Exhibit 99.1  F O R M 10-Q   SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549   [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934  For the quarterly period ended September 30, 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 162,779,676 common units outstanding as of October 31, 2006.   1 <PAGE>   KINDER MORGAN ENERGY PARTNERS, L.P. TABLE OF CONTENTS   Page Number PART I. FINANCIAL INFORMATION  Item 1:  Financial Statements (Unaudited)...............................  3  Consolidated Statements of Income - Three and Nine Months Ended September 30, 2006 and 2005.....................  3 Consolidated Balance Sheets - September 30, 2006 and December 31, 2005............................................  4 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2006 and 2005............................  5 Notes to Consolidated Financial Statements...................  6  Item 2:  Management's Discussion and Analysis of Financial Condition and Results of Operations.......................... 60 Critical Accounting Policies and Estimates................... 60 Results of Operations........................................ 61 Financial Condition.......................................... 79 Information Regarding Forward-Looking Statements............. 86  Item 3:  Quantitative and Qualitative Disclosures About Market Risk..... 88  Item 4:  Controls and Procedures........................................ 88     PART II. OTHER INFORMATION  Item 1:  Legal Proceedings.............................................. 90  Item 1A: Risk Factors................................................... 90  Item 2:  Unregistered Sales of Equity Securities and Use of Proceeds.... 90  Item 3:  Defaults Upon Senior Securities................................ 90  Item 4:  Submission of Matters to a Vote of Security Holders............ 90  Item 5:  Other Information.............................................. 90  Item 6:  Exhibits....................................................... 90  Signature...................................................... 92    2 <PAGE>   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)  <TABLE> <CAPTION> Three Months Ended         Nine Months Ended September 30,              September 30, --------------------       ------------------- 2006          2005         2006         2005 ------        ------       ------       ------ Revenues <S>                                                    <C>          <C>          <C>          <C> Natural gas sales................................... $1,516,874   $1,975,583   $4,679,236   $4,820,732  Services............................................    532,392      470,469    1,554,052    1,369,496 Product sales and other.............................    224,167      185,202      628,234      539,313 ---------    ---------    ---------    --------- 2,273,433    2,631,254    6,861,522    6,729,541 ---------    ---------    ---------    --------- Costs, Expenses and Other Gas purchases and other costs of sales..............  1,511,217    1,970,579    4,649,851    4,795,923 Operations and maintenance..........................    208,816      156,486      575,352      448,621 Fuel and power......................................     56,644       44,951      160,621      132,329 Depreciation, depletion and amortization............    106,830       85,356      296,780      258,644 General and administrative..........................     59,694       47,073      183,913      171,058 Taxes, other than income taxes......................     28,005       28,198       90,859       80,249 Other expense (income)..............................         --           --      (15,114)          -- ---------    ---------    ---------    --------- 1,971,206    2,332,643    5,942,262    5,886,824 ---------    ---------    ---------    ---------  Operating Income......................................    302,227      298,611      919,260      842,717  Other Income (Expense) Earnings from equity investments....................     14,032       20,512       57,203       69,422 Amortization of excess cost of equity investments...     (1,416)      (1,407)      (4,244)      (4,233) Interest, net.......................................    (88,301)     (68,348)    (246,109)    (192,387) Other, net..........................................      3,339        2,880       11,179        2,208 Minority Interest.....................................     (2,018)      (1,806)      (7,881)      (6,648) ---------    ---------    ---------    ---------  Income Before Income Taxes............................    227,863      250,442      729,408      711,079  Income Taxes..........................................     (4,045)      (5,055)     (11,820)     (20,245) ---------    ---------    ---------    ---------  Net Income............................................ $  223,818   $  245,387   $  717,588   $  690,834 =========    =========    =========    =========  General Partner's interest in Net Income.............. $  133,881   $  122,744   $  393,565   $  351,724  Limited Partners' interest in Net Income..............     89,937      122,643      324,023      339,110 ---------    ---------    ---------    ---------   Net Income............................................ $  223,818   $  245,387   $  717,588   $  690,834 =========    =========    =========    =========  Basic Limited Partners' Net Income per Unit........... $     0.40   $     0.58   $     1.45   $     1.61 =========    =========    =========    =========  Diluted Limited Partners' Net Income per Unit......... $     0.40   $     0.57   $     1.45   $     1.61 =========    =========    =========    =========  Weighted average number of units used in computation of Limited Partners' Net Income per unit: Basic.................................................    225,809      213,192      222,810      210,001 =========    =========    =========    =========  Diluted...............................................    226,155      213,496      223,144      210,199 =========    =========    =========    =========  Per unit cash distribution declared................... $     0.81   $     0.79   $     2.43   $     2.33 =========    =========    =========    ========= </TABLE>  The accompanying notes are an integral part of these consolidated financial statements.    3 <PAGE>  KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Thousands) (Unaudited)  September 30,   December 31, -------------   ------------ 2006           2005 ----           ---- ASSETS Current Assets Cash and cash equivalents.....................  $    23,953     $    12,108 Accounts, notes and interest receivable, net Trade......................................      811,897       1,011,716 Related parties............................        7,230           2,543 Inventories Products...................................       15,924          18,820 Materials and supplies.....................       12,909          13,292 Gas imbalances Trade......................................        9,464          18,220 Related parties............................        5,241               - Gas in underground storage....................       26,036           7,074 Other current assets..........................      129,643         131,451 ----------      ---------- 1,042,297       1,215,224 ----------      ---------- Property, Plant and Equipment, net..............    9,222,800       8,864,584 Investments.....................................      429,924         419,313 Notes receivable Trade.........................................        1,241           1,468  Related parties...............................       90,854         109,006 Goodwill........................................      818,800         798,959 Other intangibles, net..........................      210,074         217,020 Deferred charges and other assets...............      207,042         297,888 ----------      ---------- Total Assets.................................... $12,023,032     $11,923,462 ==========      ==========   LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Cash book overdrafts.......................  $    43,220     $    30,408 Trade......................................      677,652         996,174 Related parties............................          739          16,676 Current portion of long-term debt.............    1,147,213               - Accrued interest..............................       45,384          74,886 Accrued taxes.................................       70,903          23,536 Deferred revenues.............................       15,699          10,523 Gas imbalances Trade......................................        9,780          22,948 Related parties............................            -           1,646 Accrued other current liabilities.............      689,840         632,088 ----------      ---------- 2,700,430       1,808,885 ----------      ---------- Long-Term Liabilities and Deferred Credits Long-term debt Outstanding................................    4,386,706       5,220,887 Market value of interest rate swaps........       44,806          98,469 ----------      ---------- 4,431,512       5,319,356 Deferred revenues.............................       23,494           6,735 Deferred income taxes.........................       71,225          70,343 Asset retirement obligations..................       46,873          42,417 Other long-term liabilities and deferred credits    849,271       1,019,655 ----------      ---------- 5,422,375       6,458,506 ----------      ---------- Commitments and Contingencies (Note 3) Minority Interest...............................       44,666          42,331 ----------      ---------- Partners' Capital Common Units..................................    2,778,382       2,680,352 Class B Units.................................      104,487         109,594 i-Units.......................................    1,870,072       1,783,570 General Partner...............................      125,113         119,898 Accumulated other comprehensive loss..........   (1,022,493)     (1,079,674) ----------      ---------- 3,855,561       3,613,740 ----------      ---------- Total Liabilities and Partners' Capital.........  $12,023,032     $11,923,462 ==========      ==========  The accompanying notes are an integral part of these consolidated financial statements.    4 <PAGE>  KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Increase/(Decrease) in Cash and Cash Equivalents In Thousands) (Unaudited)  <TABLE> <CAPTION>  Nine Months Ended September 30, --------------------------- 2006           2005 ------------   ------------ Cash Flows From Operating Activities <S>                                                                             <C>            <C> Net income.................................................................   $  717,588     $  690,834 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization.................................      296,780        258,644 Amortization of excess cost of equity investments........................        4,244          4,233 Gains and other non-cash income from the sale of property, plant and equipment......................................................      (15,716)          (635)  Earnings from equity investments.........................................      (57,203)       (69,422) Distributions from equity investments......................................       56,281         51,552 Changes in components of working capital: Accounts receivable......................................................      216,850       (249,056) Other current assets.....................................................       (3,775)          (394) Inventories..............................................................        6,083         (7,172) Accounts payable.........................................................     (334,434)       222,739 Accrued interest.........................................................      (29,503)       (17,057) Accrued liabilities......................................................       (2,269)        (1,218) Accrued taxes............................................................       47,759         40,722 FERC rate reparations and refunds........................................      (19,079)            -- Other, net.................................................................       (4,879)       (22,170) Net Cash Provided by Operating Activities....................................      878,727        901,600  Cash Flows From Investing Activities Acquisitions of assets.....................................................     (367,292)      (289,751) Additions to property, plant and equip. for expansion and maintenance projects...................................................     (751,346)      (597,186) Sale of property, plant and equipment, and other net assets net of removal costs................................................       71,532          2,987 Net proceeds from margin deposits..........................................        1,390             -- Contributions to equity investments........................................         (106)        (1,202) Natural gas stored underground and natural gas liquids line-fill...........      (12,863)       (20,208) Other......................................................................       (3,401)          (211) Net Cash Used in Investing Activities........................................   (1,062,086)      (905,571)  Cash Flows From Financing Activities  Issuance of debt...........................................................    3,730,016      3,812,933 Payment of debt............................................................   (3,005,384)    (3,401,190) Repayments from loans to related party.....................................        1,097             -- Debt issue costs...........................................................       (1,554)        (5,723) Increase in cash book overdrafts...........................................       12,812          6,782 Proceeds from issuance of common units.....................................      248,376        285,407 Contributions from minority interest.......................................      109,294          4,509 Distributions to partners: Common units.............................................................     (380,245)      (337,994) Class B units............................................................      (12,858)       (12,115) General Partner..........................................................     (388,350)      (337,633) Minority interest........................................................     (115,424)        (8,754) Other, net.................................................................       (2,693)        (2,063) Net Cash Provided by Financing Activities....................................      195,087          4,159  Effect of exchange rate changes on cash and cash equivalents.................          117           (188)  Increase in Cash and Cash Equivalents........................................       11,845             -- Cash and Cash Equivalents, beginning of period...............................       12,108             -- Cash and Cash Equivalents, end of period.....................................   $   23,953     $       --  Noncash Investing and Financing Activities: Contribution of net assets to partnership investments......................   $   17,003     $       -- Assets acquired by the issuance of units...................................           --         49,635 Assets acquired by the assumption of liabilities...........................        3,725         68,045 </TABLE>  The accompanying notes are an integral part of these consolidated financial statements.     5 <PAGE>  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. Certain amounts from prior periods have been reclassified to conform to the current presentation.  Net Income Per Unit  We compute Basic Limited Partners' Net Income per Unit by dividing our limited partners' interest in net income by the weighted average number of units outstanding during the period. Diluted Limited Partners' Net Income per Unit reflects the 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 <PAGE>  2. Acquisitions, Joint Ventures and Divestitures  Acquisitions and Joint Ventures  During the first nine months of 2006, we completed or made adjustments for the following acquisitions. Each of the acquisitions was accounted for under the purchase method and the assets acquired and liabilities assumed were recorded at their estimated fair market values as of the acquisition date. The preliminary 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 these acquisitions are included in our consolidated financial statements from the acquisition date.  Kinder Morgan River Terminals LLC   Effective October 6, 2004, we acquired Global Materials Services LLC and its consolidated subsidiaries from Mid-South Terminal Company, L.P. for approximately $87.9 million, consisting of $31.8 million in cash and $56.1 million of assumed liabilities, including debt of $33.7 million. In the third quarter of 2006, we made certain immaterial purchase price adjustments based on a further evaluation of acquired income tax assets and liabilities. Global Materials Services LLC, which we renamed Kinder Morgan River Terminals LLC, operates a network of 21 river terminals and two rail transloading facilities primarily located along the Mississippi River system. The network provides loading, storage and unloading points for various bulk commodity imports and exports. The acquisition further expanded and diversified our customer base and complemented our existing terminal facilities located along the lower-Mississippi River system. The acquired terminals are included in our Terminals business segment.  Our allocation of the purchase price to assets acquired and liabilities assumed after giving effect to the above adjustments is as follows (in thousands):  Purchase price: Cash paid, including transaction costs......  $31,819 Debt assumed................................   33,677 Liabilities assumed (excluding debt)........   22,371 ------ Total purchase price........................  $87,867 ====== Allocation of purchase price: Current assets..............................   $9,855 Property, plant and equipment...............   43,191 Goodwill....................................   20,218 Other intangibles, net......................   12,400 Deferred charges and other assets...........    2,203 ------ $87,867 ======  The $20.2 million of goodwill was assigned to our Terminals business segment, and the entire amount is expected to be deductible for tax purposes. We believe this acquisition resulted in the recognition of goodwill primarily due to the fact that certain advantageous factors and conditions existed that contributed to the fair value of acquired identifiable net assets and liabilities exceeding our acquisition price--in the aggregate, these factors represented goodwill. The $12.4 million of other intangibles in the table above includes $11.9 million representing the fair value of intangible customer relationships, which encompass both the contractual life of customer contracts plus any future customer relationship value beyond the contract life.  General Stevedores, L.P.  Effective July 31, 2005, we acquired all of the partnership interests in General Stevedores, L.P. for an aggregate consideration of approximately $8.9 million, consisting of $2.0 million in cash, $3.4 million in common units, and $3.5 million in assumed liabilities, including debt of $3.0 million. In August 2005, we paid the $3.0 million outstanding debt balance. General Stevedores, L.P. owns, operates and leases barge unloading facilities located along the Houston, Texas ship channel. Its operations primarily consist of receiving, storing and transferring semi-finished steel products, including coils, pipe and billets. The acquisition complemented and further expanded our existing Texas Gulf Coast terminal facilities, and its operations are included as part of our Terminals business segment. In the second quarter of 2006, we made our final purchase price adjustments and the final allocation of our purchase price to assets acquired and liabilities assumed. The adjustments included minor revisions to acquired working capital items, and, pursuant to an    7 <PAGE>  appraisal of acquired fixed asset and land values, an adjustment of $2.9 million  from property, plant and equipment to goodwill.  Our allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands):  Purchase price: Cash paid, including transaction costs......  $1,995 Common units issued.........................   3,385 Debt assumed................................   3,009 Liabilities assumed (excluding debt)........     479 ----- Total purchase price........................  $8,868 ===== Allocation of purchase price: Current assets..............................  $  601 Property, plant and equipment...............   5,197 Goodwill....................................   2,870 Other intangibles, net .....................     200 ----- $8,868 =====  The $2.9 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes.  Entrega Gas Pipeline LLC  Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega Gas Pipeline LLC from EnCana Corporation for $244.6 million in cash. West2East Pipeline LLC is a limited liability company and is the sole owner of Rockies Express Pipeline LLC. We contributed 66 2/3% of the consideration for this purchase, which corresponded to our percentage ownership of West2East Pipeline LLC at that time. At the time of acquisition, Sempra Energy held the remaining 33 1/3% ownership interest and contributed this same proportional amount of the total consideration.  On the acquisition date, Entegra Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas pipeline that will, when fully constructed, 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 the Rockies Express Pipeline, an interstate natural gas pipeline that is currently being developed by Rockies Express Pipeline LLC. The acquired operations are included as part of our Natural Gas Pipelines business segment.  In the first quarter of 2006, EnCana Corporation completed construction of the pipeline segment that extends from the Meeker Hub to the Wamsutter Hub, and interim service began on that portion of the pipeline. Under the terms of the purchase and sale agreement, Rockies Express Pipeline LLC will construct the segment that extends from the Wamsutter Hub to the Cheyenne Hub. Construction on this pipeline segment began in the second quarter of 2006, and it is anticipated that both pipeline segments will be placed into service by January 1, 2007.  With regard to Rockies Express Pipeline LLC's acquisition of Entrega Gas Pipeline LLC, the allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands):  Purchase price: Cash paid, including transaction costs......  $244,572 Liabilities assumed.........................         - ------- Total purchase price........................  $244,572 ======= Allocation of purchase price: Current assets..............................  $      - Property, plant and equipment...............   244,572 Deferred charges and other assets ..........         - ------- $244,572  =======  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 (including the lines currently being developed) will be known as the Rockies Express Pipeline. The combined 1,663-mile pipeline system    8 <PAGE>  will be one of the largest natural gas pipelines ever constructed in North America. The approximately $4.4 billion project will have the capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments have been secured for virtually all of the pipeline capacity.  On June 30, 2006, ConocoPhillips exercised its option to acquire a 25% ownership interest in West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline LLC). On that date, a 24% ownership interest was transferred to ConocoPhillips, and an additional 1% interest will be transferred once construction of the entire project is completed. Through our subsidiary Kinder Morgan W2E Pipeline LLC, we will continue to operate the project but our ownership interest decreased to 51% of the equity in the project (down from 66 2/3%). Sempra's ownership interest in West2East Pipeline LLC decreased to 25% (down from 33 1/3%). When construction of the entire project is completed, our ownership interest will be reduced to 50% at which time the capital accounts of West2East Pipeline LLC will be trued up to reflect our 50% economics in the project. We do not anticipate any additional changes in the ownership structure of the Rockies Express Pipeline project.  West2East Pipeline LLC qualifies as a variable interest entity as defined by Financial Accounting Standards Board Interpretation No. 46 (Revised December 2003) (FIN 46R), "Consolidation of Variable Interest Entities-An Interpretation of ARB No. 51," due to the fact that the total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by any parties, including equity holders. Furthermore, following ConocoPhillips' acquisition of its ownership interest in West2East Pipeline LLC on June 30, 2006, we receive 50% of the economics of the Rockies Express project on an ongoing basis, and thus, effective June 30, 2006, we were no longer considered the primary beneficiary of this entity as defined by FIN 46R. Accordingly, on that date, we made the change in accounting for our investment in West2East Pipeline LLC from full consolidation to the equity method following the decrease in our ownership percentage.  Under the equity method, we record the costs of our investment within the "Investments" line on our consolidated balance sheet and as changes in the net assets of West2East Pipeline LLC occur (for example, earnings and dividends), we recognize our proportional share of that change in the "Investment" account. We also record our proportional share of any accumulated other comprehensive income or loss within the "Accumulated other comprehensive loss" line on our consolidated balance sheet.  Summary financial information as of September 30, 2006, for West2East Pipeline LLC, which is accounted for under the equity method, is as follows (in thousands; amounts represent 100% of investee information):   September 30, Balance Sheet                          2006 -----------------------------           ----------------- Current assets............................  $    935 Non-current assets........................   594,947 Current liabilities.......................    14,098 Non-current liabilities...................   588,296 Accumulated other comprehensive income....  $ (6,512)  In addition, we have guaranteed our proportional share of West2East Pipeline LLC's debt borrowings under a $2 billion credit facility entered into by Rockies Express Pipeline LLC. For more information on our contingent debt,  see Note 7.  April 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. for an aggregate consideration of approximately $63.7 million, consisting of $60.2 million in cash and $3.5 million in assumed liabilities. The acquisition was effective March 1, 2006. However, we divested certain acquired properties that are not considered candidates for carbon dioxide enhanced oil recovery, thus reducing our total investment. As of September 30, 2006, we received proceeds of approximately $27.0 million from the sale of these properties.  The properties are primarily located in the Permian Basin area of West Texas and New Mexico, produce approximately 425 barrels of oil equivalent per day, and include some fields with potential for enhanced oil recovery   9 <PAGE>  development near our current carbon dioxide operations. The acquired operations are included as part of our CO2 business segment. Following our acquisition, and continuing through the remainder of 2006, 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.  As of September 30, 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......  $60,188 Long-term liabilities assumed...............    3,548 ------ Total purchase price........................  $63,736 ====== Allocation of purchase price: Current assets..............................  $   229 Property, plant and equipment...............   63,507 ------ $63,736 ======  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.  Our allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands):  Purchase price: Cash paid, including transaction costs......  $61,614  Long-term liabilities assumed...............      253 ------ Total purchase price........................  $61,867 ====== Allocation of purchase price: Current assets..............................  $   509 Property, plant and equipment...............   43,595 Goodwill....................................   17,763 ------ $61,867 ======  The $17.8 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes.  Pro Forma Information  Pro forma information regarding consolidated income statement information that assumes all of the acquisitions we have made and joint ventures we have entered into since January 1, 2005, including the ones listed above, had occurred as of January 1, 2005, is not materially different from the information presented in our accompanying consolidated statements of income.    10 <PAGE>   Divestitures  Effective April 1, 2006, we sold our Douglas natural gas gathering system and our Painter Unit fractionation facility to Momentum Energy Group, LLC for approximately $42.5 million in cash. Our investment in net assets, including all transaction related accruals, was approximately $24.5 million, most of which represented property, plant and equipment, and we recognized approximately $18.0 million of gain on the sale of these net assets. We used the proceeds from these asset sales to reduce the outstanding balance on our commercial paper borrowings.  The Douglas gathering system is comprised of approximately 1,500 miles of 4-inch to 16-inch diameter pipe that gathers approximately 26 million cubic feet per day of natural gas from 650 active receipt points. Gathered volumes are processed at our Douglas plant (which we retained), located in Douglas, Wyoming. As part of the transaction, we executed a long-term processing agreement with Momentum Energy Group, LLC which dedicates volumes from the Douglas gathering system to our Douglas processing plant. The Painter Unit, located near Evanston, Wyoming, consists of a natural gas processing plant and fractionator, a nitrogen rejection unit, a natural gas liquids terminal, and interconnecting pipelines with truck and rail loading facilities. Prior to the sale, we leased the plant to BP, which operates the fractionator and the associated Millis terminal and storage facilities for its own account.  Additionally, with regard to the natural gas operating activities of our Douglas gathering system, we utilized certain derivative financial contracts to offset our exposure to fluctuating expected future cash flows caused by periodic changes in the price of natural gas and natural gas liquids. According to the provisions of current accounting principles, changes in the fair value of derivative contracts that are designated and effective as cash flow hedges of forecasted transactions are reported in other comprehensive income (not net income) and recognized directly in equity (included within accumulated other comprehensive income/(loss)). Amounts deferred in this way are reclassified to net income in the same period in which the forecast transactions are recognized in net income. However, if a hedged transaction is no longer expected to occur by the end of the originally specified time period, because, for example, the asset generating the hedged transaction is disposed of prior to the occurrence of the transaction, then the net cumulative gain or loss recognized in equity should be transferred to net income in the current period.  Accordingly, upon the sale of our Douglas gathering system, we reclassified a net loss of $2.9 million from "Accumulated other comprehensive loss" into net  income on those derivative contracts that effectively hedged uncertain future cash flows associated with forecasted Douglas gathering transactions. We included the net amount of the gain, $15.1 million, within the caption "Other expense (income)" in our accompanying consolidated statement of income for the nine months ended September 30, 2006. For more information on our accounting for derivative contracts, see Note 10.   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 and protests regarding interstate rates on our Pacific operations' pipeline systems.  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.    11 <PAGE>   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.  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    12 <PAGE>  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.  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    13 <PAGE>  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. The FERC's decision in Docket No. PL05-5 has been appealed to the United States Court of Appeals for the District of Columbia, and final briefs were filed on September 11, 2006.  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).  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      14 <PAGE>  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 discussed further below.  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 moved to intervene in the review proceedings brought by the other parties. The proceedings before the Court are addressed further below.  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.  Watson Station proceedings. The FERC's June 1, 2005 Order on Remand and Rehearing initiated a separate proceeding regarding the reasonableness of the Watson Station charge. All Watson-related issues in Docket No. OR92-8, Docket No. OR96-2 and other dockets were also consolidated in that proceeding. After discovery and the filing of prepared direct testimony, the procedural schedule  was suspended while the parties pursued settlement negotiations.  On May 17, 2006, the parties entered into a settlement agreement and filed an offer of settlement with the FERC. On August 2, 2006, the FERC approved the settlement without modification and directed that it be implemented. Pursuant to the settlement, SFPP filed a new tariff, which took effect September 1, 2006, lowering SFPP's going-forward rate to $0.003 per barrel and including certain volumetric pumping rates. SFPP also paid refunds to all shippers for the period since April 1, 1999 through August 31, 2006. Those refunds were based upon the difference between the Watson Station charge as filed in SFPP's prior tariffs and the reduced charges set forth in the agreement. On September 28, 2006, SFPP filed a refund report with the FERC, setting forth the refunds that had    15 <PAGE>  been paid and describing how the refund calculations were made. Two of the settling parties, BP and ExxonMobil, protested the refund report, and SFPP responded to that protest. The FERC has yet to act on the protest. As of September 30, 2006, SFPP had made aggregate payments, including accrued interest, of $19.1 million.  For the period prior to April 1, 1999, the parties agreed to reserve for briefing issues related to whether shippers are entitled to reparations. To the extent any reparations are owed, the parties agreed on how reparations would be calculated. Initial briefs regarding the reserved legal issues are due November 15, 2006. Reply briefs are due December 21, 2006.  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 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. The FERC has not yet ruled on the initial decision in this proceeding.  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    16 <PAGE>  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 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. Initial briefs to the Court were filed May 30, 2006, and final briefs were filed October 19, 2006. Oral argument has been scheduled for December 12, 2006.  On July 24, 2006, the FERC filed with the Court of Appeals a motion for voluntary partial remand, requesting that the portion of the March 26, 2004 and June 1, 2005 orders in which the FERC removed grandfathering protection from SFPP's West Line rates and affirmed such protection for the North Line and Oregon Line rates be returned to the FERC for reconsideration in light of arguments presented by SFPP and other parties in their initial briefs. In response to the FERC's remand motion, SFPP filed on August 1, 2006 to reinstate its West Line rates at the previous, grandfathered level effective August 2, 2006, and asked for FERC approval of such reinstatement on the ground that, pending the FERC's reconsideration of its grandfathering rulings, the prior grandfathered rate level is the lawful rate. On August 17, 2006, the Court of Appeals denied without prejudice the FERC's motion for voluntary partial remand. In light of this denial, on August 31, 2006, the FERC issued an order rejecting SFPP's August 1, 2006 filing seeking reinstatement of SFPP's grandfathered West Line rates.  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.    17 <PAGE>  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 that the FERC's policy statement and its decision in these cases have been 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 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 July 31, 2006, the court of appeals held the appeals of these orders in abeyance pending further FERC action.  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). In accordance with the December 16, 2005 order, rate reductions were 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, OR96-2, and IS05-230 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.    18 <PAGE>  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 is expected to be approximately $15 million.  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 United States 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. 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.    19 <PAGE>  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, 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. 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. On September 5, 2006, the presiding administrative law judge suspended the procedural schedule in Docket No. OR03-5 pending a decision by the United States Court of Appeals for the District of Columbia regarding various issues before the court that directly impact the Docket No. OR03-5 proceeding.  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, 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 presiding administrative law judge issued his initial decision on September 26, 2006.  The initial decision held that SFPP should be allowed to include in its rate base all costs associated with relocating the Concord to Sacramento Segment, but to include only 14/20ths of the cost of constructing the new line; it further held that the FERC's policy statement on income tax allowance is inconsistent with the Court's decision in BP West Coast Products, LLC v. Federal Energy Regulatory Commission and that, therefore, SFPP should be allowed no income tax allowance. While the initial decision held that SFPP could recover its litigation costs, it otherwise made rulings generally adverse to SFPP on cost of service issues. These issues included the capital structure to be used in computing SFPP's "starting rate base," treatment of SFPP's accumulated deferred income tax account, costs of debt and equity, as well as allocation of overhead. Briefs on exceptions are due on October 25, 2006. The FERC has not yet reviewed the initial decision, and it is not possible to predict the outcome of FERC and/or appellate review.  East Line rate case, IS06-283 proceeding. In April 2006, SFPP filed to increase its East Line interstate rates to reflect increased costs, principally due to the installation of replacement pipe between El Paso, Texas and Tucson, Arizona, significantly increasing the East Line's capacity. Under FERC regulations, SFPP was required to demonstrate that there was a substantial divergence between the revenues generated by its existing East Line rates and its increased costs. SFPP's rate increase was protested by various shippers and accepted subject to refund by the FERC. FERC established an investigation and hearing before an administrative law judge. A procedural schedule has been established, with a hearing scheduled for February 2007.  Index Increases, IS06-356, IS05-327. On May 27, 2005, SFPP filed to increase certain rates pursuant to the FERC's indexing methodology. Various shippers protested, and the FERC accepted and suspended all but one of    20  <PAGE>  the filed tariffs, subject to SFPP's filing of a revised Page 700 of its FERC Form 6 and subject to the outcome of various proceedings involving SFPP at the FERC. BP West Coast Products and ExxonMobil Oil Corporation filed for rehearing and challenged the revised Page 700 filed by SFPP. On December 12, 2005, the FERC denied the request for rehearing; this decision is currently on appeal before the Court of Appeals. Initial briefs were filed on August 25, 2006, and final briefs are due on November 28, 2006.  On May 30, 2006, SFPP also filed to increase certain interstate rates pursuant to the FERC's indexing methodology. This filing was protested, but the FERC determined that SFPP's tariff filing was consistent with the FERC's regulations. Certain shippers requested rehearing, which the FERC granted for further consideration on August 21, 2006. The FERC's order has been appealed to the United States Court of Appeals for the District of Columbia Circuit. On August 31, 2006, the FERC filed a motion with the Court to hold the case in abeyance, and SFPP and BP West Coast subsequently intervened. The Court has not yet issued a ruling on the motions filed by the FERC, SFPP, and BP West Coast.  Calnev Pipe Line LLC  On May 22, 2006, Calnev Pipe Line LLC filed to increase its interstate rates pursuant to the FERC's indexing methodology applicable to oil pipelines. The filing was docketed in IS06-296. Calnev's filing was protested by ExxonMobil, claiming that Calnev was not entitled to an indexing increase in its rates based on its cost of service. Calnev answered the protest. On June 29, 2006, the FERC accepted and suspended the filing, subject to refund, permitting the increased rates to go into effect on July 1, 2006. The FERC found that Calnev's indexed rates exceeded its change in costs to a degree that warranted establishing an investigation and hearing. However, the FERC initially directed the parties to attempt to reach a settlement of the dispute before a FERC settlement judge. The settlement process is proceeding.  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 at any time.  In October, 2002, the CPUC issued a resolution, referred to in this report as the Power Surcharge 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    21 <PAGE>  the CPUC in determining whether SFPP's overall rates for California intrastate transportation services are reasonable. The resolution reserves the right to require refunds, from the date of issuance of the resolution, to the extent the CPUC's analysis of cost data to be submitted by SFPP demonstrates that SFPP's California jurisdictional rates are unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data required by the CPUC, which submittal was protested by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and Chevron Products Company. Issues raised by the protest, including the reasonableness of SFPP's existing intrastate transportation rates, were the subject of evidentiary hearings conducted in December 2003 and may be resolved by the CPUC at any time.  With regard to the CPUC complaints and the Power Surcharge Resolution, we currently believe the complainants/protestants seek approximately $31 million in prospective annual tariff reductions. Based upon CPUC practice and procedure which precludes refunds or reparations in complaints in which the complainants challenge the reasonableness of rates previously found reasonable by the CPUC (as is the case with the two pending complaints contesting the reasonableness of SFPP's rates) except for matters which have been expressly reserved by the CPUC for further consideration (as is the case with respect to the reasonableness of the rate charged for use of the Watson Station gathering enhancement facilities), we currently believe that complainants/protestants are seeking approximately $15 million in refunds/reparations. There is no way to quantify the potential extent to which the CPUC could determine that SFPP's existing California rates are unreasonable.  SFPP also has various, pending ratemaking matters before the CPUC that are unrelated to the above-referenced complaints and the Power Surcharge Resolution. On November 22, 2004, SFPP filed an application with the CPUC requesting a $9 million annual 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. Because no schedule has been established by the CPUC for addressing the issues raised by the contested rate increase application nor does any record exist upon which the CPUC could base a decision, SFPP has no basis for estimating either the prospective rate reductions or the potential refunds at issue or for establishing a date by which the CPUC is likely to render a decision regarding the application.  On January 26, 2006, SFPP filed a request for a rate increase of approximately $5.4 million annually 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. As a consequence of the protests, the related rate increases are being collected subject to refund. Because no schedule has been established by the CPUC for addressing the issues raised by the contested rate increase application nor does any record exist upon which the CPUC could base a decision, SFPP has no basis for estimating either the prospective rate reductions or the potential refunds at issue or for establishing a date by which the CPUC is likely to render a decision regarding the application.  On August 25, 2006, SFPP filed an application to increase rates by approximately $0.5 million annually to recovers costs incurred to comply with revised Ultra Low Sulfur Diesel regulations and to offset the revenue loss associated with reduction of the Watson Station Volume Deficiency Charge (intrastate) by increasing rates on a system-wide basis by approximately $3.1 million annually to be effective as of October 5, 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. As a consequence of the protests, the related rate increases are being collected subject to refund. Because no schedule has been established by the CPUC for addressing the issues raised by the contested rate increase application, nor does any record exist upon which the CPUC could base a decision, SFPP has no basis for estimating either the prospective rate reductions, or the potential refunds at issue, or for establishing a date by which the CPUC is likely to render a decision regarding the application.    22 <PAGE>  All of the referenced pending matters before the CPUC have been consolidated and assigned to a single Administrative Law Judge who has indicated his intention to refer the matters to mediation under CPUC procedures applicable to alternative dispute resolution processes.  With regard to the Power Surcharge Resolution, the November 2004 rate increase application, the January 2006 rate increase application, and the August 2006 rate increase application, 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 rate reductions or 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).  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. The case is currently set for trial on June 11, 2007.  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 case is currently set for trial on June 11, 2007.  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     23 <PAGE>  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 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 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 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 that are virtually identical to the 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, asserted 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,    24 <PAGE>  breach of contract and implied duties to market and good faith and fair dealing, and civil theft and conversion. Ptasynski sought actual damages, treble damages, forfeiture, disgorgement, and declaratory and injunctive relief. The Colorado court transferred the case to Houston federal district court, and Ptasynski subsequently sought to non-suit the case. The Houston federal district court granted Ptasynski's request to non-suit. Prior to non-suiting the case, Ptasynski filed an appeal in the Tenth Circuit seeking to overturn the Colorado court's order transferring the case to Houston federal district court. That appeal is currently pending.  Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company were 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 involved 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 claimed breaches of contractual and potential fiduciary duties owed by the defendants and also alleged 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 sought 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. In August 2006, plaintiffs and defendants reached a settlement of all claims. Pursuant to the settlement, the case was dismissed with prejudice on September 27, 2006.  Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor in interest to Shell CO2 Company, Ltd., were among the named defendants in CO2 Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005. The arbitration arose 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 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 alleged 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 $12 million. The plaintiff also alleged that Cortez Pipeline Company should have used certain funds to further reduce its debt, which, in turn, would have allegedly increased the value of royalty and other payments by approximately $0.5 million. Defendants denied that there was any breach of the settlement agreement. The arbitration panel issued various preliminary evidentiary rulings. The arbitration hearing took place in Albuquerque, New Mexico on June 26-30, 2006. On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement. The arbitration opinion remains subject to further proceedings to confirm, vacate, or modify the opinion.  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     25 <PAGE>  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 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. Kinder Morgan appealed that ruling to the New Mexico Court of Appeals. Oral arguments took place before the New Mexico Court of Appeals on March 23, 2006, and the New Mexico Court of Appeals affirmed the district court's order on August 8, 2006. Kinder Morgan filed a petition for  writ of certiorari in the New Mexico Supreme Court. The New Mexico Supreme Court granted the petition on October 11, 2006.  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.  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 sought appellate review of the interest award. In July 2006, the Court of Appeals disallowed the award of interest.  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. In July 2006, a trial before a judge regarding the circumstances under which we must pay for relocations concluded, and a decision from the judge is expected in the fourth quarter of 2006. In addition,    26 <PAGE>   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 positions, 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 greater 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 filed briefs opposing leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's  Motion to Amend.    27 <PAGE>  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.  On October 20, 2006, the United States District Court, for the District of Wyoming, issued its Order on Report and Recommendations of Special Master. In its Order, the Court upheld the dismissal of the claims against the Kinder Morgan defendants on jurisdictional grounds, finding that the Grynberg's claims are based upon public disclosures and that Grynberg does not qualify as an original source. It is probable that Grynberg will appeal this Order 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 various defendants have filed motions arguing that the Arkansas courts lack personal jurisdiction over them. The Court has not yet ruled on these motions. 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.  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. In September 2005 and subsequent thereto, we    28 <PAGE>  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 believe that the federal authorities are also investigating coal inventory practices at one or more of our other terminals. While we have no indication of the direction of this additional investigation, our records do not reflect any sales of excess coal from our other terminals, and we are not aware of any wrongdoing or improper activities at our terminals. We are cooperating fully with federal law enforcement authorities in this investigation, and expect several of our officers and employees to be interviewed formally by federal authorities. 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  Claims asserted by residents and businesses. 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 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, referred to in this report as 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.   In June, 2006, the parties reached an agreement to partially settle the class action suit. On June 29, 2006, the plaintiffs filed an unopposed motion for conditional certification of a settlement class. The settlement provides for a fund of $2.0 million to distribute to residents within the evacuation zone ("Zone 1") and residents immediately adjacent to the evacuation zone ("Zone 2"). Persons in Zones 1 and 2 reside within approximately one mile from the site of the incident. The court preliminarily approved the partial class action settlement on July 7, 2006. Kinder Morgan Energy Partners agreed to participate in and fund a minor percentage of the settlement. A fairness hearing occurred on August 18, 2006 for the purpose of establishing final approval of the partial settlement. The Court approved the settlement, entered a final judgment, and certified a settlement class for Zones 1 and 2. The bar date for claims has passed and Plaintiffs' counsel reports that they will be paying claims in the immediate future. Certain claims by other residents and businesses remain pending. Specifically, the settlement and final judgment does not apply to purported class action claims by residents in outlying geographic zones more than one mile from the site of the incident. Defendants deny liability to such other residents in outlying geographic zones and intend to vigorously defend such claims. In addition, the non-Kinder Morgan defendants have agreed to settle remaining claims asserted by businesses and will obtain a release of such claims favoring all defendants, including Kinder Morgan and its affiliates, subject to the retention by all defendants of their claims against each other for contribution and indemnity. Kinder Morgan expects that a claim will be asserted by other defendants against Kinder Morgan seeking contribution or indemnity for any settlements funded exclusively by other defendants, and Kinder Morgan expects to vigorously defend against any such claims.     29 <PAGE>  Claims asserted by the city of Cincinnati. 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. 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, the Kinder Morgan defendants filed a motion for summary judgment seeking dismissal of the remaining aspects of the city's complaint. The issues have been thoroughly briefed, and oral argument will be heard on December 8, 2006. The parties agreed to stay discovery until after the hearing, if necessary. No trial date has been established.  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 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.     30 <PAGE>  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. This motion was denied by the 9th Circuit Court of Appeals on May 25, 2006.  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 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 filed motions to dismiss all causes of action excluding plaintiffs' cause of action for negligence. Defendants also filed motions to strike portions of the complaint. By order dated May 5, 2006, the Court granted defendants' motions to dismiss as to the counts purporting to assert claims for fraud, but denied defendants' motions to dismiss as to the remaining counts, as well as defendants' motions to strike. Defendant Kennametal, Inc. has filed a third-party complaint naming the United States and the United States Navy (the "United States") as additional defendants. In response, the United States removed the case to the United States District Court for the District of Nevada and filed a motion to dismiss the third-party complaint, which motion is currently pending. Plaintiff has also filed a motion to dismiss the United States and/or to remand the case back to state court. Briefing on these motions is currently underway.     31 <PAGE>   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 third amended complaint and all defendants filed motions to dismiss all causes of action excluding plaintiffs' cause of action for negligence. Defendants also filed motions to strike portions of the complaint. By order dated May 5, 2006, the Court granted defendants' motions to dismiss as to the counts purporting to assert claims for fraud, but denied defendants' motions to dismiss as to the remaining counts, as well as defendants' motions to strike. Defendant Kennametal, Inc. has filed a third-party complaint naming the United States and the United States Navy (the "United States") as additional defendants. In response, the United States removed the case to the United States District Court for the District of Nevada and filed a motion to dismiss the third-party complaint, which motion is currently pending. Plaintiff has also filed a motion to dismiss the United States and/or to remand the case back to state court. Briefing on these motions is currently underway.  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 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 executed a settlement agreement and release of all claims and counterclaims in the above captioned matter. On August 14, 2006, the case was dismissed with prejudice.  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    32 <PAGE>   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. Each of these lawsuits are currently coordinated in Contra Costa County Superior Court. There are also several cross-complaints for indemnity between the co-defendants in the coordinated lawsuits. The majority of the cases 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 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 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.  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. The parties are currently engaged in discovery and court ordered mediation.  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    33 <PAGE>   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 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. The released product did not ignite and there were no deaths or injuries. Plantation    34 <PAGE>   estimates the amount of product released to be approximately 553 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. 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 while the cause is investigated and a remediation plan is proposed and approved by PHMSA. The cause of the release is related to an original pipe manufacturing seam defect.  Dublin, California  In June 2006, near Dublin, California, our SFPP pipeline, which transports refined petroleum products to San Jose, California, experienced a failure, resulting in a release of product that affected a limited area along a recreation path known as the Iron Horse Trail. Product impacts were primarily limited to backfill of utilities crossing the pipeline. The release was located on land administered by Alameda County, California. Remediation and monitoring activities are ongoing under the supervision of The State of California Department of Fish & Game. The cause of the release was outside force damage. We are currently investigating potential recovery against third parties.  Soda Springs, California  In August 2006, our SFPP pipeline, which transports refined petroleum products to Reno, Nevada, experienced a failure near Soda Springs, California, resulting in a release of product that affected a limited area along Interstate Highway 80. Product impacts were primarily limited to soil in an area between the pipeline and Interstate Highway 80. The release was located on land administered by Nevada County, California. Remediation and monitoring activities are ongoing under the supervision of The State of California Department of Fish & Game and Nevada County. 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 Pipeline and Hazardous Materials Safety Administration (PHMSA) 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. PHMSA sought to have us implement a number of changes to our integrity management program and also to impose a proposed civil penalty of approximately $0.3 million. An administrative hearing was held on April 11 and 12, 2005, and a final order was issued on June 26, 2006. We have already addressed most of the concerns identified by PHMSA and continue to work  with them to ensure that our integrity management program satisfies all applicable regulations. However, we are seeking clarification for portions of this order and have received an extension of time to allow for discussions. Along with the extension, we reserved our right to seek reconsideration if needed. We have established a reserve for the $0.3 million proposed civil penalty, and this matter is not expected to have a material impact 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.    35 <PAGE>   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.  The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC; Continental Oil Company; Chevron Corporation, California Superior Court, County of Los Angeles, Case No. NC041463.  We are and some of our subsidiaries are defendants in a lawsuit filed in 2005 captioned The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC;  Continental Oil Company; Chevron Corporation, California Superior Court, County of Los Angeles, Case No. NC041463. The suit involves claims for environmental cleanup costs and rent at the former Los Angeles Marine Terminal in the Port of Los Angeles. Plaintiff alleges that terminal cleanup costs could approach $18 million; however, Kinder Morgan believes that the clean up costs should be substantially less and that cleanup costs must be apportioned among all the parties to the litigation. Plaintiff also alleges that it is owed approximately $2.8 million in past rent and an unspecified amount for future rent; however, we believe that previously paid rents paid will offset some of the Plaintiff's rent claim and that we have certain defenses to the payment of rent allegedly owed. The lawsuit is set for trial in October 2007. We will vigorously defend these matters and believe that the outcome will not have a material adverse effect on us  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.    36 <PAGE>  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 September 30, 2006, we have accrued an environmental reserve of $65.2 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.   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.    37 <PAGE>  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 September 30, 2006, we have recognized asset retirement obligations in the aggregate amount of $46.6 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 September 30, 2006, we have recognized asset retirement obligations in the aggregate amount of $1.7 million relating to the businesses within our Natural Gas Pipelines business segment.  We have included $1.4 million of our total asset retirement obligations as of September 30, 2006 with "Accrued other current liabilities" in our accompanying consolidated balance sheet. The remaining $46.9 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 nine months ended September 30, 2006 and 2005 is as follows (in thousands):  Nine Months Ended September 30, ------------------------------- 2006            2005  --------------    -------------  Balance at beginning of period.........  $ 43,227       $  38,274 Liabilities incurred.................     4,950             521 Liabilities settled..................    (1,762)         (1,497) Accretion expense....................     1,853             807 Revisions in estimated cash flows....        --            (522) -------        -------- Balance at end of period...............  $ 48,268       $  37,583 =======         =======   5. Distributions  On August 14, 2006, we paid a cash distribution of $0.81 per unit to our common unitholders and our Class B unitholders for the quarterly period ended June 30, 2006. KMR, our sole i-unitholder, received 1,131,777 additional i-units based on the $0.81 cash distribution per common unit. The distributions were declared on July 19, 2006, payable to unitholders of record as of July 31, 2006.  On October 18, 2006, we declared a cash distribution of $0.81 per unit for the quarterly period ended September 30, 2006. The distribution will be paid on November 14, 2006, to unitholders of record as of October 31, 2006. Our common unitholders and Class B unitholders will receive cash. KMR will receive a distribution in the form of additional i-units based on the $0.81 distribution per common unit. The number of i-units distributed will be 1,160,520. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.018981) will be issued. The fraction was determined by dividing:  o    $0.81, the cash amount distributed per common unit  by  o    $42.675, the average of KMR's shares' closing market prices from October 13-26, 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.     38 <PAGE>  6. Intangibles  Goodwill  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. Goodwill is not subject to amortization but must be tested for impairment at least annually. Following is information related to our goodwill (in thousands):   September 30,     December 31, 2006              2005 -------------     ------------ Goodwill Gross carrying amount.......   $ 832,942          $813,101 Accumulated amortization....     (14,142)          (14,142) --------           -------- Net carrying amount.........     818,800           798,959 ========           =======  Changes in the carrying amount of our goodwill for the nine months ended September 30, 2006 are summarized as follows (in thousands):  <TABLE> <CAPTION>  Products    Natural Gas Pipeline     Pipelines      CO2       Terminals      Total --------     ---------      ---       ---------      ----- <S>                    <C> <C>         <C>          <C>          <C>         <C>          <C> Balance as of December 31, 2005......  $263,182     $288,435     $46,101     $201,241     $798,959 Acquisitions.......................         -            -           -       17,763       17,763 Purchase price adjustments.........         -            -           -        2,078        2,078 Impairments........................         -            -           -            -            - -------      -------      ------      -------      ------- Balance as of September 30, 2006.....  $263,182     $288,435     $46,101     $221,082     $818,800 =======      =======      ======      =======      ======= </TABLE>   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. 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 September 30, 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. The caption "Investments" in our accompanying consolidated balance sheets includes excess fair value of net assets over book value costs of $178.6 million as of September 30, 2006 and $181.7 million as of December 31, 2005.  Other Intangibles  Excluding goodwill, our other intangible assets include lease value, contracts, customer relationships and agreements. These 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. Following is information related to our intangible assets subject to amortization (in thousands):   39 <PAGE>  September 30,   December 31, 2006            2005 -------------   ------------ Lease value Gross carrying amount.........   $   6,592       $   6,592 Accumulated amortization......      (1,274)         (1,168) --------        -------- Net carrying amount...........       5,318           5,424 --------        --------  Contracts and other  Gross carrying amount.........     224,550         221,250 Accumulated amortization......     (19,794)         (9,654) --------        -------- Net carrying amount...........     204,756         211,596 --------        --------  Total Other intangibles, net....   $ 210,074       $ 217,020 ========        ========  Amortization expense on our intangiblesconsisted of the following (in thousands):  <TABLE> <CAPTION> Three Months Ended September 30,        Nine Months Ended September 30, --------------------------------        ------------------------------- 2006              2005                  2006              2005 --------------    --------------        --------------    -------------- <S>                        <C>               <C>                  <C>                <C> Lease value............    $    35           $    35              $    106           $   106 Contracts and other....      3,372             3,487                10,140             4,318 -------           -------              --------           ------- Total amortization.....    $ 3,407           $ 3,522              $ 10,246           $ 4,424 =======           =======              ========           ======= </TABLE>  As of September 30, 2006, our weighted average amortization period for our intangible assets was approximately 18.9 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, $11.9 million and $11.8 million, respectively.   7. Debt  Our outstanding short-term debt as of September 30, 2006 was $1,147.2 million. The balance consisted of:  o    $887.6 million of commercial paper borrowings;  o    $250.0 million in principal amount of 5.35% senior notes due August 15, 2007;  o    a $5.8 million portion of 5.23% senior notes (our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes);  o    a $5.0 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).  The weighted average interest rate on all of our borrowings was approximately 6.44% during the third quarter of 2006 and 5.40% during the third quarter of 2005.  Credit Facility  Effective August 28, 2006, we terminated our $250 million unsecured nine-month bank credit facility due November 21, 2006, and we increased our existing five-year bank credit facility from $1.60 billion to $1.85 billion. The five-year unsecured bank credit facility remains due August 18, 2010; however, the bank facility can now be amended to allow for borrowings up to $2.1 billion. There were no borrowings under our five-year credit facility as of December 31, 2005 or as of September 30, 2006.  Our five-year credit facility is with a syndicate of financial institutions, and Wachovia Bank, National Association is the administrative agent. The amount available for borrowing under our credit facility as of September 30, 2006 was reduced by:    40 <PAGE>  o    our outstanding commercial paper borrowings ($887.6 million as of September 30, 2006);  o    a combined $353 million in five letters of credit that support our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil;  o    a combined $49 million in two letters of credit that support tax-exempt bonds;  o    a $19.9 million letter of credit that supports the construction of our Kinder Morgan Louisiana Pipeline (a natural gas pipeline); and  o    a combined $16.2 million in 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. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. As of September 30, 2006, we had $887.6 million of commercial paper outstanding with an average interest rate of 5.42%.  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.  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 ownership 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 will be 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.     41 <PAGE>  As of September 30, 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 September 30, 2006, Cortez Capital Corporation had $76.2 million of commercial paper outstanding with an average interest rate of 5.31%, 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 September 30, 2006, $39.3 million in principal amount of Senior 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 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 September 30, 2006, this letter of credit had an outstanding balance under our credit facility of $24.9 million.  Rockies Express Pipeline LLC Debt  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 supports a $2.0 billion commercial paper program that was established in May 2006, and borrowings under the commercial paper program reduce the borrowings allowed under the credit facility; this facility can be amended to allow for borrowings up to $2.5 billion. Borrowings under the Rockies Express credit facility and commercial paper program will be primarily used to finance the construction of the Rockies Express interstate natural gas pipeline and to  pay related expenses, and the borrowings will not reduce the borrowings allowed under our credit facility described above in "--Credit Facility."  In addition, pursuant to certain guaranty agreements, all three member owners of West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline, LLC) have agreed to guarantee borrowings under the Rockies Express credit facility and under the Rockies Express commercial paper program severally in the same proportion as their percentage ownership of the member interests in Rockies Express Pipeline LLC. The three member owners and their respective ownership interests consist of the following: our subsidiary Kinder Morgan W2E Pipeline LLC - 51%, Sempra Energy - 25%, and ConocoPhillips - 24%. As of September 30, 2006, Rockies Express Pipeline LLC had $583.5 million of commercial paper outstanding, and there were no borrowings under its five-year credit    42 <PAGE>  facility. Accordingly, as of September 30, 2006, our contingent share of Rockies Express' debt was $297.6 million (51% of total commercial paper borrowings).  Certain Relationships and Related Transactions  In conjunction with our acquisition of Natural Gas Pipelines assets from KMI on December 31, 1999 and 2000, KMI agreed to indemnify us and our general partner with respect to 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 agreed to indemnify us and our general partner with respect to approximately $210.8 million of our debt. Thus, as of September 30, 2006, KMI has agreed to indemnify us and our general partner with respect to a total of approximately $733.5 million of our debt. KMI would be obligated to perform under this indemnity only if our assets were insufficient 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 September 30, 2006 and December 31, 2005, our partners' capital consisted of the following limited partner units:  September 30,    December 31, 2006            2005 -------------    ------------  Common units.......................   162,779,676      157,005,326 Class B units......................     5,313,400        5,313,400 i-units............................    61,141,156       57,918,373 -----------      ----------- Total limited partner units......   229,234,232      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 September 30, 2006, our common unit totals consisted of 148,423,941 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 August 15, 2006, we issued, in a public offering, 5,000,000 of our  common units at a price of $44.80 per unit, less commissions and underwriting expenses. At the time of the offering, we granted the underwriters a 30-day option to purchase up to an additional 750,000 common units from us on the same terms and conditions, and we issued the additional 750,000 common units on August 23, 2006 upon the underwriters' exercise of this option. After commissions and underwriting expenses, we received net proceeds of approximately $248.0 million for the issuance of these 5,750,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.  On both September 30, 2006 and December 31, 2005, all of our 5,313,400 Class B units were held entirely by a wholly-owned subsidiary of KMI. The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. All of our Class B units were issued to a wholly-owned subsidiary of KMI in December 2000.  On both September 30, 2006 and December 31, 2005, all of our i-units were held entirely by KMR. Our i-units are a separate class of limited partner interests in us 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 to 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    43 <PAGE>  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 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 1,131,777 i-units from us on August 14, 2006. These additional i-units distributed were based on the $0.81 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 $0.81 per unit paid on August 14, 2006 for the second quarter of 2006 required an incentive distribution to our general partner of $129.0 million. Our distribution of $0.78 per unit paid on August 12, 2005 for the second quarter of 2005 required an incentive distribution to our general partner of $115.7 million. The increased incentive distribution to our general partner paid for the second quarter of 2006 over the distribution paid for the second quarter of 2005 reflects the increase in the amount distributed per unit as well as the issuance of additional units.   Our declared distribution for the third quarter of 2006 of $0.81 per unit will result in an incentive distribution to our general partner of approximately $133.0 million. This compares to our distribution of $0.79 per unit and incentive distribution to our general partner of approximately $121.5 million for the third 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 and nine month periods ended September 30, 2006, and September 30, 2005, the difference between our net income and our comprehensive income resulted from unrealized gains or losses on derivative contracts utilized for hedging purposes and from foreign currency translation adjustments. For more information on our hedging activities, see Note 10. Our total comprehensive income was as follows (in thousands):  <TABLE> <CAPTION> Three Months Ended          Nine Months Ended September 30,              September 30, ----------------------       -------------------- 2006          2005           2006        2005 --------      --------       --------    -------- <S>                                           <C>           <C>            <C>        <C> Net income................................... $223,818      $245,387       $717,588   $ 690,834  Foreign currency translation adjustments.....       72             8            456        (596) Change in fair value of derivatives used for hedging purposes....................  203,572      (259,826)      (281,295) (1,016,695) Reclassification of change in fair value of derivatives to net income...........  118,868       141,361        338,020     287,032 --------      --------       --------   --------- Total other comprehensive income/(loss)................................  322,512      (118,457)        57,181    (730,259) --------      --------       --------   ---------  Comprehensive income/(loss).................. $546,330      $126,930       $774,769   $ (39,425) ========      ========       ========   ========= </TABLE>    44 <PAGE>  10. Risk Management  Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil. We also have exposure to interest rate risk as a result of the issuance of our fixed rate debt obligations. Pursuant to our management's approved risk management policy, we use derivative contracts to hedge or reduce our exposure to these risks, and we account for these hedging transactions according to the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" and associated amendments, collectively, SFAS No. 133.  Energy Commodity Price Risk Management  We are exposed to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil as a result of the forecasted purchase or sale of these products. Such changes are often caused by shifts in the supply and demand for these commodities, as well as their locations. Our energy commodity derivative contracts act as a hedging (offset) mechanism against the volatility of energy commodity prices by allowing us to transfer this price risk to counterparties who are able and willing to bear it.  Hedging effectiveness and ineffectiveness   These contracts are used to offset the risk associated with an anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain, therefore the resulting hedges are designated and qualified as cash flow hedges in accordance with SFAS No. 133. For cash flow hedges, the portion of the change in the value of derivative contracts that is effective in offsetting undesired changes in expected cash flows (the effective portion) is reported as a component of other comprehensive income (outside current earnings, net income), but only to the extent that they can later offset the undesired changes in expected cash flows during the period in which the hedged cash flows affect earnings. Other comprehensive income consists of those financial items that are included in "accumulated other comprehensive income/loss" on the balance sheet but not included within net income on the statement of income. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the change in the value of the derivative contacts and there is no impact on earnings.  To the contrary, the portion of the change in the value of derivative contracts that is not effective in offsetting undesired changes in expected cash flows (the ineffective portion), as well as any component excluded from the computation of the effectiveness of the derivative contracts, is required to be recognized currently in earnings. Accordingly, as a result of ineffective hedges, we recognized a gain of $0.5 million and a loss of $1.3 million, respectively, during the three and nine month periods ended September 30, 2006, and losses of $1.9 million and $2.3 million, respectively, during the three and nine month periods ended September 30, 2005. All of the gains and losses we recognized as a result of ineffective hedges are reported within the captions "Natural gas sales," "Gas purchases and other costs of sales," and "Product sales and other" in our accompanying consolidated statements of income. For each of the three and nine months ended September 30, 2006 and 2005, we did not exclude any component of the derivative contracts' gain or loss from the assessment of hedge effectiveness.  When the hedged sales and purchases take place and we record them into earnings, or when a determination is made that a forecasted transaction will no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, the gains and losses from the effective portion of the change in the value of the derivative contracts are removed from "accumulated other comprehensive income/loss" on the balance sheet and reclassified into earnings. During the three and nine month periods ended September 30, 2006, we reclassified $118.9 million and $338.0 million, respectively, of "Accumulated other comprehensive loss" into earnings, and during the three and nine month periods ended September 30, 2005, we reclassified $141.3 million and $287.0 million, respectively, of "Accumulated other comprehensive loss" into earnings.  With the exception of the $2.9 million loss resulting from the discontinuance of cash flow hedges related to the sale of our Douglas gathering assets (described in Note 2), none of the reclassification of Accumulated other comprehensive loss into earnings during the first nine months of 2006 or 2005 resulted from the discontinuance of    45 <PAGE>  cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather resulted from the hedged forecasted transactions actually affecting earnings (for example, when the forecasted sales and purchases actually occurred). Approximately $437.4 million of our "Accumulated other comprehensive loss" balance of $1,022.5 million as of September 30, 2006 is expected to be reclassified into earnings during the next twelve months.  Fair Value of Energy Commodity Derivative Contracts  Derivative contracts represent rights or obligations that meet the definitions of assets or liabilities and should be reported in financial statements. Furthermore, SFAS No. 133 requires derivative contracts 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 energy commodity derivative contracts reflect 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 energy commodity derivative contracts that we use, including: commodity futures and options contracts, fixed price swaps, and basis swaps.  The fair values of our energy commodity derivative contracts are included in our accompanying consolidated balance sheets within "Other current assets," "Deferred charges and other assets," "Accrued other current liabilities," "Other 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 commodity derivative contracts associated with our commodity price risk management activities and included on our accompanying consolidated balance sheets as of September 30, 2006 and December 31, 2005 (in thousands):  September 30,     December 31, 2006             2005 -------------     ------------ Derivatives-net asset/(liability) Other current assets......................      $  115,347       $  109,437 Deferred charges and other assets.........          17,977           47,682 Accounts payable-Related parties..........              --          (16,057) Accrued other current liabilities.........        (553,330)        (507,306) Other long-term liabilities and deferred credits..........................      $ (602,900)      $ (727,929)  Our over-the-counter swaps and options are contracts 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 September 30, 2006. We both owe money and are owed money under these derivative contracts. 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 contracts 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 derivative contracts or when the market value of our derivative contracts 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 September 30, 2006, we had five outstanding letters of credit totaling $353 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 September 30, 2006, we had no cash margin deposits associated with our commodity contract positions and over-the-counter swap partners; however, our counterparties associated with our commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $1.4 million, and we reported this amount within "Accrued other liabilities" in our accompanying consolidated balance sheet as of September 30,    46 <PAGE>  2006. As of December 31, 2005, we had no cash margin deposits associated with our commodity contract positions and over-the-counter swap partners.   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 September 30, 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.  As of September 30, 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 September 30, 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.  Hedging effectiveness and ineffectiveness  Our interest rate swaps have been designated as fair value hedges as defined by SFAS No. 133. According to the provisions of SFAS No. 133, when derivative contracts are used 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    47 <PAGE>  contract is appropriate, 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.  Fair Value of Interest Rate Swap Agreements  The differences between the fair value and the original carrying value associated with our interest rate swap agreements, that is, the derivative contracts' 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.  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 September 30, 2006 and December 31, 2005 (in thousands):  September 30,  December 31, 2006          2005 -------------  ------------ Derivatives-net asset/(liability) Deferred charges and other assets.................  $  67,444      $ 112,386 Other long-term liabilities and deferred credits..    (22,638)       (13,917) ---------      --------- Market value of interest rate swaps.............  $  44,806      $  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 contracts 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 September 30, 2006, all of our interest rate swap agreements were with counterparties with investment grade credit ratings.  Other  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.    11. Reportable Segments  We divide our operations into four reportable business segments:  o    Products Pipelines;  o    Natural Gas Pipelines;  o    CO2; and    48 <PAGE>  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, the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields, and the production and sale of natural gas and natural gas liquids. 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):  <TABLE> <CAPTION> Three Months Ended             Nine Months Ended September 30,                 September 30, --------------------------     ------------------------- 2006            2005           2006           2005 ----------      ----------     ----------     ---------- Revenues(a) <S>     <C>    <C>    <C>    <C>    <C>    <C> Products Pipelines Revenues from external customers.......  $   207,726     $   181,903    $   577,273    $   527,818 Intersegment revenues..................            -               -              -              - Natural Gas Pipelines Revenues from external customers.......    1,650,427       2,108,788      5,082,183      5,198,337 Intersegment revenues..................            -               -              -              - CO2 Revenues from external customers.......      192,303         163,079        552,783        488,271 Intersegment revenues..................            -               -              -              - Terminals Revenues from external customers.......      222,977         177,484        649,283        515,115  Intersegment revenues..................          174               -            539              - -----------     -----------    -----------    ----------- Total segment revenues....................    2,273,607       2,631,254      6,862,061      6,729,541 Less: Total intersegment revenues.........         (174)              -           (539)             - -----------     -----------    -----------    ----------- Total consolidated revenues.............  $ 2,273,433     $ 2,631,254    $ 6,861,522    $ 6,729,541 ===========     ===========    ===========    ===========  Operating expenses(b) Products Pipelines........................  $    94,609     $    60,613    $   234,149    $   169,739 Natural Gas Pipelines.....................    1,519,129       1,996,737      4,693,969      4,863,524 CO2.......................................       68,888          48,546        194,212        152,389 Terminals.................................      122,230          94,318        354,892        271,470 -----------     -----------    -----------    ----------- Total consolidated operating expenses...  $ 1,804,856     $ 2,200,214    $ 5,477,222    $ 5,457,122 ===========     ===========    ===========    ===========  Other expense (income)(c) Products Pipelines........................  $         -     $         -    $         -    $         - Natural Gas Pipelines.....................            -               -        (15,114)             - CO2.......................................            -               -              -              - Terminals.................................            -               -              -              - -----------     -----------    -----------    ----------- Total consolidated other expense (income)........................  $         -     $         -    $   (15,114)   $         - ===========     ===========    ===========    ===========  Depreciation, depletion and amortization Products Pipelines........................  $    20,820     $    19,849    $    61,541    $    59,071 Natural Gas Pipelines.....................       15,959          15,205         47,938         45,779 CO2.......................................       50,731          34,658        132,021        111,822 Terminals.................................       19,320          15,644         55,280         41,972 -----------     -----------    -----------    ----------- Total consol. depreciation, depletion and amortization........................  $   106,830     $    85,356    $   296,780    $   258,644 ===========     ===========    ===========    =========== </TABLE>     49 <PAGE>   <TABLE> <CAPTION> Three Months Ended             Nine Months Ended September 30,                 September 30, --------------------------     ------------------------- 2006            2005           2006           2005 ----------      ----------     ----------     ---------- Earnings from equity investments(d) <S>                                             <C>             <C>            <C>            <C> Products Pipelines........................   $     514       $   6,256      $   11,067     $   21,706 Natural Gas Pipelines.....................      10,062           8,705          31,833         25,733 CO2.......................................       3,380           5,533          14,113         21,932 Terminals.................................          76              18             190             51 ---------       ---------      ----------     ---------- Total consolidated equity earnings......   $  14,032       $  20,512      $   57,203     $   69,422 =========       =========      ==========     ==========  Amortization of excess cost of equity investments Products Pipelines........................   $     841       $     832      $    2,521     $    2,512 Natural Gas Pipelines.....................          71              70             210            208 CO2.......................................         504             505           1,513          1,513 Terminals.................................           -               -               -              - ---------       ---------      ----------     ---------- Total consol. amortization of excess cost of investments.....................   $   1,416       $   1,407      $    4,244     $    4,233 =========       =========      ==========     ==========  Interest income Products Pipelines........................   $   1,123       $   1,147      $    3,358     $    3,445 Natural Gas Pipelines.....................           -             193             150            530 CO2.......................................           -               -               -              - Terminals.................................           -               -               -              - Total segment interest income...........       1,123           1,340           3,508          3,975 Unallocated interest income...............         238             109           1,599            374 ---------       ---------      ----------     ---------- Total consolidated interest income......   $   1,361       $   1,449      $    5,107     $    4,349 =========       =========      ==========     ==========  Other, net - income (expense)(e) Products Pipelines........................   $   1,583       $     633      $    7,783     $      998 Natural Gas Pipelines.....................         376           1,367             725          1,509  CO2.......................................         324              (6)            336             (6) Terminals.................................       1,056             886           2,335           (293) ---------       ---------      ----------     ---------- Total consolidated other, net - income (expense)...............................   $   3,339       $   2,880      $   11,179     $    2,208 =========       =========      ==========     ==========  Income tax benefit (expense)(f) Products Pipelines........................   $     584       $  (2,171)     $   (3,288)    $   (8,209) Natural Gas Pipelines.....................        (973)           (361)           (900)        (1,899) CO2.......................................         (57)           (151)           (181)          (263) Terminals.................................      (3,599)         (2,372)         (7,451)        (9,874) ---------       ---------      ----------     ---------- Total consolidated income tax benefit (expense)...............................   $  (4,045)      $  (5,055)     $  (11,820)    $  (20,245) =========       =========      ==========     ==========  Segment earnings Products Pipelines........................   $  95,260       $ 106,474      $  297,982     $  314,436 Natural Gas Pipelines.....................     124,733         106,680         386,988        314,699 CO2.......................................      75,827          84,746         239,305        244,210 Terminals.................................      79,134          66,054         234,724        191,557 ---------       ---------      ----------     ---------- Total segment earnings(g)...............     374,954         363,954       1,158,999      1,064,902 Interest and corporate administrative expenses(h)...............................    (151,136)       (118,567)       (441,411)      (374,068) ---------       ---------      ----------     ---------- Total consolidated net income...........   $ 223,818       $ 245,387      $  717,588     $  690,834 =========       =========      ==========     ==========  Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(i) Products Pipelines........................   $ 116,921       $ 127,155      $  362,044     $  376,019 Natural Gas Pipelines.....................     140,763         121,955         435,136        360,686 CO2.......................................     127,062         119,909         372,839        357,545 Terminals.................................      98,454          81,698         290,004        233,529 ---------       ---------      ----------     ---------- Total segment earnings before DD&A......     483,200         450,717       1,460,023      1,327,779 Total consol. depreciation, depletion and amortization..............................    (106,830)        (85,356)       (296,780)      (258,644) Total consol. amortization of excess cost  of investments............................      (1,416)         (1,407)         (4,244)        (4,233) Interest and corporate administrative expenses..................................    (151,136)       (118,567)       (441,411)      (374,068) ---------       ---------      ----------     ---------- Total consolidated net income ..........   $ 223,818       $ 245,387      $  717,588     $  690,834 =========       =========      ==========     ========== </TABLE>     50 <PAGE>  <TABLE> <CAPTION> Three Months Ended             Nine Months Ended September 30,                 September 30, --------------------------     ------------------------- 2006            2005           2006           2005 ----------      ----------     ----------     ---------- Capital expenditures(j) <S>                                             <C>             <C>            <C>            <C> Products Pipelines.........................  $   30,685      $   82,592     $  151,927     $  180,309 Natural Gas Pipelines......................      18,725          31,707        228,294         64,854 CO2........................................      75,304          92,603        208,396        219,545 Terminals..................................      65,392          48,675        162,729        132,478 ----------      ----------     ----------     ---------- Total consolidated capital expenditures..  $  190,106      $  255,577     $  751,346     $  597,186 ==========      ==========     ==========     ========== </TABLE>  September 30,     December 31, 2006             2005 -------------     ------------ Assets Products Pipelines............  $  3,895,385     $  3,873,939 Natural Gas Pipelines.........     3,896,528        4,139,969 CO2...........................     1,859,407        1,772,756 Terminals.....................     2,243,150        2,052,457 ------------     ------------ Total segment assets..........    11,894,470       11,839,121 Corporate assets(k)...........       128,562           84,341 ------------     ------------ Total consolidated assets.....  $ 12,023,032     $ 11,923,462 ============     ============ --------  (a)  Nine month 2006 amounts include a reduction of $1,819 to our CO2 business segment from a loss on derivative contracts used to hedge forecasted crude oil sales.  (b)  Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. Nine month 2006 amounts include expenses of $13,458 to our Products Pipelines business segment and $1,500 to our Natural Gas Pipelines business  segment associated with environmental liability adjustments, and a $6,244 reduction in expense to our Natural Gas Pipelines business segment due to the release of a reserve related to a natural gas purchase/sales contract. Three and nine month 2005 amounts include a $5,000 increase in expense to our Products Pipelines business segment associated with a North System liquids inventory reconciliation adjustment.  (c)  Nine month 2006 amount represents a $15,114 gain to our Natural Gas Pipelines business segment from the combined sale of our Douglas natural gas gathering system and our Painter Unit fractionation facility.  (d)  Nine month 2006 amounts include a $4,861 increase in expense to our Products Pipelines business segment associated with environmental liability adjustments on Plantation Pipe Line Company.  (e)  Nine month 2006 amounts include a $5,700 increase in income to our Products Pipelines business segment from the settlement of transmix processing contracts.  (f)  Nine month 2006 amounts include a $1,871 decrease in expense to our Products Pipelines business segment associated with the tax effect on expenses from environmental liability adjustments made by Plantation Pipe Line Company and described in footnote (d).  (g)  Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses, other expense (income), depreciation, depletion and amortization, and amortization of excess cost of equity investments.  (h)  Includes unallocated interest income, interest and debt expense, general and administrative expenses and minority interest expense.  (i)  Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses and other expense (income).  (j)  Includes sustaining capital expenditures of $15,576 and $42,845 for the three months ended September 30, 2006 and 2005, respectively, and includes sustaining capital expenditures of $76,229 and $95,801 for the nine months ended September 30, 2006 and 2005, respectively. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset.  (k)  Includes cash, cash equivalents, margin and restricted deposits, certain unallocable deferred charges, and risk management assets related to the market value of interest rate swaps.    51 <PAGE>  We do not attribute interest and debt expense to any of our reportable business segments. For the three months ended September 30, 2006 and 2005, we reported (in thousands) total consolidated interest expense of $89,662 and $69,797, respectively. For the nine months ended September 30, 2006 and 2005, we reported (in thousands) total consolidated interest expense of $251,216 and $196,736, 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 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):  <TABLE> <CAPTION> Other Post-retirement Benefits -------------------------------------------------------------------- Three Months Ended September 30,     Nine Months Ended September 30, --------------------------------     ------------------------------- 2006              2005               2006             2005 --------------    --------------     --------------   -------------- Net periodic benefit cost <S>                                         <C>               <C>                <C>              <C> Service cost...........................     $    3            $    2             $    8           $    6 Interest cost..........................         68                77                202              231 Amortization of prior service cost.....        (29)              (29)               (88)             (87) Actuarial (gain).......................       (114)             (127)              (340)            (381) Net periodic benefit cost..............     $  (72)           $  (77)            $ (218)          $ (231) </TABLE>   Our net periodic benefit cost for the third quarter and the first nine months of 2006 were credits of $72,000 and $218,000, respectively, 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 were 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 September 30, 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   52 <PAGE>  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 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."  In June 2006, Plantation paid to us $1.1 million in principal amount under the note, and as of September 30, 2006, the principal amount receivable from this note was $93.1 million. We included $2.2 million of this balance within "Accounts, notes and interest receivable, net-Related parties" on our consolidated balance sheet as of September 30, 2006, and we included the remaining $90.9 million balance as "Notes receivable-Related parties."  Coyote Gas Treating, LLC  Coyote Gas Treating, LLC is a joint venture that was organized in December 1996. It is referred to as Coyote Gulch in this report. The sole asset owned by Coyote Gulch is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. Prior to the contribution of our ownership interest in Coyote Gulch to Red Cedar Gathering on September 1, 2006, discussed below, we were the managing partner and owned a 50% equity interest in 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 corresponded 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, the owners of Coyote Gulch agreed to a resolution that would transfer Coyote Gulch's notes payable 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.  In the third quarter of 2006, the Southern Ute Indian Tribe acquired the remaining 50% ownership interest in Coyote Gulch from Enterprise Field Services LLC. The acquisition was made effective March 1, 2006. On September 1, 2006, we and the Southern Ute Tribe agreed to a resolution that would transfer all of the members' equity in Coyote Gulch to the members' equity of Red Cedar Gathering, a joint venture organized in August 1994 and referred to in this report as Red Cedar. Red Cedar owns and operates natural gas gathering, compression and treating facilities in the Ignacio Blanco Field in La Plata County, Colorado, and is owned 49% by us and 51% by the Southern Ute Tribe. Under the terms of a five-year operating lease agreement that became effective January 1, 2002, Red Cedar also operates the gas treating facility owned by Coyote Gulch and is responsible for all operating and maintenance expenses and capital costs.  According to the provisions of the September 1, 2006 resolution, we and the Southern Ute Tribe contributed the value of our respective 50% ownership interests in Coyote Gulch to Red Cedar, and as a result, Coyote Gulch became a wholly owned subsidiary of Red Cedar. The value of our 50% equity contribution from Coyote Gulch to Red Cedar on September 1, 2006 was $16.7 million, and this  amount remains included within "Investments" on our consolidated balance sheet as of September 30, 2006.     53 <PAGE>  14. Regulatory Matters  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  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, referred to in this report as INGAA, 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. On May 10, 2006, the court issued an order establishing a briefing schedule. Under the schedule, INGAA filed its initial brief on June 23, 2006. Both the FERC's and INGAA's reply briefs have been filed.  Due to the implementation of this FERC order on January 1, 2006, which caused our FERC-regulated natural gas pipelines to expense certain pipeline integrity management program costs that would have been capitalized, our Kinder Morgan Interstate Gas Transmission system, referred to in this report as KMIGT, expects an increase of approximately $0.9 million in operating expenses in 2006 compared to 2005. Also, beginning in the third quarter of 2006, our Texas intrastate natural gas pipeline group and the operations included in our Products Pipelines and CO2 business segments began recognizing certain costs incurred as part of their pipeline integrity management program as operating expense in the period incurred, and in addition, recorded an expense for costs previously capitalized during the first six months of 2006. For the year 2006 compared to 2005, we expect this change to result in operating expense increases of approximately $1.8 million for our Texas intrastate gas group, $26.8 million  for our Products Pipelines business segment, and $1.4 million for our CO2 business segment. Combined, this change did not have any material effect to prior periods and is not expected to have a material impact on our financial position, results of operations, or cash flows for the 2006 annual period. In addition, due to the fact that these amounts will not be capitalized but instead charged to expense, we expect our 2006 sustaining capital expenditures to be reduced by similar amounts.  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    54 <PAGE>  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.  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, the FERC proposed 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 proposed 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.  On June 19, 2006, FERC issued Order No. 678 allowing for broader market-based pricing of storage services. The rule expands the alternatives that can be considered in evaluating competition, provides that market-based pricing may be available even when market power is present (if market-based pricing is needed to stimulate development), and treats expansions of existing storage facilities similar to new storage facilities. The order became effective July 27, 2006. Several parties have filed for rehearing of this Order.  Natural Gas Pipeline Expansion Filings  Rockies Express Pipeline  On May 31, 2006, in FERC Docket No. CP06-354-000, Rockies Express Pipeline LLC filed an application for authorization to construct and operate certain facilities comprising its proposed "Rockies Express-West Project." This project is the first planned segment extension of the Rockies Express' currently certificated facilities, which includes (i) a 136-mile pipeline segment currently in operation from the Meeker Hub in Colorado to the Wamsutter Hub in Wyoming, and (ii) a 191-mile segment currently under construction and expected to be in service by January 1, 2007, from Wamsutter to the Cheyenne Hub located in Weld County, Colorado. The Rockies Express-West Project will be comprised of approximately 713 miles of 42-inch diameter pipeline extending from the Cheyenne  Hub to an interconnection with Panhandle Eastern Pipe Line located in Audrain County, Missouri. The segment extension proposes to transport approximately 1.5 billion cubic feet per day of natural gas across the following five states: Wyoming, Colorado, Nebraska, Kansas and Missouri. The project will also include certain improvements to existing Rockies Express facilities located to the west of the Cheyenne Hub.  On September 21, 2006, the FERC issued a favorable preliminary determination on all non-environmental issues of the project, approving Rockies Express' application (i) to construct and operate the 713 miles of new natural gas transmission facilities from the Cheyenne Hub and (ii) to lease capacity on Questar Overthrust Pipeline Company, which will extend the Rockies Express system 140 miles west from Wamsutter to the Opal Hub in Wyoming. Pending completion of the FERC environmental review and the issuance of a certificate, the project is expected to begin service on January 1, 2008. Rockies Express will file a separate application in the future for its proposed "Rockies Express-East Project," which will extend the pipeline from eastern Missouri to the Clarington Hub in eastern Ohio.     55 <PAGE>  TransColorado Pipeline  On June 23, 2006, in FERC Docket No. CP06-401-000, TransColorado Gas Transmission Company filed an application for authorization to construct and operate certain facilities comprising its proposed "Blanco-Meeker Expansion Project." Upon implementation, this project will facilitate the transportation of up to approximately 250 million cubic feet per day of natural gas from the Blanco Hub area in San Juan County, New Mexico through TransColorado's existing interstate pipeline for delivery to the Rockies Express Pipeline at an existing point of interconnection located in the Meeker Hub in Rio Blanco County, Colorado.  Kinder Morgan Louisiana Pipeline  On September 8, 2006, in FERC Docket No. CP06-449-000, we filed an application with the FERC requesting approval to construct and operate our Kinder Morgan Louisiana Pipeline. The pipeline will extend approximately 135 miles from Cheniere's Sabine Pass liquefied natural gas terminal in Cameron Parish, Louisiana, to various delivery points in Louisiana and will provide interconnects with many other natural gas pipelines, including KMI's Natural Gas Pipeline Company of America. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total. The entire approximately $500 million project is expected to be in service in the second quarter of 2009.  FERC Order No. 2004  On July 20, 2006, the FERC accepted our interstate pipelines' May 19, 2005 compliance filing under Order No. 2004, the order adopting standards of conduct that govern the relationships between natural gas transmission providers and all their marketing and energy affiliates.   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.    56 <PAGE>  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.  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 from 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    57 <PAGE>  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). Adoption of this Statement should not have any immediate effect on our consolidated financial statements, and we will apply this guidance prospectively.  EITF 06-3  On June 28, the FASB ratified the consensuses reached by the Emerging Issues Task Force on EITF 06-3, "How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation)." According to the provisions of EITF 06-3:  o    taxes assessed by a governmental authority that are directly imposed on a revenue-producing transaction between a seller and a customer may include, but are not limited to, sales, use, value added, and some excise taxes; and  o    that the presentation of such taxes on either a gross (included in revenues and costs) or a net (excluded from revenues) basis is an accounting policy decision that should be disclosed pursuant to Accounting Principles Board Opinion No. 22 (as amended) "Disclosure of Accounting Policies." In addition, for any such taxes that are reported on a gross basis, a company should disclose the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. The disclosure of those taxes can be done on an aggregate basis.  EITF 06-3 should be applied to financial reports for interim and annual  reporting periods beginning after December 15, 2006 (January 1, 2007 for us). Because the provisions of EITF 06-3 require only the presentation of additional disclosures, we do not expect the adoption of EITF 06-3 to have an effect on our consolidated financial statements.  FIN 48  In June 2006, the FASB issued Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109." This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS No. 109, "Accounting for Income Taxes." This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This Interpretation is effective for fiscal years beginning after December 15, 2006 (January 1, 2007 for us). We are currently reviewing the effects of this Interpretation.  SAB 108  In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108. This Bulletin requires a "dual approach" for quantifications of errors using both a method that focuses on the income statement impact, including the cumulative effect of prior years' misstatements, and a method that focuses on the period-end balance sheet. SAB No. 108 will be effective for us as of January 1, 2007. The adoption of this Bulletin is not expected to have a material impact on our consolidated financial statements.  SFAS No. 157  On September 15, 2006, the FASB issued SFAS No. 157, "Fair Value Measurements." This Statement defines fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It addresses how companies should measure fair value when they are required to use a fair value measure for    58 <PAGE>  recognition or disclosure purposes under generally accepted accounting principles and, as a result, there is now a common definition of fair value to be used throughout generally accepted accounting principles.  This Statement applies to other accounting pronouncements that require or permit fair value measurements; the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements; however, for some entities the application of this Statement will change current practice. The changes to current practice resulting from the application of this Statement relate to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.  This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 (January 1, 2008 for us), and interim periods within those fiscal years. This Statement is to be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, with certain exceptions. The disclosure requirements of this Statement are to be applied in the first interim period of the fiscal year in which this Statement is initially applied. We are currently reviewing the effects of this Statement.  SFAS No. 158  On September 29, 2006, the FASB issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R)." This Statement requires an employer to:  o    recognize the overfunded or underfunded status of a defined benefit  pension plan or postretirement benefit plan (other than a multiemployer plan) as an asset or liability in its statement of financial position;  o    measure a plan's assets and its obligations that determine its funded status as of the end of the employer's fiscal year (with limited exceptions), and to disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations; and  o    recognize changes in the funded status of a plan in the year in which the changes occur through comprehensive income.  Past accounting standards only required an employer to disclose the complete funded status of its plans in the notes to the financial statements. Recognizing the funded status of a company's benefit plans as a net liability or asset on its balance sheet will require an offsetting adjustment to "Accumulated other comprehensive income/loss" in shareholders' equity ("Partners' Capital" for us). SFAS No. 158 does not change how pensions and other postretirement benefits are accounted for and reported in the income statement--companies will continue to follow the existing guidance in previous accounting standards. Accordingly, the amounts to be recognized in "Accumulated other comprehensive income/loss" representing unrecognized gains/losses, prior service costs/credits, and transition assets/obligations will continue to be amortized under the existing guidance. Those amortized amounts will continue to be reported as net periodic benefit cost in the income statement. Prior to SFAS No. 158, those unrecognized amounts were only disclosed in the notes to the financial statements.  According to the provisions of this Statement, an employer with publicly traded equity securities is required to initially recognize the funded status of a defined benefit pension plan or postretirement benefit plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006 (December 31, 2006 for us). In the year that the recognition provisions of this Statement are initially applied, an employer is required to disclose, in the notes to the annual financial statements, the incremental effect of applying this Statement on individual line items in the year-end statement of financial position. The requirement to measure plan assets and benefit obligations as of the date of the employer's fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008 (December 31, 2008 for us). In the year that the measurement date provisions of this Statement are initially applied, a business entity is required to disclose the separate adjustments of retained earnings ("Partners' Capital" for us) and "Accumulated other comprehensive income/loss" from applying this Statement. While earlier application of the recognition of measurement date provisions is allowed, we have opted not to adopt this part of the Statement early.    59 <PAGE>  We will apply the guidance of SFAS No. 158 prospectively; retrospective application of this Statement is not permitted. We are currently reviewing the effects of this Statement, but we do not expect the adoption of this Statement to have a material effect on our statement of financial position as of December 31, 2006. Currently, based on the most recent measurement of our benefit plan assets and obligations, we expect the incremental impact on our December 31, 2006 statement of financial position from adopting the recognition provisions of this Statement to be as follows (amounts are approximations): a $6.1 million decrease in total liabilities, and a $6.1 million increase in partners' capital ("Accumulated other comprehensive income/loss.")   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. You should read the following discussion and analysis 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  Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of generally accepted accounting principles involves the exercise of varying degrees of judgment. 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 our assets and liabilities, our revenues and expenses during the reporting period, 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, examples of certain areas that require more judgment relative to others include our use of estimates in determining:  o    the economic useful lives of our assets;  o    the fair values used to determine possible asset impairment charges;  o    reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities;  o    provisions for uncollectible accounts receivables;  o    exposures under contractual indemnifications; and  o    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    60 <PAGE>  not been any significant changes in these policies and estimates during the three and nine months ended September 30, 2006.  Results of Operations  Consolidated  <TABLE> <CAPTION> Three Months Ended              Nine Months Ended  September 30,                  September 30, --------------------            ------------------- 2006            2005            2006           2005 ----            ----            ----           ---- (In thousands) Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments <S>                                                                 <C>             <C>            <C>            <C> Products Pipelines...........................................   $ 116,921       $ 127,155      $  362,044     $  376,019 Natural Gas Pipelines........................................     140,763         121,955         435,136        360,686 CO2..........................................................     127,062         119,909         372,839        357,545 Terminals....................................................      98,454          81,698         290,004        233,529 ---------       ---------      ----------     ---------- Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)..........................................     483,200         450,717       1,460,023      1,327,779  Depreciation, depletion and amortization expense.............    (106,830)        (85,356)       (296,780)      (258,644) Amortization of excess cost of equity investments............      (1,416)         (1,407)         (4,244)        (4,233) Interest and corporate administrative expenses(b)............    (151,136)       (118,567)       (441,411)      (374,068) ---------       ---------      ----------     ---------- Net income.......................................................   $ 223,818       $ 245,387      $  717,588     $  690,834 =========       =========      ==========     ========== </TABLE>  -----------   (a)  Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses and other expense (income). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes.  (b)  Includes unallocated interest income, interest and debt expense, general and administrative expenses (including unallocated litigation and environmental expenses) and minority interest expense.  Our consolidated net income for the quarterly period ended September 30, 2006 was $223.8 million ($0.40 per diluted unit), compared to $245.4 million ($0.57 per diluted unit) for the quarterly period ended September 30, 2005. Our consolidated net income was negatively impacted in the third quarter of 2006 by (i) an $18.1 million decrease in net income from our Products Pipelines business segment, consisting of an approximate $11.6 million decrease related to a change that transferred certain pipeline integrity management costs from sustaining capital expenditures to expense and an approximate $6.5 million decrease related to pipeline integrity costs expensed in the third quarter of 2006 and (ii) a $16.1 million decrease in net income from our CO2 business segment, related to higher depreciation expenses that were largely caused by a higher unit-of-production depreciation rate as a result of a reduction in reserves at our SACROC oil field unit. However, due to the fact that we deduct our sustaining capital expenditures from our net income to determine distributable cash flow, and that depreciation, depletion and amortization expenses do not  affect cash and are therefore added to our net income to determine distributable cash flow, these two items negatively impacted our overall distributable cash flow for the third quarter of 2006 by only $3.5 million. The difference primarily relates to our share of Plantation Pipe Line's third quarter 2006 pipeline integrity expenses, which were included in our net income under the equity method of accounting but excluded from our consolidated sustaining capital expenditures.  Net income for the nine months ended September 30, 2006 was $717.6 million ($1.45 per diluted unit), compared to $690.8 million ($1.61 per diluted unit) for the first nine months of 2005. We earned total revenues of $2,273.4 million and $2,631.3 million, respectively, in the three month periods ended September 30, 2006 and 2005, and revenues of $6,861.5 million and $6,729.5 million, respectively, in the nine month periods ended September 30, 2006 and 2005.  We declared a cash distribution of $0.81 per unit for the third quarter of 2006 (an annualized rate of $3.24). This distribution is almost 3% higher than the $0.79 per unit distribution we made for the third quarter of 2005. 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.    61 <PAGE>  Our annual published budget calls for cash distributions of $3.28 per unit for 2006; however, no assurance can be given that we will be able to achieve this level of distribution. Our budget does not take into account any transportation rate reductions or capital costs associated with financing the payment of reparations sought by shippers on our Pacific operations' interstate pipelines, which we now estimate will be approximately $15 million in 2006. We currently expect to distribute between $3.24 and $3.28 per unit for 2006. For more information on our Pacific operations' regulatory proceedings, see Note 3 to our consolidated financial statements included elsewhere in this report.  Segment earnings before depreciation, depletion and amortization expenses  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 (segment earnings before depreciation, depletion and amortization expenses) internally for evaluating segment performance and deciding how to allocate resources to our four reportable business segments. For the third quarters of 2006 and 2005, our total segment earnings before depreciation, depletion and amortization totaled $483.2 million and $450.7 million, respectively, and for the first nine months of 2006 and 2005, our total segment earnings before depreciation, depletion and amortization totaled $1,460.0 million and $1,327.8 million, respectively. As discussed below in "--Products Pipelines," our total segment earnings before depreciation, depletion and amortization expenses in both the third quarter and first nine months of 2006 were negatively impacted by $18.1 million due to a change related to the expensing of pipeline integrity costs.  On a consolidated basis, throughout the first nine months of 2006, we increased our segment earnings before depreciation, depletion and amortization expenses in 2006, relative to 2005, by capitalizing on:  o    improved sales margins on renewal and incremental natural gas sale contracts and higher earnings from natural gas storage and processing activities, largely from our Texas intrastate natural gas pipeline group;  o    strong natural gas gathering operations from the Red Cedar Gathering Company, our 49%-owned equity investee;   o    the sales of carbon dioxide, crude oil and natural gas plant liquids products at higher average prices, and transporting higher volumes of carbon dioxide for use in enhanced oil recovery operations; and  o    incremental contributions from bulk and liquids terminal operations acquired since the third quarter of 2005.  Products Pipelines  <TABLE> <CAPTION> Three Months Ended             Nine Months Ended September 30,                  September 30, --------------------           ------------------- 2006            2005           2006           2005 ----            ----           ----           ---- (In thousands, except operating statistics) <S>                                                            <C>             <C>             <C>            <C> Revenues...................................................    $ 207,726       $ 181,903       $ 577,273      $ 527,818 Operating expenses(a)......................................      (94,609)        (60,613)       (234,149)      (169,739) Earnings from equity investments(b)........................          514           6,256          11,067         21,706 Interest income and Other, net-income (expense)(c).........        2,706           1,780          11,141          4,443 Income taxes(d)............................................          584          (2,171)         (3,288)        (8,209) ---------       ---------       ---------      --------- Earnings before depreciation, depletion and amortization Expense and amortization of excess cost of equity investments...............................      116,921         127,155         362,044        376,019  Depreciation, depletion and amortization expense...........      (20,820)        (19,849)        (61,541)       (59,071) Amortization of excess cost of equity investments..........         (841)           (832)         (2,521)        (2,512) ---------       ---------       ---------      --------- Segment earnings.........................................    $  95,260       $ 106,474       $ 297,982      $ 314,436 =========       =========       =========      ========= </TABLE>    62 <PAGE>  <TABLE> <CAPTION> Three Months Ended             Nine Months Ended September 30,                 September 30, -------------------           -------------------- 2006           2005           2006           2005  ----           ----           ----           ---- <S>                                                                 <C>            <C>            <C>            <C> Gasoline (MMBbl)...........................................         117.1          117.5          344.1          344.4 Diesel fuel (MMBbl)........................................          42.2           41.7          120.2          122.8 Jet fuel (MMBbl)...........................................          30.0           29.3           89.4           88.1 -----          -----          -----          ----- Total refined products volumes (MMBbl)...................         189.3          188.5          553.7          555.3 Natural gas liquids (MMBbl)................................           9.3            8.4           28.0           26.1 -----          -----          -----          ----- Total delivery volumes (MMBbl)(e)........................         198.6          196.9          581.7          581.4  </TABLE> ----------  (a)  Nine month 2006 amount includes a $13,458 increase in expense associated with environmental liability adjustments. Third quarter and nine month 2005 amounts include a $5,000 increase in expense associated with a North System liquids inventory reconciliation adjustment. (b)  Nine month 2006 amount includes a $4,861 increase in expense associated with environmental liability adjustments on Plantation Pipe Line Company. (c)  Nine month 2006 amount includes a $5,700 increase in income from the settlement of transmix processing contracts. (d)  Nine month 2006 amount includes a $1,871 decrease in expense associated with the tax effect on our share of environmental expenses incurred by Plantation Pipe Line Company and described in footnote (b). (e)  Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress and Heartland pipeline volumes.  Our Products Pipelines segment reported earnings before depreciation, depletion and amortization of $116.9 million on revenues of $207.7 million in the third quarter of 2006. This compares to earnings before depreciation, depletion and amortization of $127.2 million on revenues of $181.9 million in the third quarter of 2005. For the comparable nine month periods, the segment reported earnings before depreciation, depletion and amortization of $362.0 million on revenues of $577.3 million in 2006, and earnings before depreciation, depletion and amortization of $376.0 million on revenues of $527.8 million in 2005.  Segment Earnings before Depreciation, Depletion and Amortization  The segment's $10.3 million (8%) decrease in earnings before depreciation, depletion and amortization expenses in the third quarter of 2006 compared with the third quarter of 2005, and its $14.0 million (4%) decrease in earnings before depreciation, depletion and amortization in the first nine months of 2006 compared with the first nine months of 2005 were largely related to incremental pipeline maintenance expenses recognized in the third quarter of 2006, related to a change that both recognized and transferred a portion of the segment's pipeline integrity costs from sustaining capital expenditures (within "Property, plant and equipment, net" on our accompanying consolidated balance sheets) to maintenance expense (within "Operations and maintenance" in our accompanying consolidated statements of income).  Pipeline integrity costs encompass those costs incurred as part of an overall pipeline integrity management program, which is a process for assessing and mitigating pipeline risks in order to reduce both the likelihood and consequences of incidents. An effective pipeline integrity program is a systematic, comprehensive process that entails pipeline assessment services, maintenance and repair services, and regulatory compliance. Our pipeline integrity program is designed to provide our management the information needed to effectively allocate resources for appropriate prevention, detection and mitigation activities.   Beginning in the third quarter of 2006, the refined petroleum products pipelines and associated terminal operations included within our Products Pipelines segment (including Plantation Pipe Line Company, our 51%-owned equity investee) began recognizing certain costs incurred as part of its pipeline integrity management program as maintenance expense in the period incurred, and in addition, recorded an expense for costs previously capitalized during the first six months of 2006. Combined, this change reduced the segment's earnings before depreciation, depletion and amortization expenses by $18.1 million--increasing maintenance expenses by $14.9 million, decreasing earnings from equity investments by $5.2 million, and decreasing income tax expenses by $2.0 million.     63 <PAGE>  In addition, as noted in the table above, the segment's earnings before depreciation, depletion and amortization expenses for the first nine months of 2006 included environmental expenses of $16.4 million, net of taxes, from the adjustment of environmental liabilities, and other income of $5.7 million from the settlement of transmix processing contracts. Both of these items occurred in the second quarter of 2006. Also, the segment's earnings before depreciation, depletion and amortization expenses for the third quarter and first nine months of 2005 included a loss of $5.0 million, recognized in September 2005, to account for differences between physical and book natural gas liquids inventory on our North System natural gas liquids pipeline.  The overall decreases of $10.3 million (8%) and $14.0 million (4%), respectively, in the three and nine month segment earnings before depreciation, depletion and amortization expenses in 2006, relative to 2005, were primarily due to the following:  o    increases of $5.9 million (480%) and $7.5 million (94%) respectively, from our North System--due primarily to the $5.0 million inventory reconciliation reserve taken in the third quarter of 2005, as discussed above, and to higher throughput revenues in both the third quarter and first nine months of 2006. The overall increases were partly offset by a $1.0 million increase in pipeline maintenance expenses due to the expensing of pipeline integrity costs;  o    increases of $1.1 million (22%) and $6.0 million (37%), respectively, from our petroleum pipeline transmix processing operations--due primarily to incremental earnings before depreciation, depletion and amortization from the inclusion of our recently constructed Greensboro, North Carolina transmix facility and (for the comparable nine month periods) to an increase of $5.7 million related to favorable settlements of transmix contract agreements.  In the second quarter of 2006, we completed construction and placed into service the approximately $11 million Greensboro facility, which is capable of processing 6,000 barrels of transmix per day for Plantation and other interested parties. In the three and nine months ended September 30, 2006, the Greensboro facility accounted for incremental earnings before depreciation, depletion and amortization of $1.3 million and $1.5 million, respectively. The increase from contract settlements consisted of two separate settlements in the second quarter of 2006. First, we recorded income of $6.2 million from fees received for the early termination of a long-term transmix processing agreement at our Colton, California processing facility. Secondly, we recorded an expense of $0.5 million related to payments we made to Motiva Enterprises LLC in June 2006 to settle claims for prior period transmix purchase costs at our Richmond, Virginia processing facility;  o    an increase of $1.1 million (15%) and a decrease of $0.2 million (1%), respectively, from our Central Florida Pipeline--the quarterly increase was driven by higher operating revenues, due to higher average tariff rates, and the nine month decrease resulted from higher  operating expenses, which included $0.4 million of pipeline integrity expenses and which more than offset a year-over-year increase in revenues;  o    a decrease of $1.8 million (9%) and an increase of $1.3 million (2%), respectively, from the combined operations of our West Coast and Southeast refined products terminal operations--the quarterly decrease included a $1.6 million (17%) drop in earnings before depreciation, depletion and amortization from our West Coast terminals, due primarily to incremental environmental expenses in the third quarter of 2006. The nine month increase in earnings was driven by higher earnings from our Southeast terminals, due to higher 2006 throughput volumes at higher rates, relative to 2005;  o    decreases of $3.4 million (43%) and $6.9 million (24%), respectively, from our approximate 51% ownership interest in Plantation Pipe Line Company--primarily due to lower equity earnings from Plantation, net of income taxes. The overall quarterly decrease in earnings before depreciation, depletion and amortization was primarily due to a $3.2 million decrease, representing our proportionate share of Plantation's pipeline integrity expenses, net of income taxes that were recognized in the third quarter of 2006. The decrease across the comparable nine month periods includes the $3.2 million decrease due to pipeline integrity expenses and a $3.5 million decrease, representing our proportionate share of additional environmental expense recognized by Plantation Pipe Line Company in the second quarter of 2006. The expense was related to environmental    64 <PAGE>  and clean-up liability adjustments associated with an April 17, 2006 pipeline release of turbine fuel from Plantation's 12-inch petroleum products pipeline located in Henrico County, Virginia;  o    decreases of $5.1 million (127%) and $5.4 million (34%), respectively, from our 49.8% ownership interest in the Cochin pipeline system--due mainly to incremental pipeline integrity expenses of $5.4 million recognized in the third quarter of 2006; and  o    decreases of $7.8 million (9%) and $16.1 million (7%), respectively, from our combined Pacific and CALNEV Pipeline operations--the quarterly decrease was largely due to higher pipeline maintenance expenses, resulting from incremental pipeline integrity expenses of $7.5 million in the third quarter of 2006, and the nine month decrease was primarily due to higher environmental expenses associated with environmental liability adjustments, the expensing of pipeline integrity expenses in the third quarter of 2006, and higher year-over-year fuel and power costs as a result of higher electricity usage and higher utility rates.  Segment Details  Revenues for the segment increased $25.8 million (14%) in the third quarter of 2006, compared to the third quarter of 2005. For the comparable nine month periods, revenues increased $49.5 million (9%) in 2006 versus 2005. The period-to-period increases in segment revenues for the comparable three and nine month periods of 2006 and 2005, respectively, were principally due to the following:  o    increases of $12.2 million (80%) and $21.4 million (50%), respectively, from our Southeast terminals--largely attributable to higher ethanol blending and sales revenues and higher liquids inventory sales (offset by higher costs of sales, as described below);  o    increases of $5.3 million (6%) and $10.5 million (4%), respectively, from our Pacific operations--the quarter-to-quarter increase consisted of a $3.3 million (5%) increase in refined products delivery revenues and a $2.0 million (9%) increase in refined products terminal revenues  in the third quarter of 2006, compared to the third quarter of 2005. The increase from refined products delivery revenues was due to a 3% increase in mainline delivery volumes and an almost 2% increase in mainline average tariff rates, reflecting the impact of both rate reductions that went into effect on May 1, 2006 according to settlements reached in connection with our Pacific operations' rate litigation, and rate increases that went into effect July 1, 2006 according to the FERC annual index rate increase (a producer price index-finished goods adjustment).  For the comparable nine month periods, the overall increase in revenues consisted of a $5.8 million (3%) increase from mainline delivery revenues and a $4.7 million (7%) increase in product terminal revenues. The increase from product delivery revenues was due to a 2% increase in mainline delivery volumes and a slight (almost 1%) increase in mainline average tariff rates. The increase from terminal revenues was due to the higher transportation barrels and to incremental service revenues, including diesel lubricity-improving injection services that we began offering in May 2005;  o    increases of $2.3 million (29%) and $3.5 million (13%), respectively, from our North System--due to higher natural gas liquids delivery revenues in 2006 versus 2005. The period-to-period increases in delivery revenues were driven by increases of 18% and 6%, respectively, in system throughput volumes, due largely to additional refinery demand, and by increases of 10% and 7%, respectively, in average tariff rates. The tariff increases resulted from a combination of annual indexed tariff increases approved by the FERC (effective July 1, 2005 and 2006), and from increases in the proportion of volumes shipped at higher versus lower tariffs;  o    increases of $2.2 million (15%) and $5.7 million (13%), respectively, from our West Coast terminals--related to rent escalations, higher throughput barrels and rates at various locations, and additional tank capacity at our Carson/Los Angeles Harbor system terminals;  o    increases of $1.6 million (10%) and $4.9 million (11%), respectively, from our CALNEV Pipeline--due mainly to higher refined products deliveries, higher terminal revenues as a result of additional transportation barrels delivered at our Barstow, California and Las Vegas, Nevada terminals, and higher diesel lubricity    65 <PAGE>  additive injection service revenues. Revenues from refined products deliveries increased $1.3 million (11%) and $4.0 million (12%), respectively, in the three and nine months ended September 30, 2006, when compared to the same periods last year. The quarter-to-quarter increase from refined products deliveries was due to a 3% increase in delivery volumes and a 7% increase in average tariff rates (including a FERC tariff index increase in July 2006). The nine month increase was due to a 6% increase in delivery volumes and a 5% increase in average tariff rates (including FERC annual index rate increases effective July 1, 2005 and July 1, 2006); and  o    increases of $0.9 million (9%) and $2.6 million (9%), respectively, from our Central Florida Pipeline--driven by increases of 13% and 10%, respectively, in average tariff rates for the three and nine month periods of 2006 compared to 2005. The increased rates reflect reductions in zone-based credits in 2006 versus 2005.  Combining all of the segment's operations, total delivery volumes of refined petroleum products increased a slight 0.4% in the third quarter of 2006, compared to the third quarter of 2005, but transport volumes increased by 10.5% in the Arizona market during the third quarter of 2006, as our Pacific operations' East Line expansion was in service for the entire quarter. The expansion project substantially increased pipeline capacity from El Paso, Texas to Tucson and Phoenix, Arizona. Excluding volumes delivered by Plantation Pipe  Line, combined deliveries of refined petroleum products were up 2% for the third quarter of 2006 compared to the third quarter of 2005. In the third quarter of 2006, Plantation realized a 3.9% decrease in delivery volumes compared to the third quarter of 2005, primarily due to alternative pipeline service into Southeast markets and to changes in supply from Louisiana and Mississippi refineries related to new ultra low sulfur diesel and ethanol blended gasoline requirements. Compared to the third quarter of 2005, total deliveries of natural gas liquids increased almost 11% in the third quarter of 2006.  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 $34.0 million (56%) and $64.4 million (38%), respectively, in the third quarter and first nine months of 2006, compared to the same year-ago periods. The overall increases in operating expenses for the comparable three and nine month periods were mainly due to the following:  o    increases of $12.4 million (228%) and $18.5 million (105%), respectively, from our Southeast terminals--largely attributable to higher costs of sales related to higher ethanol blending and purchases (offset by higher ethanol revenues) and higher liquids purchases;  o    increases of $10.4 million (51%) and $23.9 million (38%), respectively, from our Pacific operations--due primarily to higher overall major maintenance expenses, including $5.8 million of pipeline integrity expenses in the third quarter of 2006, lower capitalized expenses primarily due to the September 2006 reclassification of pipeline integrity management costs from capital to expense, and to higher period-to-period fuel and power expenses, due to both higher refined products delivery volumes and overall higher utility rates. The nine month increase was also due to higher environmental expenses in 2006 versus 2005, due to environmental liability adjustments, and higher electricity expenses resulting from a utility rebate credit received in the first quarter of 2005;  o    increases of $5.2 million (140%) and $4.9 million (42%), respectively, from our proportionate interest in the Cochin Pipeline--due principally to an incremental $5.4 million of pipeline integrity expenses in the third quarter of 2006. The incremental pipeline integrity expenses were partly offset by lower pipeline operating expenses, in the first nine months of 2006, related to the decrease in transportation volumes in 2006 compared to 2005. The decrease in delivery volumes was primarily due to pipeline operating pressure restrictions;  o    increases of $4.9 million (93%) and $8.1 million (55%), respectively, from our West Coast terminals--primarily related to incremental environmental expenses, higher materials and supplies expense as a result of lower capitalized overhead, and incremental pipeline integrity expenses;  o    increases of $4.0 million (114%) and $7.7 million (71%), respectively, from our CALNEV Pipeline--due primarily to higher period-to-period environmental expense accruals, higher overall major maintenance expenses, including $1.7 million of pipeline integrity expenses in the third quarter of 2006, and to higher power expenses, related to increases in product delivery volumes and average utility rates;    66 <PAGE>  o    a decrease of $0.1 million (4%) and an increase of $2.9 million (42%), respectively, from our Central Florida Pipeline operations--the slight quarterly decrease reflects incremental pipeline integrity expenses of $0.4 million in 2006, offset by lower maintenance expenses due to additional expense accruals related to a pipeline release occurring in September 2005. The nine month increase was chiefly due to incremental environmental expenses, in 2006, resulting from quarterly environmental liability adjustments; and   o    decreases of $3.6 million (37%) and $3.4 million (17%), respectively, from our North System--due primarily to the $5.0 million inventory reconciliation reserve taken in the third quarter of 2005, as discussed above, partly offset by both incremental pipeline integrity expenses of $1.0 million in the third quarter of 2006, and higher property tax expenses related to an expense true-up recognized in the third quarter of 2006.  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. Earnings from these investments decreased $5.7 million (92%) in the third quarter of 2006 and $10.6 million (49%) in the first nine months of 2006, when compared to the same periods last year. Both decreases primarily related to the lower earnings from Plantation, as described above.  Income from both allocable interest income and other income and expense items increased $0.9 million (52%) and $6.7 million (151%), respectively, in the comparable three and nine month periods. The quarterly increase was due to higher administrative overhead collected by our West Coast terminals from a reimbursable project, and the nine month increase was primarily due to the $5.7 million other income item from the settlement of transmix processing contracts in the second quarter of 2006.  For the comparable three and nine month periods, the segment's income tax expenses decreased $2.8 million (127%) and $4.9 million (60%), respectively. Both decreases related to the lower pre-tax earnings from Plantation and Cochin, as described above.  Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of equity investments, increased $1.0 million (5%) in the third quarter of 2006 and $2.5 million (4%) in the first nine months of 2006, when compared to the same prior year periods. The period-to-period increases were primarily due to higher depreciation expenses from our Pacific and Southeast terminal operations. The increase from our Pacific operations related to higher depreciable costs as a result of the capital spending we have made for both pipeline and storage expansion since the end of the third quarter of 2005. The increase from our Southeast terminal operations related to incremental depreciation charges resulting from final purchase price allocations, 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.  Natural Gas Pipelines  <TABLE> <CAPTION> Three Months Ended              Nine Months Ended September 30,                   September 30, ----------------------------   ---------------------------- 2006            2005            2006           2005 ----            ----            ----           ---- (In thousands, except operating statistics) <S>                                                             <C>             <C>            <C>            <C> Revenues...................................................     $ 1,650,427     $ 2,108,788    $ 5,082,183    $ 5,198,337 Operating expenses and Other expense(a)....................      (1,519,129)     (1,996,737)    (4,678,855)    (4,863,524) Earnings from equity investments...........................          10,062           8,705         31,833         25,733 Interest income and Other, net-income (expense)............             376           1,560            875          2,039  Income taxes...............................................            (973)           (361)          (900)        (1,899) -----------     -----------    -----------    ----------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity               140,763         121,955        435,136        360,686 investments................................................  Depreciation, depletion and amortization expense...........         (15,959)        (15,205)       (47,938)       (45,779) Amortization of excess cost of equity investments..........             (71)            (70)          (210)          (208) -----------     -----------    -----------    ----------- Segment earnings.........................................     $   124,733     $   106,680    $   386,988    $   314,699 ===========     ===========    ===========    ===========  Natural gas transport volumes (Trillion Btus)(b)...........           384.9           353.1        1,067.4          998.1 ===========     ===========    ===========    =========== Natural gas sales volumes (Trillion Btus)(c)...............           243.5           239.3          690.0          688.6 ===========     ===========    ===========    =========== </TABLE> ---------  67 <PAGE>  (a)  Nine month 2006 amount includes a $1,500 increase in expense associated with environmental liability adjustments, a $6,244 reduction in expense due to the release of a reserve related to a natural gas pipeline contract obligation, and a $15,114 gain from the combined sale of our Douglas natural gas gathering system and Painter Unit fractionation facility. (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.  Our Natural Gas Pipelines business segment reported earnings before depreciation, depletion and amortization of $140.8 million on revenues of $1,650.4 million in the third quarter of 2006. This compares to earnings before depreciation, depletion and amortization of $122.0 million on revenues of $2,108.8 million in the third quarter of 2005. For the comparable nine month periods, the segment reported earnings before depreciation, depletion and amortization of $435.1 million on revenues of $5,082.2 million in 2006, and earnings before depreciation, depletion and amortization of $360.7 million on revenues of $5,198.3 million in 2005.  As noted in the table above, the segment's earnings before depreciation, depletion and amortization expenses for the first nine months of 2006 included an increase in expense of $1.5 million from the adjustment of environmental liabilities, a reduction in expense of $6.2 million due to the release of a reserve related to a natural gas purchase/sales contract, and a gain of $15.1 million from the combined sale of our Douglas natural gas gathering system and Painter Unit fractionation facility. All three items occurred in the second quarter of 2006.  Segment Earnings before Depreciation, Depletion and Amortization  The segment's $18.8 million (15%) increase in earnings before depreciation, depletion and amortization expenses in the third quarter of 2006 compared with the third quarter of 2005, and its $74.4 million (21%) increase in earnings in the first nine months of 2006 compared with the first nine months of 2005 were primarily due to the following:  o    increases of $9.9 million (44%) and $6.9 million (9%), respectively,  from our Kinder Morgan Interstate Gas Transmission system--due largely to higher operational sales of natural gas and incremental natural gas park and loan service revenues earned in the third quarter of 2006. The year-over-year increase in earnings in 2006 relative to 2005 was partially offset by favorable imbalance valuation adjustments recognized in the second quarter of 2005;  o    increases of $6.3 million (9%) and $41.5 million (23%), respectively, from our Texas intrastate natural gas pipeline group--due primarily to improved margins resulting from the negotiation of profitable gas purchase and sales contracts, and higher value from storage and processing activities. With regard to our natural gas sales activities, 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. Our Texas intrastate group's margins can vary depending upon, among other things, the price volatility of natural gas produced in and delivered from the Gulf Coast region and Texas, the availability of transportation systems with adequate capacity, the availability of pipeline and/or underground system storage, and any changes or trends in the terms or conditions in which natural gas sale and purchase prices are contractually indexed.  The increase in earnings in the first nine months of 2006 versus the first nine months of 2005 includes the $6.2 million increase resulting from the release of a previously established reserve related to a natural gas purchase/sales contract. The contract is associated with the operations of our West Clear Lake natural gas storage facility located in Harris County, Texas. We acquired this storage facility as part of our acquisition of Kinder Morgan Tejas on January 31, 2002, and upon acquisition, we established a reserve for a contract liability;  o    an increase of $2.0 million (18%) and a decrease of $0.4 million (1%), respectively, from our Trailblazer Pipeline--due to timing differences on the settlements of pipeline transportation imbalances in 2006, relative to 2005. These pipeline imbalances were due to differences between the volumes nominated and volumes delivered at an inter-connecting point by the pipeline;    68 <PAGE>  o    increases of $1.3 million (18%) and $6.2 million (28%), respectively, from our 49% equity investment in Red Cedar Gathering Company--due largely to higher natural gas gathering revenues and to higher prices on incremental sales of excess fuel gas;  o    increases of $0.2 million (2%) and $3.9 million (14%), respectively, from our TransColorado Pipeline--the quarter-to-quarter increase was largely due to a favorable property tax liability adjustment recognized in the third quarter of 2006, and the nine month increase was largely due to higher gas transmission revenues earned in 2006 compared to 2005. The revenue increase related to higher natural gas delivery volumes resulting from system improvements 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; and  o    a decrease of $0.9 million (34%) and an increase of $16.5 million (196%), respectively, from the combined operations of our Casper Douglas and Painter natural gas gathering and processing operations. The quarter-to-quarter decrease was primarily due to decreased revenues in 2006 compared to 2005, mainly due to lower natural gas sales and partly due to the sale of our Douglas natural gas gathering system and our Painter Unit fractionation facility in April 2006. Effective April 1, 2006, we sold our Douglas natural gas gathering  system and our Painter Unit fractionation facility to a third party for approximately $42.5 million in cash, and we included a net gain of $15.1 million within "Other expense (income)" in our accompanying consolidated statements of income for the three and nine months ended September 30, 2006. For more information on this gain, see Note 2 to our consolidated financial statements included elsewhere in this report.  The nine month increase in earnings in 2006 versus 2005 was mainly due to the $15.1 million gain discussed above, a $3.2 million increase in revenues due mainly to increased natural gas sales, favorable gas imbalance gains and higher commodity prices, and a $1.5 million decrease related to incremental environmental expenses in the second quarter of 2006.  Segment Details  Compared to the same two periods in 2005, total segment operating revenues, including revenues from natural gas sales, decreased $458.4 million (22%) in the third quarter of 2006, and decreased $116.1 million (2%) in the first nine months of 2006. Similarly, combined operating expenses, including natural gas purchase costs, decreased $477.6 million (24%) in the third quarter of 2006, and decreased $184.7 million (4%) in the first nine months of 2006, when compared to the same periods of 2005.  The period-to-period changes in segment revenues and operating expenses reflect changes in average natural gas prices and changes in natural gas volumes purchased and sold, which affect both natural gas sales revenues and natural gas purchase expenses; however, we increased earnings by realizing higher margins from our Texas intrastate natural gas pipeline group's purchasing and sales activities, and from its natural gas storage and processing activities. For the comparable three and nine month periods, the Texas intrastate groups' natural gas sales margin increased $7.4 million (20%) and $47.4 million (53%), respectively, in 2006 versus 2005. The variations in natural gas sales margin for both the three and nine months ended September 30, 2006, compared with the same periods last year, were driven by changes in natural gas prices and sales volumes--the $7.4 million quarterly margin increase consisted of a $10.5 million increase from favorable changes in average sales versus average purchase prices (favorable price variance) and a $3.1 million decrease from lower volumes (unfavorable volume variance)--the $47.4 million nine month margin increase consisted of a $50.8 million increase from favorable changes in average sales prices versus average purchase prices and a $3.4 million decrease from lower volumes. Also, the intrastate groups' margins from natural gas processing activities increased $6.2 million (111%) and $8.4 million (47%), respectively, in the comparable three and nine month periods of 2006 versus 2005.  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. Combined earnings from these three investees increased $1.4 million (16%) and $6.1 million (24%), respectively, in the third quarter and first nine months of 2006, when compared to the same periods last year. The increases were chiefly due to higher net income earned by Red Cedar during 2006, as described above.    69 <PAGE>  On September 1, 2006, we and the Southern Ute Indian Tribe agreed to a resolution that would transfer all of the members' equity in Coyote Gas Treating, LLC to the members' equity of Red Cedar Gathering Company. According to the provisions of this resolution, we and the Southern Ute Tribe contributed the value of our respective 50% ownership interests in Coyote Gas Treating, LLC to Red Cedar, and as a result, Coyote Gas Treating, LLC became a wholly owned subsidiary of Red Cedar. For more information on this contribution, see Note 13 to our consolidated financial statements included elsewhere in this report.  The segment's combined interest income and earnings from other income items (Other, net) decreased $1.2 million in both the three and nine month periods of  2006, when compared to the same prior year periods. The decrease was chiefly due to a gain from a property disposal by our Kinder Morgan Tejas Pipeline in the third quarter of 2005. Income tax expenses increased $0.6 million in the third quarter of 2006, but decreased $1.0 million in the first nine months of 2006, when compared to the same periods in 2005. The changes primarily related to tax accrual adjustments related to the operations of our Mier-Monterrey Mexico Pipeline.  Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments, increased a slight $0.8 million (5%) in the third quarter of 2006 versus the third quarter of 2005; for the nine month periods, depreciation related expenses increased $2.2 million (5%) in 2006 versus 2005. The increases were largely due to incremental capital spending since last year's third quarter, and to additional depreciation charges on our Kinder Morgan Texas system due to the acquisition of our North Dayton, Texas natural gas storage facility in August 2005.  CO2  <TABLE> <CAPTION> Three Months Ended             Nine Months Ended September 30,                  September 30, --------------------           ------------------- 2006            2005           2006           2005 ----            ----           ----           ---- (In thousands, except operating statistics) <S>                                                                  <C>             <C>            <C>            <C> Revenues(a).......................................................   $ 192,303       $ 163,079      $ 552,783      $ 488,271 Operating expenses................................................     (68,888)        (48,546)      (194,212)      (152,389) Earnings from equity investments..................................       3,380           5,533         14,113         21,932 Other, net-income (expense).......................................         324              (6)           336             (6) Income taxes......................................................         (57)           (151)          (181)          (263) ---------       ---------      ---------      --------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments...     127,062         119,909        372,839        357,545   Depreciation, depletion and amortization expense(b)...............     (50,731)        (34,658)      (132,021)      (111,822) Amortization of excess cost of equity investments.................        (504)           (505)        (1,513)        (1,513) ---------       ---------      ---------      --------- Segment earnings................................................   $  75,827       $  84,746      $ 239,305      $ 244,210 =========       =========      =========      =========  Carbon dioxide delivery volumes (Bcf)(c)..........................       164.3           153.6          503.4          479.0 =========       =========      =========      ========= SACROC oil production (gross) (MBbl/d)(d).........................        30.3            30.8           30.8           32.4 =========       =========      =========      =========  SACROC oil production (net) (MBbl/d)(e)...........................        25.3            25.6           25.7           26.9 =========       =========      =========      ========= Yates oil production (gross) (MBbl/d)(d)..........................        26.3            24.1           25.9           24.0 =========       =========      =========      ========= Yates oil production (net) (MBbl/d)(e)............................        11.7            10.7           11.5           10.7 =========       =========      =========      ========= Natural gas liquids sales volumes (net) (MBbl/d)(e)...............         8.4             9.4            8.9            9.5 =========       =========      =========      ========= Realized weighted average oil price per Bbl(f)(g).................    $  32.49       $   26.12      $   31.42      $   27.46 =========       =========      =========      ========= Realized weighted average natural gas liquids price per Bbl(g)(h).............................................    $  47.68       $   41.89      $   44.82      $   37.09 =========       =========      =========      ========= </TABLE> ----------  (a)  Nine month 2006 amount includes a $1,819 loss on derivative contracts used to hedge forecasted crude oil sales. (b)  Includes depreciation, depletion and amortization expense associated with oil and gas producing and gas processing activities in the amount of $45,704 for the third quarter of 2006, $30,336 for the third quarter of 2005, $117,628 for the first nine months of 2006, and $98,628 for the first nine months of 2005. Includes depreciation, depletion and amortization expense associated with sales and transportation services activities in the amount of $5,027 for the third quarter of 2006, $4,322 for the third quarter of 2005, $14,393 for the first nine months of 2006, and $13,194 for the first nine months 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.   70 <PAGE>   (f)  Includes all Kinder Morgan crude oil production properties. (g)  Hedge gains/losses for crude 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.  Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates. The segment's primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO2) and crude oil, and the production and marketing of natural gas and natural gas liquids. For the third quarter of 2006, the segment reported earnings before depreciation, depletion and amortization of $127.1 million on revenues of $192.3 million. These amounts compare to earnings before depreciation, depletion and amortization of $119.9 million on revenues of $163.1 million in the same quarter last year. For the comparable nine month periods, the segment reported earnings before depreciation, depletion and amortization of $372.8 million on revenues of $552.8 million in 2006, and earnings before depreciation, depletion and amortization of $357.5 million on revenues of $488.3 million in 2005.   Segment Earnings before Depreciation, Depletion and Amortization  Sales and Transportation Activities  For our CO2 segment, both the $7.2 million (6%) increase in earnings before depreciation, depletion and amortization in the third quarter of 2006 over the third quarter of 2005, and the $15.3 million (4%) increase in the first nine months of 2006 over the first nine months of 2005 were driven by higher earnings from the segment's carbon dioxide sales and transportation activities. Earnings before depreciation, depletion and amortization from these activities increased $7.6 million (18%) and $20.6 million (17%), respectively, in the third quarter and first nine months of 2006, when compared to the same prior year periods. The increases in earnings were driven by higher revenues--from both carbon dioxide sales and deliveries, and from crude oil pipeline transportation. The overall increases were partly offset by lower equity earnings from the segment's 50% ownership interest in the Cortez Pipeline Company.  The period-to-period increases in carbon dioxide sales revenues were due to both higher average prices and higher sales volumes. The increases in volumes were largely attributable to the continued strong demand for carbon dioxide from tertiary oil recovery projects in the Permian Basin area since the end of the third quarter last year, and to increased carbon dioxide production from the McElmo Dome source field. We operate and own a 45% interest in McElmo Dome, which supplies carbon dioxide to oil recovery fields in the Permian Basin of southeastern New Mexico and West Texas. It is the largest known carbon dioxide deposit in the world--covering approximately 203,000 acres from south of McElmo Canyon into Delores County, Colorado.  Correlating closely with the increase in crude oil prices since the end of the third quarter of 2005, average carbon dioxide sales prices increased 19% and 26%, respectively, for the three and nine month periods of 2006, when compared to the same periods a year ago. In addition, during both nine month periods, we did not use derivative contracts to hedge or help manage the financial impacts associated with the increases in carbon dioxide prices, and as always, we did not recognize profits on carbon dioxide sales to ourselves.  Oil and Gas Producing Activities  The remaining changes in period-to-period segment earnings before depreciation, depletion and amortization--a decrease of $0.4 million (1%) in the comparable three month periods and a decrease of $5.3 million (2%) in the comparable nine month periods, were attributable to the segment's crude oil and natural gas producing activities, which also include its natural gas processing activities. The decreases in period-to-period earnings were largely due to higher combined operating expenses and partly due to lower crude oil production at the SACROC oil field unit. The higher operating expenses included higher field operating and maintenance expenses, higher property and severance taxes, and higher fuel and power expenses. The increases in expenses more than offset higher overall crude oil and natural gas plant product sales revenues.    71 <PAGE>  In addition, increased crude oil production at the Yates oil field unit was offset by a previously announced decline in crude oil production at the SACROC unit. On a gross basis (meaning total quantity produced), average crude oil production increased 9% quarter-over-quarter at Yates, but decreased 2% at the SACROC unit, where the decline in production is mostly due to one section of the field that is underperforming. As originally disclosed in our report on Form 10-Q filed for the quarter ended March 31, 2006, we now expect our CO2 segment to fall short of its annual published budget of segment earnings before depreciation, depletion and amortization expenses by approximately $45 million, or 8%. However, we continue to expect strong annual carbon dioxide production volumes and earnings at the McElmo Dome unit in 2006, and we expect the crude oil production and earnings from the Yates field unit to exceed their annual budgeted amounts.  Segment Details   Our CO2 segment's revenues increased $29.2 million (18%) in the third quarter of 2006 compared to the third quarter of 2005, and including a $1.8 million hedge ineffectiveness loss in June 2006, revenues increased $64.5 million (13%) in the first nine months of 2006 versus 2005. The respective third quarter and nine month increases were primarily due to the following:  o    increases of $24.0 million (27%) and $39.2 million (14%), respectively, from crude oil sales--attributable to increases of 24% and 14%, respectively, in our realized weighted average price of crude oil and a 2% increase in quarter-to-quarter sales volumes. For the comparable nine month periods, crude oil sales volumes were essentially flat;  o    increases of $3.9 million (26%) and $14.3 million (41%), respectively, from carbon dioxide sales--due mainly to higher average sales prices, discussed above, and to increases of 12% and 8%, respectively, in period-to-period sales volumes;  o    increases of $2.9 million (19%) and $7.2 million (17%), respectively, from carbon dioxide and crude oil pipeline transportation revenues--due largely to increases of 7% and 5%, respectively, in system-wide carbon dioxide delivery volumes. The improvements in carbon dioxide throughput volumes were driven by higher contract demand, and the higher crude oil pipeline transportation revenues reflect higher crude oil throughputs from our Kinder Morgan Wink Pipeline;  o    increases of $0.5 million (2%) and $12.8 million (13%), respectively, from natural gas liquids sales--attributable to higher average sales prices, partially offset by decreases in volumes primarily related to the lower production at SACROC; and  o    decreases of $0.9 million (70%) and $9.1 million (73%), respectively, from natural gas sales--mainly attributable to lower volumes of gas available for sale in the third quarter and first nine months of 2006 versus the same periods last year, 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. We constructed the SACROC power plant in order to reduce our purchases of electricity from third-parties, but it reduces our sales of natural gas because some natural gas volumes are consumed by the plant. The power plant now provides approximately half of SACROC's current electricity needs. KMI operates and maintains the power plant under a five-year contract expiring in June 2010, and we reimburse KMI for its operating and maintenance costs.  We mitigate commodity price risk through a long-term hedging strategy that uses derivative contracts to reduce the impact of unpredictable changes in crude oil and natural gas liquids sales prices. Our goal is to use derivative contracts in order to prevent or reduce the possibility of future losses, and our strategy is intended to generate more stable realized prices. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $68.20 per barrel in the third quarter of 2006, and $61.17 per barrel in the third quarter of 2005. 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.     72 <PAGE>  Compared to the same periods of 2005, the segment's operating expenses increased $20.3 million (42%) in the third quarter of 2006 and $41.8 million (27%) in the first nine months of 2006. The increases consisted of the following:  o    increases of $12.3 million (58%) and $25.0 million (36%), respectively, from combined cost of sales and field operating and  maintenance expenses-- largely due to higher well workover and completion expenses related to infrastructure expansions at the SACROC and Yates oil field units since the third quarter last year. Workover expenses, including labor, relate to incremental operating and maintenance charges incurred on producing wells in order to restore or increase production, and are often performed in order to stimulate production, add pumping equipment, remove fill from the wellbore, or mechanically repair the well.  Our oil and gas operations, coupled with carbon dioxide flooding, often require a high level of investment, including ongoing expenses for facility upgrades, wellwork and drilling. We continue to aggressively pursue opportunities to drill new wells and/or expand existing wells for both carbon dioxide and crude oil in order to benefit from robust demand for energy commodities in and around the Permian Basin area;  o    increases of $6.6 million (40%) and $9.6 million (18%), respectively, from fuel and power expenses-- 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, however, by the benefits provided from the power plant we constructed at the SACROC oil field unit, described above; and  o    increases of $1.4 million (13%) and $7.2 million (23%), respectively, from taxes, other than income taxes--attributable mainly to higher property and production (severance) taxes. The higher property taxes related to both increased asset infrastructure and higher assessed property values since the end of the third quarter of 2005. The higher severance taxes, which are primarily based on the gross wellhead production value of crude oil and natural gas, were driven by the higher period-to-period crude oil revenues.  Earnings from equity investments, representing equity earnings from our 50% ownership interest in the Cortez Pipeline Company, decreased $2.2 million (39%) and $7.8 million (36%), respectively, in the third quarter and first nine months of 2006, versus the same periods in 2005. The decreases reflect lower overall net income earned by Cortez in 2006 relative to 2005. The decreases were expected because the 2005 periods benefited from higher tariffs, due to making up under-collected revenues in prior years. The decrease in revenues from lower tariffs more than offset incremental revenues realized as a result of higher carbon dioxide delivery volumes.  Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments, increased $16.1 million (46%) in the third quarter and $20.2 million (18%) in first nine months of 2006, when compared to the same prior year periods.  The increases were largely due to a higher unit-of-production depletion rate used in third quarter of 2006, related to our interest in the SACROC oil field unit, and to higher depreciable costs, related to incremental capital spending since the end of the third quarter last year.  In addition, we recognized incremental depreciation charges of $0.8 million and $2.2 million, respectively, attributable to the various oil and gas properties we acquired in April 2006 from Journey Acquisition - I, L.P. and Journey 2000, L.P.          73 <PAGE>  Terminals  <TABLE> <CAPTION>  Three Months Ended             Nine Months Ended September 30,                 September 30, --------------------------     ------------------------- 2006           2005           2006           2005 ----           ----           ----           ---- (In thousands, except operating statistics) <S>                                                             <C>             <C>            <C>            <C> Revenues...................................................     $  223,151      $ 177,484      $ 649,822      $ 515,115 Operating expenses.........................................       (122,230)       (94,318)      (354,892)      (271,470) Earnings from equity investments...........................             76             18            190             51 Other, net-income (expense)................................          1,056            886          2,335           (293) Income taxes...............................................         (3,599)        (2,372)        (7,451)        (9,874) ----------      ---------      ---------      --------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity               98,454         81,698        290,004        233,529 investments................................................  Depreciation, depletion and amortization expense...........        (19,320)       (15,644)       (55,280)       (41,972) Amortization of excess cost of equity investments..........              -              -              -              - ----------      ---------      ---------      --------- Segment earnings.........................................     $   79,134      $  66,054      $ 234,724      $ 191,557 ==========      =========      =========      =========  Bulk transload tonnage (MMtons)(a).........................           23.2           20.4           67.9           65.8 ==========      =========      =========      ========= Liquids leaseable capacity (MMBbl).........................           43.5           40.3           43.5           40.3 ==========      =========      =========      ========= Liquids utilization %......................................           97.8%          96.5%          97.8%          96.5% ==========      =========      =========      ========= </TABLE> ----------  (a)  Volumes for acquired terminals are included for all periods.  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. In the third quarter of 2006, our Terminals segment reported earnings before depreciation, depletion and amortization of $98.5 million on revenues of $223.2 million. This compares to earnings before depreciation, depletion and amortization of $81.7 million on revenues of $177.5 million in the third quarter last year. For the first nine months of 2006, our Terminals segment reported earnings before depreciation, depletion and amortization of $290.0 million on revenues of $649.8 million, while in the same prior-year period, the segment reported earnings before depreciation, depletion and amortization of $233.5  million on revenues of $515.1 million.  Segment Earnings before Depreciation, Depletion and Amortization  The segment's $16.8 million (21%) increase in earnings before depreciation, depletion and amortization expenses in the third quarter of 2006 compared with the third quarter of 2005, and the $56.5 million (24%) increase in earnings in the first nine months of 2006 compared with the first nine months of 2005 were driven by a combination of internal expansions, incremental volumes, and acquisitions.  Our terminal acquisitions since the beginning of 2005 primarily included the following:  o    our Texas Petcoke terminals, located in and around the Ports of Houston and Beaumont, Texas, acquired effective April 29, 2005;  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;  o    our Kinder Morgan Blackhawk terminal located in Black Hawk County, Iowa, acquired in August 2005;  o    a terminal-related repair shop located in Jefferson County, Texas, acquired in September 2005; and   74 <PAGE>  o    three terminal operations acquired separately in April 2006: terminal equipment and infrastructure located on the Houston Ship Channel, a rail terminal located at the Port of Houston, and a rail ethanol terminal located in Carson, California.  Combined, these terminal operations acquired since the beginning of 2005 accounted for incremental amounts of earnings before depreciation, depletion and amortization of $4.0 million, revenues of $9.2 million and operating expenses of $5.2 million, respectively, in the third quarter of 2006, and incremental amounts of earnings before depreciation, depletion and amortization of $29.4 million, revenues of $58.8 million and operating expenses of $29.4 million, respectively, in the first nine months of 2006, when compared to the same periods a year ago. The incremental amounts above relate to the acquired terminals' operations during the additional months of ownership in the third quarter and first nine months of 2006, as compared to 2005, and do not include increases or decreases during the same months we owned the assets in both years.  For the comparable three months, most of the period-to-period increases in operating results from terminal acquisitions were attributable to the terminal assets and operations we acquired from A&L Trucking, L.P. and U.S. Development Group in April 2006 for an aggregate consideration of approximately $61.9 million. Combined, these assets accounted for incremental amounts of earnings before depreciation, depletion and amortization of $3.8 million, revenues of $8.7 million and operating expenses of $4.9 million, respectively, in the third quarter of 2006.  For the comparable nine month periods, most of the period-to-period increases in operating results from terminal acquisitions were attributable to the inclusion of our Texas petroleum coke terminals and repair shop assets, which we acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an aggregate consideration of approximately $247.2 million. The primary assets acquired included facilities and railway equipment located at the Port of Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship Channel. Combined, these assets accounted for incremental amounts of earnings before depreciation, depletion and amortization of $16.8 million,  revenues of $31.0 million and operating expenses of $14.2 million, respectively, during the first four months of 2006.  For all other terminal operations (those owned during identical periods in both 2005 and 2006), earnings before depreciation, depletion and amortization increased $12.8 million (16%) in the third quarter of 2006 versus the third quarter of 2005, and increased $27.1 million (12%) in the first nine months of 2006 versus the first nine months of 2005. The respective third quarter and nine month year-to-date increases in earnings from terminal operations owned during both years were primarily due to the following:  o    increases of $5.1 million (25%) and $9.6 million (17%), respectively, from our Gulf Coast region. The increases were primarily due to higher earnings from our Pasadena and Galena Park, Texas liquids facilities. The period-to-period increases were driven by higher revenues from new and incremental customer agreements, additional liquids tank capacity from capital expansions at our Pasadena terminal since the third quarter of 2005, higher truck loading rack service fees, and incremental revenues from customer deficiency charges in the third quarter of 2006;  o    increases of $3.5 million (47%) and $7.9 million (32%), respectively, from our Mid-Atlantic region. The quarterly increase was driven by a $1.8 million increase from our Chesapeake Bay, Maryland bulk terminal and a $1.4 million increase from our Shipyard River terminal, located in Charleston, South Carolina. The increase at Chesapeake was due to higher revenues earned from transferring higher volumes of petroleum coke, coal, and pig iron; the increase at Shipyard was due to higher revenues from increased coal volumes, tank rentals and ancillary terminal services.  The nine month increase was driven by a $3.6 million increase from our Shipyard River terminal, a $2.9 million increase from our Fairless Hills, Pennsylvania bulk terminal, and a $1.3 million increase from our Philadelphia, Pennsylvania liquids terminal. The increase from Shipyard reflects higher revenues from liquids warehousing and coal and cement handling, the increase at Fairless Hills was due to higher volumes of steel imports and heavier shipping activity on the Delaware River, and the increase at Philadelphia was due to higher revenues from an increase in fuel grade ethanol volumes, and annual rate escalations on certain customer contracts;    75 <PAGE>  o    increases of $2.0 million (49%) and $1.7 million (9%), respectively, from terminals included in our Lower Mississippi (Louisiana) region. The quarterly increase was primarily due to higher earnings 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.  The nine month increase was primarily due to higher earnings from IMT and our DeLisle, Mississippi terminal, both negatively impacted by hurricane damage in 2005, incremental income related to a favorable settlement associated with the purchase of our Kinder Morgan St. Gabriel terminal in September 2002, and to incremental earnings from our Amory, Mississippi bulk terminal, which began operations in July 2005;  o    increases of $1.9 million (17%) and $2.1 million (6%), respectively, from terminals included in our Northeast region. The increases were primarily due to higher earnings from our liquids terminals located in Carteret, New Jersey and Staten Island, New York. The quarterly increase was largely due to higher revenues from new and renegotiated customer contracts at Carteret, and to additional tankage and transmix sales at our Kinder Morgan Staten Island terminal. The nine month  increase was due to the same factors that affected third quarter results, and to an overall increase in petroleum imports to New York Harbor, resulting in an 11% increase in total liquids throughput at Carteret; and  o    increases of $0.4 million (4%) and $3.9 million (26%), respectively, from our Texas Petcoke region. The increases were due to higher revenues from petroleum coke transfers, which more than offset higher sales costs and operating expenses.  Segment Details  Segment revenues for all terminals owned during identical periods of both years increased $36.5 million (21%) in the third quarter of 2006, and $75.9 million (15%) in the first nine months of 2006, when compared to the same prior-year periods. The overall changes in three and nine month revenues from terminals owned during identical periods of both years included the following:  o    increases of $9.6 million (52%) and $19.9 million (32%), respectively, from our Mid-Atlantic region, due primarily to higher revenues from our Fairless Hills, Chesapeake Bay, and Shipyard River terminals, as discussed above;  o    increases of $6.5 million (24%) and $12.6 million (16%), respectively, from our Gulf Coast liquids facilities, due primarily to higher revenues from Pasadena and Galena Park, as discussed above;  o    increases of $5.3 million (21%) and $5.8 million (7%), respectively, from terminals included in our Lower Mississippi (Louisiana) region. The increases were largely due to higher tonnage, dockage and insurance revenues at our IMT facility, higher bulk transfer revenues from our DeLisle and Amory, Mississippi terminals, and higher revenues from ship and cargo brokerage;  o    increases of $5.0 million (29%) and $15.4 million (57%), respectively, from our Texas Petcoke terminal region, due to higher petroleum coke transfer volumes;  o    increases of $3.6 million (102%) and $10.3 million (101%), respectively, from engineering and terminal design services, due to both incremental revenues from new clients and from existing clients starting new projects due to economic growth, and to increased revenues from material sales;  o    increases of $2.6 million (9%) and $3.8 million (4%), respectively, from terminals included in our Midwest region, due largely to increased liquids throughput and storage activities from our two Chicago liquids terminals, increases of 34% and 10%, respectively, in coal transfer volumes from the combined operations of our Cora, Illinois and Grand Rivers, Kentucky coal terminals, and higher marine oil fuel and asphalt sales from our Dravosburg, Pennsylvania bulk terminal; and   76 <PAGE>  o    increases of $2.2 million (10%) and $2.8 million (4%), respectively, from our Northeast terminals, largely to increases at our Carteret and Kinder Morgan Staten Island terminals, as discussed above.  Operating expenses for all terminals owned during both periods increased $22.7 million (24%) in the third quarter of 2006, and $54.0 million (20%) in the first nine months of 2006, when compared to the same periods last year. The respective third quarter and nine month year-to-date increases in operating expenses from terminal operations owned during identical periods of both years were primarily due to the following:  o    increases of $6.1 million (55%) and $11.3 million (30%), respectively, from our Mid-Atlantic terminals, largely due to higher operating and maintenance expenses at our Fairless Hills, Shipyard River, and Pier  IX terminals. The increases at Fairless Hills were largely due to higher wharfage, trucking and general maintenance expenses related to the increase in steel products handled, the increases at Shipyard were due to higher labor, equipment rentals, and general maintenance expenses, all associated with increased tonnage, and the increases at Pier IX, located in Newport News, Virginia, related to major maintenance repairs and to higher expenses related to a fire that occurred at the terminal in June 2006;  o    increases of $4.8 million (61%) and $11.7 million (99%), respectively, from our Texas Petcoke terminal region, due largely to higher labor expenses, rail service and railcar maintenance expenses, and harbor and barge expenses, all related to higher petroleum coke volumes;  o    increases of $4.4 million (139%) and $11.8 million (124%), respectively, 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    increases of $2.4 million (13%) and $8.1 million (14%), respectively, from our Louisiana terminals, largely due to property damage, demurrage and other expenses, which in large part related to the effects of hurricanes Katrina and Rita, both of which impacted the Gulf Coast since the third quarter of 2005. Increases also resulted from higher stevedoring, dockage, and demurrage expenses related to increased shipping activities;  o    increases of $1.9 million (12%) and $3.3 million (7%), respectively, from our Midwest region terminals, due primarily to higher marine fuel costs of sales at our Dravosburg terminal, higher maintenance and outside service expenses associated with increases in coal transfer volumes, and additional labor and equipment rental expenses from the combined operations of our Argo and Chicago, Illinois liquids terminals due to increased ethanol throughput and incremental liquids storage and handling business;  o    increases of $1.5 million (33%) and $2.8 million (19%), respectively, from terminals in our Ferro alloys region, due primarily to higher labor and higher equipment maintenance and rentals related to increased ores and metals handling at our Chicago and Industry, Pennsylvania terminals; and  o    increases of $1.4 million (19%) and $3.1 million (15%), respectively, from our Gulf Coast liquids terminals, due primarily to incremental labor expenses, tank cleaning and maintenance, power expenses and permitting fees.  The segment's earnings from equity investments remained essentially flat across both comparable periods, and income from other items increased $0.2 million and $2.6 million, respectively, in the comparable three and nine periods of 2006, compared to 2005. The three month increase was largely due to gains realized from the sale of our Kinder Morgan River Terminals' Fort Smith, Arkansas warehouse operating assets in the third quarter of 2006. The nine month increase included a $1.8 million income item recognized in the first quarter of 2006 and described above, related to a favorable settlement associated with the purchase of our Kinder Morgan St. Gabriel terminal, and a $1.2 million increase related to a disposal loss recognized in the first quarter of 2005 on warehouse property at our Elizabeth River bulk terminal, located in Chesapeake, Virginia.  Income tax expenses increased $1.2 million (52%) and decreased $2.4 million (25%) in the third quarter and first nine months of 2006, respectively, compared to the same periods a year ago. The quarter-to-quarter increase was primarily due to higher taxable earnings from all combined tax-paying terminal entities. The decrease in the comparable nine month periods was largely impacted by a $1.8 million reduction in expense associated with a June    77 <PAGE>   2006 adjustment to the accrued federal income tax liability account of Kinder Morgan Bulk Terminals, Inc., the tax-paying entity that owns many of our bulk terminal businesses.  Compared to the same periods in 2005, non-cash depreciation, depletion and amortization charges increased $3.7 million (23%) in the third quarter of 2006, and $13.3 million (32%) in the first nine months of 2006. The year-over-year increases in depreciation expenses resulted from the capital expenditures and terminal acquisitions we have made since the beginning of 2005. Since the beginning of last year, we completed numerous improvement projects and acquired various terminal operations in order to expand and enhance our terminalling services. Collectively, the terminal assets we acquired since the beginning of 2005 and listed above accounted for incremental depreciation expenses of $1.1 million and $7.8 million, respectively, in the third quarter and first nine months of 2006.  Other  <TABLE> <CAPTION> Three Months Ended             Nine Months Ended September 30,                 September 30, ---------------------------    -------------------------- 2006            2005           2006           2005 ----            ----           ----           ---- (In thousands-income/(expense)) <S>                                                            <C>             <C>            <C>            <C> General and administrative expenses........................    $  (59,694)     $  (47,073)    $ (183,913)    $ (171,058) Unallocable interest, net..................................       (89,424)        (69,688)      (249,617)      (196,362) Minority interest..........................................        (2,018)         (1,806)        (7,881)        (6,648) ----------      ----------     ----------     ---------- Interest and corporate administrative expenses...........    $ (151,136)     $ (118,567)    $ (441,411)    $ (374,068) ==========      ==========     ==========     ========== </TABLE>  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.  Our total general and administrative expenses increased $12.6 million (27%) in the third quarter of 2006, when compared to the third quarter of 2005. The increase was primarily due to a $4.8 million drop in capitalized overhead costs in the third quarter of 2006 compared to the third quarter of 2005, reflecting both a lower capitalization rate and lower spending on capital projects. In addition, we accrued incremental insurance expenses and realized higher employee benefit expenses in the third quarter of 2006 compared to the third quarter of 2005. The increase in insurance expenses reflect higher period-to-period rates and the increase in employee benefit expenses reflect higher wage and benefit costs influenced by changes in compensation levels and health-related expenses.  For the first nine months of 2006, general and administrative expenses increased $12.9 million (8%) when compared to the same 2005 period. The year-over-year increase was partly due to lower capitalized overhead costs  (described above), higher corporate service charges, insurance, and employee benefit expenses in the first nine months of 2006, and partly due to increased costs associated with new acquisitions made since the third quarter of 2005. The overall increase was partly offset by lower unallocated litigation and environmental settlement expenses in 2006--in the first nine months of 2005, we recognized unallocated litigation and environmental settlement expenses of $33.4 million, consisting of a $25.0 million expense for a settlement reached between us and a former joint venture partner on our Kinder Morgan Tejas natural gas pipeline system and a cumulative $8.4 million expense related to settlements of environmental matters at certain of our operating sites located in the State of California.  Unallocable interest expense, net of interest income, increased $19.7 million (28%) and $53.3 million (27%), respectively, in the third quarter and first nine months of 2006, compared to the same year-earlier periods. The increases were due to both higher average debt levels and higher effective interest rates. Average borrowings for the three and nine month periods ending September 30, 2006, increased 8% and 9%, respectively, versus the same periods last year. The increases were mainly due to higher capital spending and to the acquisition of external assets and businesses since the end of the third quarter of 2005. Generally, we fund both our capital spending (including payments for pipeline project construction costs) and our acquisition outlays from borrowings under our commercial paper program.  In addition, for the comparable nine month periods, average borrowings increased in 2006 versus 2005 due to a net increase of $300 million in principal amount of long-term senior notes. On March 15, 2005, we both closed a    78 <PAGE>  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 weighted average interest rate on all of our borrowings increased 19% and 17%, respectively, in the third quarter and first nine months of 2006, compared to the same prior year periods. The increases in our average borrowing rates reflect a general rise in variable interest rates since the end of the third 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.  Minority interest, representing the deduction in our consolidated net income attributable to all outstanding ownership interests in our five operating limited partnerships and their consolidated subsidiaries that are not held by us, was essentially flat across both quarterly periods, but increased $1.2 million (19%) in the first nine months of 2006, compared to the same period last year. The increase was primarily due to incremental interest income and expense allocated to the minority interest in West2East Pipeline LLC, the sole owner of Rockies Express Pipeline LLC. Prior to ConocoPhillips' acquisition of a 24% ownership interest in West2East Pipeline LLC on June 30, 2006, we fully consolidated West2East Pipeline LLC and we reported the 33 1/3% interest we did not own as minority interest.   Financial Condition  Capital Structure  We attempt to maintain a conservative overall capital structure, with a long-term target mix of approximately 50% equity and 50% debt. In addition to our results of operations, our debt and capital balances are affected by our  financing activities, as discussed below in "--Financing Activities." The following table illustrates the sources of our invested capital (dollars in thousands):  <TABLE> <CAPTION> September 30,    December 31, 2006              2005 --------------    ------------ <S>                                                                  <C>               <C> Long-term debt, excluding market value of interest rate swaps......  $  4,386,706      $ 5,220,887 Minority interest..................................................        44,666           42,331 Partners' capital, excluding accumulated other comprehensive loss.................................................     4,878,054        4,693,414 ------------      ----------- Total capitalization.............................................     9,309,426        9,956,632 Short-term debt, less cash and cash equivalents....................     1,123,260          (12,108) ------------      ----------- Total invested capital...........................................  $ 10,432,686      $ 9,944,524 ============      ===========  Capitalization: Long-term debt, excluding market value of interest rate swaps....          47.1%            52.4% Minority interest................................................           0.5%             0.4% Partners' capital, excluding accumulated other comprehensive loss...............................................          52.4%            47.2% ------------      ----------- 100.0%           100.0% ============      ===========  Invested Capital: Total debt, less cash and cash equivalents and excluding market value of interest rate swaps.....................              52.8%            52.4% Partners' capital and minority interest, excluding accumulated other comprehensive loss ...............................              47.2%            47.6% ------------      ----------- 100.0%           100.0% ============      =========== </TABLE>  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    79 <PAGE>  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.  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 proceeds from purchases of additional i-units by 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. Our debt credit ratings are currently rated BBB+ by Standard & Poor's Rating Services, and Baa1 by Moody's Investors Service. On May 30, 2006, S&P and Moody's each placed our ratings on credit watch pending resolution of a management buyout proposal for all of the outstanding shares of KMI. We are not able to predict with certainty the final outcome of the pending buyout proposal; however, even if the buyout proposal is consummated, we expect to maintain an investment grade credit rating.  Short-term Liquidity  Our principal sources of short-term liquidity are:  o    our $1.85 billion five-year senior unsecured revolving credit facility that matures August 18, 2010;  o    our $1.85 billion short-term commercial paper program (which is supported by our bank credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings); and  o    cash from operations (discussed following).  Borrowings under our credit facility can be used for general corporate purposes and as a backup for our commercial paper program. There were no borrowings under our credit facility as of December 31, 2005, or as of September 30, 2006. As of September 30, 2006, we had $887.6 million of commercial paper outstanding.  We provide 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 facility was $524.3 million as of September 30, 2006. As of September 30, 2006, our outstanding short-term debt was $1,147.2 million. Currently, we believe our liquidity to be adequate.     80 <PAGE>  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 and debt markets for our limited partner units and long-term notes, and there can be no assurance we will be able or willing to access the public or private markets for our limited partner units and/or long-term notes 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. Our ability to access the public and private debt markets is affected by our credit ratings. See "--Capital Structure" above for a discussion of our credit ratings.  All of our long-term debt securities issued to date, other than those issued under our long-term revolving credit facility 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 September 30, 2006, our total liability balance due on the various series of our senior notes was $4,490.4 million, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $155.9 million. For additional information regarding our debt securities and credit facility, 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 $878.7 million for the nine months ended September 30, 2006, versus $901.6 million in the comparable period of 2005. The period-to-period decrease of $22.9 million (3%) in cash flow from operations consisted of:  o    an $87.8 million decrease in cash inflows relative to net changes in working capital items, mainly due to timing differences that resulted in higher net cash payments of $91.3 million with regard to the collection and payment of both trade and related party receivables and payables;  o    a $19.1 million decrease in cash related to payments made in June 2006 to certain shippers on our Pacific operations' pipelines. The payment related to a settlement agreement reached in May 2006 that resolved certain challenges by complainants with regard to delivery tariffs and gathering enhancement fees at our Pacific operations' Watson Station, located in Carson, California. The agreement called for estimated refunds to be paid into an escrow account pending final approval by the FERC, which was made in the third quarter of 2006;  o    a $62.0 million increase in cash from overall higher partnership income--net of non-cash items including depreciation charges, undistributed earnings from equity investments, and gains from the sale of assets. The higher partnership income reflects an increase in cash earnings from our four reportable business segments in    81 <PAGE>  the first nine months of 2006, as discussed above in "-Results of Operations." The non-cash items include the $15.1 million gain from the combined sale of our Douglas natural gas gathering system and Painter Unit fractionation facility in the second quarter of 2006;   o    a $17.3 million increase in cash inflows relative to net changes in non-current assets and liabilities, which represent offsetting changes in cash from various long-term asset and liability accounts. On a net basis, the increase in cash inflows from non-current items reflects, among other things, higher environmental expense accruals in the first nine months of 2006, higher spending on deferred project study costs in the first nine months of 2005, and incremental property tax refunds received in the second quarter of 2006, pursuant to successful litigation between our Pacific operations and various Arizona taxing authorities concerning differences over the assessed value of property owned by our Pacific operations for the tax years 2000 through 2002; and  o    a $4.7 million increase related to higher distributions received from equity investments--chiefly due to higher distributions received from Red Cedar Gathering Company in the first nine months of 2006. The increase in distributions received resulted from Red Cedar's higher year-over-year net income in the first nine months of 2006 versus the first nine months of 2005, and also from the fact that Red Cedar had higher capital expansion spending in 2005, and funded a large portion of the expenditures with retained cash.  Investing Activities  Net cash used in investing activities was $1,062.1 million for the nine month period ended September 30, 2006, compared to $905.6 million in the comparable 2005 period. The $156.5 million (17%) increase in cash used in investing activities was primarily attributable to:  o    a $154.1 million (26%) increase in capital expenditures--driven by a $163.4 million increase in capital spending from our Natural Gas Pipelines business segment, largely due to increased investment in natural gas pipeline and natural gas storage expansion projects. Including expansion and maintenance projects, our capital expenditures were $751.3 million in the first nine months of 2006, compared to $597.2 million in the same prior-year period.  Our sustaining capital expenditures were $76.2 million for the first nine months of 2006, compared to $95.8 million for the first nine months of 2005. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset. Beginning in the third quarter of 2006, our Products Pipelines business segment began recognizing certain costs incurred as part of its pipeline integrity management program as maintenance expense in the period incurred, and in addition, recorded an expense for costs previously capitalized as sustaining capital expenditures during the first six months of 2006. Combined, this change reduced the segment's earnings before depreciation, depletion and amortization expenses by $18.1 million and its sustaining capital expenditures by $14.6 million.  Our forecasted expenditures for the fourth quarter of 2006 for sustaining capital expenditures are approximately $45.9 million. This amount has been forecasted primarily for the purchase of plant and equipment. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary;  o    a $77.5 million (27%) increase due to higher expenditures made for strategic business acquisitions--in the first nine months of 2006, our acquisition outlays totaled $367.3 million, which consisted of $244.6 million for the acquisition of Entrega Gas Pipeline LLC, $62.5 million for the acquisition of bulk terminal operations and related assets, and $60.2 million for the purchase of additional oil and gas properties. In the first nine months of 2005, we spent $289.8 million, which primarily included $188.6 million for the acquisition of Texas Petcoke terminal assets from Trans-Global Solutions, Inc., $50.9 million for our North Dayton, Texas natural gas storage facility, and $23.9 million for the acquisition of our Kinder Morgan Staten Island terminal, a petroleum products liquids terminal located in the New York Harbor area on Staten Island, New York;   o    a $68.5 million decrease in cash used due to higher net proceeds received from the sales of property, plant and equipment and other net assets, net of salvage and removal costs. The increase in sale proceeds was driven    82 <PAGE>  by (i) the $42.5 million we received in the second quarter of 2006 from Momentum Energy Group, LLC for the combined sale of our Douglas natural gas gathering system and Painter Unit fractionation facility and (ii) the $27.0 million we received in the first half of 2006 from the sale of certain oil and gas properties from Journey Acquisition-I, L.P. and Journey 2000, L.P.; and  o    a $7.3 million decrease due to lower payments for natural gas stored underground and natural gas liquids pipeline line-fill--largely related to lower investments in underground natural gas storage volumes in the first nine months of this year relative to the first nine months of last year.  In addition, we recently made the following announcements related to our investing activities:  o    On September 11, 2006, we announced major expansions at certain of our Texas liquids terminal facilities that will provide additional infrastructure to help meet the growing need for refined petroleum products storage capacity along the Gulf Coast. The investment of approximately $195 million will include the construction of:  o    new storage tanks at our Pasadena and Galena Park terminals on the Houston Ship Channel;  o    an additional cross-channel pipeline to increase the connectivity between the two terminals;  o    a new ship dock at Galena Park; and  o    an additional loading bay at our fully automated truck loading rack located at our Pasadena terminal.  The expansions are supported by long-term customer commitments and will result in approximately 3.4 million barrels of additional tank storage capacity at the Pasadena and Galena Park terminals. Construction began in October 2006 and all of the projects are expected to be completed by the spring of 2008; and  o    On October 19, 2006, we announced plans to invest approximately $388 million to further expand our 550-mile CALNEV Pipeline. CALNEV currently transports refined petroleum products from the Los Angeles, California area to the Las Vegas, Nevada market through parallel 14-inch and 8-inch diameter pipelines. The proposed expansion would include construction of a new 16-inch diameter pipeline and would increase system capacity to approximately 200,000 barrels per day upon completion. Capacity could be increased as necessary to over 300,000 barrels per day with the addition of pump stations.  Environmental permitting and right-of-way acquisition is expected to take between 24 to 30 months, and construction is anticipated to be competed within nine months thereafter. The expansion is subject to environmental permitting, right-of-way acquisition and the receipt of approvals from the FERC authorizing rates that are economic to CALNEV. Start-up of the new pipeline is scheduled for late 2009 or early 2010.  Financing Activities  Net cash provided by financing activities amounted to $195.1 million for the nine months ended September 30, 2006. For the same nine month period last year, our financing activities provided net cash of $4.2 million. The $190.9  million increase from the comparable 2005 period was primarily due to:  o    a $318.2 million increase from overall debt financing activities--which include our issuances and payments of debt and our debt issuance costs. The overall increase was primarily due to a $612.1 million increase from higher net commercial paper borrowings in the first nine months of 2006, partially offset by a $294.4 million decrease due to both issuances and payments of senior notes during 2005. The increase in commercial paper debt includes net borrowings of $412.5 million under the commercial paper program of Rockies Express Pipeline LLC. We held a 66 2/3% ownership interest in Rockies Express Pipeline LLC until June 30, 2006, and according to the provisions of generally accepted accounting principles, we included its cash inflows and outflows in our consolidated statement of cash flows for the six months ended June 30, 2006.  On June 30, 2006, following ConocoPhillips' acquisition of a 24% ownership interest in West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline LLC), we deconsolidated West2East Pipeline LLC and we have subsequently accounted for our investment under the equity method of accounting. Following the    83 <PAGE>  change to the equity method on June 30, 2006, Rockies Express' debt balances were no longer included in our consolidated balance sheet and its cash inflows and outflows for all periods subsequent to June 2006 were not included in our consolidated statement of cash flows.  The decrease in cash inflows from changes in our senior notes related to debt activities occurring on March 15, 2005. On that date, we both 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 $104.8 million increase from contributions from minority interests--principally due to contributions of $104.2 million received from Sempra Energy with regard to its ownership interest in Rockies Express Pipeline LLC. The contribution from Sempra includes an amount of $80 million, contributed in the first quarter of 2006, for Sempra's original 33 1/3% share of the purchase price of Entrega Pipeline LLC. 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;  o    a $6.0 million increase from net changes in cash book overdrafts--which represent checks issued but not yet endorsed;  o    a $200.4 million decrease from higher partnership distributions--distributions to all partners, consisting of our common and Class B unitholders, our general partner and minority interests, totaled $896.9 million in the first nine months of 2006, compared to $696.5 million in the comparable 2005 period. The overall increase in period-to-period distributions included minority interest distributions of $105.2 million paid from our Rockies Express Pipeline LLC subsidiary to Sempra Energy in the first half of 2006.  The distributions to Sempra (and distributions to us for our proportional ownership interest) were made in conjunction with Rockies Express' establishment of and subsequent borrowings under its commercial paper program during the second quarter of 2006, as discussed above. During the second quarter of 2006, Rockies Express both issued a net amount of $412.5 million of commercial paper and distributed $315.5 million to its member owners. Prior to the  establishment of its commercial paper program (supported by its five-year unsecured revolving credit agreement), Rockies Express funded its acquisition of Entrega Gas Pipeline LLC and its Rockies Express Pipeline construction costs with contributions from both us and Sempra.  Excluding the minority interest distributions to Sempra, overall distributions increased $95.2 million. The increase primarily resulted from higher distributions in 2006 of "Available Cash," as described below in "--Partnership Distributions." The increase in "Available Cash" distributions in 2006 versus 2005 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; and  o    a $37.0 million decrease in cash inflows from equity issuances--primarily related to the incremental cash we received for our third quarter 2005 common unit issuance compared to our third quarter 2006 common unit issuance. In the third quarter of 2005, we issued, in a public offering, 5,750,000 of our common units at a price of $51.25 per unit. After commissions and underwriting expenses, we received net proceeds of $283.6 million for the issuance of these units. Similarly, in an August 2006 public offering, we issued an additional 5,750,000 of our common units at a price of $44.80, less commissions and underwriting expenses. After all fees, we received net proceeds of $248.0 million for the issuance of these common units. We used the proceeds from each of these two equity issuances to reduce the borrowings under our commercial paper program.     84 <PAGE>  Partnership Distributions  Our partnership agreement requires that we distribute 100% of "Available Cash," as defined in our partnership agreement, to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available Cash consists generally of all of our cash receipts, including cash received by our operating partnerships 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;  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.  On August 14, 2006, we paid a quarterly distribution of $0.81 per unit for the second quarter of 2006. This distribution was 4% greater than the $0.78 distribution per unit we paid in August 2005 for the second 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 $0.81 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 that we paid on August 14, 2006 to our general partner (for the second quarter of 2006) was $129.0 million. Our general partner's incentive distribution that we paid in August 2005 to our general partner (for the second quarter of 2005) was $115.7 million. Our general partner's incentive distribution for the distribution that we declared for the third    85 <PAGE>  quarter of 2006 was $133.0 million. Our general partner's incentive distribution for the distribution that we paid for the third quarter of 2005 was $121.5 million.  Litigation and Environmental  As of September 30, 2006, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $65.2 million. In addition, we have recorded a receivable of $27.1 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 or accidental spills or releases at facilities that we own. 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.   Additionally, as of September 30, 2006, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $112.7 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.  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 our contractual obligations that would affect the disclosures presented as of December 31, 2005 in our 2005 Form 10-K report.  Off Balance Sheet Arrangements  Except as set forth under "--Rockies Express Pipeline LLC Debt" in Note 7 to our consolidated financial statements included elsewhere in this report, there have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2005 in our 2005 Form 10-K.   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,    86 <PAGE>  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;  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;    87 <PAGE>  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 3 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 and Part II, Item 1A "Risk Factors" of this report, 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 report and this report. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Other than as required by applicable law, 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 September 30, 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,    88 <PAGE>   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 September 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.    89 <PAGE>  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.  Except as set forth below, 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.  The consummation of a transaction to acquire all of the outstanding common stock of KMI that results in substantially more debt at KMI could have an adverse effect on us, such as a downgrade in the ratings of our debt securities. On August 28, 2006, KMI entered into an agreement and plan of merger whereby investors led by Richard D. Kinder, Chairman and CEO of KMI, would acquire all of the outstanding shares of KMI for $107.50 per share in cash. The investors include members of senior management of KMI, most of whom are also senior officers of our general partner and of KMR. As a result, prior to the closing of this transaction, our senior management's attention may be diverted from the management of our daily operations. In response to this proposed transaction, Moody's Investor Services placed both our long-term and short-term debt ratings under review for possible downgrade and Standard & Poor's put our long-term debt rating on credit watch with negative implications. In connection with the merger, KMI will incur substantially more debt, which could have an adverse effect on us, such as a downgrade in the ratings of our debt securities, which could be significant.   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    90 <PAGE>  to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.  10.1 -- First Amendment, dated October 28, 2005, to Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent.  10.2 -- Second Amendment, dated April 13, 2006, to Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent.  10.3 -- Third Amendment, dated October 6, 2006, to Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent.  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.  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.  -----------    91 <PAGE>  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:  November 7, 2006       92