailblazer to refund all amounts paid by Marathon above Trailblazer's Expansion 2002 recourse rate since the facilities went into service in May 2002, with interest. In addition, Marathon asked the FERC to require Trailblazer to bill Marathon the Expansion 2002 recourse rate for future billings. Marathon estimated that the amount of Trailblazer's refund obligation at the time of the filing was over $15 million. Trailblazer filed its response to Marathon's complaint on April 13, 2005. On May 20, 2005, the FERC issued an order denying the Marathon complaint and found that (i) Trailblazer did not violate FERC policy and regulations and (ii) there is insufficient justification to initiate further action under Section 5 of the Natural Gas Act to invalidate and change the negotiated rate. On June 17, 2005, Marathon filed its Request for Rehearing of the May 20, 2005 order. On January 19, 2006, the FERC issued an order which denied Marathon's rehearing request. 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 may occur within the second quarter of 2006. 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 17 Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and Chevron Products Company. Issues raised by the protest, including the reasonableness of SFPP's existing intrastate transportation rates, were the subject of evidentiary hearings conducted in December 2003 and may be resolved by the CPUC in the second quarter of 2006. On November 22, 2004, SFPP filed an application with the CPUC requesting a $9 million increase in existing intrastate rates to reflect the in-service date of SFPP's replacement and expansion of its Concord-to-Sacramento pipeline. The requested rate increase, which automatically became effective as of December 22, 2004 pursuant to California Public Utilities Code Section 455.3, is being collected subject to refund, pending resolution of protests to the application by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and ChevronTexaco Products Company. The CPUC is not expected to resolve the matter before the third quarter of 2006. 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. With regard to 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, referred to above, such refunds could total about $6 million per year from October 2002 to the anticipated date of a CPUC decision. On January 26, 2006, SFPP filed a request for an annual rate increase of approximately $5.4 million with the CPUC, to be effective as of March 2, 2006. Protests to SFPP's rate increase application have been filed by Tesoro Refining and Marketing Company, BP West Coast Products LLC, ExxonMobil Oil Corporation, Southwest Airlines Company, Valero Marketing and Supply Company, Ultramar Inc. and Chevron Products Company, asserting that the requested rate increase is unreasonable. Pending the outcome of protests to SFPP's filing, the rate increase, which will be collected in the form of a surcharge to existing rates, will be collected subject to refund. SFPP believes the submission of the required, representative cost data required by the CPUC indicates 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. Other Regulatory Matters 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 or that such challenges will not have a material adverse effect on our business, financial position, results of operations or cash flows. 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 a material adverse effect on our business, financial position, results of operations or cash flows. Carbon Dioxide Litigation Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez Pipeline Company were among the named defendants in Shores, et al. v. Mobil Oil Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed March 29, 2001). These cases were originally filed as class actions on behalf of classes of overriding royalty interest owners (Shores) and royalty interest owners (Bank of Denton) for damages relating to alleged underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes were initially certified at the trial court level, appeals resulted in the decertification and/or abandonment of the class claims. On February 22, 2005, the trial judge dismissed both cases for lack of jurisdiction. Some of the individual plaintiffs in these cases re-filed their claims in new lawsuits (discussed below). 18 On May 13, 2004, William Armor, one of the former plaintiffs in the Shores matter whose claims were dismissed by the Court of Appeals for improper venue, filed a new case alleging the same claims for underpayment of royalties against the same defendants previously sued in the Shores case, including Kinder Morgan CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas filed May 13, 2004). Defendants filed their answers and special exceptions on June 4, 2004. Trial is presently scheduled to occur on June 12, 2006, but will likely take place in late 2006 on account of an uncontested motion filed by the Plaintiffs to continue the trial date. On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd., two of the former plaintiffs in the Bank of Denton matter, filed a new case in Dallas state district court alleging the same claims for underpayment of royalties. Reddy and Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial District Court, Dallas County, Texas filed May 20, 2005). The defendants include Kinder Morgan CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. On June 23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the court in the Armor lawsuit granted the motion to transfer and consolidate and ordered that the Reddy lawsuit be transferred and consolidated into the Armor lawsuit. The defendants filed their answer and special exceptions on August 10, 2005. The consolidated Armor/Reddy trial is presently scheduled to occur on June 12, 2006, but will likely take place in late 2006 on account of an uncontested motion filed by the Plaintiffs to continue the trial date. Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2 Company, L.P., is among the named counter-claim defendants in Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial District Court, Harris County, Texas filed June 17, 1998) (the "Bailey State Court Action"). The counter-claim plaintiffs are overriding royalty interest owners in the McElmo Dome Unit and have sued seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. In the Bailey State Court Action, the counter-claim plaintiffs asserted claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, negligence, negligence per se, unjust enrichment, violation of the Texas Securities Act, and open account. The trial court in the Bailey State Court Action granted a series of summary judgment motions filed by the counter-claim defendants on all of the counter-plaintiffs' counter-claims except for the fraud-based claims. In 2004, one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit to allege purported claims as a private relator under the False Claims Act and antitrust claims. The federal government elected to not intervene in the False Claims Act counter-suit. On March 24, 2005, Bailey filed a notice of removal, and the case was transferred to federal court. Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company, No. H-05-1029 (S.D. Tex., Houston Division removed March 24, 2005) (the "Bailey Houston Federal Court Action"). Also on March 24, 2005, Bailey filed an instrument under seal in the Bailey Houston Federal Court Action that was later determined to be a motion to transfer venue of that case to the federal district court of Colorado, in which Bailey and two other plaintiffs have filed another suit against Kinder Morgan CO2 Company, L.P. asserting claims under the False Claims Act. The Houston federal district judge ordered that Bailey take steps to have the False Claims Act case pending in Colorado transferred to the Bailey Houston Federal Court Action, and also suggested that the claims of other plaintiffs in other carbon dioxide litigation pending in Texas should be transferred to the Bailey Houston Federal Court Action. In response to the court's suggestion, the case of Gary Shores et al. v. ExxonMobil Corp. et al., No. 05-1825 (S.D. Tex., Houston Division) was consolidated with the Bailey Houston Federal Court Action on July 18, 2005. That case, in which the plaintiffs assert claims for McElmo Dome royalty underpayment, includes Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., and Cortez Pipeline Company as defendants. Bailey requested the Houston federal district court to transfer the Bailey Houston Federal Court Action to the federal district court of Colorado. Bailey also filed a petition for writ of mandamus in the Fifth Circuit Court of Appeals, asking that the Houston federal district court be required to transfer the case to the federal district court of Colorado. On June 3, 2005, the Fifth Circuit Court of Appeals denied Bailey's petition for writ of mandamus. On June 22, 2005, the Fifth Circuit denied Bailey's petition for rehearing en banc. On September 14, 2005, Bailey filed a petition for writ of certiorari in the United States Supreme Court, which the U.S. Supreme Court denied on November 28, 2005. On November 21, 2005, the federal district court in Colorado transferred Bailey's False Claims Act case pending in Colorado to the Houston federal district court. On November 30, 2005, Bailey filed a petition for mandamus seeking to vacate the transfer. The Tenth Circuit Court of Appeals denied the petition on December 19, 2005. The U.S. Supreme Court has denied Bailey's petition for writ of certiorari. The Houston federal district court subsequently realigned the parties in the Bailey Houston Federal Court Action. Pursuant to the Houston federal district court's order, Bailey and the other realigned plaintiffs have filed amended complaints in which they assert claims for fraud/fraudulent inducement, real 19 estate fraud, negligent misrepresentation, breach of fiduciary and agency duties, breach of contract and covenants, violation of the Colorado Unfair Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment, and open account. Bailey also asserted claims as a private relator under the False Claims Act and for violation of federal and Colorado antitrust laws. The realigned plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief. The Shell and Kinder Morgan defendants, along with Cortez Pipeline Company and ExxonMobil defendants, have filed motions for summary judgment on all claims. No current trial date is set. On March 1, 2004, Bridwell Oil Company, one of the named defendants/realigned plaintiffs in the Bailey actions, filed a new matter in which it asserts claims which are virtually identical to the counter-claims it asserts against Shell CO2 Company, Ltd. in the Bailey lawsuit. Bridwell Oil Co. v. Shell Oil Co. et al, No. 160,199-B (78th Judicial District Court, Wichita County, Texas filed March 1, 2004). The defendants in this action include Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell entities, ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004, defendants filed answers, special exceptions, pleas in abatement, and motions to transfer venue back to the Harris County District Court. On January 31, 2005, the Wichita County judge abated the case pending resolution of the Bailey State Court Action. The case remains abated. On April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Colorado federal action filed by Bailey under the False Claims Act (which was transferred to the Bailey Houston Federal Court Action as described above), filed suit against Kinder Morgan G.P., Inc. in Colorado federal district court. Harry Ptasynski v. Kinder Morgan G.P., Inc., No. 06-CV-00651 (LTB) (U.S. District Court for the District of Colorado). Ptasynski, who holds an overriding royalty interest at McElmo Dome, asserts claims for civil conspiracy, violation of the Colorado Organized Crime Control Act, violation of Colorado antitrust laws, violation of the Colorado Unfair Practices Act, breach of fiduciary duty and confidential relationship, violation of the Colorado Payment of Proceeds Act, fraudulent concealment, breach of contract and implied duties to market and good faith and fair dealing, and civil theft and conversion. Ptasynski seeks actual damages, treble damages, forfeiture, disgorgement, and declaratory and injunctive relief. Kinder Morgan G.P., Inc. intends to seek dismissal of the case or, alternatively, transfer of the case to the Bailey Houston Federal Court Action. No trial date is currently set. Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case involves claims by overriding royalty interest owners in the McElmo Dome and Doe Canyon Units seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome and Doe Canyon. The plaintiffs also possess a small working interest at Doe Canyon. Plaintiffs claim breaches of contractual and potential fiduciary duties owed by the defendants and also allege other theories of liability including breach of covenants, civil theft, conversion, fraud/fraudulent concealment, violation of the Colorado Organized Crime Control Act, deceptive trade practices, and violation of the Colorado Antitrust Act. In addition to actual or compensatory damages, plaintiffs seek treble damages, punitive damages, and declaratory relief relating to the Cortez Pipeline tariff and the method of calculating and paying royalties on McElmo Dome carbon dioxide. The Court denied plaintiffs' motion for summary judgment concerning alleged underpayment of McElmo Dome overriding royalties on March 2, 2005. The parties are continuing to engage in discovery. No trial date is currently set. Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor in interest to Shell CO2 Company, Ltd., are among the named defendants in CO2 Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005. The arbitration arises from a dispute over a class action settlement agreement which became final on July 7, 2003 and disposed of five lawsuits formerly pending in the U.S. District Court, District of Colorado. The plaintiffs in such lawsuits primarily included overriding royalty interest owners, royalty interest owners, and small share working interest owners who alleged underpayment of royalties and other payments on carbon dioxide produced from the McElmo Dome Unit in southwest Colorado. The settlement imposed certain future obligations on the defendants in the underlying litigation. The plaintiff in the current arbitration is an entity that was formed as part of the settlement for the purpose of monitoring compliance with the obligations imposed by the settlement agreement. The plaintiff alleges that, in calculating royalty and other payments, defendants used a transportation expense in excess of what is allowed by the settlement agreement, thereby causing alleged underpayments of approximately $10.3 million. The plaintiff also alleges that Cortez Pipeline Company should have used certain 20 funds to further reduce its debt, which, in turn, would have allegedly increased the value of royalty and other payments by approximately $0.2 million. Defendants deny that there was any breach of the settlement agreement. The arbitration panel has issued various preliminary evidentiary rulings. The arbitration is currently scheduled to commence on June 26, 2006. J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and on behalf of all other private royalty and overriding royalty owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New Mexico) This case involves a purported class action against Kinder Morgan CO2 Company, L.P. alleging that it has failed to pay the full royalty and overriding royalty ("royalty interests") on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome Unit in the period beginning January 1, 2000. The complaint purports to assert claims for violation of the New Mexico Unfair Practices Act, constructive fraud, breach of contract and of the covenant of good faith and fair dealing, breach of the implied covenant to market, and claims for an accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome Unit. The plaintiffs allege that they were members of a class previously certified as a class action by the United States District Court for the District of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et al., USDC N.M. Civ. No. 95-0012 (the "Feerer Class Action"). Plaintiffs allege that Kinder Morgan CO2 Company's method of paying royalty interests is contrary to the settlement of the Feerer Class Action. Kinder Morgan CO2 Company has filed a motion to compel arbitration of this matter pursuant to the arbitration provisions contained in the Feerer Class Action settlement agreement, which motion was denied by the trial court. An appeal of that ruling has been filed and is pending before the New Mexico Court of Appeals. Oral arguments took place before the New Mexico Court of Appeals on March 23, 2006. No date for arbitration or trial is currently set. In addition to the matters listed above, various audits and administrative inquiries concerning Kinder Morgan CO2 Company L.P.'s royalty and tax payments on carbon dioxide produced from the McElmo Dome Unit are currently ongoing. These audits and inquiries involve various federal agencies, the State of Colorado, the Colorado oil and gas commission, and Colorado county taxing authorities. Commercial Litigation Matters Union Pacific Railroad Company Easements SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company and referred to in this report as UPRR) are engaged in two proceedings 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 UPRR should be adjusted pursuant to existing contractual arrangements for each of the ten year periods beginning January 1, 1994 and January 1, 2004 (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; and Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D", Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). With regard to the first proceeding, covering the ten year period beginning January 1, 1994, the trial court, on July 16, 2003, set the rent for years 1994 - 2003 at approximately $5.0 million per year as of January 1, 1994, subject to annual inflation increases throughout the ten year period. On February 23, 2005, the California Court of Appeals affirmed the trial court's ruling, except that it reversed a small portion of the decision and remanded it back to the trial court for determination. On remand, the trial court held that there was no adjustment to the rent relating to the portion of the decision that was reversed, but awarded Southern Pacific Transportation Company interest on rental amounts owing as of May 7, 1997. 21 In April 2006, we paid UPRR $15.3 million in satisfaction of our rental obligations through December 31, 2003. However, we do not believe that the assessment of interest awarded Southern Pacific Transportation Company on rental amounts owing as of May 7, 1997 was proper, and we are seeking appellate review of the interest award. In addition, SFPP, L.P. and UPRR are engaged in a second 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 UPRR should be adjusted pursuant to existing contractual arrangements for the ten year period beginning January 1, 2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D", Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). SFPP was served with this lawsuit on August 17, 2004. SFPP expects that the trial in this matter will occur in late 2006. SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right of way and the safety standards that govern relocations. SFPP believes that it must pay for relocation of the pipeline only when so required by the railroad's common carrier operations, and in doing so, it need only comply with standards set forth in the federal Pipeline Safety Act in conducting relocations. UPRR contends that it has complete discretion to cause the pipeline to be relocated at SFPP's expense at any time and for any reason, and that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards. Each party is seeking declaratory relief with respect to its positions regarding relocations. It is difficult to quantify the effects of the outcome of these cases on SFPP because SFPP does not know UPRR's plans for projects or other activities that would cause pipeline relocations. Even if SFPP is successful in advancing its position, significant relocations for which SFPP must nonetheless bear the expense (i.e. for railroad purposes, with the standards in the federal Pipeline Safety Act applying) would have an adverse effect on our financial position and results of operations. These effects would be even more in the event SFPP is unsuccessful in one or more of these litigations. 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. 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 Claims 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. Subsequently, Grynberg's appeal was dismissed for lack of appellate jurisdiction. Discovery to determine issues related to the Court's subject matter jurisdiction arising out of the False Claims Act is complete. Briefing has been completed and oral arguments on jurisdiction were held before the Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave to file a Third Amended Complaint, which adds allegations of undermeasurement related to carbon dioxide production. Defendants have 22 filed briefs opposing leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's Motion to Amend. On May 13, 2005, the Special Master issued his Report and Recommendations to Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. The Special Master found that there was a prior public disclosure of the mismeasurement fraud Grynberg alleged, and that Grynberg was not an original source of the allegations. As a result, the Special Master recommended dismissal of the Kinder Morgan defendants on jurisdictional grounds. On June 27, 2005, Grynberg filed a motion to modify and partially reverse the Special Master's recommendations and the Defendants filed a motion to adopt the Special Master's recommendations with modifications. An oral argument was held on December 9, 2005 on the motions concerning the Special Master's recommendations. It is likely that Grynberg will appeal any dismissal to the 10th Circuit Court of Appeals. Weldon Johnson and Guy Sparks, individually and as Representative of Others Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit Court, Miller County Arkansas). On October 8, 2004, plaintiffs filed the above-captioned matter against numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC; and MidCon Corp. (the "Kinder Morgan Defendants"). The complaint purports to bring a class action on behalf of those who purchased natural gas from the CenterPoint defendants from October 1, 1994 to the date of class certification. The complaint alleges that CenterPoint Energy, Inc., by and through its affiliates, has artificially inflated the price charged to residential consumers for natural gas that it allegedly purchased from the non-CenterPoint defendants, including the above-listed Kinder Morgan entities. The complaint further alleges that in exchange for CenterPoint's purchase of such natural gas at above market prices, the non-CenterPoint defendants, including the above-listed Kinder Morgan entities, sell natural gas to CenterPoint's non-regulated affiliates 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, unlawful enrichment and civil conspiracy against all of the defendants, and seeks relief in the form of actual, exemplary and punitive damages, interest, and attorneys' fees. The parties have recently concluded jurisdictional discovery and a hearing is scheduled for summer 2006 on various defendants' assertion that the Arkansas courts lack personal jurisdiction over them. 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. Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party in interest for Enron Helium Company, a division of Enron Corp., Enron Liquids Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th Judicial District Court, Harris County, Texas) On September 1, 2000, plaintiff Exxon Mobil Corporation filed its original petition and application for declaratory relief against Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P., Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron Helium Company. Plaintiff added Enron Corp. as party in interest for Enron Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a defendant. The claims against Enron Corp. were severed into a separate cause of action. Plaintiff's claims are based on a gas processing agreement entered into on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company relating to gas produced in the Hugoton Field in Kansas and processed at the Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff also asserts claims relating to the helium extraction agreement entered between Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated March 14, 1988. Plaintiff alleges that defendants failed to deliver propane and to allocate plant products to the 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, the 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 23 processing agreement, civil conspiracy, fraud, breach of a duty of good faith and fair dealing, negligent misrepresentation and conversion. As of April 7, 2003, the plaintiff alleged economic damages for the period from November 1987 through March 1997 in the amount of $30.7 million. On May 2, 2003, the plaintiff added claims for the period from April 1997 through February 2003 in the amount of $12.9 million. On June 23, 2003, the plaintiff filed a fourth amended petition that reduced its total claim for economic damages to $30.0 million. On October 5, 2003, the plaintiff filed a fifth amended petition that purported to add a cause of action for embezzlement. On February 10, 2004, the plaintiff filed its eleventh supplemental responses to requests for disclosure that restated its alleged economic damages for the period of November 1987 through December 2003 as approximately $37.4 million. The matter went to trial on June 21, 2004. On June 30, 2004, the jury returned a unanimous verdict in favor of all defendants as to all counts. Final judgment was entered in favor of the defendants on August 19, 2004. Plaintiff has appealed the jury's verdict to the 14th Court of Appeals for the State of Texas. On February 21, 2006, the Court of Appeals unanimously affirmed the judgment in our favor entered by the trial court, and ordered ExxonMobil to pay all costs incurred in the appeal. ExxonMobil has not filed an appeal of this decision to the Texas Supreme Court, so the matter is now concluded. Cannon Interests-Houston v. Kinder Morgan Texas Pipeline, L.P., No. 2005-36174 (333rd Judicial District, Harris County, Texas). On June 6, 2005, after unsuccessful mediation, Cannon Interests sued Kinder Morgan Texas Pipeline, L.P., referred to in this report as KMTP, and alleged breach of contract for the purchase of natural gas storage capacity and for failure to pay under a profit-sharing arrangement. KMTP counterclaimed that Cannon Interests failed to provide it with five billion cubic feet of winter storage capacity in breach of the contract. The plaintiff is claiming approximately $13 million in damages. A trial date has been set for September 18, 2006. KMTP will defend the case vigorously, and based upon the information available to date, it believes that the claims against it are without merit and will be more than offset by its claims against Cannon Interests. Federal Investigation at Cora and Grand Rivers Coal Facilities On June 22, 2005, we announced that the Federal Bureau of Investigation is conducting an investigation related to our coal terminal facilities located in Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involves certain coal sales from our Cora, Illinois and Grand Rivers, Kentucky coal terminals that occurred from 1997 through 2001. During this time period, we sold excess coal from these two terminals for our own account, generating less than $15 million in total net sales. Excess coal is the weight gain that results from moisture absorption into existing coal during transit or storage and from scale inaccuracies, which are typical in the industry. During the years 1997 through 1999, we collected, and, from 1997 through 2001, we subsequently sold, excess coal for our own account, as we believed we were entitled to do under then-existing customer contracts. We have conducted an internal investigation of the allegations and discovered no evidence of wrongdoing or improper activities at these two terminals. Furthermore, we have contacted customers of these terminals during the applicable time period and have offered to share information with them regarding our excess coal sales. Over the five year period from 1997 to 2001, we moved almost 75 million tons of coal through these terminals, of which less than 1.4 million tons were sold for our own account (including both excess coal and coal purchased on the open market). We have not added to our inventory of excess coal since 1999 and we have not sold coal for our own account since 2001, except for minor amounts of scrap coal. We are fully cooperating with federal law enforcement authorities in this investigation. In September 2005 and subsequent thereto, we responded to a subpoena in this matter by producing a large volume of documents, which, we understand, are being reviewed by the FBI and auditors from the Tennessee Valley Authority, which is a customer of the Cora and Grand Rivers terminals. We do not expect that the resolution of the investigation will have a material adverse impact on our business, financial position, results of operations or cash flows. Queen City Railcar Litigation On August 28, 2005, a railcar containing the chemical styrene began leaking styrene gas in Cincinnati, Ohio while en route to our Queen City Terminal. The railcar was sent by the Westlake Chemical Corporation from Louisiana, transported by Indiana & Ohio Railway, and consigned to Westlake at its dedicated storage tank at Queen City Terminals, Inc., a subsidiary of Kinder Morgan Bulk Terminals, Inc. The railcar leak resulted in the evacuation 24 of many residents and the alleged temporary closure of several businesses in the Cincinnati area. Within three weeks of the incident, seven separate class action complaints were filed in the Hamilton County Court of Common Pleas, including case numbers: A0507115, A0507120, A0507121, A0507149, A0507322, A0507332, and A0507913. In addition, a complaint was filed by the city of Cincinnati, described further below. On September 28, 2005, the court consolidated the complaints under consolidated case number A0507913. Concurrently, thirteen designated class representatives filed a Master Class Action Complaint against Westlake Chemical Corporation, Indiana and Ohio Railway Corporation, Queen City Terminals, Inc., Kinder Morgan Liquids Terminals, LLC, Kinder Morgan GP, Inc. and Kinder Morgan Energy Partners, L.P., collectively the defendants, in the Hamilton County Court of Common Pleas, case number A0507105. The complaint alleges negligence, absolute nuisance, nuisance, trespass, negligence per se, and strict liability against all defendants stemming from the styrene leak. The complaint seeks compensatory damages in excess of $25,000, punitive damages, pre and post-judgment interest, and attorney fees. The claims against the Indiana and Ohio Railway and Westlake are based generally on an alleged failure to deliver the railcar in a timely manner which allegedly caused the styrene to become unstable and leak from the railcar. The plaintiffs allege that we had a legal duty to monitor the movement of the railcar en route to our terminal and guarantee its timely arrival in a safe and stable condition. On October 28, 2005, we filed an answer denying the material allegations of the complaint. On December 1, 2005, the plaintiffs filed a motion for class certification. On December 12, 2005, we filed a motion for an extension of time to respond to plaintiffs' motion for class certification in order to conduct discovery regarding class certification. On February 10, 2006, the court granted our motion for additional time to conduct class discovery. The court has not established a scheduling order or trial date, and discovery is ongoing. On September 6, 2005, the city of Cincinnati, the plaintiff, filed a complaint on behalf of itself and in parens patriae against Westlake, Indiana and Ohio Railway, Kinder Morgan Liquids Terminals, LLC, Queen City Terminals, Inc. and Kinder Morgan GP, Inc., collectively the defendants, in the Court of Common Pleas, Hamilton County, Ohio, case number A0507323. Plaintiff's complaint arose out of the same railcar incident reported immediately above. The plaintiff's complaint alleges public nuisance, negligence, strict liability, and trespass. The complaint seeks compensatory damages in excess of $25,000, punitive damages, pre and post-judgment interest, and attorney fees. On September 28, 2005, Kinder Morgan filed a motion to dismiss the parens patriae claim. On December 15, 2005, Kinder Morgan filed a motion for summary judgment. The plaintiff has not responded to either motion. A trial date has not been set. Leukemia Cluster Litigation We are a party to several lawsuits in Nevada that allege that the plaintiffs have developed leukemia as a result of exposure to harmful substances. 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 these matters are without merit and intend to defend against them vigorously. The following is a summary of these cases. 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 25 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. 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 filed a notice of appeal to the United States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit affirmed the dismissal of this case. 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 filed a notice of appeal to the United States Court of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit dismissed the appeal, upholding the District Court's dismissal of the case. 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. On April 13, 2004, plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the entire case in State Court. The court has accepted the stipulation and the case was dismissed on April 27, 2004. Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters (now dismissed) 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. 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. On December 5, 2003, the District Court granted the Kinder Morgan defendants' motion to dismiss, but granted plaintiff leave to file a second amended complaint. Plaintiff filed a second amended complaint on December 13, 2003, and a third amended complaint on January 5, 2004. The Kinder Morgan defendants filed a motion to dismiss the third amended complaint on January 13, 2004. The motion to dismiss was granted with prejudice on April 30, 2004. On May 7, 2004, plaintiff filed a notice of appeal in the United States Court of Appeals for the 9th Circuit. On March 31, 2006, the 9th Circuit affirmed the District Court's dismissal of the case. On April 27, 2006, plaintiff filed a motion for an en banc review of this decision by the full 9th Circuit Court of Appeals. The Kinder Morgan defendants intend to oppose this motion. 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. 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 26 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 (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages. The Jernee case has been consolidated for pretrial purposes with the Sands case (see below). Plaintiffs have filed a third amended complaint and all defendants have filed motions to dismiss all causes of action excluding plaintiffs' cause of action for negligence. Defendants have also filed motions to strike portions of the complaint. These motions remain pending before the court. As is its practice, the court has not scheduled argument on any such motions. In addition to the above, the parties have filed motions to implement case management orders, the Jernee matter having now been deemed "complex" by the court. Such orders are designed to stage discovery, motions and pretrial proceedings. The court initially entered the case management order proposed by the defendants. Following plaintiffs' motion for reconsideration, however, the court reversed itself, vacated the original case management order, and entered a case management order submitted by the plaintiffs. Defendants plan to file a motion to vacate this second case management order and re-institute the original case management order. 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. The Kinder Morgan defendants were served with the complaint on January 10, 2004. 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 (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages. The Sands case has been consolidated for pretrial purposes with the Jernee case (see above). Plaintiffs have filed a second amended complaint and all defendants have filed motions to dismiss all causes of action excluding plaintiffs' cause of action for negligence. Defendants have also filed motions to strike portions of the complaint. These motions remain pending before the court. As is its practice, the court has not scheduled argument on any such motions. In addition to the above, the parties have filed motions to implement case management orders, the Sands matter having now been deemed "complex" by the court. Such orders are designed to stage discovery, motions and pretrial proceedings. The court initially entered the case management order proposed by the defendants. Following plaintiffs' motion for reconsideration, however, the court reversed itself, vacated the original case management order, and entered a case management order submitted by the plaintiffs. Defendants plan to file a motion to vacate this second case management order and re-institute the original case management order. Pipeline Integrity and Releases Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona. On January 28, 2005, Meritage Homes Corp. and its above-named affiliates filed a complaint in the above-entitled action against Kinder Morgan Energy Partners, L.P. and SFPP, L.P. The plaintiffs are homebuilders who constructed a subdivision known as Silver Creek II located in Tucson, Arizona. Plaintiffs allege that, as a result of a July 30, 2003 pipeline rupture and accompanying release of petroleum products, soil and groundwater adjacent to, on and underlying portions of Silver Creek II became contaminated. Plaintiffs allege that they have incurred and continue to incur costs, damages and expenses associated with the delay of closings of home sales within Silver 27 Creek II and damage to their reputation and goodwill as a result of the rupture and release. Plaintiffs' complaint purports to assert claims for negligence, breach of contract, trespass, nuisance, strict liability, subrogation and indemnity, and negligence per se. Plaintiffs seek "no less than $1.5 million in compensatory damages and necessary response costs," a declaratory judgment, interest, punitive damages and attorneys' fees and costs. The parties have agreed to submit the claims to arbitration and are currently engaged in discovery. We dispute the legal and factual bases for many of plaintiffs' claimed compensatory damages, deny that punitive damages are appropriate under the facts, and intend to vigorously defend this action. Walnut Creek, California Pipeline Rupture On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a water main installation project hired by East Bay Municipal Utility District ("EBMUD"), struck and ruptured an underground petroleum pipeline owned and operated by SFPP, L.P. in Walnut Creek, California. An explosion occurred immediately following the rupture that resulted in five fatalities and several injuries to employees or contractors of Mountain Cascade. The explosion and fire also caused other property damage. On May 5, 2005, the California Division of Occupational Safety and Health ("CalOSHA") issued two civil citations against us relating to this incident assessing civil fines of $140,000 based upon our alleged failure to mark the location of the pipeline properly prior to the excavation of the site by the contractor. CalOSHA, with the assistance of the Contra Costa County District Attorney's office, is continuing to investigate the facts and circumstances surrounding the incident for possible criminal violations. In addition, on June 27, 2005, the Office of the California State Fire Marshal, Pipeline Safety Division ("CSFM") issued a Notice of Violation against us which also alleges that we did not properly mark the location of the pipeline in violation of state and federal regulations. The CSFM assessed a proposed civil penalty of $500,000. The location of the incident was not our work site, nor did we have any direct involvement in the water main replacement project. We believe that SFPP acted in accordance with applicable law and regulations, and further that according to California law, excavators, such as the contractor on the project, must take the necessary steps (including excavating with hand tools) to confirm the exact location of a pipeline before using any power operated or power driven excavation equipment. Accordingly, we disagree with certain of the findings of CalOSHA and the CSFM, and we have appealed the civil penalties while, at the same time, continuing to work cooperatively with CalOSHA and the CSFM to resolve these matters. As a result of the accident, fifteen separate lawsuits have been filed. Eleven are personal injury and wrongful death actions. These are: Knox, et al. v.. Mountain Cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-00281); Farley v. Mountain cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-01573); Reyes, et al. v. East Bay Municipal Utility District, et al. (Alameda Sup. Ct. Case No. RG-05-207720); Arias, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No. RG-05-195567); Angeles, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No. RG-05-195680); Ramos, et al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case No. C05-01840); Taylor, et al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case No. C05-02306); Becerra v. Kinder Morgan Energy Partners, L.P., et al., (Contra Costa County Superior Court Case No. C05-02451); Im, et al. v. Kinder Morgan, Inc. et al. (Contra Costa County Superior Court Case No. C05-02077); Paasch, et al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case No. C05-01844); and Fuentes et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. C05-02286). These complaints all allege, among other things, that SFPP/Kinder Morgan failed to properly field mark the area where the accident occurred. All of these plaintiffs seek compensatory and punitive damages. These complaints also allege that the general contractor who struck the pipeline, Mountain Cascade, Inc. ("MCI"), and EBMUD were at fault for negligently failing to locate the pipeline. Some of these complaints also name various engineers on the project for negligently failing to draw up adequate plans indicating the bend in the pipeline. A number of these actions also name Comforce Technical Services as a defendant. Comforce supplied SFPP with temporary employees/independent contractors who performed line marking and inspections of the pipeline on behalf of SFPP. Some of these complaints also named various governmental entities--such as the City of Walnut Creek, Contra Costa County, and the Contra Costa Flood Control and Water Conservation District--as defendants. Two of the fifteen suits are related to alleged damage to a residence near the accident site. These are: USAA v. East Bay Municipal Utility District, et al., (Contra Costa County Superior Court Case No. C05-02128); and Chabot v. East Bay Municipal Utilities District, et al., (Contra Costa Superior Court Case No. C05-02312). The remaining two suits are by MCI and the welding subcontractor, Matamoros. These are: Matamoros v. Kinder Morgan Energy 28 Partners, L.P., et al., (Contra Costa County Superior Court Case No. C05-02349); and Mountain Cascade, Inc. v. Kinder Morgan Energy Partners, L.P., et al, (Contra Costa County Superior Court Case No. C-05-02576). Like the personal injury and wrongful death suits, these lawsuits allege that SFPP/Kinder Morgan failed to properly mark its pipeline, causing damage to these plaintiffs. The Chabot and USAA plaintiffs allege property damage, while MCI and Matamoros Welding allege damage to their business as a result of SFPP/Kinder Morgan's alleged failures, as well as indemnity and other common law and statutory tort theories of recovery. Fourteen of these lawsuits are currently coordinated in Contra Costa County Superior Court; the fifteenth is expected to be coordinated with the other lawsuits in the near future. There are also several cross-complaints for indemnity between the co-defendants in the coordinated lawsuits. Based upon our investigation of the cause of the rupture of SFPP, LP's petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and fire, we have denied liability for the resulting deaths, injuries and damages, are vigorously defending against such claims, and seeking contribution and indemnity from the responsible parties. Cordelia, California On April 28, 2004, SFPP, L.P. discovered a spill of diesel fuel into a marsh near Cordelia, California from a section of SFPP's 14-inch Concord to Sacramento, California pipeline. Estimates indicated that the size of the spill was approximately 2,450 barrels. Upon discovery of the spill and notification to regulatory agencies, a unified response was implemented with the United States Coast Guard, the California Department of Fish and Game, the Office of Spill Prevention and Response and SFPP. The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on May 2, 2004. SFPP has completed recovery of diesel from the marsh and has completed an enhanced biodegradation program for removal of the remaining constituents bound up in soils. The property has been turned back to the owners for its stated purpose. There will be ongoing monitoring under the oversight of the California Regional Water Quality Control Board until the site conditions demonstrate there are no further actions required. SFPP is currently in negotiations with the United States Environmental Protection Agency, the United States Fish & Wildlife Service, the California Department of Fish & Game and the San Francisco Regional Water Quality Control Board regarding potential civil penalties and natural resource damages assessments. Since the April 2004 release in the Suisun Marsh area near Cordelia, California, SFPP has cooperated fully with federal and state agencies and has worked diligently to remediate the affected areas. As of December 31, 2005, the remediation was substantially complete. Oakland, California In February 2005, we were contacted by the U.S. Coast Guard regarding a potential release of jet fuel in the Oakland, California area. Our northern California team responded and discovered that one of our product pipelines had been damaged by a third party, which resulted in a release of jet fuel which migrated to the storm drain system and the Oakland estuary. We have coordinated the remediation of the impacts from this release, and are investigating the identity of the third party who damaged the pipeline in order to obtain contribution, indemnity, and to recover any damages associated with the rupture. The United States Environmental Protection Agency, the San Francisco Bay Regional Water Quality Control Board, the California Department of Fish and Game, and possibly the County of Alameda are asserting civil penalty claims with respect to this release. We are currently in settlement negotiations with these agencies. We will vigorously contest any unsupported, duplicative or excessive civil penalty claims, but hope to be able to resolve the demands by each governmental entity through out-of-court settlements. Donner Summit, California In April 2005, our SFPP pipeline in Northern California, which transports refined petroleum products to Reno, Nevada, experienced a failure in the line from external damage, resulting in a release of product that affected a limited area adjacent to the pipeline near the summit of Donner Pass. The release was located on land administered by the Forest Service, an agency within the U.S. Department of Agriculture. Initial remediation has been conducted in the immediate vicinity of the pipeline. All agency requirements have been met and the site will be closed upon completion of the remediation. We have received civil penalty claims on behalf of the United States Environmental 29 Protection Agency, the California Department of Fish and Game, and the Lahontan Regional Water Quality Control Board. We are currently in settlement negotiations with these agencies. We will vigorously contest any unsupported, duplicative or excessive civil penalty claims, but hope to be able to resolve the demands by each governmental entity through out-of-court settlements. Baker California In November 2004, near Baker, California, our CALNEV Pipeline experienced a failure in its pipeline from external damage, resulting in a release of gasoline that affected approximately two acres of land in the high desert administered by The Bureau of Land Management, an agency within the U.S. Department of the Interior. Remediation has been conducted and continues for product in the soils. All agency requirements have been met and the site will be closed upon completion of the soil remediation. The State of California Department of Fish & Game has alleged a small natural resource damage claim that is currently under review. CALNEV expects to work cooperatively with the Department of Fish & Game to resolve this claim. Henrico County, Virginia On April 17, 2006, Plantation Pipeline, which transports refined petroleum products across the southeastern United States and which is 51.17% owned and operated by us, experienced a pipeline release of turbine fuel from its 12-inch pipeline. The release occurred in a residential area and impacted adjacent homes, yards and common areas, as well as a nearby stream. Drinking water sources were not impacted. The released product did not ignite and there were no deaths or injuries. Plantation currently estimates the amount of product released to be approximately 665 barrels. Immediately following the release, the pipeline was shut down and emergency remediation activities were initiated. Remediation and monitoring activities are ongoing under the supervision of the United States Environmental Protection Agency (referred to in this report as the EPA) and the Virginia Department of Environmental Quality pursuant to the terms of an Emergency Removal/Response Administrative Order issued by the EPA under section 311(c) of the Clean Water Act. Repairs to the pipeline were completed on April 19, 2006 with the approval of the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, referred to in this report as the PHMSA, and pipeline service resumed on April 20, 2006. On April 20, 2006, the PHMSA issued a Corrective Action Order which, among other things, requires that Plantation maintain a 20% reduction in the operating pressure along the pipeline between the Richmond and Newington, Virginia pump stations. The cause of the release is currently under investigation. Proposed Office of Pipeline Safety Civil Penalty and Compliance Order On July 15, 2004, the U.S. Department of Transportation's Office of Pipeline Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance Order concerning alleged violations of certain federal regulations concerning our products pipeline integrity management program. The violations alleged in the proposed order are based upon the results of inspections of our integrity management program at our products pipelines facilities in Orange, California and Doraville, Georgia conducted in April and June of 2003, respectively. As a result of the alleged violations, the OPS seeks to have us implement a number of changes to our integrity management program and also seeks to impose a proposed civil penalty of approximately $0.3 million. We have already addressed a number of the concerns identified by the OPS and intend to continue to work with the OPS to ensure that our integrity management program satisfies all applicable regulations. However, we dispute some of the OPS findings and disagree that civil penalties are appropriate, and therefore requested an administrative hearing on these matters according to the U.S. Department of Transportation regulations. An administrative hearing was held on April 11 and 12, 2005. We have provided supplemental information to the hearing officer and to the OPS. It is anticipated that the decision in this matter and potential administrative order will be issued by the end of the fourth quarter of 2006. Pipeline and Hazardous Materials Safety Administration Corrective Action Order On August 26, 2005, we announced that we had received a Corrective Action Order issued by the PHMSA. The corrective order instructs us to comprehensively address potential integrity threats along the pipelines that comprise our Pacific operations. The corrective order focused primarily on eight pipeline incidents, seven of which occurred in the State of California. The PHMSA attributed five of the eight incidents to "outside force damage," such as 30 third-party damage caused by an excavator or damage caused during pipeline construction. Following the issuance of the corrective order, we engaged in cooperative discussions with the PHMSA and we reached an agreement in principle on the terms of a consent agreement with the PHMSA, subject to the PHMSA's obligation to provide notice and an opportunity to comment on the consent agreement to appropriate state officials pursuant to 49 USC Section 60112(c). This comment period closed on March 26, 2006. On April 10, 2006, we announced the final consent agreement, which will, among other things, require us to perform a thorough analysis of recent pipeline incidents, provide for a third-party independent review of our operations and procedural practices, and restructure our internal inspections program. Furthermore, we have reviewed all of our policies and procedures and are currently implementing various measures to strengthen our integrity management program, including a comprehensive evaluation of internal inspection technologies and other methods to protect our pipelines. We expect to spend approximately $90 million on pipeline integrity activities for our Pacific operations' pipelines over the next five years. Of that amount, approximately $26 million is related to this consent agreement. We do not expect that our compliance with the consent agreement will have a material adverse effect on our business, financial position, results of operations or cash flows. General Although no assurances can be given, we believe that we have meritorious defenses to all of these actions. Furthermore, to the extent an assessment of the matter is possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability. We also believe that these matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. Environmental Matters Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, Inc. and ST Services, Inc. On April 23, 2003, Exxon Mobil Corporation filed a 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 the 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 obligation we may owe to ST Services for 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. The parties have completed limited discovery. In October 2004, the judge assigned to the case dismissed himself from the case based on a conflict, and the new judge has ordered the parties to participate in mandatory mediation. The parties participated in a mediation on November 2, 2005 but no resolution was reached regarding the claims set out in the lawsuit. At this time, the parties are considering another mediation session but no date is confirmed. 31 Other Environmental Our Kinder Morgan Transmix Company has been in discussions with the United States Environmental Protection Agency regarding allegations by the EPA that it violated certain provisions of the Clean Air Act and the Resource Conservation & Recovery Act. Specifically, the EPA claims that we failed to comply with certain sampling protocols at our Indianola, Pennsylvania transmix facility in violation of the Clean Air Act's provisions governing fuel. The EPA further claims that we improperly accepted hazardous waste at our transmix facility in Indianola. Finally, the EPA claims that we failed to obtain batch samples of gasoline produced at our Hartford (Wood River), Illinois facility in 2004. In addition to injunctive relief that would require us to maintain additional oversight of our quality assurance program at all of our transmix facilities, the EPA is seeking monetary penalties of $0.6 million. 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 and Kinder Morgan Tejas indicates possible environmental impacts from petroleum releases into the soil and groundwater at nine sites. Further delineation and remediation of any environmental impacts from these matters will be conducted. Reserves have been established to address these issues. 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, among others, 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 law and 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 several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory authorities related to compliance with environmental regulations associated with our assets. We have established a reserve to address the costs associated with the cleanup. We are also involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide. See "--Pipeline Integrity and Ruptures" above for information with respect to the environmental impact of recent ruptures of some of our pipelines. 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. However, we are not able to reasonably estimate when the eventual settlements of these claims will occur. Many factors may change in the future affecting our reserve estimates, such as regulatory changes, groundwater and land use near our sites, and changes in cleanup technology. As of March 31, 2006, we have accrued an environmental reserve of $50.1 million. 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. 32 4. Asset Retirement Obligations We account for our legal obligations associated with the retirement of long-lived assets pursuant to Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. 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. In our CO2 business segment, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of March 31, 2006, we have recognized asset retirement obligations in the aggregate amount of $41.9 million relating to these requirements at existing sites within our CO2 business 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 March 31, 2006, we have recognized asset retirement obligations in the aggregate amount of $1.6 million relating to the businesses within our Natural Gas Pipelines business segment. We have included $0.8 million of our total asset retirement obligations as of March 31, 2006 with "Accrued other current liabilities" in our accompanying consolidated balance sheet. The remaining $42.7 million obligation is reported separately as a non-current liability. 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 each of the three months ended March 31, 2006 and 2005 is as follows (in thousands): Three Months Ended March 31, ---------------------------- 2006 2005 ------------- ------------- Balance at beginning of period......... $ 43,227 $ 38,274 Liabilities incurred................. 58 (238) Liabilities settled.................. (350) (233) Accretion expense.................... 596 520 Revisions in estimated cash flows.... -- -- -------- -------- Balance at end of period............... $ 43,531 $ 38,323 ======== ======== 5. Distributions On February 14, 2006, we paid a cash distribution of $0.80 per unit to our common unitholders and our Class B unitholders for the quarterly period ended December 31, 2005. KMR, our sole i-unitholder, received 997,180 additional i-units based on the $0.80 cash distribution per common unit. The distributions were declared on January 18, 2006, payable to unitholders of record as of January 31, 2006. On April 19, 2006, we declared a cash distribution of $0.81 per unit for the quarterly period ended March 31, 2006. The distribution will be paid on May 15, 2006, to unitholders of record as of April 28, 2006. Our common unitholders and Class B unitholders will receive cash. KMR will receive a distribution in the form of additional 33 i-units based on the $0.81 distribution per common unit. The number of i-units distributed will be 1,093,826. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.018566) will be issued. The fraction was determined by dividing: o $0.81, the cash amount distributed per common unit by o $43.629, the average of KMR's shares' closing market prices from April 11-25, 2006, 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 Our intangible assets include goodwill, lease value, contracts, customer relationships and agreements. Excluding goodwill, our other intangible assets have definite lives, are being amortized on a straight-line basis over their estimated useful lives, and are reported separately as "Other intangibles, net" in our accompanying consolidated balance sheets. For our investments in affiliated entities that are included in our consolidation, the excess cost over underlying fair value of net assets is referred to as goodwill and reported separately as "Goodwill" in our accompanying consolidated balance sheets. According to the provisions of SFAS No. 142, "Goodwill and Other Intangible Assets," goodwill is not subject to amortization but must be tested for impairment at least annually. Following is information related to our intangible assets subject to amortization and our goodwill (in thousands): March 31, December 31, 2006 2005 --------- ------------ Goodwill Gross carrying amount......... $ 813,101 $ 813,101 Accumulated amortization...... (14,142) (14,142) ---------- ---------- Net carrying amount........... 798,959 798,959 ---------- ---------- Lease value Gross carrying amount......... 6,592 6,592 Accumulated amortization...... (1,204) (1,168) ---------- ---------- Net carrying amount........... 5,388 5,424 ---------- ---------- Contracts and other Gross carrying amount......... 224,250 221,250 Accumulated amortization...... (13,050) (9,654) ---------- ---------- Net carrying amount........... 211,200 211,596 ---------- ---------- Total intangibles, net.......... $1,015,547 $1,015,979 ========== ========== Amortization expense on our intangibles consisted of the following (in thousands): Three Months Ended March 31, 2006 2005 ----------- ----------- Lease value............... $ 36 $ 36 Contracts and other....... 3,396 330 ------- ------ Total amortization........ $ 3,432 $ 366 ======= ====== As of March 31, 2006, our weighted average amortization period for our intangible assets was approximately 19.3 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $13.3 million, $13.2 million, $12.0 million, $11.8 million and $11.7 million, respectively. There were no changes in the carrying amount of our goodwill for the three months ended March 31, 2006. The carrying amount of our goodwill as of March 31, 2006 and as of December 31, 2005 is summarized as follows (in thousands): 34 Products Natural Gas Pipelines Pipelines CO2 Terminals Total --------- --------- --- --------- ----- Balance as of March 31, 2006 and December 31, 2005........ $ 263,182 $ 288,435 $ 46,101 $ 201,241 $ 798,959 ========= ========= ======== ========= ========= In addition, pursuant to ABP No. 18, any premium paid by an investor, which is analogous to goodwill, must be identified. For the investments we account for under the equity method of accounting, this premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. According to the provisions of SFAS No. 142, equity method goodwill is not subject to amortization but rather to impairment testing in accordance with Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." 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. Therefore, in addition to our annual impairment test of goodwill, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method. As of both March 31, 2006 and December 31, 2005, we have reported $138.2 million in equity method goodwill within the caption "Investments" in our accompanying consolidated balance sheets. We also, periodically, reevaluate the difference between the fair value of net assets accounted for under the equity method and our proportionate share of the underlying book value (that is, the investee's net assets per its financial statements) of the investee at date of acquisition. In almost all instances, this differential, relating to the discrepancy between our share of the investee's recognized net assets at book values and at current fair values, represents our share of undervalued depreciable assets, and since those assets (other than land) are subject to depreciation, we amortize this portion of our investment cost against our share of investee earnings. We reevaluate this differential, as well as the amortization period for such undervalued depreciable assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives in accordance with APB Opinion No. 18. 7. Debt Our outstanding short-term debt as of March 31, 2006 was $1,060.8 million. The balance consisted of: o $1,051.3 million of commercial paper borrowings; o a $5.7 million portion of 5.23% senior notes (our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes); and o a $5 million portion of 7.84% senior notes (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes); and o an offset of $1.2 million (which represents the net of other borrowings and the accretion of discounts on our senior note issuances). As of March 31, 2006, we intended and had the ability to refinance all of our short-term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated balance sheet. The weighted average interest rate on all of our borrowings was approximately 5.527% during the first quarter of 2006 and 4.901% during the first quarter of 2005. Credit Facility As of March 31, 2006, we had two credit facilities: o a $1.6 billion unsecured five-year credit facility due August 18, 2010; and 35 o a $250 million unsecured nine-month credit facility due November 21, 2006. We entered into our nine-month credit facility on February 22, 2006, and this facility contains borrowing rates and restrictive financial covenants that are similar to the borrowing rates and covenants under our $1.6 billion bank facility. Our credit facilities are with a syndicate of financial institutions, and Wachovia Bank, National Association is the administrative agent. There were no borrowings under either credit facility as of March 31, 2006, and there were no borrowings under our five-year credit facility as of December 31, 2005. The amount available for borrowing under our credit facilities as of March 31, 2006 was reduced by: o our outstanding commercial paper borrowings ($1,051.3 million as of March 31, 2006); o a combined $394 million in five letters of credit that support our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids, oil and carbon dioxide; o a combined $49 million in two letters of credit that support tax-exempt bonds; and o $16.2 million of other letters of credit supporting other obligations of us and our subsidiaries. Interest Rate Swaps Information on our interest rate swaps is contained in Note 10. Commercial Paper Program As of December 31, 2005, our commercial paper program provided for the issuance of up to $1.6 billion of commercial paper. In April 2006, we increased our commercial paper program by $250 million to provide for the issuance of up to $1.85 billion. As of March 31, 2006, we had $1,051.3 million of commercial paper outstanding with an average interest rate of 4.6854%. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facilities. Debt Issuances Subsequent to March 31, 2006 On April 28, 2006, Rockies Express Pipeline LLC entered into a $2.0 billion five-year, unsecured revolving credit facility due April 28, 2011. This credit facility will support a planned $2.0 billion commercial paper program, and borrowings under the planned commercial paper program will reduce the borrowings allowed under the credit facility. As of April 28, 2006, there were no borrowings under the credit facility, and terms of the commercial paper program were being negotiated. Borrowings under the credit facility and commercial paper program will be primarily used to finance the construction of the Rockies Express interstate natural gas pipeline, and the borrowings will not reduce the borrowings allowed under our credit facilities. Rockies Express Pipeline LLC is a limited liability company owned 66 2/3% and controlled by us. Sempra Energy holds the remaining 33 1/3% ownership interest. Both we and Sempra have agreed to guarantee borrowings under the Rockies Express credit facility in the same proportion as our percentage ownership of the member interests in Rockies Express Pipeline LLC. Contingent Debt We apply the provisions of Financial Accounting Standards Board Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" to our agreements that contain guarantee or indemnification clauses. These disclosure provisions expand those required by SFAS No. 5, "Accounting for Contingencies," by requiring a guarantor to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance is remote. The following is a description of our contingent debt agreements. 36 Cortez Pipeline Company Debt Pursuant to a certain Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% partner; a subsidiary of Exxon Mobil Corporation - 37% partner; and Cortez Vickers Pipeline Company - 13% partner) are required, on a several, 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 partners 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 partners further severally guarantee, on a percentage basis, the obligations of the Cortez Pipeline Company partners 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 several guaranty obligations jointly and severally; however, we are obligated to indemnify Shell for liabilities it incurs in connection with such guaranty. With respect to Cortez's long-term revolving credit facility, Shell is released of its guaranty obligations on December 31, 2006. Furthermore, with respect to Cortez's short-term commercial paper program and Series D notes, we must use commercially reasonable efforts to have Shell released of its guaranty obligations by December 31, 2006. If we are unable to obtain Shell's release in respect of the Series D Notes by that date, we are required to provide Shell with collateral (a letter of credit, for example) to secure our indemnification obligations to Shell. As of March 31, 2006, the debt facilities of Cortez Capital Corporation consisted of: o $75 million of Series D notes due May 15, 2013; o a $125 million short-term commercial paper program; and o a $125 million five-year committed revolving credit facility due December 22, 2009 (to support the above-mentioned $125 million commercial paper program). As of March 31, 2006, Cortez Capital Corporation had $87.1 million of commercial paper outstanding with an average interest rate of 4.6332%, the average interest rate on the Series D notes was 7.14%, and there were no borrowings under the credit facility. Red Cedar Gathering Company Debt In October 1998, Red Cedar 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 Gathering Company. The Senior Notes are also guaranteed by us and the other owner of Red Cedar Gathering Company jointly and severally. The principal is to be repaid in seven equal installments beginning on October 31, 2004 and ending on October 31, 2010. As of March 31, 2006, $39.3 million in principal amount of notes were outstanding. 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. The bond indenture is for 30 years and allows the bonds to remain outstanding until December 1, 2020. 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 37 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. Principal payments on the bonds are made on the first of December each year, and corresponding reductions are made to the letter of credit. As of March 31, 2006, this letter of credit had an outstanding balance under our credit facility of $24.9 million. Certain Relationships and Related Transactions 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. In conjunction with our acquisition of all of the partnership interests in TransColorado Gas Transmission Company from two wholly-owned subsidiaries of KMI on November 1, 2004, KMI became a guarantor of approximately $210.8 million of our debt. Thus, KMI was a guarantor of a total of approximately $733.5 million of our debt as of March 31, 2006, and KMI would be obligated to perform under this guarantee only if we and/or our assets were unable to satisfy our obligations. 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, 2005. 8. Partners' Capital As of March 31, 2006 and December 31, 2005, our partners' capital consisted of the following limited partner units: March 31, December31, 2006 2005 ----------- ----------- Common units....................... 157,015,376 157,005,326 Class B units...................... 5,313,400 5,313,400 i-units............................ 58,915,553 57,918,373 ----------- ----------- Total limited partner units...... 221,244,329 220,237,099 =========== =========== The total limited partner 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 March 31, 2006, our common unit totals consisted of 142,659,641 units held by third parties, 12,631,735 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner. As of December 31, 2005, our common unit total consisted of 142,649,591 units held by third parties, 12,631,735 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. On both March 31, 2006 and December 31, 2005, our Class B units were held entirely by a wholly-owned subsidiary of KMI and our i-units were held entirely by KMR. All of our Class B units were issued to a wholly-owned subsidiary of KMI 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. Our 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 us, and controlling and managing our business and affairs and the business and affairs of our operating limited partnerships and their 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. 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 38 additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on 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 for use in our business. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. Based on the preceding, KMR received a distribution of 997,180 i-units from us on February 14, 2006. These additional i-units distributed were based on the $0.80 per unit distributed to our common unitholders on that date. For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. Incentive distributions allocated to our general partner are determined by the amount quarterly distributions to unitholders exceed certain specified target levels. Our distribution of $0.80 per unit paid on February 14, 2006 for the fourth quarter of 2005 required an incentive distribution to our general partner of $125.6 million. Our distribution of $0.74 per unit paid on February 14, 2005 for the fourth quarter of 2004 required an incentive distribution to our general partner of $106.0 million. The increased incentive distribution to our general partner paid for the fourth quarter of 2005 over the distribution paid for the fourth quarter of 2004 reflects the increase in the amount distributed per unit as well as the issuance of additional units. Our declared distribution for the first quarter of 2006 of $0.81 per unit will result in an incentive distribution to our general partner of approximately $128.3 million. This compares to our distribution of $0.76 per unit and incentive distribution to our general partner of approximately $111.1 million for the first quarter of 2005. 9. Comprehensive Income SFAS No. 130, "Accounting for Comprehensive Income," requires that enterprises report a total for comprehensive income. For each of the three months ended March 31, 2006 and March 31, 2005, the difference between our net income and our comprehensive income resulted from unrealized gains or losses on derivatives utilized for hedging purposes and from foreign currency translation adjustments. For more information on our hedging activities, see Note 10. Our total comprehensive income is as follows (in thousands): Three Months Ended March 31, --------------------- 2006 2005 --------- --------- Net income................................. $ 246,709 $ 223,621 Foreign currency translation adjustments... 119 (227) Change in fair value of derivatives used for hedging purposes.................. (218,012) (556,835) Reclassification of change in fair value of derivatives to net income......... 102,173 60,920 --------- --------- Total other comprehensive income/(loss).. (115,720) (496,142) --------- --------- Comprehensive income/(loss)................ $ 130,989 $(272,521) ========= ========= 10. Risk Management Energy Commodity Price Risk Management Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil. We use energy financial instruments to reduce our risk of changes in the prices of 39 natural gas, natural gas liquids and crude oil markets, as discussed below. These risk management instruments are also called derivatives, which are defined as a financial instrument or other contract which derives its value from the value of some other (underlying) financial instrument, variable or asset. Examples of derivative instruments include the following: forward contracts, futures contracts, options and swaps (also called contracts for differences). Pursuant to our management's approved risk management policy, we use energy financial instruments as a hedging (offset) mechanism against the volatility of energy commodity prices caused by shifts in the supply and demand for a commodity, as well as its location. Characteristically, we use energy financial instruments to hedge or reduce our exposure to price risk associated with: o pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; o natural gas purchases; and o system use and storage. Our risk management activities are primarily 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. Specifically, our risk management committee is a separately designated standing committee comprised of 15 executive-level employees of KMI or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. Our risk management committee is chaired by our President and is charged with the following three responsibilities: o establish and review risk limits consistent with our risk tolerance philosophy; o recommend to the audit committee of our general partner's delegate any changes, modifications, or amendments to our risk management policy; and o address and resolve any other high-level risk management issues. A derivative contract's cash flow or fair value fluctuates and varies based on the changes in one or more underlying variables (for example, a specified interest rate, commodity price, or other variable), and the contract is based on one or more notional amounts or payment provisions or both (for example, a number of commodities, shares, or other units specified in a derivative instrument). While the value of the underlying variable changes due to changes in market conditions, the notional amount remains constant throughout the life of the derivative contract. Together, the underlying and the notional amounts determine the amount of settlement, and, in some cases, whether or not a settlement is required. Current accounting standards require derivatives to be reflected as assets or liabilities at their fair market values and current market values should be used to track changes in derivative holdings; that is, mark-to-market valuation should be employed. The fair value of our 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, including: commodity futures and options contracts, fixed price swaps, and basis swaps. Furthermore, if a company uses derivatives to hedge the fair value of an asset, liability, or firm commitment, then reporting changes in the fair value of the hedged item as well as in the value of the derivative is appropriate. In SFAS No. 133, the Financial Accounting Standards Board defined these hedges as fair value hedges, and the balance sheet impact for a fair value hedge results in both the derivative (asset or liability) and the hedged item being reported at fair value. When changes in the value of the derivative exactly offset changes in the value of the hedged item, there should be no impact on earnings (net income); however, when the derivative is not effective in exactly offsetting changes in the value of the hedged item, then the ineffective amount should be included in earnings. 40 To be considered 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. A perfectly effective hedge is one in which changes in the value of the derivative exactly offset changes in the value of the hedged item or expected cash flow of the future transactions in reporting periods covered by the hedging instrument. The ineffective portion of the gain or loss and any component excluded from the computation of the effectiveness of the derivative instrument is reported in earnings immediately. Our energy commodity derivatives hedge the commodity price risks derived from our normal business activities, which include the sale of natural gas, natural gas liquids and crude oil, and these derivatives have been designated by us as cash flow hedges as defined by SFAS No. 133. A cash flow hedge uses a derivative to hedge the anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain. With a cash flow hedge, it is the cash flow from an expected future transaction that is being hedged (as opposed to the value of an asset, liability, or firm commitment) and so there is no balance sheet entry for the hedged item. According to the provisions of SFAS No. 133, the FASB allows for special accounting treatment for cash flow hedges--the change in the fair value of the hedging instrument (derivative), to the extent that the hedge is effective, is initially reported as a component of other comprehensive income (outside "Net Income" reported in our consolidated statements of income). Other comprehensive income consists of those financial items that are included in "Accumulated other comprehensive loss" in our accompanying consolidated balance sheets but not included in our net income. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivatives and there is no impact on earnings. When the hedged forecasted transaction does take place and affects earnings, the effective part of the hedge is also recognized in the income statement, and the earlier recognized amounts are removed from "Accumulated other comprehensive loss." If the forecasted transaction results in an asset or liability, amounts in "Accumulated other comprehensive loss" should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc. The gains and losses that are included in "Accumulated other comprehensive loss" in our accompanying consolidated balance sheets are primarily related to the derivative instruments associated with our hedging of anticipated future cash flows from the sales and purchases of natural gas, natural gas liquids and crude oil. As described above, these gains and losses are reclassified into earnings as the hedged sales and purchases take place. During the three months ended March 31, 2006, we reclassified $102.2 million of Accumulated other comprehensive loss into earnings as a result of hedged forecasted transactions occurring during the period. During the three months ended March 31, 2005, we reclassified $60.9 million of Accumulated other comprehensive loss into earnings as a result of hedged forecasted transactions occurring during the period. None of the reclassification of Accumulated other comprehensive loss into earnings during the first three months of 2006 or 2005 resulted from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period, but rather resulted from the hedged forecasted transactions actually affecting earnings (for example, when the forecasted sales and purchases actually occurred). For all of our derivatives combined, approximately $437.3 million of the Accumulated other comprehensive loss balance of $1,195.4 million as of March 31, 2006 is expected to be reclassified into earnings during the next twelve months. As discussed above, the part of the change in the value of derivatives that are not effective in offsetting undesired changes in expected cash flows (the ineffective portion) is required to be recognized currently in earnings. Accordingly, we recognized a loss of $0.2 million during the first quarter of 2006, and a loss of $0.2 million during the first quarter of 2005 as a result of ineffective hedges. All gains and losses recognized as a result of ineffective hedges are reported within the captions "Natural gas sales" and "Gas purchases and other costs of sales" in our accompanying consolidated statements of income. For each of the three months ended March 31, 2006 and 2005, we did not exclude any component of the derivative instruments' gain or loss from the assessment of hedge effectiveness. The fair values of our energy financial instruments are included in our accompanying consolidated balance sheets within "Other current assets," "Deferred charges and other assets," "Accrued other current liabilities," "Other 41 long-term liabilities and deferred credits," and, as of December 31, 2005 only, "Accounts payable-Related parties." The following table summarizes the fair values of our energy financial instruments associated with our commodity market risk management activities and included on our accompanying consolidated balance sheets as of March 31, 2006 and December 31, 2005 (in thousands): March 31, December 31, 2006 2005 ----------- -------------- Derivatives-net asset/(liability) Other current assets................ $ 85,789 $ 109,437 Deferred charges and other assets... 25,459 47,682 Accounts payable-Related parties.... -- (16,057) Accrued other current liabilities... (514,992) (507,306) Other long-term liabilities and deferred credits.................... $(791,307) $(727,929) Our over-the-counter swaps and options are instruments we entered into with counterparties outside centralized trading facilities such as a futures, options or stock exchange. These contracts are with a number of parties, all of which had investment grade credit ratings as of March 31, 2006. 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. In addition, in conjunction with the purchase of exchange-traded derivatives or when the market value of our derivatives with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of March 31, 2006, we had five outstanding letters of credit totaling $394 million in support of our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil. As of December 31, 2005, we had five outstanding letters of credit totaling $534 million in support of our hedging of commodity price risks. As of March 31, 2006, our margin deposits associated with our commodity contract positions and over-the-counter swap partners totaled $33.1 million; as of December 31, 2005, we had no cash margin deposits associated with our commodity contract positions and over-the-counter swap partners. Certain of our business activities expose us to foreign currency fluctuations. However, due to the limited size of this exposure, 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. As a result, we do not significantly hedge our exposure to fluctuations in foreign currency. Interest Rate Risk Management 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 both March 31, 2006 and December 31, 2005, we were a party to interest rate swap agreements with notional principal amounts of $2.1 billion. We entered into these agreements for the purposes of: o hedging the interest rate risk associated with our fixed rate debt obligations; and o transforming a portion of the underlying cash flows related to our long- term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Since the fair value of fixed rate debt varies with changes in the market rate of interest, we enter into swaps to receive fixed and pay variable interest. Such swaps result in future cash flows that vary with the market rate of interest, and therefore hedge against changes in the fair value of our fixed rate debt due to market rate changes. 42 As of March 31, 2006, a notional principal amount of $2.1 billion of these agreements effectively converts the interest expense associated with the following series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread: o $200 million principal amount of our 5.35% senior notes due August 15, 2007; o $250 million principal amount of our 6.30% senior notes due February 1, 2009; o $200 million principal amount of our 7.125% senior notes due March 15, 2012; o $250 million principal amount of our 5.0% senior notes due December 15, 2013; o $200 million principal amount of our 5.125% senior notes due November 15, 2014; o $300 million principal amount of our 7.40% senior notes due March 15, 2031; o $200 million principal amount of our 7.75% senior notes due March 15, 2032; o $400 million principal amount of our 7.30% senior notes due August 15, 2033; and o $100 million principal amount of our 5.80% senior notes due March 15, 2035. These swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes, therefore, as of March 31, 2006, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035. 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 in March 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 or seven years. Our interest rate swaps have been designated as fair value hedges as defined by SFAS No. 133. As discussed above, 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. 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 by SFAS No. 133 for fair value hedges of a fixed rate asset or liability using an interest rate swap. 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 under the swaps. Interest expense is accrued monthly and paid semi-annually. When there is no ineffectiveness in the hedging relationship, employing the shortcut method results in the same net effect on earnings, accrual and payment of interest, net effect of changes in interest rates, and level-yield amortization of hedge accounting adjustments as produced by explicitly amortizing the hedge accounting adjustments on the debt. The differences between the fair value and the original carrying value associated with our interest rate swap agreements, that is, the derivatives' changes in fair value, are included within "Deferred charges and other assets" and "Other long-term liabilities and deferred credits" in our accompanying consolidated balance sheets. The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is recognized as "Market value of interest rate swaps" on our accompanying consolidated balance sheets. 43 The following table summarizes the net fair value of our interest rate swap agreements associated with our interest rate risk management activities and included on our accompanying consolidated balance sheets as of March 31, 2006 and December 31, 2005 (in thousands): March 31, December 31, 2006 2005 ---------- ------------ Derivatives-net asset/(liability) Deferred charges and other assets........ $ 51,406 $ 112,386 Other long-term liabilities and deferred credits......................... (41,167) (13,917) --------- --------- Market value of interest rate swaps.... $ 10,239 $ 98,469 ========= ========= 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. As of March 31, 2006, all of our interest rate swap agreements were with counterparties with investment grade credit ratings. 11. Reportable Segments We divide our operations into four reportable business segments: o Products Pipelines; o Natural Gas Pipelines; o CO2; and o Terminals. We evaluate performance principally based on each segments' earnings before depreciation, depletion and amortization, which exclude general and administrative expenses, third-party debt costs and interest expense, unallocable interest income and minority interest. Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies. Our Products Pipelines segment derives its revenues primarily from the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its revenues primarily from the sale, transmission, storage and gathering of natural gas. Our CO2 segment derives its revenues primarily from the production, sale, and transportation of crude oil from fields in the Permian Basin of West Texas and from the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and chemicals. Financial information by segment follows (in thousands): Three Months Ended March 31, ------------------------- 2006 2005 ----------- ----------- Revenues Products Pipelines........................ $ 180,526 $ 171,283 Natural Gas Pipelines..................... 1,829,996 1,472,892 CO2....................................... 174,691 163,163 Terminals................................. 206,388 164,594 ----------- ----------- Total consolidated revenues.............. $ 2,391,601 $ 1,971,932 =========== =========== 44 Three Months Ended March 31, ------------------------- 2006 2005 ----------- ----------- Operating expenses(a) Products Pipelines........................ $ 60,647 $ 52,056 Natural Gas Pipelines..................... 1,697,766 1,357,095 CO2....................................... 58,609 49,509 Terminals................................. 115,781 85,416 ----------- ----------- Total consolidated operating expenses..... $ 1,932,803 $ 1,544,076 =========== =========== Depreciation, depletion and amortization Products Pipelines........................ $ 20,242 $ 19,394 Natural Gas Pipelines..................... 15,933 14,758 CO2....................................... 39,272 38,702 Terminals................................. 17,274 12,173 ----------- ----------- Total consol. depreciation, depletion and amortization.......................... $ 92,721 $ 85,027 =========== =========== Earnings from equity investments Products Pipelines........................ $ 7,865 $ 8,385 Natural Gas Pipelines..................... 11,162 8,430 CO2....................................... 5,658 9,248 Terminals................................. 36 9 ----------- ----------- Total consolidated equity earnings....... $ 24,721 $ 26,072 =========== =========== Amortization of excess cost of equity investments Products Pipelines........................ $ 841 $ 844 Natural Gas Pipelines..................... 69 69 CO2....................................... 504 504 Terminals................................. - - ----------- ----------- Total consol. amortization of excess cost of investments....................... $ 1,414 $ 1,417 =========== =========== Interest income Products Pipelines........................ $ 1,111 $ 1,149 Natural Gas Pipelines..................... 150 171 CO2....................................... - - Terminals................................. - - ----------- ----------- Total segment interest income............ 1,261 1,320 Unallocated interest income............... 603 172 ----------- ----------- Total consolidated interest income....... $ 1,864 $ 1,492 =========== =========== Other, net - income (expense) Products Pipelines........................ $ 95 $ 142 Natural Gas Pipelines..................... 302 (254) CO2....................................... 1 1 Terminals................................. 1,377 (1,210) ----------- ------------ Total consolidated Other, net - income (expense)................................. $ 1,775 $ (1,321) =========== ============ Income tax benefit (expense) Products Pipelines........................ $ (3,055) $ (3,301) Natural Gas Pipelines..................... (312) (457) CO2....................................... (73) (45) Terminals................................. (2,051) (3,772) ------------ ------------ Total consolidated income tax benefit (expense)................................. $ (5,491) $ (7,575) ============ ============ Segment earnings Products Pipelines........................ $ 104,812 $ 105,364 Natural Gas Pipelines..................... 127,530 108,860 CO2....................................... 81,892 83,652 Terminals................................. 72,695 62,032 ----------- ----------- Total segment earnings(b)................. 386,929 359,908 Interest and corporate administrative expenses(c)............................... (140,220) (136,287) ------------ ------------ Total consolidated net income............ $ 246,709 $ 223,621 =========== =========== 45 Three Months Ended March 31, ------------------------- 2006 2005 ----------- -------- Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(d) Products Pipelines........................ $ 125,895 $ 125,602 Natural Gas Pipelines..................... 143,532 123,687 CO2....................................... 121,668 122,858 Terminals................................. 89,969 74,205 ----------- ----------- Total segment earnings before DD&A........ 481,064 446,352 Total consol. depreciation, depletion and amortization.......................... (92,721) (85,027) Total consol. amortization of excess cost of investments....................... (1,414) (1,417) Interest and corporate administrative expenses.................................. (140,220) (136,287) ----------- ----------- Total consolidated net income............. $ 246,709 $ 223,621 =========== =========== Capital expenditures Products Pipelines........................ $ 56,705 $ 41,070 Natural Gas Pipelines..................... 20,469 9,659 CO2....................................... 74,197 52,557 Terminals................................. 42,292 40,522 ----------- ----------- Total consolidated capital expenditures(e) $ 193,663 $ 143,808 =========== =========== March 31, December 31, --------- ------------ 2006 2005 --------- ------------ Assets Products Pipelines........................ $ 3,881,020 $ 3,873,939 Natural Gas Pipelines..................... 4,186,027 4,139,969 CO2....................................... 1,770,149 1,772,756 Terminals................................. 2,098,814 2,052,457 ----------- ----------- Total segment assets..................... 11,936,010 11,839,121 Corporate assets(f)....................... 85,241 84,341 ----------- ----------- Total consolidated assets................ $12,021,251 $11,923,462 =========== =========== (a) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses, depreciation, depletion and amortization, and amortization of excess cost of equity investments. (c) Includes unallocated interest income, interest and debt expense, general and administrative expenses and minority interest expense. (d) Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses. (e) Includes sustaining capital expenditures of $25,665 and $24,209 for the three months ended March 31, 2006 and 2005, respectively. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset. (f) Includes cash, cash equivalents, restricted deposits and certain unallocable deferred charges. We do not attribute interest and debt expense to any of our reportable business segments. For the three months ended March 31, 2006 and 2005, we reported (in thousands) total consolidated interest expense of $77,570 and $60,219, respectively. 12. Pensions and Other Post-retirement Benefits In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk Terminals, Inc. in 1998, we acquired certain liabilities for pension and post-retirement benefits. We provide medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. We also provide the same benefits to former salaried employees of SFPP. Additionally, we will continue to fund these costs 46 for those employees currently in the plan during their retirement years. SFPP's post-retirement benefit plan is frozen, and no additional participants may join the plan. The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement Plan. The benefits under this plan are based primarily upon years of service and final average pensionable earnings; however, benefit accruals were frozen as of December 31, 1998. Net periodic benefit costs for the SFPP post-retirement benefit plan includes the following components (in thousands): Other Post-retirement Benefits ------------------------------ Three Months Ended March 31, ------------------------------ 2006 2005 ------------ ------------ Net periodic benefit cost Service cost......................... $ 2 $ 2 Interest cost........................ 67 77 Expected return on plan assets....... --- -- Amortization of prior service cost... (29) (29) Actuarial (gain)..................... (113) (127) ----- ----- Net periodic benefit cost............ $(73) $(77) ===== ===== Our net periodic benefit cost for the first quarter of 2006 was a credit of $73,000, which resulted in increases to income, largely due to the amortization of an unrecognized net actuarial gain and to the amortization of a negative prior service cost, primarily related to the following: o there have been changes to the plan for both 2004 and 2005 which reduced liabilities, creating a negative prior service cost that is being amortized each year; and o there was a significant drop in 2004 in the number of retired participants reported as pipeline retirees by Burlington Northern Santa Fe, which holds a 0.5% special limited partner interest in SFPP, L.P. As of March 31, 2006, we estimate our overall net periodic post-retirement benefit cost for the year 2006 will be an annual credit of approximately $0.3 million. This amount could change in the remaining months of 2006 if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. 13. Related Party Transactions Plantation Pipe Line Company We own a 51.17% equity interest in Plantation Pipe Line Company. An affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004, Plantation repaid a $10 million note outstanding and $175 million in outstanding commercial paper borrowings with funds of $190 million borrowed from its owners. We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership interest, in exchange for a seven year note receivable bearing interest at the rate of 4.72% per annum. The note provides for semiannual payments of principal and interest on December 31 and June 30 each year beginning on December 31, 2004 based on a 25 year amortization schedule, with a final principal payment of $157.9 million due July 20, 2011. We funded our loan of $97.2 million with borrowings under our commercial paper program. An affiliate of ExxonMobil owns the remaining 48.83% equity interest in Plantation and funded the remaining $92.8 million on similar terms. As of both March 31, 2006 and December 31, 2005, the principal amount receivable from this note was $94.2 million. We included $2.2 million of this balance within "Accounts, notes and interest receivable, net-Related parties" on our accompanying consolidated balance sheets, and we included the remaining $92.0 million balance within "Notes receivable-Related parties." 47 Coyote Gas Treating, LLC We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise Field Services LLC owns the remaining 50% equity interest. We are the managing partner of Coyote Gulch. In June 2001, Coyote repaid the $34.2 million in outstanding borrowings under its 364-day credit facility with funds borrowed from its owners. We loaned Coyote $17.1 million, which corresponds to our 50% ownership interest, in exchange for a one-year note receivable bearing interest payable monthly at LIBOR plus a margin of 0.875%. On June 30, 2002 and June 30, 2003, the note was extended for one year. On June 30, 2004, the term of the note was made month-to-month. In 2005, we reduced our investment in the note by $0.1 million to account for our share of investee losses in excess of the carrying value of our equity investment in Coyote, and as of December 31, 2005, we included the principal amount of $17.0 million related to this note within "Notes Receivable-Related Parties" on our consolidated balance sheet. In March 2006, Enterprise and we agreed to a resolution that would transfer Coyote Gulch's notes payable to Enterprise and us to members' equity. According to the provisions of this resolution, we then contributed the principal amount of $17.0 million related to our note receivable to our equity investment in Coyote Gulch. The $17.0 million amount is included within "Investments" on our consolidated balance sheet as of March 31, 2006. 14. Regulatory Matters FERC Policy statement re: Use of Gas Basis Differentials for Pricing 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. Moreover, in subsequent orders in individual pipeline cases, the FERC has allowed negotiated rate transactions using pricing indices so long as revenue is capped by the applicable maximum rate(s). In a FERC order on rehearing and clarification issued January 19, 2006, the FERC modified its previous policy statement and now will again permit the use of gas commodity basis differentials in negotiated rate transactions without regard to rate or revenue caps. On March 23, 2006, the FERC dismissed rehearing requests and denied requests for clarification--all related to the January 19, 2006 order. Accounting for Integrity Testing Costs On November 5, 2004, the FERC issued a Notice of Proposed Accounting Release that would require FERC jurisdictional entities to recognize costs incurred in performing pipeline assessments that are a part of a pipeline integrity management program as maintenance expense in the period incurred. The proposed accounting ruling was in response to the FERC's finding of diverse practices within the pipeline industry in accounting for pipeline assessment activities. The proposed ruling would standardize these practices. Specifically, the proposed ruling clarifies the distinction between costs for a "one-time rehabilitation project to extend the useful life of the system," which could be capitalized, and costs for an "on-going inspection and testing or maintenance program," which would be accounted for as maintenance and charged to expense in the period incurred. On June 30, 2005, the FERC issued an order providing guidance to the industry on accounting for costs associated with pipeline integrity management requirements. The order is effective prospectively from January 1, 2006. Under the order, the costs to be expensed as incurred include those to: o prepare a plan to implement the program; o identify high consequence areas; o develop and maintain a record keeping system; and 48 o inspect affected pipeline segments. The costs of modifying the pipeline to permit in-line inspections, such as installing pig launchers and receivers, are to be capitalized, as are certain costs associated with developing or enhancing computer software or to add or replace other items of plant. The Interstate Natural Gas Association of America sought rehearing of the FERC's June 30, 2005 order. The FERC denied INGAA's request for rehearing on September 19, 2005. On December 15, 2005, INGAA filed with the United States Court of Appeals for the District of Columbia Circuit, in docket No. 05-1426, a petition for review asking the court whether the FERC lawfully ordered that interstate pipelines subject to FERC rate regulation and related accounting rules must treat certain costs incurred in complying with the Pipeline Safety Improvement Act of 2002, along with related pipeline testing costs, as expenses rather than capital items for purposes of complying with the FERC's regulatory accounting regulations. The implementation of this FERC order on January 1, 2006, had no material impact on our financial position, results of operations, or cash flows in the first quarter of 2006. Our Kinder Morgan Interstate Gas Transmission system expects an increase of approximately $0.8 million in operating expenses in 2006 related to pipeline integrity management programs due to its implementation of this FERC order on January 1, 2006, which will cause KMIGT to expense certain program costs that previously were capitalized. In addition, our intrastate natural gas pipelines located within the State of Texas are not FERC-regulated but instead follow accounting regulations promulgated by the Railroad Commission of Texas. We will maintain our current accounting procedures with respect to our accounting for pipeline integrity testing costs for our intrastate natural gas pipelines. Selective Discounting On November 22, 2004, the FERC issued a notice of inquiry seeking comments on its policy of selective discounting. Specifically, the FERC is asking parties to submit comments and respond to inquiries regarding the FERC's practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons - when the discount is given to meet competition from another gas pipeline. Comments were filed by numerous entities, including Natural Gas Pipeline Company of America (a Kinder Morgan, Inc. affiliate), on March 2, 2005. Several reply comments have subsequently been filed. By an order issued on May 31, 2005, the FERC reaffirmed its existing policy on selective discounting by interstate pipelines without change. Several entities filed for rehearing; however, by an order issued on November 17, 2005, the FERC denied all requests for rehearing. On January 9, 2006, a petition for judicial review of the FERC's May 31, 2005 and November 17, 2005 orders was filed by the Northern Municipal District Group/Midwest Region Gas Task Force Association. Index of Customer Audit On July 14, 2005, the FERC commenced an audit of TransColorado Gas Transmission Company, as well as a number of other interstate gas pipelines, to test compliance with the FERC's requirements related to the filing and posting of the Index of Customers report. On September 21, 2005, the FERC's staff issued a draft audit report which cited two minor issues with TransColorado's Index of Customers filings and postings. Subsequently, on October 11, 2005, the FERC issued a final order which closed its examination, citing the minor issues contained in its draft report and approving the corrective actions planned or already taken by TransColorado. TransColorado has implemented corrective actions and has applied those actions to its most recent Index of Customer filing, dated October 1, 2005. No further compliance action is expected and TransColorado anticipates operating in compliance with applicable FERC rules regarding the filing and posting of its future Index of Customers reports. Notice of Proposed Rulemaking - Market Based Storage Rates On December 22, 2005, the FERC issued a notice of proposed rulemaking to amend its regulations by establishing two new methods for obtaining market based rates for underground natural gas storage services. First, 49 the FERC is proposing to modify its market power analysis to better reflect competitive alternatives to storage. Doing so would allow a storage applicant to include other storage services as well as non-storage products such as pipeline capacity, local production, or liquefied natural gas supply in its calculation of market concentration and its analysis of market share. Secondly, the FERC is proposing to modify its regulations to permit the FERC to allow market based rates for new storage facilities even if the storage provider is unable to show that it lacks market power. Such modifications would be allowed provided the FERC finds that the market based rates are in the public interest, are necessary to encourage the construction of needed storage capacity, and that customers are adequately protected from the abuse of market power. KMI's Natural Gas Pipeline Company of America and our Kinder Morgan Interstate Gas Transmission LLC, as well as numerous other parties, filed comments on the notice of proposed rulemaking on February 27, 2006. 15. Recent Accounting Pronouncements SFAS No. 123R On December 16, 2004, the Financial Accounting Standards Board issued SFAS No. 123R (revised 2004), "Share-Based Payment." This Statement amends SFAS No. 123, "Accounting for Stock-Based Compensation," and requires companies to expense the value of employee stock options and similar awards. Significant provisions of SFAS No. 123R include the following: o share-based payment awards result in a cost that will be measured at fair value on the awards' grant date, based on the estimated number of awards that are expected to vest. Compensation cost for awards that vest would not be reversed if the awards expire without being exercised; o when measuring fair value, companies can choose an option-pricing model that appropriately reflects their specific circumstances and the economics of their transactions; o companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects. Upon settlement of share-based payment awards, the tax effects will be recognized in the income statement or additional paid-in capital; and o public companies are allowed to select from three alternative transition methods - each having different reporting implications. For us, this Statement became effective January 1, 2006. However, we have not granted common unit options or made any other share-based payment awards since May 2000, and as of December 31, 2005, all outstanding options to purchase our common units were fully vested. Therefore, the adoption of this Statement did not have an effect on our consolidated financial statements due to the fact that we have reached the end of the requisite service period for any compensation cost resulting from share-based payments made under our common unit option plan. SFAS No. 154 On June 1, 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections." This Statement replaces Accounting Principles Board Opinion No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements." SFAS No. 154 applies to all voluntary changes in accounting principle, and changes the requirements for accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods' financial statements of a voluntary change in accounting principle unless it is impracticable. In contrast, APB No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. The FASB believes the provisions of SFAS No. 154 will improve financial reporting because its requirement to report voluntary changes in accounting principles via retrospective application, unless impracticable, will enhance the consistency of financial information between periods. 50 The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (January 1, 2006 for us). The Statement does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of the effective date of this Statement. Adoption of this Statement did not have any immediate effect on our consolidated financial statements, and we will apply this guidance prospectively. EITF 04-5 In June 2005, the Emerging Issues Task Force reached a consensus on Issue No. 04-5, or EITF 04-5, "Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights." EITF 04-5 provides guidance for purposes of assessing whether certain limited partners rights might preclude a general partner from controlling a limited partnership. For general partners of all new limited partnerships formed, and for existing limited partnerships for which the partnership agreements are modified, the guidance in EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 did not have an effect on our consolidated financial statements. SFAS No. 155 On February 16, 2006, the FASB issued SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments." This Statement amends SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" and SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." The Statement improves the financial reporting of certain hybrid financial instruments by requiring more consistent accounting that eliminates exemptions and provides a means to simplify the accounting for these instruments. Specifically, it allows financial instruments that have embedded derivatives to be accounted for as a whole (eliminating the need to bifurcate the derivative form its host) if the holder elects to account for the whole instrument on a fair value basis. The provisions of this Statement are effective for all financial instruments acquired or issued after the beginning of an entity's first fiscal year that begins after September 15, 2006 (January 1, 2007 for us). Adoption of this Statement should not have any immediate effect on our consolidated financial statements, and we will apply this guidance prospectively. SFAS No. 156 On March 17, 2006, the FASB issued SFAS No. 156, "Accounting for Servicing of Financial Assets." This Statement amends SFAS No. 140 and simplifies the accounting for servicing assets and liabilities, such as those common with mortgage securitization activities. Specifically, this Statement addresses the recognition and measurement of separately recognized servicing assets and liabilities, and provides an approach to simplify efforts to obtain hedge-like (offset) accounting by permitting a servicer that uses derivative financial instruments to offset risks on servicing to report both the derivative financial instrument and related servicing asset or liability by using a consistent measurement attribute--fair value. An entity should adopt this Statement as of the beginning of its first fiscal year that begins after September 15, 2006 (January 1, 2007 for us). Earlier adoption is permitted as of the beginning of an entity's fiscal year, provided the entity has not yet issued financial statements, including interim financial statements, for any period of that fiscal year. The effective date of this Statement is the date an entity adopts the requirements of this Statement. Adoption of this Statement should not have any immediate effect on our consolidated financial statements, and we will apply this guidance prospectively. 51 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. The following discussion and analysis of our financial condition and results of operations provides you with a narrative on our financial results. It contains a discussion and analysis of the results of operations for each segment of our business, followed by a discussion and analysis of our financial condition. The following discussion and analysis should be read in conjunction with: o our accompanying interim consolidated financial statements and related notes (included elsewhere in this report), and o our consolidated financial statements, related notes and management's discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2005. Critical Accounting Policies and Estimates Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our consolidated financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the fair values used to determine possible asset impairment charges, provisions for uncollectible accounts receivable, exposures under contractual indemnifications and various other recorded or disclosed amounts. Further information about us and information regarding our accounting policies and estimates that we consider to be "critical" can be found in our Annual Report on Form 10-K for the year ended December 31, 2005. There have not been any significant changes in these policies and estimates during the three months ended March 31, 2006. Results of Operations Consolidated Three Months Ended March 31, ---------------------------- 2006 2005 ----------- ---------- (In thousands) Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments Products Pipelines..................................$ 125,895 $ 125,602 Natural Gas Pipelines............................... 143,532 123,687 CO2................................................. 121,668 122,858 Terminals........................................... 89,969 74,205 ----------- ---------- Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)...................................... 481,064 446,352 Depreciation, depletion and amortization expense............................................. (92,721) (85,027) Amortization of excess cost of equity investments... (1,414) (1,417) Interest and corporate administrative expenses(b)... (140,220) (136,287) ----------- ---------- Net income............................................$ 246,709 $ 223,621 =========== ========== ------- (a) Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses. (b) Includes unallocated interest income, interest and debt expense, general and administrative expenses (including unallocated litigation and environmental expenses) and minority interest expense. 52 Driven by improved natural gas sales and storage margins, higher natural gas transportation revenues, and earnings contributions from bulk and liquids terminal operations acquired since the first quarter of 2005, our consolidated net income for the first quarter of 2006 was $246.7 million ($0.53 per diluted unit), as compared to $223.6 million ($0.54 per diluted unit) in consolidated net income for the first quarter of 2005. Total operating revenues earned in the first quarter of 2006 totaled $2,391.6 million, a 21% improvement over revenues of $1,971.9 million earned in the same quarter last year. Additionally, in the first quarter of 2006, we recognized a $5.6 million increase in environmental expense associated with environmental liability adjustments. The $5.6 million increase in environmental expense resulted in a $4.9 million increase in expense to our Products Pipelines segment, a $0.7 million increase in expense to our Terminals business segment, a $0.1 million increase in expense to our Natural Gas Pipelines business segment, and a $0.1 million decrease in expense to our CO2 business segment. The adjustment included a $5.6 million increase in our overall accrued environmental and related claim liabilities, and we included the additional expense within "Operations and maintenance" in our accompanying consolidated statement of income for the three months ended March 31, 2006. Because our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash consists primarily of all our cash receipts, less cash disbursements and changes in reserves), we consider each period's earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. We also use this measure of profit and loss internally for evaluating segment performance and deciding how to allocate resources to our business segments. In the first quarter of 2006, our total segment earnings before depreciation, depletion and amortization totaled $481.1 million, up 8% from the $446.4 million in total segment earnings before depreciation, depletion and amortization in last year's first quarter. Furthermore, we declared a cash distribution of $0.81 per unit for the first quarter of 2006 (an annualized rate of $3.24). This distribution is almost 7% higher than the $0.76 per unit distribution we made for the first quarter of 2005. We hope to declare cash distributions of at least $3.28 per unit for 2006; however, no assurance can be given that we will be able to achieve this level of distribution. Our expectation does not take into account: o any impact from rate reductions due to our Pacific operations' rate case, which we now estimate will be approximately $20 million in 2006; or o the expected $45 million shortfall to our budgeted crude oil production at our SACROC field unit, as described below in "--CO2." Our general partner and our common and Class B unitholders receive quarterly distributions in cash, while KMR, the sole owner of our i-units, receives quarterly distributions in additional i-units. The value of the quarterly per-share distribution of i-units is based on the value of the quarterly per-share cash distribution made to our common and Class B unitholders. Products Pipelines Three Months Ended March 31, ---------------------------- 2006 2005 ------------ ------------ (In thousands, except operating statistics) Revenues........................................ $ 180,526 $ 171,283 Operating expenses(a)........................... (60,647) (52,056) Earnings from equity investments................ 7,865 8,385 Interest income and Other, net-income (expense) 1,206 1,291 Income taxes.................................... (3,055) (3,301) ----------- ---------- Earnings before depreciation, depletion and amortization expense and amortization of 125,895 125,602 excess cost of equity investments........... Depreciation, depletion and amortization expense......................................... (20,242) (19,394) Amortization of excess cost of equity investments..................................... (841) (844) ----------- ---------- Segment earnings.............................. $ 104,812 $ 105,364 =========== ========== 53 Three Months Ended March 31, ---------------------------- 2006 2005 ------------ ------------ Gasoline (MMBbl)............................... 111.6 108.9 Diesel fuel (MMBbl)............................ 38.7 40.2 Jet fuel (MMBbl)............................... 29.5 29.3 ---------- ---------- Total refined product volumes (MMBbl)........ 179.8 178.4 Natural gas liquids (MMBbl).................... 9.8 9.6 ---------- ---------- Total delivery volumes (MMBbl)(b)............ 189.6 188.0 ========== ========== ---------- (a) Includes costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress and Heartland pipeline volumes. Segment Earnings before Depreciation, Depletion and Amortization Our Products Pipelines segment reported earnings before depreciation, depletion and amortization of $125.9 million for the first quarter of 2006, essentially flat versus the $125.6 million of earnings before depreciation, depletion and amortization in the first quarter of 2005. As referred to above in "--Consolidated," the segment's 2006 earnings also include a charge of $4.9 million from the adjustment of our environmental liabilities. The segment's overall $0.3 million increase in quarter-to-quarter segment earnings before depreciation, depletion and amortization expenses primarily consisted of the following: o a $2.1 million (3%) increase from our combined West Coast refined petroleum products pipelines and terminal operations, which include our Pacific operations, our CALNEV Pipeline and our West Coast terminals. The overall increase reflected higher earnings before depreciation, depletion and amortization from our CALNEV Pipeline operations, driven by a $2.3 million (17%) increase in operating revenues. The increase in revenues was due to an almost 12% increase in product delivery volumes and to higher average tariff rates. The higher volumes in 2006 were attributable to both strong demand, primarily from the Las Vegas, Nevada market, and to service interruptions in the first quarter of 2005 resulting from adverse weather on the West Coast. The higher tariffs were due to a Federal Energy Regulatory Commission tariff index increase in July 2005 (producer price index-finished goods adjustment). Earnings before depreciation, depletion and amortization expenses from our Pacific operations and West Coast terminal operations increased $0.3 million and decreased $0.3 million, respectively, in the first quarter of 2006 versus the first quarter of 2005. The increase in earnings from our Pacific operations was driven by a $5.4 million (7%) increase in operating revenues, but largely offset by incremental environmental expenses of $2.7 million and by a $2.0 million (26%) increase in fuel and power costs. The decrease in earnings before depreciation, depletion and amortization expense from our West Coast terminals related to higher property tax expense accruals in the first quarter of 2006, and to settlement income, recognized in the first quarter of 2005, related to sale negotiations on our Gaffey Street terminal, which was closed in the fourth quarter of 2004; o a $0.9 million (13%) increase from our Southeast product terminal operations, primarily due to higher product inventory sales at higher average prices; o a $0.8 million (7%) decrease from our approximate 51% ownership interest in Plantation Pipe Line Company, chiefly due to lower equity earnings. The decrease reflects lower overall net income earned by Plantation in the first quarter of 2006, due primarily to higher oil loss expenses related to higher product prices, and lower transportation revenues. Compared to last year's first quarter, Plantation's overall pipeline deliveries of refined products declined 4% in 2006, due principally to warmer than normal winter weather, and partly to incremental volumes being diverted to competing pipelines in the first quarter of 2006 versus the first quarter of 2005; and o a $0.6 million decrease from each of our North System, Central Florida Pipeline, and petroleum pipeline transmix processing operations. The decrease from our North System was primarily due to a 50% increase in fuel and power expenses, due to higher fuel and natural gas prices in first quarter 2006 versus first quarter 2005. The decrease from our Central Florida Pipeline was largely due to incremental environmental expenses 54 of $1.1 million. The decrease from our transmix operations was primarily due to lower revenues as a result of a 7% decrease in overall processing volumes, largely due to a decrease at our Indianola, Pennsylvania transmix facility. Segment Details The segment reported revenues of $180.5 million in the first quarter of 2006 and $171.3 million in the first quarter of 2005. The $9.2 million (5%) quarter-to-quarter increase in segment revenues was primarily due to the following: o a $5.4 million (7%) increase from our Pacific operations, consisting of a $3.5 million (6%) increase in refined product delivery revenues and a $1.9 million (9%) increase in product terminal revenues. The increase from product delivery revenues was due to an over 3% increase in mainline delivery volumes and an over 2% increase in average tariff rates, which included both the FERC approved 2005 annual indexed interstate tariff increase and a requested rate increase with the California Public Utility Commission. In November 2004, we filed an application with the CPUC requesting a $9 million increase in existing intrastate transportation rates to reflect the in-service date of our $95 million North Line expansion project. Pursuant to CPUC regulations, this increase automatically became effective as of December 22, 2004, but is being collected subject to refund, pending resolution of protests to the application by certain shippers. The CPUC may resolve the matter in the second quarter of 2006. The increase from terminal revenues was due to the higher transportation volumes and to incremental revenues from diesel lubricity-improving injection services that we began offering in May 2005; o a $2.3 million (17%) increase from our CALNEV Pipeline, as discussed above; o a $1.7 million (13%) increase from our West Coast terminals, related to rent escalations, higher throughput barrels and rates at various locations, and additional tank capacity at our Los Angeles Harbor terminal; o a $0.5 million (5%) increase from our Central Florida Pipeline, driven by an over 6% increase in the average tariff per barrel moved; and o a $1.1 million (7%) decrease from our Southeast terminals, largely attributable to lower butane revenues (partially offset by lower butane purchases) related to changes in customer agreements, partly offset by higher revenues from expanded storage agreements from terminal operations we acquired in November 2004 from Charter Terminal Company and Charter-Triad Terminals, LLC. Combining all of the segment's operations, total delivery volumes of refined petroleum products increased 0.8% in the first quarter of 2006, compared to the first quarter of 2005. Increases on our Pacific and CALNEV systems were offset by decreases on Plantation and Central Florida, due principally to warmer winter weather in the Southeast. Gasoline volumes for all pipelines in this segment were up 2.5% quarter-over-quarter, and excluding Plantation, segment deliveries of gasoline, diesel fuel and jet fuel increased 0.9%, 4.7% and 7.3%, respectively, in the first quarter of 2006, compared to the first quarter of 2005. Quarter-to-quarter deliveries of natural gas liquids were up 2.1%, as higher volumes on our Cypress Pipeline more than offset a drop in volumes on our North System. The increase from Cypress was due to increased demand from a petrochemical plant in Lake Charles, Louisiana that is served by the pipeline; the decrease from our North System was due to continued low demand for propane, primarily due to warmer winter weather across the Midwest. The FERC has set the oil pipeline tariff rate index increase that will apply beginning July 1, 2006, at producer price index plus 1.3%, which will positively impact the results of operations of our Products Pipelines segment beginning in the third quarter. The segment's combined operating expenses, which consist of all cost of sales expenses, operating and maintenance expenses, fuel and power expenses, and all tax expenses, excluding income taxes, increased $8.6 million (17%) in the first quarter of 2006, compared to the same year-ago period. The overall increase in operating expenses was mainly due to the following: 55 o a $5.2 million (28%) increase from our Pacific operations, due to the incremental environmental expenses of $2.7 million and the $2.0 million increase in fuel and power costs described above, and to a $0.5 million increase in operating expenses mainly associated with increased terminal activities. The increase in fuel and power expenses was due to both product delivery volume and utility rate increases, in 2006, and a utility rebate credit received in the first quarter of 2005; o a $1.8 million (42%) increase from our West Coast terminals, primarily related to incremental environmental expenses and to higher labor expenses, due to pay period timing differences and an increase in the number of employees; o a $1.1 million (56%) increase from our Central Florida Pipeline operations, due to the first quarter 2006 environmental expense adjustments discussed above; o a $0.8 million (16%) increase from our North System, due to higher fuel and power expenses and slightly higher natural gas liquids product losses; o a $0.7 million (13%) increase from the operation of the Plantation Pipeline, due primarily to higher labor expenses following timing differences that resulted in an additional pay period in the first quarter of 2006 versus the first quarter of 2005; and o a $2.0 million (27%) decrease from our Southeast terminals, largely attributable to lower butane purchases, discussed above, and higher fuel costs. The segment's equity investments consist of our approximate 51% interest in Plantation Pipe Line Company, our 50% interest in the Heartland Pipeline Company, and our 50% interest in Johnston County Terminal, LLC that was included in our November 2004 Charter products terminals acquisition. Earnings from these investments decreased $0.5 million (6%) in the first quarter of 2006, when compared to the same period last year. The decrease was primarily due to a $0.7 million (10%) decrease in equity earnings from our investment in Plantation, due to overall lower net income as described above. The segment's income from allocable interest income and other income and expense items remained flat quarter-over-quarter, and income tax expenses decreased $0.2 million (7%) in the first quarter of 2006, due primarily to the lower pre-tax earnings from Plantation. Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of equity investments, increased $0.8 million (4%) in the first quarter of 2006, when compared to the same period last year. The increase was primarily due to incremental depreciation charges associated with our Southeast terminal and Pacific operations' assets. The increase from our Southeast terminals reflected additional depreciation charges related to our final purchase price allocation, made in the fourth quarter of 2005, for depreciable terminal assets we acquired in November 2004 from Charter Terminal Company and Charter-Triad Terminals, LLC. The increase from our Pacific operations related to higher depreciable costs as a result of the capital spending we have made since the end of the first quarter of 2005. 56 Natural Gas Pipelines Three Months Ended March 31, ---------------------------- 2006 2005 ----------- ----------- (In thousands, except operating statistics) Revenues......................................... $ 1,829,996 $ 1,472,892 Operating expenses(a)............................ (1,697,766) (1,357,095) Earnings from equity investments................. 11,162 8,430 Interest income and Other, net-income (expense).. 452 (83) Income taxes..................................... (312) (457) ----------- ----------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments......... 143,532 123,687 Depreciation, depletion and amortization expense.......................................... (15,933) (14,758) Amortization of excess cost of equity investments...................................... (69) (69) ----------- ----------- Segment earnings............................... $ 127,530 $ 108,860 =========== =========== Natural gas transport volumes (Trillion Btus)(b)............................... 336.6 338.0 =========== =========== Natural gas sales volumes (Trillion Btus)(c)..... 223.5 226.6 =========== =========== ---------- (a) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate natural gas pipeline group, Trailblazer and TransColorado pipeline volumes. (c) Represents Texas intrastate natural gas pipeline group. Segment Earnings before Depreciation, Depletion and Amortization Our Natural Gas Pipelines segment reported earnings before depreciation, depletion and amortization of $143.5 million in the first quarter of 2006, and $123.7 million in earnings before depreciation, depletion and amortization in the first quarter of 2005. The segment's overall $19.8 million (16%) increase in the first quarter of 2006 versus the first quarter of 2005 primarily consisted of the following: o a $16.3 million (26%) increase from our Texas intrastate natural gas pipeline group, due primarily to improved margins from natural gas sales activities and higher natural gas transportation and storage demand revenues on our Kinder Morgan Texas and Kinder Morgan Tejas pipeline systems. Combined, these two systems reported a $14.4 million (25%) increase in quarter-to-quarter earnings before depreciation, depletion and amortization, driven by a $9.4 million (33%) increase in gross margin (revenues less cost of sales) from natural gas sales and purchases, higher transportation and storage revenues, and favorable settlements of pipeline transportation imbalances. Margin is defined as the difference between the prices at which we buy gas in our supply areas and the prices at which we sell gas in our market areas, less the cost of fuel to transport. We realize earnings by capturing the favorable differences between the changes in our gas sales prices, purchase prices and transportation costs, including fuel. In addition, our Texas intrastate group earns revenues from natural gas sales and transportation activities on our Mier-Monterrey Mexico and Kinder Morgan North Texas pipelines. Combined, these two systems reported a $1.9 million (38%) increase in earnings before depreciation, depletion and amortization in 2006 compared to 2005, primarily due to incremental gross margins from natural gas sales on our Kinder Morgan North Texas Pipeline; o a $3.0 million (42%) increase from our 49% equity investment in the Red Cedar Gathering Company, related to Red Cedar's higher year-over-year net income in 2006 that was largely driven by higher prices on incremental sales of excess fuel gas and by higher natural gas gathering revenues; o a $1.8 million (21%) increase from our TransColorado Pipeline, due primarily to higher gas transmission revenues, related to higher delivery volumes. The increase in volumes resulted from system improvements 57 associated with an expansion, completed since the end of the first quarter of 2005, on the northern portion of the pipeline. TransColorado's north system expansion project was in-service on January 1, 2006, and provides for up to 300 million cubic feet per day of additional northbound transportation capacity; o a $1.8 million (55%) increase from our Casper Douglas natural gas gathering and processing operations, due mainly to favorable gas imbalance gains and to comparative differences in hedge settlements associated with the rolling-off of older low price crude oil and propane positions at December 31, 2005; and o a $3.6 million (22%) decrease from our Trailblazer Pipeline, due to timing differences on the settlements of pipeline transportation imbalances in the first quarter of 2006 versus the first quarter of 2005. These pipeline imbalances were due to differences between the volumes nominated and volumes delivered at an inter-connecting point by the pipeline. Additionally, on April 18, 2006, we announced that we have entered into a long-term agreement with CenterPoint Energy Resources Corp. to provide the natural gas utility with firm transportation and storage services through our Texas intrastate natural gas pipeline group. According to the provisions of the agreement, CenterPoint Energy has contracted for one billion cubic feet per day of natural gas transportation capacity and 16 billion cubic feet of natural gas storage capacity, effective April 1, 2007. Currently, our Intrastate group is pursuing projects to expand the transport and storage capabilities in its system in order to take advantage of increasing gas production in East Texas and pending liquefied natural gas supplies targeted for the Texas Gulf Coast. Segment Details Total segment operating revenues, including revenues from natural gas sales, increased $357.1 million (24%) in the first quarter of 2006, compared to the same year-earlier quarter. Combined operating expenses, including natural gas purchase costs, increased $340.7 million (25%). The increases in revenues and operating expenses were largely due to higher natural gas sales revenues and higher natural gas cost of sales, respectively, due mainly to higher average natural gas prices in the first quarter of 2006, and to the purchase and sales activities of our Texas intrastate natural gas pipeline group. Although the Intrastate group's natural gas sales volumes decreased 1% in the first quarter of 2006 versus the first quarter of 2005, revenues from the sales of natural gas increased $339.9 million (25%); similarly, the Texas intrastate group's costs of sales, including natural gas purchase costs, increased $329.6 million (25%) in the first three months of 2006 versus the first three months of 2005. Changes in the segment's period-to-period sales revenues and costs of sales are largely impacted by changes in energy commodity prices. However, due to the fact that our Texas intrastate group sells natural gas in the same price environment in which it is purchased, the increases in gas sales revenues are largely offset by corresponding increases in gas purchase costs. For the comparative three month periods, the average price for natural gas sold by our Kinder Morgan Texas and Kinder Morgan Tejas systems increased 28% (from $5.93 per million British thermal units in 2005 to $7.57 per million British thermal units in 2006). The increases in natural gas sales and costs of sales from the Texas intrastate group also included incremental amounts of $19.1 million and $18.4 million, respectively, from our Kinder Morgan North Texas Pipeline, due to the fact that the pipeline did not begin purchasing and selling natural gas until June 2005. The purchase and sale activities of our Texas intrastate group result in considerably higher revenues and operating expenses compared to the interstate operations of our Rocky Mountain pipelines, which include our Kinder Morgan Interstate Gas Transmission, Trailblazer, TransColorado and Rockies Express pipelines. All four pipelines charge a transportation fee for gas transmission service and have the authority to initiate natural gas sales for operational purposes, but none engage in significant gas purchases for resale. Our Rockies Express Pipeline began limited interim service in the first quarter of 2006 on its westernmost segment (the segment that extends from Meeker, Colorado to Wamsutter, Wyoming). Construction of the second segment of the pipeline (that extends from Wamsutter to Cheyenne, Wyoming) is scheduled to begin this summer, and the entire line is expected to be in service by January 1, 2007. Our revenues and expenses will not be impacted 58 during the construction of the pipeline due to the fact that regulatory accounting provisions require capitalization of revenues and expenses until the second segment of the project is complete and in-service. We account for the segment's investments in Red Cedar Gathering Company, Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity method of accounting. In the first quarter of 2006, equity earnings from these three investees increased $2.7 million (32%), when compared to the first quarter of 2005. The increase was chiefly due to the $3.0 million increase in equity earnings from Red Cedar, as described above. The segment's interest income and earnings from other income items increased $0.5 million in the first quarter of 2006, compared to the first quarter of 2005. The increase was mainly due to incremental litigation expense accruals, recognized in the first quarter of 2005, by our Kinder Morgan North Texas Pipeline. Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments, increased $1.2 million (8%) in the first quarter of 2006, when compared to the same period last year. The increase was largely due to higher depreciation charges on our Kinder Morgan Texas system due to the acquisition of our North Dayton, Texas natural gas storage facility in August 2005. We allocated $64.1 million of our total purchase price of $109.4 million to our depreciable asset base. CO2 Three Months Ended March 31, --------------------------- 2006 2005 ----------- ---------- (In thousands, except operating statistics) Revenues....................................... $ 174,691 $ 163,163 Operating expenses(a).......................... (58,609) (49,509) Earnings from equity investments............... 5,658 9,248 Other, net-income (expense).................... 1 1 Income taxes................................... (73) (45) ----------- ---------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments......... 121,668 122,858 Depreciation, depletion and amortization expense(b)..................................... (39,272) (38,702) Amortization of excess cost of equity investments.................................... (504) (504) ----------- ---------- Segment earnings............................. $ 81,892 $ 83,652 =========== ========== Carbon dioxide delivery volumes (Bcf)(c)......... 172.4 169.9 =========== ========== SACROC oil production (gross)(MBbl/d)(d)......... 31.3 33.8 =========== ========== SACROC oil production (net)(MBbl/d)(e)........... 26.1 28.1 =========== ========== Yates oil production (gross)(MBbl/d)(d).......... 25.0 24.1 =========== ========== Yates oil production (net)(MBbl/d)(e)............ 11.1 10.7 =========== ========== Natural gas liquids sales volumes (net)(MBbl/d)(e)................................. 9.3 9.7 =========== ========== Realized weighted average oil price per Bbl(f)(g).................................... $ 30.47 $ 28.81 =========== ========== Realized weighted average natural gas liquids price per Bbl(g)(h)...................... $ 41.35 $ 33.97 =========== ========== ---------- (a) Includes costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes depreciation, depletion and amortization expense associated with oil and gas producing and gas processing activities in the amount of $34,590 for the first quarter of 2006 and $34,313 for the first quarter of 2005. Includes depreciation, depletion and amortization expense associated with sales and transportation services activities in the amount of $4,682 for the first quarter of 2006 and $4,389 for the first quarter of 2005. (c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes. (d) Represents 100% of the production from the field. We own an approximate 97% working interest in the SACROC unit and an approximate 50% working interest in the Yates unit. (e) Net to Kinder Morgan, after royalties and outside working interests. (f) Includes all Kinder Morgan crude oil production properties. (g) Hedge gains/losses for oil and natural gas liquids are included with crude oil. (h) Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements. 59 Segment Earnings before Depreciation, Depletion and Amortization Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates. The segment's primary businesses involve the production, transportation and marketing of carbon dioxide, commonly called CO2, and the production, marketing and transportation of crude oil, natural gas and natural gas liquids. For the first quarter of 2006, the segment reported earnings before depreciation, depletion and amortization of $121.7 million, down a slight 1% from the $122.9 million of earnings before depreciation, depletion and amortization reported for the first quarter last year. The overall $1.2 million decrease in quarter-to-quarter segment earnings before depreciation, depletion and amortization included the following: o a $6.6 million (8%) decrease in earnings before depreciation, depletion and amortization expenses from the segment's oil and natural gas producing activities, which include its natural gas processing activities. The decrease was largely attributable to a $10.0 million (18%) increase in combined operating expenses, due primarily to higher well workover expenses, higher fuel and power expenses, and higher property and severance taxes. The increase in operating expenses more than offset a $3.4 million (2%) increase in revenues, due primarily to increased prices on the sales of both natural gas liquids and crude oil, as discussed below; and o a $5.4 million (15%) increase in earnings before depreciation, depletion and amortization from the segment's carbon dioxide sales and transportation activities. The increase was driven by higher revenues from carbon dioxide sales, higher carbon dioxide and crude oil pipeline transportation revenues, and higher oil field and processing plant service revenues. On a gross basis (meaning total quantity produced) combined daily oil production from the two largest oil field units in which we hold ownership interests decreased almost 3% in the first quarter of 2006, as compared to the same prior-year period. The two oil field interests include our approximate 97% working interest in the SACROC unit and our approximate 50% working interest in the Yates oil field unit, both located in the Permian Basin area of West Texas. Similarly, natural gas plant liquids product sales volumes decreased 4% in the first quarter of 2006 when compared with the first quarter last year, largely due to the quarter-to-quarter decrease in production from the SACROC unit. Average oil production increased by almost 4% quarter-over-quarter at Yates, but decreased 7% at the SACROC unit. For the entire year of 2006, production at Yates is expected to exceed our budgeted average oil production of 24.6 thousand barrels per day by approximately one thousand barrels per day. At SACROC, the decline in production is specific to one section of the field that is underperforming, and we now expect oil production to average approximately three to four thousand barrels per day less for the year than its budget. As a result of this projected shortfall at SACROC, we expect our CO2 segment to underperform its annual published budget of segment earnings before depreciation, depletion and amortization expenses by approximately 8%, or approximately $45 million. However, we benefited from increases of 45%, 22% and 6%, respectively, in our realized weighted average price of carbon dioxide, natural gas liquids and crude oil per barrel in the first quarter of 2006, versus the first quarter of 2005. The increase in average sale prices for carbon dioxide in 2006 compared to 2005 was largely related to an overall improvement in energy prices and to continuing strong demand for carbon dioxide from tertiary oil recovery projects. We do not recognize profits on carbon dioxide sales to ourselves. The higher prices for natural gas liquids reflect favorable gas processing margins, which is the relative difference in economic value (on an energy content basis) between natural gas liquids as a separated liquid, on the one hand, and as a portion of the residue natural gas stream, on the other hand. Had we not used energy financial instruments to transfer commodity price risk, our crude oil sale prices would have averaged $60.62 per barrel in the first quarter of 2006, and $47.93 per barrel in the first quarter of 2005. Because we are exposed to market risks related to the price volatility of crude oil, natural gas and natural gas liquids, we mitigate our commodity price risk through a long-term hedging strategy that is intended to generate more stable, predictable realized prices. Our strategy involves the use and designation of energy financial instruments (derivatives) as hedges to the exposure of fluctuating expected future cash flows produced by unpredictable changes in crude oil and natural gas liquids sales prices. All of our hedge gains and losses for crude oil and natural gas liquids are included in our realized average price for oil; none are allocated to natural gas liquids. For more information on our hedging activities, see Note 10 to our consolidated financial statements, included elsewhere in this report. 60 Segment Details Our CO2 segment reported revenues of $174.7 million in the first quarter of 2006 and $163.2 million in the first quarter of 2005. The $11.5 million (7%) quarter-to-quarter increase in segment revenues included increases of $4.9 million (16%) and $1.4 million (1%), respectively, in plant product and crude oil sales revenues. As described above, the increases were attributable to higher average prices partially offset by decreases in production. In addition, revenues from carbon dioxide sales increased $6.9 million (92%) in the first quarter of 2006 versus the first quarter of 2005, due mainly to higher average sale prices, discussed above, and to slightly higher sales volumes. Carbon dioxide and crude oil pipeline transportation revenues increased $1.2 million (9%) in the three month period of 2006 versus 2005, due primarily to an over 1% increase in carbon dioxide delivery volumes and a $0.4 million (6%) increase in crude oil transportation revenues from our Wink Pipeline. Oil field and processing plant service revenues increased $0.6 million (21%) in the first quarter of 2006 compared to the first quarter of 2005, largely due to increased produced gas third-party processing fees in and around the SACROC oil field unit. Partially offsetting the overall quarter-to-quarter increase in segment revenues was a $4.1 million (66%) decrease in natural gas sales revenues, attributable to lower sales volumes. The decrease in volumes sold was largely due to natural gas volumes used at the power plant we constructed at the SACROC oil field unit and placed in service in June 2005. As a result, we had lower volumes of gas available for sale in the first quarter of 2006 versus the first quarter last year. The segment's combined operating expenses increased $9.1 million (18%) in the first quarter of 2006, versus the same prior-year period. The increase was primarily the result of higher field operating and maintenance expenses, property and production taxes, and fuel and power expenses. The increase in field operating and maintenance expenses was largely due to higher well workover and completion expenses, including labor, related to infrastructure expansions at the SACROC and Yates oil field units since the end of the first quarter last year. Workover expenses relate to incremental operating and maintenance charges incurred on producing wells in order to restore or increase production. Workovers are often performed in order to stimulate production, add pumping equipment, remove fill from the wellbore, to mechanically repair the well, or for other reasons. The increase in property taxes was related to both increased asset infrastructure and higher assessed property values since the end of the first quarter of 2005. The increase in production (severance) taxes was driven by higher crude oil revenues. The increase in fuel and power expenses was due to increased carbon dioxide compression and equipment utilization, higher fuel costs, and higher electricity expenses due to higher rates as a result of higher fuel costs to electricity providers. Overall higher electricity costs were partly offset by the benefits provided from the power plant we constructed at the SACROC oil field unit, described above. KMI operates the power plant, which provides the majority of SACROC's electricity needs, and we reimburse KMI for its costs to operate and maintain the plant. Earnings from equity investments, representing the equity earnings from our 50% ownership interest in the Cortez Pipeline Company, decreased $3.6 million (39%) in the first quarter of 2006, when compared to the first quarter of 2005. The decrease was due to lower overall net income earned by Cortez. The lower earnings were primarily due to lower carbon dioxide transportation revenues as a result of lower average tariff rates, which more than offset an almost 3% increase in carbon dioxide delivery volumes. Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments, increased $0.6 million (1%) in the first quarter of 2006, when compared to the same period last year. The increase was due to higher depreciable costs, related to incremental capital spending since March 2005. 61 Terminals Three Months Ended March 31, ---------------------------- 2006 2005 ----------- ---------- (In thousands, except operating statistics) Revenues....................................... $ 206,388 $ 164,594 Operating expenses(a).......................... (115,781) (85,416) Earnings from equity investments............... 36 9 Other, net-income (expense).................... 1,377 (1,210) Income taxes................................... (2,051) (3,772) ----------- ---------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments......... 89,969 74,205 Depreciation, depletion and amortization expense........................................ (17,274) (12,173) Amortization of excess cost of equity investments.................................... - - ----------- ---------- Segment earnings............................. $ 72,695 $ 62,032 =========== =========== Bulk transload tonnage (MMtons)(b)............. 22.0 23.1 =========== ========== Liquids leaseable capacity (MMBbl)............. 42.8 36.6 =========== ========== Liquids utilization %.......................... 97.8% 96.7% =========== ========== ---------- (a) Includes costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Volumes for acquired terminals are included for both periods. Segment Earnings before Depreciation, Depletion and Amortization Our Terminals segment includes the operations of our petroleum and petrochemical-related liquids terminal facilities (other than those included in our Products Pipelines segment) as well as all of our coal and dry-bulk material services, including all transload, engineering and other in-plant services. For the first three months of 2006 and 2005, the segment reported earnings before depreciation, depletion and amortization of $90.0 million and $74.2 million, respectively. Terminal operations acquired since the end of the first quarter of 2005 and identified separately in post-acquisition periods included the following: o our Texas petroleum coke terminals and repair shop assets, located in and around the Ports of Houston and Beaumont, Texas, acquired separately in April and September 2005, respectively; o three terminals acquired separately in July 2005: our Kinder Morgan Staten Island terminal, a dry-bulk terminal located in Hawesville, Kentucky and a liquids/dry-bulk facility located in Blytheville, Arkansas; o all of the ownership interests in General Stevedores, L.P., which operates a break-bulk terminal facility located along the Houston Ship Channel, acquired July 31, 2005; and o our Kinder Morgan Blackhawk terminal located in Black Hawk County, Iowa, acquired in August 2005. Combined, these operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $15.1 million, revenues of $30.0 million and operating expenses of $14.9 million in the first quarter of 2006. Most of the increase in operating results from acquisitions was attributable to our Texas petroleum coke bulk terminals, which we acquired from Trans-Global Solutions, Inc. for an aggregate consideration of approximately $247.2 million. The acquired assets include facilities at the Port of Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship Channel. Combined, these terminal operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $13.0 million, revenues of $24.7 million and operating expenses of $11.7 million in the first quarter of 2006. For all other terminal operations (those owned during both years), earnings before depreciation, depletion and amortization were essentially flat, increasing $0.7 million (1%) in the first quarter of 2006 versus the first quarter of 62 2005. The overall increase included a $2.3 million (14%) increase from our Pasadena and Galena Park, Texas Gulf Coast liquids facilities, two large terminals located on the Houston Ship Channel that serve as a distribution hub for Houston's crude oil refineries. The increase was driven by higher revenues from excess throughput charges, incremental sales of petroleum transmix, new customer agreements and higher truck loading rack service fees. We also benefited from record volumes of steel imports at our bulk terminal located in Fairless Hills, Pennsylvania and record volumes of fertilizer imports at both our Port Sutton, Florida terminal and our Elizabeth River bulk terminal located in Chesapeake, Virginia. The overall increase in earnings from terminals owned both quarters was offset by a $1.2 million (14%) decrease from our Lower Mississippi River (Louisiana) region, largely due to a $2.3 million decrease from our International Marine Terminals facility, a Louisiana partnership owned 66 2/3% by us. IMT, located in Port Sulphur, Louisiana, suffered property damage and a general loss of business due to the effects of Hurricane Katrina, which struck the Gulf Coast in the third quarter of 2005. For our entire liquids terminals combined, total throughput volumes decreased 3.6% in the first quarter of 2006, versus the same period in 2005. The decrease was primarily due to lower petroleum volumes at our Pasadena terminal, due in large part to the continued shutdown of a Texas-based refinery that was impacted by Hurricane Rita, which struck the Texas-Louisiana Gulf Coast in the third quarter of 2005; however, earnings before depreciation, depletion and amortization were still up in first quarter 2006 versus first quarter 2005 due to the factors discussed above. Through a combination of business acquisitions and internal capital spending, we have increased our liquids leaseable capacity by 6.2 million barrels (17%) since the end of the first quarter of 2005, while at the same time, increasing our liquids utilization rate (the ratio of our actual capacity to our estimated potential capacity) by 1.1%. Segment Details Segment revenues for all terminals owned during both three month periods increased $11.8 million (7%) in the first quarter of 2006, when compared to the same prior-year period. The quarter-to-quarter increase was primarily due to the following: o a $4.4 million (19%) increase from our Mid-Atlantic region, due primarily to higher steel volumes at our Fairless Hills terminal, and to higher tank rentals and cement and petroleum coke volumes at our Shipyard River terminal, located in Charleston, South Carolina; o a $3.5 million (15%) increase from our Pasadena and Galena Park Gulf Coast facilities, as discussed above; and o a $3.3 million (96%) increase from engineering and terminal design services, due to both incremental revenues from new clients and increased revenues from existing clients starting new projects due to economic growth. Operating expenses for all terminals owned during both quarters increased $15.5 million (18%) in the first quarter of 2006, when compared to the first quarter of 2005. The overall increase in segment operating expenses included increases of: o $4.9 million (26%) from our Louisiana terminals, largely due to additional insurance, property damage and demurrage expenses related to hurricanes Katrina and Rita; o $3.6 million (110%) from engineering-related services, due primarily to higher salary, overtime and other employee-related expenses, as well as increased contract labor, all associated with the increased project work described above; o $2.8 million (21%) from our Mid-Atlantic terminals, largely due to higher operating and maintenance expenses at our Fairless Hills terminal, due to the increase in steel products handled. This includes higher wharfage, trucking and general maintenance expenses; 63 o $1.4 million (10%) from our Midwest terminals, mainly due to a $0.5 million increase at our Cora, Illinois coal terminal and a $0.4 million increase at our Argo, Illinois liquids terminal facility. Both increases were largely due to higher operating and maintenance expenses--related to a 32% increase in coal transfer volumes at Cora, and a 15% increase in liquids throughput volume at Argo; o $1.2 million (17%) from our Pasadena and Galena Park, Texas Gulf Coast terminals, due to incremental labor expenses, power expenses and permitting fees; and o $1.1 million (18%) from our Southeast region, due primarily to higher labor and equipment maintenance at our Port Sutton, Florida bulk terminal, related to higher bulk tonnage. The segment's other income items increased $2.6 million in the first quarter of 2006, versus the first quarter of 2005. The increase included incremental income of $1.8 million, recognized in the first quarter of 2006, related to a favorable settlement associated with our purchase of the Kinder Morgan St. Gabriel terminal in September 2002. The overall increase in other income also included a $1.2 million increase due to a disposal loss, recognized in the first quarter of 2005, on warehouse property at our Elizabeth River bulk terminal. The segment's income tax expenses decreased $1.7 million (46%) in the first three months of 2006, compared to the first three months of 2005. The decrease was due to lower taxable earnings from Kinder Morgan Bulk Terminals, Inc., the tax-paying entity that owns many of our bulk terminal businesses. Compared to the first quarter of 2005, non-cash depreciation, depletion and amortization charges increased $5.1 million (42%) in the first quarter of 2006. In addition to increases associated with normal capital spending, the periodic increase reflected higher depreciation charges due to the terminal acquisitions we have made since the end of the first quarter of 2005. Collectively, these terminal assets, described above, accounted for incremental depreciation expenses of $4.3 million in the first quarter of 2006. Other Three Months Ended March 31, ---------------------------- 2006 2005 ---------- ---------- (In thousands-income/(expense)) General and administrative expenses............ $ (60,883) $ (73,852) Unallocable interest, net...................... (76,967) (60,047) Minority interest.............................. (2,370) (2,388) ---------- ---------- Interest and corporate administrative expenses $ (140,220) $ (136,287) ========== ========== Items not attributable to any segment include general and administrative expenses, unallocable interest income, interest expense and minority interest. General and administrative expenses include such items as salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services, including accounting, information technology, human resources, and legal fees. Our total general and administrative expenses decreased $13.0 million (18%) in the first quarter of 2006, when compared to the first quarter of 2005. The overall decrease in general and administrative expenses included a decrease of $27.4 million related to unallocated litigation and environmental settlement expenses that we recognized in the first quarter of 2005--consisting of a $25 million expense for a settlement reached between us and a joint venture partner on our Kinder Morgan Tejas natural gas pipeline system, a $5.4 million expense related to settlements of environmental matters at certain of our operating sites located in the State of California, and a $3.0 million decrease in expense related to favorable settlements of obligations that Enron Corp. had to us in conjunction with derivatives we were accounting for as hedges under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." Offsetting the decrease related to unallocated litigation and environmental settlement expenses were higher general and administrative expenses, in the first quarter of 2006, in the amount of $14.4 million, primarily due to higher period-to-period corporate services--due in part to acquisitions made since the first quarter of 2005, and to higher employee benefit costs, payroll taxes, and corporate insurance expenses. Currently and prospectively, we 64 face the challenge of rising general and administrative expenses due to increasing employee health care costs and business insurance costs; however, we continue to manage aggressively our infrastructure expense and we remain focused on maintaining affordable expense levels and eliminating unnecessary overhead expenses. Unallocable interest expense, net of interest income, increased $16.9 million (28%) in the first quarter of 2006, compared to the same year-earlier period. The increase was due to both higher quarter-to-quarter average debt levels and higher effective interest rates. The increase in our average borrowings was due to higher capital spending--related to internal expansions and improvements, external assets and businesses acquired since the end of the first quarter of 2005, and a net increase of $300 million in principal amount of long-term senior notes since the beginning of 2005. On March 15, 2005, we both closed a public offering of $500 million in principal amount of senior notes and retired a principal amount of $200 million. We issue senior notes in order to refinance commercial paper borrowings used for both internal capital spending and acquisition expenditures. The increase in our average borrowing rates reflects a general rise in variable interest rates since the end of the first quarter of 2005. The weighted average interest rate on all of our borrowings increased 13% in the first quarter of 2006, compared to the first quarter of 2005. We use interest rate swap agreements to help manage our interest rate risk. The swaps are contractual agreements we enter into in order to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. However, in a period of rising interest rates, these swaps will result in period-to-period increases in our interest expense. For more information on our interest rate swaps, see Note 10 to our consolidated financial statements, included elsewhere in this report. Financial Condition Capital Structure We attempt to maintain a conservative overall capital structure, with a long-term target mix of approximately 60% equity and 40% debt. The following table illustrates the sources of our invested capital (dollars in thousands). In addition to our results of operations, these balances are affected by our financing activities as discussed below: March 31, December 31, 2006 2005 ----------- ----------- Long-term debt, excluding market value of interest rate swaps................................ $ 5,704,920 $ 5,220,887 Minority interest.................................. 131,087 42,331 Partners' capital, excluding accumulated other comprehensive loss................................. 4,682,849 4,693,414 ----------- ----------- Total capitalization............................. 10,518,856 9,956,632 Short-term debt, less cash and cash equivalents.... (32,636) (12,108) ----------- ----------- Total invested capital........................... $10,486,220 $ 9,944,524 =========== =========== Capitalization: Long-term debt, excluding market value of interest rate swaps.............................. 54.2% 52.4% Minority interest................................ 1.3% 0.4% Partners' capital, excluding accumulated other comprehensive loss........................ 44.5% 47.2% ----------- ----------- 100.0% 100.0% =========== =========== Invested Capital: Total debt, less cash and cash equivalents and excluding Market value of interest rate swaps.. 54.1% 52.4% Partners' capital and minority interest, excluding accumulated other comprehensive loss... 45.9% 47.6% ----------- ----------- 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 facility, issuing short-term commercial paper, long-term notes or additional common units or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares. 65 In general, we expect to fund: o cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; o expansion capital expenditures and working capital deficits with retained cash (resulting from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), additional borrowings, the issuance of additional common units or the proceeds from purchases of additional i-units by KMR; o interest payments with cash flows from operating activities; and o debt principal payments with additional borrowings, as such debt principal payments become due, or by the issuance of additional common units or the issuance of additional i-units to KMR. As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations. We are able to access this segment of the capital market through KMR's purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors. As part of our financial strategy, we try to maintain an investment-grade credit rating, which involves, among other things, the issuance of additional limited partner units in connection with our acquisitions and internal growth activities in order to maintain acceptable financial ratios, including total debt to total capital. On August 2, 2005, following KMI's announcement of its proposed acquisition of Terasen Inc., Standard & Poor's Rating Services placed our debt credit ratings, as well as KMI's ratings, on CreditWatch with negative implications. On December 5, 2005, S&P affirmed our debt credit ratings, as well as KMI's ratings, with a negative outlook and removed them from CreditWatch. On February 23, 2006, Moody's Investors Service, which also publishes credit ratings on commercial entities, affirmed our debt credit ratings and changed its rating outlook from negative to stable. Short-term Liquidity Our principal sources of short-term liquidity are: o our $1.6 billion five-year senior unsecured revolving credit facility that matures August 18, 2010; o our $250 million nine-month unsecured revolving credit facility that matures November 21, 2006; o our $1.85 billion short-term commercial paper program (which was increased from $1.6 billion to $1.85 billion in April 2006, and which is supported by our bank credit facilities, with the amount available for borrowing under our credit facilities being reduced by our outstanding commercial paper borrowings); and o cash from operations (discussed following). Borrowings under our two credit facilities can be used for general corporate purposes and as a backup for our commercial paper program. There were no borrowings under our five-year credit facility as of December 31, 2005; there were no borrowings under either credit facility as of March 31, 2006. We provided for additional liquidity by maintaining a sizable amount of excess borrowing capacity related to our commercial paper program and long-term revolving credit facility. After inclusion of our outstanding commercial paper borrowings and letters of credit, the remaining available borrowing capacity under our bank credit facilities was $339.5 million as of March 31, 2006. 66 As of March 31, 2006, our outstanding short-term debt was $1,060.8 million. We intended and had the ability to refinance all of our short-term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated balance sheet. Currently, we believe our liquidity to be adequate. Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have 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. Long-term Financing In addition to our principal sources of short-term liquidity listed above, we could meet our cash requirements (other than distributions to our common unitholders, Class B unitholders and general partner) through issuing long-term notes or additional common units, or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares. We are subject, however, to changes in the equity markets for our limited partner units, and there can be no assurance we will be able or willing to access the public or private markets for our limited partner units in the future. If we were unable or unwilling to issue additional limited partner units, we would be required to either restrict potential future acquisitions or pursue other debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. All of our long-term debt securities issued to date, other than those issued under our revolving credit facilities or those issued by our subsidiaries and operating partnerships, generally have the same terms except for interest rates, maturity dates and prepayment premiums. All of our outstanding debt securities are unsecured obligations that rank equally with all of our other senior debt obligations; however, a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries. Our fixed rate notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. As of March 31, 2006, our total liability balance due on the various series of our senior notes was $4,489.8 million, and the total liability balance due on the borrowings of our operating partnerships and subsidiaries was $163.8 million. For additional information regarding our debt and credit facilities, see Note 9 to our consolidated financial statements included in our Form 10-K for the year ended December 31, 2005. Operating Activities Net cash provided by operating activities was $176.0 million for the three months ended March 31, 2006, versus $259.5 million in the comparable period of 2005. The period-to-period decrease of $83.5 million (32%) in cash flow from operations consisted of: o an $81.2 million decrease in cash inflows relative to net changes in working capital items--mainly due to timing differences that resulted in higher cash outflows with regard to our net accounts payables and receivables, and to additional payments for natural gas imbalance settlements and accrued interest; o a $16.6 million decrease in cash inflows relative to net changes in non-current assets and liabilities--related to, among other things, higher payments made in the first quarter of 2006 for pipeline project costs, studies and business development charges, largely related to our Rockies Express pipeline, and for higher payments made for natural gas liquids inventory on our North System. In the second quarter of 2006, we will transfer accumulated project costs related to our Rockies Express pipeline to within "Property, plant and equipment, net" on our consolidated balance sheet; 67 o a $9.0 million increase related to higher distributions received from equity investments--chiefly due to higher distributions received from Red Cedar Gathering Company in the first three months of 2006, partially offset by lower distributions from Cortez Pipeline Company. The change reflects higher and lower year-over-year net income in the first quarter of 2006 versus the first quarter of 2005 for Red Cedar and Cortez, respectively; and o a $5.3 million increase in cash from overall higher partnership income, net of non-cash items including depreciation charges, undistributed earnings from equity investments, and litigation and environmental expenses that impacted earnings but not cash. The higher partnership income reflects the increase in cash earnings from our four reportable business segments in the first three months of 2006, as discussed above in "-Results of Operations." Investing Activities Net cash used in investing activities was $479.9 million for the three month period ended March 31, 2006, compared to $168.0 million in the comparable 2005 period. The $311.9 million increase in cash used in investing activities was primarily attributable to: o a $233.5 million increase due to higher expenditures made for strategic business acquisitions. In the first quarter of 2006, we spent $240.0 million to acquire Entrega Gas Pipeline LLC, and in the first quarter last year, we spent $6.5 million, which primarily related to our acquisition of a 64.5% gross working interest in the Claytonville oil field unit located in West Texas; o a $49.9 million (35%) increase in capital expenditures; o a $15.0 million increase in margin deposits--associated with hedging activities utilizing energy derivative instruments; and o a $7.9 million increase related to additional investments in underground natural gas storage volumes and to higher payments made for natural gas liquids line-fill on our North System. Including expansion and maintenance projects, our capital expenditures were $193.7 million in the first quarter of 2006, compared to $143.8 million in the same prior-year period. Our sustaining capital expenditures were $25.7 million for the first three months of 2006, compared to $24.2 million for the first three months of 2005. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset. Based on our 2006 sustaining capital expenditure forecast, our forecasted expenditures for the remaining nine months of 2006 for sustaining capital expenditures were approximately $144.3 million. This amount has been committed primarily for the purchase of plant and equipment. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. Since the beginning of 2006, we made the following announcements related to our investing activities: o On March 9, 2006, we announced that we have entered into a long-term agreement with Drummond Coal Sales, Inc. that will support a $70 million expansion of our Pier IX bulk terminal located in Newport News, Virginia. The agreement has a term that can be extended for up to 30 years. The project includes the construction of a new ship dock and the installation of additional equipment; it is expected to increase throughput at the terminal by approximately 30% and will allow the terminal to begin receiving shipments of imported coal. The expansion is expected to be completed in the first quarter of 2008. Upon completion, the terminal will have an import capacity of up to 9 million tons annually. Currently, our Pier IX terminal can store approximately 1.4 million tons of coal and 30,000 tons of cement on its 30-acre storage site; and o On April 6, 2006, we announced the second of two investments in our CALNEV refined petroleum products pipeline system. Combined, the $25 million in capital improvements will upgrade and expand pipeline capacity and help provide sufficient fuel supply to the Las Vegas, Nevada market for the next several years. The first project, estimated to cost approximately $10 million, involves pipeline expansions that will increase current transportation capacity by 3,200 barrels per day (2.2%), as well as the construction of two new 80,000 68 barrel storage tanks at our Las Vegas terminal. The second project, expected to cost approximately $15 million, includes the installation of new and upgraded pumping equipment and piping at our Colton, California terminal, a new booster station with two pumps at Cajon, California, and piping upgrades at our Las Vegas terminal. In addition, we are currently exploring a $300 to $400 million future expansion that would increase capacity on the pipeline to approximately 220,000 barrels per day by 2010. Currently, our CALNEV Pipeline can transport approximately 140,000 barrels of refined products per day; o On April 7, 2006, Kinder Morgan Production Company L.P. purchased various oil and gas properties from Journey Acquisition - I, L.P. and Journey 2000, L.P. The properties are primarily located in the Permian Basin area of West Texas, produce approximately 850 barrels of oil equivalent per day net, and include some fields with enhanced oil recovery development potential near our current carbon dioxide operations. During the next several months, we will perform technical evaluations to confirm the carbon dioxide enhanced oil recovery potential and generate definitive plans to develop this potential if proven to be economic. The purchase price plus the anticipated investment to both further develop carbon dioxide enhanced oil recovery and construct a new carbon dioxide supply pipeline on all of the acquired properties is approximately $115 million. However, since we intend to divest in the near future those acquired properties that are not candidates for carbon dioxide enhanced oil recovery, our total investment is likely to be considerably less. o On April 19, 2006, our general partner's and KMR's board of directors approved a $75 million expansion of our Texas intrastate natural gas pipeline group's natural gas storage capabilities. The expansion will include the development of a third natural gas storage cavern at our North Dayton, Texas storage facility, which we acquired in August 2005. The expansion will more than double working capacity to over 9 billion cubic feet and is expected to be in service by April 1, 2009; o On April 19, 2006, we announced that the pipeline portion of our $210 million Pacific operations' East Line expansion project, initially proposed in October 2002, had been completed and the new breakout tank farm near El Paso, Texas was scheduled to be in service around June 1, 2006. This expansion project will significantly increase pipeline transportation capacity for refined petroleum products between El Paso and Phoenix, Arizona; and o On April 19, 2006, we and our partner Sempra Energy announced that we are moving forward on the approximate $4.4 billion Rockies Express Pipeline project after obtaining binding commitments from creditworthy shippers for all 1.8 billion cubic feet of transportation capacity on the 1,323-mile pipeline that will move natural gas from the Rocky Mountain Region to the eastern United States. Service on the 710-mile segment of the Rockies Express Pipeline that extends from Cheyenne to eastern Missouri is expected to commence on January 1, 2008, and the entire project is expected to be completed by June 2009, subject to regulatory approvals. In addition, interim service has begun on the western portion of the Entrega Pipeline (that extends from Meeker, Colorado to Wamsutter, Wyoming). The construction of the remainder of Entrega (that extends from Wamsutter to Cheyenne, Wyoming) is scheduled to begin this summer, and the entire system is expected to be in service by January 1, 2007. In April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas Pipeline LLC, and the remaining entity was renamed Rockies Express Pipeline LLC. Going forward, the entire pipeline system will be known as the Rockies Express Pipeline. We have ordered substantially all of the piping required for the Rockies Express and the $500 million Kinder Morgan Louisiana Pipeline projects at fixed prices consistent with project budgets. Financing Activities Net cash provided by financing activities amounted to $324.4 million for the three months ended March 31, 2006; for the same quarter last year, we used $91.5 million in financing activities. The $415.9 million overall increase in cash inflows provided by our financing activities was primarily due to: o a $343.0 million increase from overall debt financing activities, which include our issuances and payments of debt and our debt issuance costs. The increase was primarily due to a $638.6 million increase due to higher net commercial paper borrowings in the first quarter of 2006, partly offset by a $294.4 million decrease due to 69 net changes in the principal amount of senior notes. On March 15, 2005, we closed a public offering of $500 million in principal amount of 5.80% senior notes and repaid $200 million of 8.0% senior notes that matured on that date. The 5.80% senior notes are due March 15, 2035. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $494.4 million, and we used the proceeds to repay the 8.0% senior notes and to reduce our commercial paper debt; o a $90.6 million increase from contributions from minority interests, principally due to Sempra Energy's $80.0 million contribution for its 33 1/3% share of the purchase price of Entrega Pipeline LLC, discussed above in "--Investing Activities"; o a $20.3 million increase from net changes in cash book overdrafts, which represent checks issued but not yet endorsed; and o a $37.5 million decrease from higher partnership distributions. The increase was due to an increase in the per unit cash distributions paid, an increase in the number of units outstanding and an increase in our general partner incentive distributions. The increase in our general partner incentive distributions resulted from both increased cash distributions per unit and an increase in the number of common units and i-units outstanding. Partnership Distributions Distributions to all partners, consisting of our common and Class B unitholders, our general partner and minority interests, totaled $261.0 million in the first quarter 2006, compared to $223.5 million in the first quarter of 2005. 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 and net reductions in reserves, less cash disbursements and net additions to reserves 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. 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. We do not distribute cash to i-unit owners but retain the cash for use in our business. However, the cash equivalent of distributions of i-units is treated as if it had actually been distributed for purposes of determining the distributions to our general partner. Each time we make a distribution, the number of i-units owned by KMR and the percentage of our total units owned by KMR increase automatically under the provisions of our partnership agreement. Available cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets. Available cash for each quarter is distributed: o first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter; o second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter; 70 o third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and o fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to owners of i-units in the equivalent number of i-units, and 50% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. Our general partner's incentive distribution that we declared for 2005 was $473.9 million, while the incentive distribution paid to our general partner during 2005 was $454.3 million. The difference between declared and paid distributions is due to the fact that our distributions for the fourth quarter of each year are declared and paid in the first quarter of the following year. On February 14, 2006, we paid a quarterly distribution of $0.80 per unit for the fourth quarter of 2005. This distribution was 8% greater than the $0.74 distribution per unit we paid for the fourth quarter of 2004 and 5% greater than the $0.76 distribution per unit we paid for the first quarter of 2005. We paid this distribution in cash to our common unitholders and to our Class B unitholders. KMR, our sole i-unitholder, received additional i-units based on the $0.80 cash distribution per common unit. We believe that future operating results will continue to support similar levels of quarterly cash and i-unit distributions; however, no assurance can be given that future distributions will continue at such levels. 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 first quarter of 2006 was $128.3 million. Our general partner's incentive distribution for the distribution that we declared for the first quarter of 2005 was $111.1 million. Our general partner's incentive distribution that we paid during the first quarter of 2006 to our general partner (for the fourth quarter of 2005) was $125.6 million. Our general partner's incentive distribution that we paid during the first quarter of 2005 to our general partner (for the fourth quarter of 2004) was $106.0 million. 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. Litigation and Environmental As of March 31, 2006, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $50.1 million. In addition, we have recorded a receivable of $27.6 million for expected cost recoveries that have been deemed probable. The reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired. Reserves for each project are generally established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup and the costs associated with the effort. In assessing environmental risks in conjunction with proposed acquisitions, we review records relating to environmental issues, conduct site inspections, interview employees, and, if appropriate, collect soil and groundwater samples. As of March 31, 2006, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $135.6 million. The reserve is primarily related to various claims from lawsuits arising from our Pacific operations' pipeline transportation rates, and the contingent amount is based on both the circumstances of probability and reasonability of dollar estimates. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision. We believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, changing circumstances could cause these matters to have a material adverse impact. 71 Pursuant to our continuing commitment to operational excellence and our focus on safe, reliable operations, we have implemented, and intend to implement in the future, enhancements to certain of our operational practices in order to strengthen our environmental and asset integrity performance. These enhancements have resulted and may result in higher operating costs and sustaining capital expenditures; however, we believe these enhancements will provide us the greater long term benefits of improved environmental and asset integrity performance. Please refer to Notes 3 and 14, respectively, to our consolidated financial statements included elsewhere in this report for additional information regarding pending litigation, environmental and asset integrity matters. Certain Contractual Obligations There have been no material changes in either certain contractual 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, 2005 in our 2005 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," or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include: o price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, coal and other bulk materials and chemicals in North America; o economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand; o changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission; o our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as our ability to make expansions to our facilities; o difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines; o our ability to successfully identify and close acquisitions and make cost-saving changes in operations; o shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us; o crude oil and natural gas production from exploration and production areas that we serve, including, among others, the Permian Basin area of West Texas; o changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete; o changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities; 72 o our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities; o our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences; o interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes; o our ability to obtain insurance coverage without significant levels of self-retention of risk; o acts of nature, sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits; o capital markets conditions; o the political and economic stability of the oil producing nations of the world; o national, international, regional and local economic, competitive and regulatory conditions and developments; o the ability to achieve cost savings and revenue growth; o inflation; o interest rates; o the pace of deregulation of retail natural gas and electricity; o foreign exchange fluctuations; o the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products; o the extent of our success in discovering, developing and producing oil and gas reserves, including the risks inherent in exploration and development drilling, well completion and other development activities; o engineering and mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells; o the uncertainty inherent in estimating future oil and natural gas production or reserves; o the timing and success of business development efforts; and o unfavorable results of litigation and the fruition of contingencies referred to in Note 16 to our consolidated financial statements included elsewhere in this report. There is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements. See Item 1A "Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2005, 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 2005 Form 10-K 73 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. 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, 2005, in Item 7A of our 2005 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 March 31, 2006, 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 Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended March 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 74 PART II. OTHER INFORMATION Item 1. Legal Proceedings. See Part I, Item 1, Note 3 to our consolidated financial statements entitled "Litigation, Environmental and Other Contingencies," which is incorporated in this item by reference. Item 1A. Risk Factors. There have been no material changes to the risk factors disclosed in Item 1A "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2005. Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. None. Item 3. Defaults Upon Senior Securities. None. Item 4. Submission of Matters to a Vote of Security Holders. None. Item 5. Other Information. None. Item 6. Exhibits. 4.1 -- Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request. *10.1 -- Nine-Month Credit Agreement dated as of February 22, 2006 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.9 to Kinder Morgan Energy Partners, L.P.'s Form 10-K for 2005, filed on March 16, 2006). 11 -- Statement re: computation of per share earnings. 12 -- Statement re: computation of ratio of earnings to fixed charges. 31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 75 31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 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. 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. ---------- * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise. 76 SIGNATURE 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 sole General Partner By: KINDER MORGAN MANAGEMENT, LLC, the Delegate of Kinder Morgan G.P., Inc. /s/ Kimberly A. Dang ------------------------------ Kimberly A. Dang Vice President and Chief Financial Officer Date: May 9, 2006