NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

General

Kinder Morgan Energy Partners, L.P. is a Delaware limited partnership formed in August 1992. 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 own and manage a diversified portfolio of energy transportation and storage assets and presently conduct our business through four reportable business segments. These segments and the activities performed to provide services to our customers and create value for our unitholders are as follows:

o Products Pipelines - transporting, storing and processing refined petroleum products;

o Natural Gas Pipelines - transporting, storing, selling and processing natural gas;

o CO2 - producing, transporting and selling carbon dioxide, commonly called CO2, for use in, and selling crude oil produced from, enhanced oil recovery operations; and

o Terminals - transloading, storing and delivering a wide variety of bulk, petroleum, petrochemical and other liquid products at terminal facilities located across the United States.

For more information on our reportable business segments, see Note 15.

We focus on providing fee-based services to customers, generally avoiding near-term commodity price risks and taking advantage of the tax benefits of a limited partnership structure. We trade on the New York Stock Exchange under the symbol "KMP," and we conduct our operations through the following five operating limited partnerships:

o Kinder Morgan Operating L.P. "A" (OLP-A);

o Kinder Morgan Operating L.P. "B" (OLP-B);

o Kinder Morgan Operating L.P. "C" (OLP-C);

o Kinder Morgan Operating L.P. "D" (OLP-D); and

o Kinder Morgan CO2 Company (KMCO2).

Combined, the five partnerships are referred to as our operating partnerships, and we are the 98.9899% limited partner and our general partner (described following) is the 1.0101% general partner in each. Both we and our operating partnerships are governed by Amended and Restated Agreements of Limited Partnership and certain other agreements that are collectively referred to in this report as the partnership agreements.

Kinder Morgan, Inc. and Kinder Morgan G.P., Inc.

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. KMI trades on the New York Stock Exchange under the symbol "KMI" and is one of the largest energy transportation, storage and distribution companies in North America. It operates or owns an interest in, either for itself or on our behalf, approximately 43,000 miles of pipelines that transport primarily natural gas, crude oil, petroleum products and carbon dioxide; more than 155

terminals that store transfer and handle products like gasoline and coal; and provides natural gas distribution service to over 1.1 million customers. At December 31, 2006, KMI and its consolidated subsidiaries owned, through its general and limited partner interests, an approximate 14.7% interest in us.

Kinder Morgan Management, LLC

Kinder Morgan Management, LLC, a Delaware limited liability company, was formed on February 14, 2001. Its shares represent limited liability company interests and are traded on the New York Stock Exchange under the symbol "KMR." Kinder Morgan Management, LLC is referred to as "KMR" in this report. Our general partner owns all of KMR's voting securities and, pursuant to a delegation of control agreement, our general partner delegated to KMR, 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 KMR cannot take certain specified actions without the approval of our general partner. Under the delegation of control agreement, KMR 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, KMR'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. As of December 31, 2006, KMR owned approximately 27.0% of our outstanding limited partner units (which are in the form of i-units that are issued only to KMR).

2. Summary of Significant Accounting Policies

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 years have been reclassified to conform to the current presentation.

Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. We believe, however, that certain accounting policies are of more significance in our financial statement preparation process than others. Also, certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements.

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 volumetric receivable (assets) and payable (liabilities) valuations;

o exposures under contractual indemnifications; and

o various other recorded or disclosed amounts.

We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting

from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Cash Equivalents

We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

Accounts Receivables

Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. An allowance for doubtful accounts is charged to expense monthly, generally using a percentage of revenue or receivables, based on a historical analysis of uncollected amounts, adjusted as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The following tables show the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2006, 2005 and 2004.

                                                Valuation and Qualifying Accounts
                                                         (in thousands)

                                      Balance at        Additions         Additions                          Balance at
                                     beginning of   charged to costs  charged to other                         end of
Allowance for Doubtful Accounts         Period        and expenses       accounts(1)        Deductions(2)      period
--------------------------------     ------------   ---------------- ------------------ ----------------- -----------
Year ended December 31, 2006.....       $6,542           $  259            $  285              $  (267)        $6,819

Year ended December 31, 2005.....       $8,622           $  203            $    -              $(2,283)        $6,542

Year ended December 31, 2004.....       $8,783           $1,460            $  431              $(2,052)        $8,622
----------

(1) Amount for 2006 represents the allowance recognized when we acquired Devco USA L.L.C. ($155) and Transload Services, LLC ($130). Amount for 2004 represents the allowance recognized when we acquired Kinder Morgan River Terminals LLC and its consolidated subsidiaries ($393) and TransColorado Gas Transmission Company ($38).

(2) Deductions represent the write-off of receivables.

In addition, the balances of "Accrued other current liabilities" in our accompanying consolidated balance sheets include amounts related to customer prepayments of approximately $10.8 million as of December 31, 2006 and $8.2 million as of December 31, 2005.

Inventories

Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas, carbon dioxide and coal. We report these assets at the lower of weighted-average cost or market. We report materials and supplies at the lower of cost or market. The value of natural gas in our underground storage facilities under the weighted-average cost method was $8.4 million as of December 31, 2006, and $7.1 million as of December 31, 2005. We also maintain gas in our underground storage facilities on behalf of certain third parties. We receive a fee from our storage service customers but do not reflect the value of their gas stored in our facilities in our accompanying consolidated balance sheets.

Property, Plant and Equipment

We report property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition. We charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include

retirement gain or loss in income except in the case of significant retirements or sales. Gains and losses on minor system sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Gains and losses for operating systems sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines.

We compute depreciation using the straight-line method based on estimated economic lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 2.0% to 12.5%, excluding certain short-lived assets such as vehicles. Depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates included changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.

A gain on the sale of property, plant and equipment used in our oil and gas producing activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the maket value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset.

In addition, we engage in enhanced recovery techniques in which carbon dioxide is injected into certain producing oil reservoirs. In some cases, the acquisition cost of the carbon dioxide associated with enhanced recovery is capitalized as part of our development costs when it is injected. The acquisition cost associated with pressure maintenance operations for reservoir management is expensed when it is injected. When carbon dioxide is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The units-of-production rate is determined by field.

We evaluate the impairment of our long-lived assets in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell. We review for the impairment of long-lived assets whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We would recognize an impairment loss when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount.

We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total proved and risk-adjusted probable and possible reserves. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.

As discussed in "--Inventories" above, we maintain natural gas in underground storage as part of our inventory. This component of our inventory represents the portion of gas stored in an underground storage facility generally known as "working gas," and represents an estimate of the portion of gas in these facilities available for routine injection and withdrawal to meet demand. In addition to this working gas, underground gas storage reservoirs contain injected gas which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. This gas, generally known as "cushion gas," is divided into the categories of "recoverable cushion gas" and "unrecoverable cushion gas," based on an engineering analysis of whether the gas can be economically removed from the storage facility at any point during its life. The portion of the cushion gas that is determined to be unrecoverable is considered to be a permanent part of the facility itself (thus, part of our "Property, Plant and Equipment, net" balance in our accompanying consolidated balance sheets), and this unrecoverable portion is depreciated over the facility's estimated useful life. The portion of the cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.

Equity Method of Accounting

We account for investments greater than 20% in affiliates, which we do not control, by the equity method of accounting. Under this method, an investment is carried at our acquisition cost, plus our equity in undistributed earnings or losses since acquisition, and less distributions received.

Excess of Cost Over Fair Value

We account for our business acquisitions and intangible assets in accordance with the provisions of SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires that all transactions fitting the description of a business combination be accounted for using the purchase method, which establishes a new basis of accountability for the acquired business or assets. The Statement also modifies the accounting for the excess of cost over the fair value of net assets acquired as well as intangible assets acquired in a business combination. In addition, this Statement requires disclosure of the primary reasons for a business combination and the allocation of the purchase price paid to the assets acquired and liabilities assumed by major balance sheet caption.

SFAS No. 142 requires that goodwill not be amortized, but instead should be tested, at least on an annual basis, for impairment. Pursuant to this Statement, goodwill and other intangible assets with indefinite useful lives can not be amortized until their useful life becomes determinable. Instead, such assets must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We have selected an impairment measurement test date of January 1 of each year and we have determined that our goodwill was not impaired as of January 1, 2007.

Other intangible assets with definite useful economic lives are to be amortized over their remaining useful life and reviewed for impairment in accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." In addition, SFAS No. 142 requires disclosure of information about goodwill and other intangible assets in the years subsequent to their acquisition, including information about the changes in the carrying amount of goodwill from period to period and the carrying amount of intangible assets by major intangible asset class.

Our total unamortized excess cost over fair value of net assets in consolidated affiliates was $829.0 million as of December 31, 2006 and $799.0 million as of December 31, 2005. Such amounts are reported as "Goodwill" on our accompanying consolidated balance sheets. Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was $138.2 million as of both December 31, 2006 and December 31, 2005. Pursuant to SFAS No. 142, this amount, referred to as equity method goodwill, should continue to be recognized in accordance with Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." Accordingly, we included this amount within "Investments" on our accompanying consolidated balance sheets.

In almost all cases, the price we paid to acquire our share of the net assets of our equity investees differed from the underlying book value of such net assets. This differential consists of two pieces. First, an amount related to the discrepancy between the investee's recognized net assets at book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any premium in excess of fair value (representing equity method goodwill as described above) we paid to acquire the investment. The first differential, representing the excess of the fair market value of our investees' plant and other net assets over its underlying book value at the date of acquisition totaled $177.1 million and $181.7 million as of December 31, 2006 and 2005, respectively, and similar to our treatment of equity method goodwill, we included these amounts within "Investments" on our accompanying consolidated balance sheets. As of December 31, 2006, this excess investment cost is being amortized over a weighted average life of approximately 31.7 years.

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 well as the amortization period for such 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 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. As of December 31, 2006, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted.

For more information on our acquisitions, see Note 3. For more information on our investments, see Note 7.

Revenue Recognition

We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. We generally sell natural gas under long-term agreements, with periodic price adjustments. In some cases, we sell natural gas under short-term agreements at prevailing market prices. In all cases, we recognize natural gas sales revenues when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectibility of the revenue is reasonably assured. The natural gas we market is primarily purchased gas produced by third parties, and we market this gas to power generators, local distribution companies, industrial end-users and national marketing companies. We recognize gas gathering and marketing revenues in the month of delivery based on customer nominations and generally, our natural gas marketing revenues are recorded gross, not net of cost of gas sold.

We provide various types of natural gas storage and transportation services to customers. The natural gas remains the property of these customers at all times. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers' agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements.

We provide crude oil transportation services and refined petroleum products transportation and storage services to customers. Revenues are recorded when products are delivered and services have been provided, and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities.

We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered. Liquids terminal minimum take-or-pay revenue is recognized at the end of the contract year or contract term depending on the terms of the contract. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when title has passed. We recognize energy-related product sales revenues based on delivered quantities of product.

Revenues from the sale of oil, natural gas liquids and natural gas production are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer. As a result, we maintain a minimum amount of product inventory in storage and the differences between actual production and sales is not significant.

Capitalized Interest

We capitalize interest expense during the construction or upgrade of qualifying assets. Interest expense capitalized in 2006, 2005 and 2004 was $18.4 million, $9.8 million and $6.4 million, respectively.

Unit-Based Compensation

We account for common unit options granted under our common unit option plan according to the provisions of SFAS No. 123R (revised 2004), "Share-Based Payment," which became effective for us January 1, 2006. 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. According to the provisions of SFAS No. 123R, 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. Companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects, and compensation cost for awards that vest would not be reversed if the awards expire without being exercised.

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.

Environmental Matters

We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations, and we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.

In 2006, we made quarterly adjustments to our environmental liabilities to reflect changes in previous estimates. In making these liability estimations, we considered the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. As a result, in 2006, we recorded a combined $35.4 million increase in environmental expense associated with environmental liability adjustments. We recorded a $32.4 million increase in expense within "Operations and maintenance," a $4.9 million increase in expense within "Earnings from equity investments," and a $1.9 million reduction in expense within "Income Taxes" in our accompanying consolidated statement of income for 2006. The $35.4 million increase in environmental expense resulted in a $31.8 million increase in expense to our Products Pipelines business segment, a $2.2 million increase in expense to our Terminals business segment, a $1.6 million increase in expense to our Natural Gas Pipelines business segment, and a $0.2 million decrease in expense to our CO2 business segment. The environmental expense adjustment (including our share of environmental expense associated with liability adjustments recognized by

Plantation Pipe Line Company) included a $4.1 million increase in our estimated environmental receivables and reimbursables, a $3.5 million decrease in our equity investments, a $34.5 million increase in our overall accrued environmental and related claim liabilities, and a $1.5 million increase in our accrued expense liabilities.

In December 2005, we recognized a $23.3 million increase in environmental expense and in our overall accrued environmental and related claim liabilities. We included this expense within "Operations and maintenance" in our accompanying consolidated statement of income for 2005. The $23.3 million expense item resulted from the adjustment of our environmental expenses and accrued liabilities between our reportable business segments, primarily affecting our Products Pipelines and our Terminals business segments. The $23.3 million increase in environmental expense resulted in a $19.6 million increase in expense to our Products Pipelines business segment, a $3.5 million increase in expense to our Terminals business segment, a $0.3 million increase in expense to our CO2 business segment, and a $0.1 million decrease in expense to our Natural Gas Pipelines business segment.

In December 2004, we recognized a $0.2 million increase in environmental expenses and an associated $0.1 million increase in deferred income tax expense resulting from changes to previous estimates. The adjustment included an $18.9 million increase in our estimated environmental receivables and reimbursables and a $19.1 million increase in our overall accrued environmental and related claim liabilities. We included the additional $0.2 million environmental expense within "Other, net" in our accompanying consolidated statement of income for 2004. The $0.3 million expense item, including taxes, is the net impact of a $30.6 million increase in expense in our Products Pipelines business segment, a $7.6 million decrease in expense in our Natural Gas Pipelines segment, a $4.1 million decrease in expense in our CO2 segment, and an $18.6 million decrease in expense in our Terminals business segment. For more information on our environmental disclosures, see Note 16.

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available. For more information on our legal disclosures, see Note 16.

Pensions and Other Post-retirement Benefits

Effective December 31, 2006, we adopted 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 us to fully recognize the overfunded or underfunded status of our SFPP, L.P. post-retirement benefit plan as an asset or liability in our statement of financial position. Accordingly, as of December 31, 2006, we recognized a liability of $5.5 million for the unfunded portion of this post-retirement benefit plan. We included $0.2 million of this amount within "Accrued other current liabilities" and the remaining $5.3 million within "Other long-term liabilities and deferred credits" on our accompanying consolidated balance sheet. We consider our overall pension and post-retirement benefit liability exposure to be minimal in relation to the value of our total consolidated assets and net income. For more information on our pension and post-retirement benefit disclosures, see Note 10.

Gas Imbalances

We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market. Gas imbalances represent the difference between customer nominations and actual gas receipts from and gas deliveries to our interconnecting pipelines and shippers under various operational balancing and shipper imbalance agreements. Natural gas imbalances are either settled in cash or made up in-kind subject to the pipelines' various tariff provisions.

Minority Interest

As of December 31, 2006, minority interest consisted of the following:

o the 1.0101% general partner interest in each of our five operating partnerships;

o the 0.5% special limited partner interest in SFPP, L.P.;

o the 50% interest in Globalplex Partners, a Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.;

o the 33 1/3% interest in International Marine Terminals Partnership, a Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P. "C";

o the approximate 31% interest in the Pecos Carbon Dioxide Company, a Texas general partnership owned approximately 69% and controlled by Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries;

o the 1% interest in River Terminals Properties, L.P., a Tennessee partnership owned 99% and controlled by Kinder Morgan River Terminals LLC; and

o the 25% interest in Guilford County Terminal Company, LLC, a limited liability company owned 75% and controlled by Kinder Morgan Southeast Terminals LLC.

Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each partner's tax attributes in us.

Some of our corporate subsidiaries and corporations in which we have an equity investment do pay federal and state income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized.

Foreign Currency Translation

On April 26, 2006, we incorporated Kinder Morgan Canada Terminals ULC, an Alberta, Canada unlimited liability corporation. Kinder Morgan Canada Terminals ULC, located in Edmonton, Alberta, is currently constructing a crude oil tank farm which will have a storage capacity of approximately 2.2 million barrels and serve as a blending and storage hub for Canadian crude oil. We expect Kinder Morgan Canada Terminals ULC to begin operations sometime in the third quarter of 2007.

In October 2004, we acquired Kinder Morgan River Terminals LLC, formerly Global Materials Services LLC. Our acquisition of Kinder Morgan River Terminals LLC included two wholly-owned subsidiaries which conducted business outside of the United States. The two foreign subsidiaries are Arrow Terminals, B.V., which conducts bulk terminal operations in The Netherlands, and Arrow Terminals Canada Company (NSULC), which conducts bulk terminal operations in Canada.

We account for these three entities in accordance with the provisions of SFAS No. 52, "Foreign Currency Translation." We translate the assets and liabilities of each of these two entities to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and stockholders' equity accounts are translated by using historical exchange rates. Translation adjustments result from translating all assets and liabilities at current year-end rates, while stockholders' equity is translated by using historical and weighted-average rates. The cumulative translation adjustments balance is reported as a component of accumulated other comprehensive income/(loss) within Partners' Capital on our accompanying consolidated balance

sheet. Due to the limited size of our foreign operations, we do not believe these foreign currency translations are material to our financial position.

Comprehensive Income

Statement of Financial Accounting Standards No. 130, "Accounting for Comprehensive Income," requires that enterprises report a total for comprehensive income. For each of the years ended December 31, 2006, 2005 and 2004, the difference between our net income and our comprehensive income resulted from unrealized gains or losses on derivatives utilized for energy commodity price risk hedging purposes and from foreign currency translation adjustments. For more information on our risk management activities, see Note 14.

Cumulative revenues, expenses, gains and losses that under generally accepted accounting principals are included within comprehensive income but excluded from earnings are reported as accumulated other comprehensive income/(loss) within Partners' Capital in our consolidated balance sheets. In addition, pursuant to our initial application of SFAS No. 158 "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans" on December 31, 2006, we also recognized prior service credits and actuarial gains that had not yet been included in net periodic benefit cost as of the end of the fiscal year as a component of our ending balance of accumulated other comprehensive income. The following table summarizes changes in the amount of our "Accumulated other comprehensive loss" in our accompanying consolidated balance sheets for each of the two years ended December 31, 2005 and 2006 (in thousands):

                          Net unrealized       Foreign           Other              Total
                          gains/(losses)       currency     Post-retirement    Accumulated other
                           on cash flow      translation        benefit          comprehensive
                        hedge derivatives    adjustments    acctg. changes       income/(loss)
                        -----------------    -----------    ---------------    -----------------
December 31, 2004.......$        (457,718)   $       375    $            --    $        (457,343)
Change for period.......         (621,632)          (699)                --             (622,331)
                        -----------------    -----------    ---------------    -----------------
December 31, 2005.......       (1,079,350)          (324)                --           (1,079,674)
Change for period.......          240,612            722             (3,214)             238,120
                        -----------------    -----------    ---------------    -----------------
December 31, 2006.......$        (838,738)   $       398    $        (3,214)   $        (841,554)
                        =================    ===========    ===============    =================

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.

Asset Retirement Obligations

We account for asset retirement obligations pursuant to SFAS No. 143, "Accounting for Asset Retirement Obligations." For more information on our asset retirement obligations, see Note 4.

Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids and crude oil. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations.

Our derivative contracts are accounted for under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No.133" and No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." SFAS No. 133 established accounting and reporting standards requiring that every derivative contract (including certain derivative contracts embedded in other contracts) be

recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative contract's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative contract meets those criteria, SFAS No. 133 allows a derivative contract's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative contract as a hedge and document and assess the effectiveness of derivative contracts associated with transactions that receive hedge accounting.

Furthermore, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting requirements of SFAS No. 133 and is accounted for using traditional accrual accounting. Our derivative contracts that hedge our commodity price risks involve our normal business activities, which include the sale of natural gas, natural gas liquids and crude oil, and these derivative contracts have been designated as cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivative contracts that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative contract's gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. See Note 14 for more information on our risk management activities.

Accounting for Regulatory Activities

Our regulated utility operations are accounted for in accordance with the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," which prescribes the circumstances in which the application of generally accepted accounting principles is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process.

The following regulatory assets and liabilities are reflected within "Deferred charges and other assets" and "Other long-term liabilities and deferred credits," respectively, in our accompanying consolidated balance sheets as of December 31, 2006 and December 31, 2005 (in thousands):

                                        As of December 31,
                                          2006          2005
                                    -----------    ---------
Regulated Assets:
  Employee benefit costs........... $       373    $     328
  Fuel Tracker.....................       1,594           --
  Deferred regulatory expenses.....       3,238        3,363
                                    -----------    ---------
  Total regulatory assets..........       5,205        3,691

Regulated Liabilities:
  Deferred income taxes............         925        1,883
  Fuel Tracker.....................          --       (1,275)
                                    -----------    ---------
  Total regulatory liabilities.....         925          608

  Net regulatory assets............ $     4,280    $   3,083
                                    ===========    =========

As of December 31, 2006, all of our regulatory assets and regulatory liabilities were being recovered from or refunded to customers through rates over periods ranging from one to five years.

3. Aquisitions, Joint Ventures and Divestitures

During 2006, 2005 and 2004, we completed or made adjustments for the following significant acquisitions. Each of the acquisitions was accounted for under the purchase method and the assets acquired and liabilities assumed were recorded at their estimated fair market values as of the acquisition date. The preliminary allocation of assets (and any liabilities assumed) may be adjusted to reflect the final determined amounts during a short period of time following the acquisition. Although the time that is required to identify and measure the fair value of the assets acquired and the liabilities assumed in a business combination will vary with circumstances, generally our allocation period ends when we no longer are waiting for information that is known to be available or obtainable. The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date.

                                                                            Allocation of Purchase Price
                                                          ---------------------------------------------------------------
                                                                                   (in millions)
                                                          ---------------------------------------------------------------
                                                                                Property    Deferred
                                                          Purchase    Current    Plant &     Charges             Minority
Ref.   Date                  Acquisition                    Price     Assets    Equipment    & Other   Goodwill  Interest
---  ------   ------------------------------------------  ---------   -------   ---------   --------   --------  --------
(1)    3/04   ExxonMobil Products Terminals.............  $    50.9   $     -   $    50.9   $      -   $      -  $      -
(2)    8/04   Kinder Morgan Wink Pipeline, L.P..........      100.3       0.1        77.4       22.8          -         -
(3)   10/04   Interest in Cochin Pipeline System........       10.9         -        10.9          -          -         -
(4)   10/04   Kinder Morgan River Terminals LLC.........       87.9       9.9        43.2       14.6       20.2         -
(5)   11/04   Charter Products Terminals................       75.2       0.5        70.9        4.9          -      (1.1)
(6)   11/04   TransColorado Gas Transmission Company....      284.5       2.0       280.6        1.9          -         -
(7)   12/04   Kinder Morgan Fairless Hills Terminal.....        7.5       0.3         5.9        1.3          -         -
(8)    1/05   Claytonville Oil Field Unit ..............        6.5         -         6.5          -          -         -
(9)    4/05   Texas Petcoke Terminal Region ............      247.2         -        72.5      161.4       13.3         -
(10)   7/05   Terminal Assets ..........................       36.2       0.5        35.7          -          -         -
(11)   7/05   General Stevedores, L.P. .................       10.4       0.6         5.2        0.2        4.4         -
(12)   8/05   North Dayton Natural Gas Storage Facility       109.4         -        71.7       11.7       26.0         -
(13) 8-9/05   Terminal Assets ..........................        4.3       0.4         3.9          -          -         -
(14)  11/05   Allied Terminal Assets ...................       13.3       0.2        12.6        0.5          -         -
(15)   2/06   Entrega Gas Pipeline LLC..................      244.6         -       244.6          -          -         -
(16)   4/06   Oil and Gas Properties....................       63.9       0.2        63.7          -          -         -
(17)   4/06   Terminal Assets ..........................       61.9       0.5        43.6          -       17.8         -
(18)  11/06   Transload Services, LLC...................       16.8       1.6         6.6          -        8.6         -
(19)  12/06   Devco USA L.L.C...........................        7.3       0.8           -        6.5          -         -
(20)  12/06   Roanoke, Virginia Products Terminal.......  $     6.4   $     -   $     6.4   $      -   $      -  $      -

(1) ExxonMobil Products Terminals

Effective March 9, 2004, we acquired seven refined petroleum products terminals in the southeastern United States from ExxonMobil Corporation. Our purchase price was approximately $50.9 million, consisting of approximately $48.2 million in cash and $2.7 million in assumed liabilities. The terminals are located in Collins, Mississippi; Knoxville, Tennessee; Charlotte and Greensboro, North Carolina; and Richmond, Roanoke and Newington, Virginia. Combined, the terminals have a total storage capacity of approximately 3.2 million barrels for gasoline, diesel fuel and jet fuel. As part of the transaction, ExxonMobil entered into a long-term contract to store products at the terminals. As of our acquisition date, we expected to invest an additional $1.2 million in the facilities. The acquisition enhanced our terminal operations in the Southeast and complemented our December 2003 acquisition of seven products terminals from ConocoPhillips Company and Phillips Pipe Line Company. The acquired operations are included as part of our Products Pipelines business segment.

(2) Kinder Morgan Wink Pipeline, L.P.

Effective August 31, 2004, we acquired all of the partnership interests in Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings, L.P. for a purchase price of approximately $100.3 million, consisting of $89.9 million in cash and the assumption of approximately $10.4 million of liabilities, including debt of $9.5 million. In September 2004, we paid off the $9.5 million outstanding debt balance. We renamed the limited partnership Kinder Morgan Wink Pipeline, L.P., and we have included its results as part of our CO2 business segment. The acquisition included a 450-mile crude oil pipeline system, consisting of four mainline sections, numerous gathering systems and truck off-loading stations. The mainline sections, all in Texas, have a total capacity of 130,000 barrels of crude oil per day (with the use of a drag reducing agent). As part of the transaction, we entered into a long-term throughput agreement with Western Refining Company, L.P. to transport crude oil into Western's 120,000 barrel per day refinery in El Paso, Texas. The acquisition allows us to better manage crude oil deliveries from our oil field interests in West Texas. Our allocation of the purchase price to assets acquired and liabilities assumed was based on an appraisal of fair market values, which was completed in the second quarter of 2005. The $22.8 million of deferred charges and other assets in the table above represents the fair value of the intangible long-term throughput agreement.

(3) Interest in Cochin Pipeline

Effective October 1, 2004, we acquired an additional undivided 5% interest in the Cochin Pipeline System from subsidiaries of ConocoPhillips Corporation for approximately $10.9 million. On November 3, 2000, we acquired from NOVA Chemicals Corporation an undivided 32.5% interest in the Cochin Pipeline System for approximately $120.5 million. On June 20, 2001, we acquired an additional 2.3% ownership interest from Shell Canada Limited for approximately $8.1 million, and effective December 31, 2001, we purchased an additional 10% ownership interest from NOVA Chemicals Corporation for approximately $29 million. We now own approximately 49.8% of the Cochin Pipeline System. A subsidiary of BP owns the remaining interest and operates the pipeline. We record our proportional share of joint venture revenues and expenses and cost of joint venture assets with respect to the Cochin Pipeline System as part of our Products Pipelines business segment.

(4) 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 last half of 2005, we made purchase price adjustments to the acquired assets based on an appraisal of fair market values and our 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. As of our acquisition date, we expected to invest an additional $9.4 million over the next two years to expand and upgrade the terminals, which are located in 11 Mid-Continent states. 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.

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 $14.6 million of deferred charges and other assets 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.

(5) Charter Products Terminals

Effective November 5, 2004, we acquired ownership interests in nine refined petroleum products terminals in the southeastern United States from Charter Terminal Company and Charter-Triad Terminals, LLC for approximately $75.2 million, consisting of $72.4 million in cash and $2.8 million of assumed liabilities. Three terminals are located in Selma, North Carolina, and the remaining facilities are located in Greensboro and Charlotte, North Carolina; Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South Carolina. We fully own seven of the terminals and jointly own the remaining two. The nine facilities have a combined 3.2 million barrels of storage. All of the terminals are connected to products pipelines owned by either Plantation Pipe Line Company or Colonial Pipeline Company. The acquisition complemented the other terminals we own in the Southeast and increased our southeast terminal storage capacity 76% (to 7.7 million barrels) and terminal throughput capacity 62% (to over 340,000 barrels per day). The acquired terminals are included as part of our Products Pipelines business segment.

In the fourth quarter of 2005, we made purchase price adjustments that increased property, plant and equipment $11.2 million, increased investments $1.0 million, decreased goodwill $13.1 million and increased other intangibles $0.9 million. The changes were based on an appraisal of fair market values, which was completed in the fourth quarter of 2005. The $4.9 million of deferred charges and other assets in the table above includes $0.9 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.

(6) TransColorado Gas Transmission Company

Effective November 1, 2004, we acquired all of the partnership interests in TransColorado Gas Transmission Company from two wholly-owned subsidiaries of KMI. TransColorado Gas Transmission Company, a Colorado general partnership referred to in this report as TransColorado, owned assets valued at approximately $284.5 million. As consideration for TransColorado, we paid to KMI $211.2 million in cash and approximately $64.0 million in units, consisting of 1,400,000 common units. We also assumed liabilities of approximately $9.3 million. The purchase price for this transaction was determined by the boards of directors of KMR and our general partner, and KMI based on valuation parameters used in the acquisition of similar assets. The transaction was approved unanimously by the independent members of the boards of directors of both KMR and our general partner, and KMI, with the benefit of advice of independent legal and financial advisors, including the receipt of fairness opinions from separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley & Co. TransColorado owns a 300-mile interstate natural gas pipeline that originates in the Piceance Basin of western Colorado and runs to the Blanco Hub in northwest New Mexico. The acquisition expanded our natural gas operations within the Rocky Mountain region and the acquired operations are included as part of our Natural Gas Pipelines business segment.

(7) Kinder Morgan Fairless Hills Terminal

Effective December 1, 2004, we acquired substantially all of the assets used to operate the major port distribution facility located at the Fairless Industrial Park in Bucks County, Pennsylvania for an aggregate consideration of approximately $7.5 million, consisting of $7.2 million in cash and $0.3 million in assumed liabilities. The facility, referred to as our Kinder Morgan Fairless Hills Terminal, was purchased from Novolog Bucks County, Inc. and is located along the Delaware River. It is the largest port on the East Coast for the handling of semi-finished steel slabs, which are used as feedstock by domestic steel mills. The port operations at Fairless Hills also include the handling of other types of steel and specialized cargo that caters to the construction industry and service centers that use steel sheet and plate. In the second quarter of 2005, after completing a final inventory count, we allocated $0.3 million of our purchase price that was originally allocated to property, plant and equipment to current assets (materials and supplies-parts inventory). The terminal acquisition expanded our presence along the Delaware River and complemented our existing Mid-Atlantic terminal facilities. We include its operations in our Terminals business segment.

(8) Claytonville Oil Field Unit

Effective January 31, 2005, we acquired an approximate 64.5% gross working interest in the Claytonville oil field unit located in Fisher County, Texas from Aethon I L.P. The field is located nearly 30 miles east of the SACROC unit in the Permian Basin of West Texas. Our purchase price was approximately $6.5 million, consisting of $6.2 million in cash and the assumption of $0.3 million of liabilities. Following our acquisition, we became the operator of the field, which at the time of acquisition was producing approximately 200 barrels of oil per day. The acquisition of this ownership interest complemented our existing carbon dioxide assets in the Permian Basin and we include the acquired operations as part of our CO2 business segment. Currently, we are performing technical evaluations to confirm the carbon dioxide enhanced oil recovery potential and generate definitive plans to develop this potential, if proven to be economic.

(9) Texas Petcoke Terminal Region

Effective April 29, 2005, we acquired seven bulk terminal operations from Trans-Global Solutions, Inc. for an aggregate consideration of approximately $247.2 million, consisting of $186.0 million in cash, $46.2 million in common units, and an obligation to pay an additional $15 million on April 29, 2007, two years from closing. We will settle the $15 million liability by issuing additional common units. All of the acquired assets are located in the State of Texas, and include facilities at the Port of Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship Channel. We combined the acquired operations into a new terminal region called the Texas Petcoke region, as certain of the terminals have contracts in place to provide petroleum coke handling

services for major Texas oil refineries. The acquisition complemented our existing Gulf Coast terminal facilities and expanded our pre-existing petroleum coke handling operations. The acquired operations are included as part of our Terminals business segment.

In the fourth quarter of 2005, we made purchase price adjustments that increased property, plant and equipment $0.1 million, increased goodwill $1.0 million and decreased other intangibles $1.3 million. The changes were based on an appraisal of fair market values, which was completed in the fourth quarter of 2005. The $13.3 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 $161.4 million of deferred charges and other assets in the table above represents 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. In connection with the transaction, Trans-Global Solutions, Inc. agreed to indemnify Kinder Morgan G.P., Inc. for any losses relating to our failure to repay $50.9 million of indebtedness incurred to fund the acquisition, and we agreed to indemnify Trans-Global Solutions, Inc. for any taxes of Trans-Global Solutions, Inc. that may arise from the sale of any acquired assets. We have no current intention to sell any of the assets acquired in this transaction.

(10) July 2005 Terminal Assets

In July 2005, we acquired three terminal facilities in separate transactions for an aggregate consideration of approximately $36.2 million in cash. For the three terminals combined, as of the acquisition date, we expected to invest approximately $14 million subsequent to acquisition in order to enhance the terminals' operational efficiency. The largest of the transactions was the purchase of a refined petroleum products terminal in New York Harbor from ExxonMobil Oil Corporation. The second acquisition involved a dry-bulk river terminal located in the State of Kentucky, and the third involved a liquids/dry-bulk facility located in Blytheville, Arkansas. The operations of all three facilities are included in our Terminals business segment.

The New York Harbor terminal, located on Staten Island and referred to as the Kinder Morgan Staten Island terminal, complements our existing Northeast liquids terminal facilities located in Carteret and Perth Amboy, New Jersey. At the time of acquisition, the terminal had storage capacity of 2.3 million barrels for gasoline, diesel and fuel oil, and we expected to bring several idle tanks back into service that would add another 550,000 barrels of capacity. In addition, we planned to rebuild a ship berth with the ability to accommodate tanker vessels. As part of the transaction, ExxonMobil entered into a long-term storage capacity agreement with us and has continued to utilize a portion of the terminal.

The dry-bulk terminal, located along the Ohio River in Hawesville, Kentucky, primarily handles wood chips and finished paper products. The acquisition complemented our existing terminal assets located in the Ohio River Valley and further expanded our wood-chip handling businesses. As part of the transaction, we assumed a long-term handling agreement with Weyerhauser Company, an international forest products company, and we planned to expand the terminal in order to increase utilization and provide storage services for additional products.

The assets acquired at the liquids/dry-bulk facility in Blytheville, Arkansas consisted of storage and supporting infrastructure for 40,000 tons of anhydrous ammonia, 9,500 tons of urea ammonium nitrate solutions and 40,000 tons of urea. As part of the transaction, we have entered into a long-term agreement to sublease all of the existing anhydrous ammonia and urea ammonium nitrate terminal assets to Terra Nitrogen Company, L.P. The terminal is one of only two facilities in the United States that can handle imported fertilizer and provide shipment west on railcars, and the acquisition of the facility positioned us to take advantage of the increase in fertilizer imports that has resulted from the recent decrease in domestic production.

(11) 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 $10.4 million, consisting of $2.0 million in cash, $3.4 million in common units, and $5.0 million in assumed liabilities, including debt of $3.0 million. In August 2005, we paid the $3.0 million

outstanding debt balance, and in 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 appraisal of acquired fixed asset and land values, adjustments to property, plant and equipment, goodwill, and deferred tax liabilities.

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. The $4.4 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.

(12) North Dayton Natural Gas Storage Facility

Effective August 1, 2005, we acquired a natural gas storage facility in Liberty County, Texas, from Texas Genco LLC for an aggregate consideration of approximately $109.4 million, consisting of $52.9 million in cash and $56.5 million in assumed debt. The facility, referred to as our North Dayton storage facility, has approximately 6.3 billion cubic feet of total capacity, consisting of 4.2 billion cubic feet of working capacity and 2.1 billion cubic feet of pad (cushion) gas. The acquisition complemented our existing Texas intrastate natural gas pipeline group assets and positioned us to pursue expansions at the facility that will provide or offer needed services to utilities, the growing liquefied natural gas industry along the Texas Gulf Coast, and other natural gas storage users. Additionally, as part of the transaction, we entered into a long-term storage capacity and transportation agreement with Texas Genco, one of the largest wholesale electric power generating companies in the United States, with over 13,000 megawatts of generation capacity. The agreement covers storage services for approximately 2.0 billion cubic feet of natural gas capacity and expires on March 1, 2017. The North Dayton storage facility's operations are included in our Natural Gas Pipelines business segment.

Our allocation of the purchase price to assets acquired and liabilities assumed was based on an appraisal of fair market values, which was completed in the fourth quarter of 2005. The $26.0 million of goodwill was assigned to our Natural Gas Pipelines business segment and the entire amount is expected to be deductible for tax purposes. We believe our acquisition of the North Dayton natural gas storage facility resulted in the recognition of goodwill primarily due to the fact that the favorable location and the favorable association with our pre-existing assets contributed to the fair value of acquired identifiable net assets and liabilities exceeding our acquisition price--in the aggregate, these factors represented goodwill. The $11.7 million of deferred charges and other assets in the table above represents the fair value of the intangible long-term natural gas storage capacity and transportation agreement.

(13) August and September 2005 Terminal Assets

In August and September 2005, we acquired certain terminal facilities and assets, including both real and personal property, in two separate transactions for an aggregate consideration of approximately $4.3 million in cash. In August 2005, we spent $1.9 million to acquire the Kinder Morgan Blackhawk terminal from White Material Handling, Inc., and in September 2005, we spent $2.4 million to acquire a repair shop and related assets from Trans-Global Solutions, Inc.

The Kinder Morgan Blackhawk terminal consists of approximately 46 acres of land, storage buildings, and related equipment located in Black Hawk County, Iowa. The terminal primarily stores and transfers fertilizer and salt and further expanded our Midwest region bulk terminal operations. The acquisition of the repair shop, located in Jefferson County, Texas, near Beaumont, consists of real and personal property, including parts inventory. The acquisition facilitated and expanded the earlier acquisition of our Texas Petcoke terminals from Trans-Global Solutions in April 2005. The operations of both acquisitions are included in our Terminals business segment.

(14) Allied Terminal Assets

Effective November 4, 2005, we acquired certain terminal assets from Allied Terminals, Inc. for an aggregate consideration of approximately $13.3 million, consisting of $12.1 million in cash and $1.2 million in assumed liabilities. The assets primarily consisted of storage tanks, loading docks, truck racks, land and other equipment and personal property located adjacent to our Shipyard River bulk terminal in Charleston, South Carolina. The acquisition complemented an ongoing capital expansion project at our Shipyard River terminal that together, will add infrastructure in order to increase the terminal's ability to handle increasing supplies of imported coal. The acquired assets are counted as an external addition to our Shipyard River terminal and are included as part of our Terminals business segment.

(15) 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, Entrega 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 on February 24, 2006. 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 both pipeline segments were placed into service on February 14, 2007.

In April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline
LLC. Going forward, the entire pipeline system (including the lines currently being developed) will be known as the Rockies Express Pipeline. The combined 1,663-mile pipeline system 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 December 31, 2006, for West2East Pipeline LLC, which is accounted for under the equity method, is as follows (in thousands; amounts represent 100% of investee information):

                                                December 31,
     Balance Sheet                                  2006
---------------------                         ----------------
Current assets............................      $     3,456
Non-current assets........................          847,000
Current liabilities.......................           68,486
Non-current liabilities...................          790,050
Accumulated other comprehensive income....      $    (8,080)

In addition, we have guaranteed our proportionate 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.

(16) April 2006 Oil and Gas Properties

On April 5, 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 $63.9 million, consisting of $60.3 million in cash and $3.6 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. We received proceeds of approximately $27.1 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 430 barrels of oil equivalent per day, and include some fields with potential for enhanced oil recovery development near our current carbon dioxide operations. The acquired operations are included as part of our CO2 business segment. Currently, we are performing technical evaluations to confirm the carbon dioxide enhanced oil recovery potential and generate definitive plans to develop this potential, if proven to be economic.

(17) 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. 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.

(18) Transload Services, LLC

Effective November 20, 2006, we acquired all of the membership interests of Transload Services, LLC from Lanigan Holdings, LLC for an aggregate consideration of approximately $16.8 million, consisting of $15.4 million in cash, an obligation to pay $0.9 million currently held as security for the collection of certain accounts receivable and for the perfection of certain real property title rights, and $0.5 million of assumed liabilities. Transload Services, LLC is a leading provider of innovative, high quality material handling and steel processing services, operating 14 steel-related terminal facilities located in the Chicago metropolitan area and various cities in the United States. Its operations include transloading services, steel fabricating and processing, warehousing and distribution, and project staging. Specializing in steel processing and handling, Transload Services can inventory product, schedule shipments and provide customers cost-effective modes of transportation. The combined operations include over 92 acres of outside storage and 445,000 square feet of covered storage that offers customers environmentally controlled warehouses with indoor rail and truck loading facilities for handling temperature and humidity sensitive products. The acquired assets are included in our Terminals business segment, and the acquisition further expanded and diversified our existing terminals' materials services (rail transloading) operations.

The $8.6 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 it establishes a business presence in several key markets, taking advantage of the non-residential and highway construction demand for steel that contributed to the fair value of acquired identifiable net assets and liabilities exceeding our acquisition price--in the aggregate, these factors represented goodwill. Our allocation of the purchase price to assets acquired and liabilities assumed is preliminary, pending final determination of working capital balances at the time of acquisition. We expect these final working capital adjustments to be made in the first quarter of 2007.

(19) Devco USA L.L.C.

Effective December 1, 2006, we acquired all of the membership interests in Devco USA L.L.C., an Oklahoma limited liability company, for an aggregate consideration of approximately $7.3 million, consisting of $4.8 million in cash, $1.6 million in common units, and $0.9 million of assumed liabilities. The primary asset acquired was a technology based identifiable intangible asset, a proprietary process that transforms molten sulfur into premium solid formed pellets that are environmentally friendly, easy to handle and store, and safe to transport. The process was developed internally by Devco's engineers and employees. Devco, a Tulsa, Oklahoma based company, has more than 20 years of sulfur handling expertise and we believe the acquisition and subsequent application of this acquired technology complements our existing dry-bulk terminal operations. We allocated $6.5 million of our total purchase price to the value of this intangible asset, and we have included the acquisition as part of our Terminals business segment.

(20) Roanoke, Virginia Products Terminal

Effective December 15, 2006, we acquired a refined petroleum products terminal located in Roanoke, Virginia from Motiva Enterprises, LLC for approximately $6.4 million in cash. The terminal has storage capacity of approximately 180,000 barrels per day for refined petroleum products like gasoline and diesel fuel. The terminal is served exclusively by the Plantation Pipeline and Motiva has entered into a long-term contract to use the terminal. The acquisition complemented the other refined products terminals we own in the southeast region of the United States, and the acquired terminal is included as part our Products Pipelines business segment.

Pro Forma Information

The following summarized unaudited pro forma consolidated income statement information for the years ended December 31, 2006 and 2005, assumes that all of the acquisitions we have made and joint ventures we have entered into since January 1, 2005, including the ones listed above, had occurred as of January 1, 2005. We have prepared these unaudited pro forma financial results for comparative purposes only. These unaudited pro forma financial

results may not be indicative of the results that would have occurred if we had completed these acquisitions and joint ventures as of January 1, 2005 or the results that will be attained in the future. Amounts presented below are in thousands, except for the per unit amounts:

                                                            Pro Forma Year Ended
                                                                December 31,
                                                        ----------------------------
                                                            2006            2005
                                                        ------------    ------------
                                                                 (Unaudited)
Revenues.............................................   $  8,979,852    $  9,882,437
Operating Income.....................................      1,262,480       1,040,753
Net Income...........................................   $    974,501    $    823,029
Basic Limited Partners' Net Income per unit..........   $       2.05    $       1.63
Diluted Limited Partners' Net Income per unit........   $       2.05    $       1.62

Acquisitions Subsequent to December 31, 2006

On January 15, 2007, we announced that we had entered into an agreement with affiliates of BP to increase our ownership interest in the Cochin pipeline system to 100%. We purchased our original undivided 32.5% ownership interest in the Cochin pipeline system in November 2000, and currently, we own a 49.8% ownership interest. BP Canada Energy Company owns the remaining 50.2% ownership interest and is the operator of the pipeline. The agreement is subject to due diligence, regulatory clearance and other standard closing conditions. The transaction is expected to close in the first quarter of 2007, and upon closing, we will become the operator of the pipeline.

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 approximately 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 year ended December 31, 2006. For more information on our accounting for derivative contracts, see Note 14.

4. Asset Retirement Obligations

We account for our legal obligations associated with the retirement of long-lived assets pursuant to Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. Under SFAS No. 143, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.

In our CO2 business segment, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of December 31, 2006 and 2005, we have recognized asset retirement obligations relating to these requirements at existing sites within our CO2 segment in the aggregate amounts of $47.2 million and $41.5 million, respectively.

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 one inactive gas processing plant, various 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 December 31, 2006 and 2005, we have recognized asset retirement obligations relating to the businesses within our Natural Gas Pipelines segment in the aggregate amounts of $3.1 million and $1.7 million, respectively.

We have included $1.4 million and $0.8 million, respectively, of our total asset retirement obligations as of December 31, 2006 and December 31, 2005 within "Accrued other current liabilities" in our accompanying consolidated balance sheets. The remaining $48.9 million obligation as of December 31, 2006 and $42.4 million obligation as of December 31, 2005 are reported separately as non-current liabilities in our accompanying consolidated balance sheets. 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 years ended December 31, 2006 and 2005 is as follows (in thousands):

                                                     Year Ended December 31,
                                                 ------------------------------
                                                    2006                2005
                                                 ---------           ----------
Balance at beginning of period...............    $  43,227           $   38,274
  Liabilities incurred.......................        6,763                5,926
  Liabilities settled........................       (2,233)              (1,778)
  Accretion expense..........................        2,518                1,327
  Revisions in estimated cash flows..........           --                 (522)
                                                 ---------           ----------
Balance at end of period.....................    $  50,275           $   43,227
                                                 =========           ==========

5. Income Taxes

Components of the income tax provision applicable to continuing operations for federal, foreign and state taxes are as follows (in thousands):

                                                    Year Ended December 31,
                                             ------------------------------------
                                               2006          2005          2004
                                             --------      --------      --------
Taxes currently payable:
  Federal.................................   $ 12,822      $  9,604      $  7,515
  State...................................      2,339         2,112         1,497
  Foreign.................................        458           322            70
                                             --------      --------      --------
  Total...................................     15,619        12,038         9,082
Taxes deferred:
  Federa..................................      1,568         8,159         5,694
  State...................................        260           769           883
  Foreign.................................      1,601         3,495         4,067
                                             --------      --------      --------
  Total...................................      3,429        12,423        10,644
                                             --------      --------      --------
Total tax provision.......................   $ 19,048      $ 24,461      $ 19,726
                                             ========      ========      ========
Effective tax rate........................        1.9%          2.9%          2.3%

The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:

                                                                         Year Ended December 31,
                                                                     -----------------------------
                                                                       2006       2005       2004
                                                                     -------    -------    -------
Federal income tax rate.............................................    35.0%      35.0%      35.0%
Increase (decrease) as a result of:
 Partnership earnings not subject to tax............................   (35.0)%    (35.0)%    (35.0)%
 Corporate subsidiary earnings subject to tax.......................     1.0%       1.1%       0.5%
 Income tax expense attributable to corporate equity earnings.......     0.5%       1.1%       1.2%
 Income tax expense attributable to foreign corporate earnings......     0.2%       0.5%       0.5%
 State taxes........................................................     0.2%       0.2%       0.1%
                                                                     -------    -------    -------
Effective tax rate..................................................     1.9%       2.9%       2.3%
                                                                     =======    =======    =======

Our deferred tax assets and liabilities as of December 31, 2006 and 2005 result from the following (in thousands):

                                                                    December 31,
                                                               ----------------------
                                                                 2006          2005
                                                               --------      --------
Deferred tax assets:
  Book accruals.............................................   $  1,431      $  1,112
  Net Operating Loss/Alternative minimum tax credits........      2,982         1,548
  Other.....................................................      1,310         1,445
                                                               --------      --------
Total deferred tax assets...................................      5,723         4,105

Deferred tax liabilities:
  Property, plant and equipment.............................     69,964        63,562
  Other.....................................................     11,300        10,886
                                                               --------      --------
Total deferred tax liabilities..............................     81,264        74,448
                                                               --------      --------
Net deferred tax liabilities................................   $ 75,541      $ 70,343
                                                               ========      ========

We had available, at December 31, 2006, approximately $0.112 million of foreign minimum tax credit carryforwards, which are available through 2015, and $2.9 million of foreign and state net operating loss carryforwards, which will expire between the years 2008 and 2025. We believe it is more likely than not that the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary.

6. Property, Plant and Equipment

Classes and Depreciation

As of December 31, 2006 and 2005, our property, plant and equipment consisted of the following (in thousands):

                                                                                                  December 31,
                                                                                         ----------------------------
                                                                                             2006             2005
                                                                                         -----------      -----------
Natural gas, liquids and carbon dioxide pipelines.....................................   $ 4,309,501      $ 4,005,612
Natural gas, liquids, carbon dioxide pipeline, and terminals station equipment........     4,508,757        4,146,328
Coal and bulk tonnage transfer, storage and services..................................         5,946          131,265
Natural gas, liquids (including linefill), and transmix processing....................       172,720          187,061
Other.................................................................................       844,897          625,615
Accumulated depreciation and depletion................................................    (1,604,614)      (1,242,304)
                                                                                         -----------      -----------
                                                                                           8,237,207        7,853,577
Land and land right-of-way............................................................       487,123          440,497
Construction work in process..........................................................       721,141          570,510
                                                                                         -----------      -----------
Property, Plant and Equipment, net....................................................   $ 9,445,471      $ 8,864,584
                                                                                         ===========      ===========

Depreciation and depletion expense charged against property, plant and equipment consists of the following (in thousands):

                                           2006         2005         2004
                                         --------     --------     --------
Depreciation and depletion expense..     $397,525     $339,580     $285,351

Casualty Gain

On August 29, 2005, Hurricane Katrina made landfall in the United States' Gulf Coast causing widespread damage to residential and commercial real and personal property. In addition, on September 23, 2005, Hurricane Rita struck the Texas-Louisiana Gulf Coast causing additional damage to insured interests. The primary assets we operate that were impacted by these storms included several bulk and liquids terminal facilities located in the states of Louisiana and Mississippi, and certain of our Gulf Coast liquids terminals facilities, which are located along the Houston Ship Channel. Specifically, with regard to physical property damage, our International Marine Terminals facility suffered extensive property damage and a general loss of business due to the effects of Hurricane Katrina. IMT is a Louisiana partnership owned 66 2/3% by us. It operates a multi-purpose bulk commodity transfer terminal facility located in Port Sulphur, Louisiana.

All of our terminal facilities affected by these storms are currently open, and all of the facilities are covered by property casualty insurance. Some of the facilities are also covered by business interruption insurance. To account for our property casualty damage, we recognized repair expense related to hurricane damage as incurred. We also transferred off our books the net book value of the assets that were damaged or destroyed, and we offset the book value of all damaged and destroyed assets with indemnity proceeds received (and receivable in the future) according to the provisions of the insurance policies in force. We also incurred capital expenditures related to the repair and replacement of damaged assets.

When an insured asset is damaged or destroyed, the relevant accounts must be adjusted to the date of the casualty, and settlement with the insurance companies must be completed. The maximum amount recoverable from property damage is the fair market value of the property at the date of loss (the replacement value), or the amount stipulated in the insurance contract. Although net book values are irrelevant in determining indemnifications from insurers, under current accounting provisions, asset book values are used for accounting purposes to measure the gain or loss resulting from casualty settlements. Also, because indemnifications under insurance policies are based upon fair market values, indemnifications often exceed the book value of the assets destroyed or damaged, and any excess of insurance indemnifications over the book value of damaged assets represents a book casualty gain.

In the fourth quarter of 2006, we reached settlements with our insurance carriers on all of our property damage claims related to the 2005 hurricane season, including IMT's claims. As a result of these settlements, we recognized a property casualty gain of $15.2 million, excluding all hurricane repair and clean-up expenses. This casualty gain represented the excess of indemnity proceeds received or recoverable over the book value of damaged or destroyed assets. We also collected, in 2006, property insurance indemnities of $13.1 million, and we disclosed these cash receipts separately as "Property casualty indemnifications" within investing activities on our accompanying consolidated statement of cash flows. In addition, as of December 31, 2006, we signed proofs of loss totaling $8.0 million for expected future property damage proceeds, and we received these indemnity proceeds in January 2007. With the settlement of these claims, we released all remaining estimated property insurance receivables and estimated property insurance-related damage claim amounts, as these hurricane property damage claims are now

closed; however, we will recognize additional casualty gains of approximately $2.0 million in the first quarter of 2007 (before minority interest allocations), based upon our final determination of the book value of the fixed assets destroyed or damaged, and upon expected future indemnities pursuant to flood insurance coverage.

In addition to this casualty gain, 2006 income and expense items related to hurricane activity included the following: (i) a $2.8 million increase in operating and maintenance expenses from hurricane repair and clean-up activities, (ii) a $1.1 million increase in income tax expense associated with overall hurricane income and expense items, (iii) a $0.4 million decrease in general and administrative expenses from the allocation of overhead expenses to hurricane related capital projects, and (iv) a $3.1 million increase in minority interest expense related to the allocation of IMT's earnings from hurricane income and expense items to minority interest. Combined, the hurricane income and expense items, including the casualty gain, resulted in a total increase in net income of $8.6 million in 2006. For the year 2006, we spent $1,058.3 million in total capital expenditures for our continuing operations, which included approximately $12.2 million for hurricane repair and replacement costs (including accruals, sustaining capital expenditures for hurricane repair and replacement costs totaled $14.2 million).

7. Investments

Our significant equity investments as of December 31, 2006 consisted of:

o Plantation Pipe Line Company (51%);

o West2East Pipeline LLC (51%);

o Red Cedar Gathering Company (49%);

o Thunder Creek Gas Services, LLC (25%);

o Cortez Pipeline Company (50%); and

o Heartland Pipeline Company (50%).

We operate and own an approximate 51% ownership interest in Plantation Pipe Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49% interest. Each investor has an equal number of directors on Plantation's board of directors, and board approval is required for certain corporate actions that are considered participating rights. Therefore, we do not control Plantation Pipe Line Company, and we account for our investment under the equity method of accounting.

Similarly, as of December 31, 2006, we operate and own a 51% ownership interest in West2East Pipeline LLC, a limited liability company that is the sole owner of Rockies Express Pipeline LLC. ConocoPhillips owns a 24% ownership interest in West2East Pipeline LLC and Sempra Energy holds the remaining 25% interest. As discussed in Note 2, when construction of the entire Rockies Express Pipeline 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. According to the provisions of current accounting standards, due to the fact that we will receive 50% of the economics of the Rockies Express project on an ongoing basis, we are not considered the primary beneficiary of West2East Pipeline LLC and thus, effective June 30, 2006, we deconsolidated this entity and began accounting for our investment under the equity method of accounting. As of December 31, 2006, we had no material investment in the net assets of West2East Pipeline LLC due to the fact that the amount of its assets, primarily property, plant and equipment, was largely offset by the amount of its liabilities, primarily debt.

In addition, prior to the contribution of our ownership interest in Coyote Gas Treating, LLC to Red Cedar Gathering on September 1, 2006, discussed in Note 12, we were the managing partner and owned a 50% equity interest in Coyote Gas Treating, LLC.

Our total investments consisted of the following (in thousands):

                                                                      December 31,
                                                                -----------------------
                                                                  2006           2005
                                                                --------       --------

Plantation Pipe Line Company.................................   $199,555       $213,072
Red Cedar Gathering Company..................................    160,647        139,852
Thunder Creek Gas Services, LLC..............................     37,229         37,254
Cortez Pipeline Company......................................     16,168         17,938
Heartland Pipeline Company...................................      5,733          5,205
All Others...................................................      6,268          5,992
                                                                --------       --------
Total Equity Investments.....................................   $425,600       $419,313
                                                                ========       ========

Our earnings from equity investments were as follows (in thousands):

                                           Year Ended December 31,
                                         2006        2005        2004
                                      ----------  ----------  ----------
Red Cedar Gathering Company.........   $ 36,310    $ 32,000    $ 14,679
Cortez Pipeline Company.............     19,173      26,319      34,179
Plantation Pipe Line Company........     12,775      24,926      25,879
Thunder Creek Gas Services, LLC.....      2,461       2,741       2,828
Heartland Pipeline Company..........      2,177       2,122       1,369
Coyote Gas Treating, LLC............      1,676       2,071       2,453
All Others..........................      1,598       1,481       1,803
                                       --------    --------    --------
Total...............................   $ 76,170    $ 91,660    $ 83,190
                                       ========    ========    ========
Amortization of excess costs........   $ (5,664)   $ (5,644)   $ (5,575)
                                       ========    ========    ========

Summarized combined unaudited financial information for our significant equity investments (listed above) is reported below (in thousands; amounts represent 100% of investee financial information):

                                                                       Year Ended December 31,
                                                                -------------------------------------
        Income Statement                                           2006          2005         2004
-------------------------------                                 ----------    ----------    ---------
Revenues.....................................................   $ 449,669     $ 448,382     $ 418,186
Costs and expenses...........................................     303,339       282,317       265,819
                                                                ---------     ---------     ---------
Earnings before extraordinary items and cumulative
  effect of a change in accounting principle.................     146,330       166,065       152,367
                                                                =========     =========     =========
Net income...................................................   $ 146,330     $ 166,065      $152,367
                                                                =========     =========     =========

                                              December 31,
                                       ------------------------
     Balance Sheet                        2006           2005
---------------------                  ----------     ---------
Current assets......................   $   99,523     $ 107,975
Non-current assets..................    1,514,214       680,330
Current liabilities.................      213,610       182,549
Non-current liabilities.............    1,127,240       345,227
Partners'/owners' equity............   $  272,887     $ 260,529

Equity Investee Natural Gas Pipeline Expansion Filings

Rockies Express Pipeline-Currently Certificated Facilities

On August 9, 2005, the FERC approved the application of Rockies Express Pipeline LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles of pipeline facilities in two phases. For phase I (consisting of two segments), Rockies Express was granted authorization to construct and operate approximately 136 miles of pipeline extending northward from Rio Blanco County, Colorado to the Wamsutter Hub in Sweetwater County, Wyoming (segment 1), and then construct approximately 191 miles of pipeline eastward to the Cheyenne Hub in Weld County, Colorado (segment 2). Construction of segment 1 has been completed and went into interim service on February 24, 2006. Construction of segment 2 commenced in mid-summer 2006, and went into service on February 14, 2007. For Phase II, which will follow the construction of Segment 2, Rockies Express was authorized to construct three compressor stations referred to as the Meeker, Big Hole and Wamsutter compressor stations.

Rockies Express Pipeline-West Project

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 that went into service in February 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 from Questar Overthrust Pipeline Company, which will extend the Rockies Express system 140 miles west from Wamsutter to the Opal Hub in Wyoming. We expect the FERC will complete its environmental review and issue its certificate by the end of March 2007, and the project is expected to begin service in January 2008.

Rockies Express Pipeline-East Project

On June 13, 2006, the FERC agreed with Rockies Express' participation in the pre-filing process for development of the "Rockies Express-East Project." The Rockies Express-East Project will comprise approximately 635 miles of 42-inch diameter pipeline commencing from the terminus of the Rockies Express-West pipeline to a terminus near the town of Clarington in Monroe County, Ohio. The segment proposes to transport approximately 1.8 billion cubic feet per day of natural gas. On August 13, 2006, the FERC issued its notice of intent to prepare an environmental impact statement for the proposed project and hosted nine scoping meetings from September 11 through September 15, 2006 in various locations along the route. During this pre-filing process, Rockies Express has encountered opposition from certain landowners in the states of Indiana and Ohio. Rockies Express is actively participating in community outreach meetings with landowners and agencies located in these states to resolve any differences they may have with the project. Rockies Express is confident that a mutual agreement and/or understanding will be reached with these parties, and that the project is on track for a certificate application to be filed in April 2007. The application will request that a FERC order be issued by February 1, 2008 in order to meet both a December 31, 2008 project in-service date for the proposed pipeline and partial compression and a June 30, 2009 in-service date for the remaining compression.

8. Intangibles

Our intangible assets include goodwill, lease value, contracts, customer relationships and agreements.

Goodwill and Excess Investment Cost

As an investor, the price we pay to acquire an ownership interest in an investee will most likely differ from the underlying interest in book value, with book value representing the investee's net assets per its financial statements. This differential relates to both discrepancies between the investee's recognized net assets at book value and at current fair values and to any premium we pay to acquire the investment. Under ABP No. 18, any such premium paid by an investor, which is analogous to goodwill, must be identified.

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. Following is information related to our goodwill as of December 31, 2006 and 2005 (in thousands):

                                 December 30,    December 31,
                                 ------------    ------------
                                     2006            2005
                                  ----------      ----------
Goodwill
  Gross carrying amount........   $ 843,112       $ 813,101
  Accumulated amortization.....     (14,142)        (14,142)
                                  ----------      ----------
  Net carrying amount..........     828,970         798,959
                                  ==========      ==========

Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires goodwill to be assigned to an appropriate reporting unit and to determine if the implied fair value of the reporting unit's goodwill is less than its carrying amount. Changes in the carrying amount of our goodwill for each of the two years ended December 31, 2005 and 2006 are summarized as follows (in thousands):

                                                Products     Natural Gas
                                                Pipelines     Pipelines        CO2        Terminals       Total
                                                ---------    -----------    ---------     ---------     ---------
Balance as of December 31, 2004.............    $ 263,182    $  250,318     $  46,101     $ 173,237     $ 732,838
  Acquisitions and purchase price adjs......            -        38,117             -        28,004        66,121
  Disposals.................................            -             -             -             -             -
  Impairments...............................            -             -             -             -             -
                                                ---------    ----------     ---------     ---------     ---------
Balance as of December 31, 2005.............    $ 263,182    $  288,435     $  46,101     $ 201,241     $ 798,959
  Acquisitions and purchase price adjs......            -             -             -        30,011        30,011
  Disposals.................................            -             -             -             -             -
  Impairments...............................            -             -             -             -             -
Balance as of December 31, 2006.............    $ 263,182    $  288,435     $  46,101     $ 231,252     $ 828,970
                                                =========    ==========     =========     =========     =========

For our investments in entities that are not fully consolidated but instead are included in our financial statements under the equity method of accounting, the premium we pay that represents excess cost over underlying fair value of net assets is referred to as equity method goodwill, and under SFAS No. 142, this excess cost is not subject to amortization but rather to impairment testing pursuant to APB No. 18. The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. 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 well as the amortization period for such 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. As of both December 31, 2006 and 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 $177.1 million as of December 31, 2006 and $181.7 million as of December 31, 2005.

Other Intangibles

Excluding goodwill, our other intangible assets include lease value, contracts, customer relationships, technology-based assets 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):

                                             December 31,
                                       ------------------------
                                          2006          2005
                                       ----------    ----------
Lease value
  Gross carrying amount.............   $   6,592     $   6,592
  Accumulated amortization..........      (1,309)       (1,168)
                                       ---------     ---------
  Net carrying amount...............       5,283         5,424
                                       ---------     ---------

Contracts and other
  Gross carrying amount.............     231,097       221,250
  Accumulated amortization..........     (23,172)       (9,654)
                                       ---------     ---------
  Net carrying amount...............     207,925       211,596
                                       ---------     ---------

Total Other intangibles, net........   $ 213,208     $ 217,020
                                       =========     =========

Amortization expense on our intangibles consisted of the following (in thousands):

                                          Year Ended December 31,
                                     -------------------------------
                                       2006        2005       2004
                                     --------    --------   --------
Lease value......................    $    141    $   140    $    140
Contracts and other..............      13,518      8,599         752
                                     --------    -------    --------
Total amortization...............    $ 13,659    $ 8,739    $    892
                                     ========    =======    ========

As of December 31, 2006, our weighted average amortization period for our intangible assets was approximately 18.76 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $13.6 million, $13.6 million, $12.4 million, $12.2 million and $12.1 million, respectively.

9. Debt

Short-Term Debt

Our outstanding short-term debt as of December 31, 2006 was $1,359.1 million. The balance consisted of:

o $1,098.2 million of commercial paper borrowings;

o $250.0 million in principal amount of 5.35% senior notes due August 15, 2007;

o a $5.9 million portion of 5.23% senior notes (our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes); and

o a $5.0 million portion of 7.84% senior notes (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes).

Our outstanding short-term debt as of December 31, 2005 was $575.6 million, which primarily consisted of $566.2 million in outstanding commercial paper borrowings; however, we intended and had the ability to refinance all of our short-term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, this debt balance was classified as long-term debt in our accompanying consolidated balance sheet. As of December 31, 2006 we did not intend to refinance all of our short-term debt on a long-term basis under our unsecured long-term credit facility. The weighted average interest rate on all of our borrowings was approximately 6.1779% during 2006 and 5.3019% during 2005.

Long-Term Debt

Our outstanding long-term debt, excluding market value of interest rate swaps, as of December 31, 2006 and 2005 was $4,384.3 million and $5,220.9 million, respectively. The balances consisted of the following (in thousands):

                                                                                                           December 31,
                                                                                                   ---------------------------
                                                                                                       2006            2005
                                                                                                   ------------    ------------
Kinder Morgan Energy Partners, L.P. borrowings:
    5.35% senior notes due August 15,  2007.....................................................   $   250,000     $   250,000
    6.30% senior notes due February 1, 2009.....................................................       250,000         250,000
    7.50% senior notes due November 1, 2010.....................................................       250,000         250,000
    6.75% senior notes due March 15, 2011.......................................................       700,000         700,000
    7.125% senior notes due March 15, 2012......................................................       450,000         450,000
    5.00% senior notes due December 15, 2013....................................................       500,000         500,000
    5.125% senior notes due November 15, 2014...................................................       500,000         500,000
    7.400% senior notes due March 15, 2031......................................................       300,000         300,000
    7.75% senior notes due March 15, 2032.......................................................       300,000         300,000
    7.30% senior notes due August 15, 2033......................................................       500,000         500,000
    5.80% senior notes due March 15, 2035.......................................................       500,000         500,000
    Commercial paper borrowings.................................................................     1,098,192         566,200
Subsidiary borrowings:
    Central Florida Pipe Line LLC-7.840% senior notes due July 23, 2008.........................        10,000          15,000
    Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010.......................         5,325           5,325
    Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014..................        49,102          54,683
    Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due Jan. 15, 2018........        25,000          25,000
    Kinder Morgan Operating L.P. "B"-Jackson-Union Cos. IL Revenue Bonds due April 1, 2024......        23,700          23,700
    International Marine Terminals-Plaquemines, LA Revenue Bonds due March 15, 2025.............        40,000          40,000
    Other miscellaneous subsidiary debt.........................................................         1,349           1,447
Unamortized debt discount on senior notes.......................................................         (9,26)         (10,46)
Current portion of long-term debt...............................................................     (1,359,06)             --
                                                                                                   ------------    ------------
Total Long-term debt............................................................................   $ 4,384,332     $ 5,220,887
                                                                                                   ============    ============

Credit Facilities

On August 5, 2005, we increased our existing five-year unsecured bank credit facility from $1.25 billion to $1.6 billion, and we extended the maturity one year to August 18, 2010. The borrowing rates decreased slightly under the extended agreement, and there were minor changes to the financial covenants as compared to the covenants under our previous bank facility.

On February 22, 2006, we entered into a second unsecured credit facility, in the amount of $250 million, expiring on November 21, 2006. This facility contained borrowing rates and restrictive financial covenants that were similar to the borrowing rates and covenants under our $1.6 billion bank facility.

Effective August 28, 2006, we terminated our $250 million unsecured nine-month bank credit facility and we increased our existing five-year bank credit facility from $1.6 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, 2006 or as of December 31, 2005.

Similar to our previous bank credit facilities, our current 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 December 31, 2006 was reduced by:

o our outstanding commercial paper borrowings ($1,098.2 million as of December 31, 2006);

o a combined $243 million in three 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 $48 million in two letters of credit that support tax-exempt bonds;

o a combined $39.7 million in two letters of credit that support the construction of our Kinder Morgan Louisiana Pipeline (a natural gas pipeline);

o a $37.5 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and

o a combined $16.5 million in other letters of credit supporting other obligations of us and our subsidiaries.

Our five-year credit facility permits us to obtain bids for fixed rate loans from members of the lending syndicate. Interest on our credit facility accrues at our option at a floating rate equal to either:

o the administrative agent's base rate (but not less than the Federal Funds Rate, plus 0.5%); or

o LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.

Our credit facility included the following restrictive covenants as of December 31, 2006:

o total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed:

o 5.5, in the case of any such period ended on the last day of (i) a fiscal quarter in which we make any Specified Acquisition, or
(ii) the first or second fiscal quarter next succeeding such a fiscal quarter; or

o 5.0, in the case of any such period ended on the last day of any other fiscal quarter;

o certain limitations on entering into mergers, consolidations and sales of assets;

o limitations on granting liens; and

o prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.

In addition to normal repayment covenants, under the terms of our credit facility, the occurrence at any time of any of the following would constitute an event of default:

o our failure to make required payments of any item of indebtedness or any payment in respect of any hedging agreement, provided that the aggregate outstanding principal amount for all such indebtedness or payment obligations in respect of all hedging agreements is equal to or exceeds $75 million;

o our general partner's failure to make required payments of any item of indebtedness, provided that the aggregate outstanding principal amount for all such indebtedness is equal to or exceeds $75 million;

o adverse judgments rendered against us for the payment of money in an aggregate amount in excess of $75 million, if this same amount remains undischarged for a period of thirty consecutive days during which execution shall not be effectively stayed; and

o voluntary or involuntary commencements of any proceedings or petitions seeking our liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law.

Excluding the relatively non-restrictive specified negative covenants and events of defaults, our credit facility does not contain any provisions designed to protect against a situation where a party to an agreement is unable to find a basis to terminate that agreement while its counterparty's impending financial collapse is revealed and perhaps hastened through the default structure of some other agreement. The credit facility does not contain a material adverse change clause coupled with a lockbox provision; however, the facility does provide that the margin we will pay with respect to borrowings and the facility fee that we will pay on the total commitment will vary based

on our senior debt investment rating. None of our debt is subject to payment acceleration as a result of any change to our credit ratings.

Interest Rate Swaps

Information on our interest rate swaps is contained in Note 14.

Commercial Paper Program

On August 5, 2005, we increased our commercial paper program by $350 million to provide for the issuance of up to $1.6 billion. In April 2006, we increased our commercial paper program by $250 million to provide for the issuance of up to $1.85 billion. Our $1.85 billion unsecured five-year bank credit facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. As of December 31, 2006, we had $1,098.2 million of commercial paper outstanding with an average interest rate of 5.4164%. The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during 2006 and 2005.

Senior Notes

On March 15, 2005, we paid $200 million to retire the principal amount of our 8.0% senior notes that matured on that date. Also on March 15, 2005, we closed a public offering of $500 million in principal amount of 5.80% senior notes due March 15, 2035 at a price to the public of 99.746% per note. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $494.4 million. We used the proceeds remaining after the repayment of the 8.0% senior notes to reduce the outstanding balance on our commercial paper borrowings.

As of December 31, 2006, the outstanding principal balance on the various series of our senior notes (excluding unamortized debt discount) was $4,490.7 million. For a listing of the various outstanding series of our senior notes, see the table above included in "--Long-term Debt."

On January 30, 2007, we completed a public offering of senior notes. We issued a total of $1.0 billion in principal amount of senior notes, consisting of $600 million of 6.00% notes due February 1, 2017, and $400 million of 6.50% notes due February 1, 2037. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $992.8 million, and we used the proceeds to reduce the borrowings under our commercial paper program.

Subsidiary Debt

Central Florida Pipeline LLC Debt

Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As part of our purchase price, we assumed an aggregate principal amount of $40 million of senior notes originally issued to a syndicate of eight insurance companies. The senior notes have a fixed annual interest rate of 7.84% with repayments in annual installments of $5 million beginning July 23, 2001. The final payment is due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of each year. In both July 2006 and July 2005, we made an annual repayment of $5.0 million and as of December 31, 2006, Central Florida's outstanding balance under the senior notes was $10.0 million.

Arrow Terminals L.P.

Effective October 6, 2004, we acquired Global Materials Services LLC and its consolidated subsidiaries (see Note 3). We renamed Global Materials Services LLC as Kinder Morgan River Terminals LLC, and as part of our purchase price, we assumed debt of $33.7 million, consisting of third-party notes payables, current and non-current bank borrowings, and long-term bonds payable. In October 2004, we paid $28.4 million of the assumed debt and following these repayments, the only remaining outstanding debt was a $5.3 million principal amount of Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois Development Finance Authority. Our subsidiary, Arrow Terminals L.P., is the obligor on these bonds. The bonds have a maturity date of January 1, 2010, and

interest on these bonds is paid and computed quarterly at the Bond Market Association Municipal Swap Index. The bonds are collateralized by a first mortgage on assets of Arrow's Chicago operations and a third mortgage on assets of Arrow's Pennsylvania operations. As of December 31, 2006, the interest rate was 4.089%. The bonds are also backed by a $5.4 million letter of credit issued by JP Morgan Chase that backs-up the $5.3 million principal amount of the bonds and $0.1 million of interest on the bonds for up to 45 days computed at 12% per annum on the principal amount thereof.

Kinder Morgan Texas Pipeline, L.P. Debt

Effective August 1, 2005, we acquired a natural gas storage facility in Liberty County, Texas (see Note 3). As part of our purchase price, we assumed debt having a fair value of $56.5 million. We valued the debt equal to the present value of amounts to be paid determined using an approximate interest rate of 5.23%. The debt consisted of privately placed unsecured senior notes with a fixed annual stated interest rate as of August 1, 2005, of 8.85%. The assumed principal amount, along with interest, is due in monthly installments of approximately $0.7 million. The final payment is due January 2, 2014. Our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes, and as of December 31, 2006, KMTP's outstanding balance under the senior notes was $49.1 million.

Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million at a price equal to the higher of par value or the present value of the remaining scheduled payments of principal and interest on the portion being prepaid. The notes also contain certain covenants similar to those contained in our current five-year, unsecured revolving credit facility. We do not believe that these covenants will materially affect distributions to our partners.

Kinder Morgan Liquids Terminals LLC Debt

Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC. As part of our purchase price, we assumed debt of $87.9 million, consisting of five series of tax-exempt industrial revenue bonds. Kinder Morgan Liquids Terminals LLC was the obligor on the bonds, which consisted of the following:

o $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September 1, 2019;

o $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1, 2022;

o $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September 1, 2022;

o $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1, 2023; and

o $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1, 2024.

In May 2004, we exercised our right to call and retire all of the industrial revenue bonds (other than the $3.6 million of 6.625% bonds due February 1, 2024) prior to maturity at a redemption price of $84.3 million, plus approximately $1.9 million for interest, prepayment premiums and redemption fees. In October 2004, we exercised our right to call and retire the remaining $3.6 million of bonds due February 1, 2024 prior to maturity at a redemption price of $3.6 million, plus approximately $0.1 million for interest, prepayment premiums and redemption fees. For both of these redemptions and retirements, we borrowed the necessary funds under our commercial paper program. Pursuant to Accounting Principles Board Opinion No. 26, "Early Extinguishment of Debt," we recognized the $1.6 million excess of our reacquisition price over both the carrying value of the bonds and unamortized debt issuance costs as a loss on bond repurchases and we included this amount under the caption "Other, net" in our accompanying consolidated statement of income.

In November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. As part of our purchase price, we assumed $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. These bonds have a maturity date of January 15, 2018. Interest on these bonds is computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of twelve 30-day months during a Term Rate Period. As

of December 31, 2006, the interest rate was 3.87%. We have an outstanding letter of credit issued by Citibank in the amount of $25.3 million that backs-up the $25.0 million principal amount of the bonds and $0.3 million of interest on the bonds for up to 42 days computed at 12% on a per annum basis on the principal thereof.

Kinder Morgan Operating L.P. "B" Debt

This $23.7 million principal amount of tax-exempt bonds due April 1, 2024 was issued by the Jackson-Union Counties Regional Port District. These bonds bear interest at a weekly floating market rate. As of December 31, 2006, the interest rate on these bonds was 3.90%. Also, as of December 31, 2006, we had an outstanding letter of credit issued by Wachovia in the amount of $24.1 million that backs-up the $23.7 million principal amount of the bonds and $0.4 million of interest on the bonds for up to 55 days computed at 12% per annum on the principal amount thereof.

International Marine Terminals Debt

Since February 1, 2002, we have owned a 66 2/3% interest in International Marine Terminals partnership. The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. As of December 31, 2006, the interest rate on these bonds was 3.50%.

On March 15, 2005, these bonds were refunded and the maturity date was extended from March 15, 2006 to March 15, 2025. No other changes were made under the bond provisions. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, we agreed to guarantee the obligations of IMT in proportion to our ownership interest. Our obligation is approximately $30.3 million for principal, plus interest and other fees.

General Stevedores, L.P. Debt

Effective July 31, 2005, we acquired all of the partnership interests in General Stevedores, L.P. (see Note 3). As part of our purchase price, we assumed approximately $3.0 million in principal amount of outstanding debt, primarily consisting of commercial bank loans. In August 2005, we paid the $3.0 million outstanding debt balance, and following our repayment, General Stevedores, L.P. had no outstanding debt.

2007..........   $1,359,069
2008..........       11,215
2009..........      256,377
2010..........      261,618
2011..........      706,410
Thereafter....    3,148,712
                 ----------
Total.........   $5,743,401
                 ==========

Contingent Debt

We apply the disclosure 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 ExxonMobil Corporation - 37% partner; and Cortez Vickers Pipeline Company - 13% partner) are required, on a several, percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The Throughput and Deficiency Agreement contractually supports the borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including cash deficiencies relating to the repayment of principal and interest on borrowings by Cortez Capital Corporation. Parent companies of the respective Cortez Pipeline Company partners further severally guarantee, on a percentage basis, the obligations of the Cortez Pipeline Company partners under the Throughput and Deficiency Agreement.

As of December 31, 2006, the debt facilities of Cortez Capital Corporation consisted of:

o $75 million of Series D notes due May 15, 2013;

o a $125 million short-term commercial paper program; and

o a $125 million five-year committed revolving credit facility due December 22, 2009 (to support the above-mentioned $125 million commercial paper program).

As of December 31, 2006, Cortez Capital Corporation had $73.9 million of commercial paper outstanding with an average interest rate of 5.3846%, the average interest rate on the Series D notes was 7.14%, and there were no borrowings under the credit facility.

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 was released of its guaranty obligations on December 31, 2006; with respect to Cortez's Series D notes, in December 2006, we entered into a letter of credit issued by JP Morgan Chase in the amount of $37.5 million to secure our indemnification obligations to Shell for 50% of the $75 million in principal amount of Series D notes outstanding as of December 31, 2006; and with respect to Cortez's short-term commercial paper borrowings, in January 2007, we entered into an additional letter of credit issued by JP Morgan Chase in the amount of $37.5 million to secure our indemnification obligations to Shell for 50% of the outstanding commercial paper borrowings as of December 31, 2006.

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 December 31, 2006, $31.4 million in principal amount of notes were outstanding.

In the first quarter of 2007, Red Cedar plans to refinance the outstanding balance of its existing Senior Notes through a private placement of $100 million in principal amount of ten year fixed rate notes. Bids for the new notes were due February 15, 2007, and the placement is expected to close on March 15, 2007.

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 December 31, 2006, this letter of credit had an outstanding balance under our credit facility of $23.9 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 in Note 9.

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 December 31, 2006, Rockies Express Pipeline LLC had $790.1 million of commercial paper outstanding, and there were no borrowings under its five-year credit facility. Accordingly, as of December 31, 2006, our contingent share of Rockies Express' debt was $403.0 million (51% of total commercial paper borrowings).

                 December 31, 2006            December 31, 2005
             -------------------------    -------------------------
              Carrying      Estimated       Carrying      Estimated
                Value      Fair Value         Value      Fair Value
             ----------    ----------      ----------    ----------
                                 (In thousands)
Total Debt   $5,743,401    $5,864,966      $5,220,887    $5,465,215

10. 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.

Our net periodic benefit cost for the SFPP post-retirement benefit plan were credits of $0.3 million in 2006, $0.3 million in 2005, and $0.6 million in 2004. The credits resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost, primarily related to the following:

o there have been changes to the plan for both 2004 and 2005 which reduced liabilities, creating a negative prior service cost that is being amortized each year; and

o there was a significant drop in 2004 in the number of retired participants reported as pipeline retirees by Burlington Northern Santa Fe, which holds a 0.5% special limited partner interest in SFPP, L.P.

As of December 31, 2006, we estimate our overall net periodic post-retirement benefit cost for the year 2007 will be a credit of approximately $0.3 million, including amortization of approximately $0.5 million of combined prior service credits and actuarial gains from accumulated other comprehensive income. This amount could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. In addition, we expect to contribute approximately $0.4 million to our post-retirement benefit plans in 2007.

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)." One of the provisions of this Statement requires an employer with publicly traded equity securities to recognize the overfunded or underfunded status of a defined benefit pension plan or post-retirement benefit plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. Following adoption of SFAS No. 158, entities will report as part of the net benefit liability on their balance sheets amounts that have not yet been recognized as a component of benefit expense (for example, unrecognized prior service costs or credits, net (actuarial) gain or loss, and transition obligation or asset) with a corresponding adjustment to accumulated other comprehensive income.

We adopted this provision on December 31, 2006, and the primary impact on us from adopting SFAS No. 158 was to require us to fully recognize, in our consolidated balance sheet, both the funded status of the SFPP post-retirement benefit plan obligation and previously unrecognized prior service credits and actuarial gains. Both the funded status and the recorded value of our benefit obligation for the SFPP post-retirement benefit plan as of December 31, 2006 was $5.5 million. The following table discloses the incremental effect on our consolidated balance sheet of applying SFAS No. 158 on December 31, 2006 (in thousands):

                                                  Before                          After
                                               Application     Adjustments     Application
                                               -----------     -----------     -----------
Prepaid benefit cost........................    $      -        $      -        $      -
Accrued benefit liability...................      10,967          (5,510)          5,457
Intangible asset............................           -               -               -
Minority interest...........................           -              28              28
Accumulated other comprehensive income......           -           5,482           5,482

Multiemployer Plans

As a result of acquiring several terminal operations, primarily our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents' health care costs. Amounts charged to expense for these plans were $6.3 million for each of the years ended December 31, 2006 and 2005.

Kinder Morgan Savings Plan

The Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The plan permits all full-time employees of Kinder Morgan, Inc. and KMGP Services Company, Inc. to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of

base compensation per year for most plan participants, our general partner may make special discretionary contributions. Certain employees' contributions are based on collective bargaining agreements. The mandatory contributions are made each pay period on behalf of each eligible employee. All employer contributions, including discretionary contributions, are in the form of KMI stock that is immediately convertible into other available investment vehicles at the employee's discretion. Participants may direct the investment of their contributions into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement.

For employees hired on or prior to December 31, 2004, all contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Employer contributions for employees hired on or after January 1, 2005 will vest on the second anniversary of the date of hire. Effective October 1, 2005, for new employees of our Terminals segment, a tiered employer contribution schedule was implemented. This tiered schedule provides for employer contributions of 1% for service less than one year, 2% for service between one and two years, 3% for services between two and five years, and 4% for service of five years or more. All employer contributions for Terminal employees hired after October 1, 2005 will vest on the fifth anniversary of the date of hire. The total amount charged to expense for our Savings Plan was $10.2 million during 2006 and $7.9 million during 2005. All employee contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Participants may direct the investment of their contributions into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement.

At its July 2006 meeting, the compensation committee of the KMI board of directors approved a special contribution of an additional 1% of base pay into the Savings Plan for each eligible employee. Each eligible employee will receive an additional 1% company contribution based on eligible base pay each pay period beginning with the first pay period of August 2006 and continuing through the last pay period of July 2007. The additional 1% contribution is in the form of KMI common stock (the same as the current 4% contribution) and does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive. It may be converted to any other Savings Plan investment fund at any time and it will vest according to the same vesting schedule described in the preceding paragraph. Since this additional 1% company contribution is discretionary, compensation committee approval will be required annually for each additional contribution. During the first quarter of 2007, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2006.

Additionally, in 2006, an option to make after-tax "Roth" contributions (Roth 401(k) option) to a separate participant account was added to the Savings Plan as an additional benefit to all participants. Unlike traditional 401(k) plans, where participant contributions are made with pre-tax dollars, earnings grow tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k) contributions are made with after-tax dollars, earnings are tax-free, and the withdrawals are tax-free if they occur after both (i) the fifth year of participation in the Roth 401(k) option, and (ii) attainment of age 59 1/2, death or disability. The employer contribution will still be considered taxable income at the time of withdrawal.

Cash Balance Retirement Plan

Employees of KMGP Services Company, Inc. and KMI are also eligible to participate in a Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, "grandfathered" according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees accrue benefits through a personal retirement account in the Cash Balance Retirement Plan. Under the plan, we make contributions on behalf of participating employees equal to 3% of eligible compensation every pay period. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement.

11. Partners' Capital

As of December 31, 2006 and 2005, our partners' capital consisted of the following limited partner units:

                                   December 31,       December 31,
                                       2006               2005
                                   -----------        ------------
Common units..................     162,816,303         157,005,326
Class B units.................       5,313,400           5,313,400
i-units.......................      62,301,676          57,918,373
                                    ----------          ----------
  Total limited partner units.     230,431,379         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 December 31, 2006, our common unit total consisted of 148,460,568 units held by third parties, 12,631,735 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. As of December 31, 2005, our common unit total consisted of 142,649,591 units held by third parties, 12,631,735 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner.

On both December 31, 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 December 31, 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 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 1,160,520 i-units on November 14, 2006. These additional i-units distributed were based on the $0.81 per unit distributed to our common unitholders on that date. During the year ended December 31, 2006, KMR received distributions of 4,383,303 i-units. These additional i-units distributed were based on the $3.23 per unit distributed to our common unitholders during 2006.

Equity Issuances

On August 16, 2005, we issued, in a public offering, 5,000,000 of our common units at a price of $51.25 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 pursuant to this option, we issued the additional 750,000 common units on September 9, 2005 upon the underwriters' exercise of this option. After commissions and underwriting expenses, we received net proceeds of $283.6 million for the issuance of these 5,750,000 common units.

On November 8, 2005, we issued, in a public offering, 2,600,000 of our common units at a price of $51.75 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $130.1 million for the issuance of these common units.

In August 2006, we issued, in a public offering, 5,750,000 of our common units, including common units sold pursuant to the underwriters' over-allotment option, at a price of $44.80 per unit, less commissions and underwriting expenses. We received net proceeds of approximately $248.0 million for the issuance of these 5,750,000 common units.

We used the proceeds from each of these three issuances to reduce the borrowings under our commercial paper program.

Income Allocation and Declared Distributions

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. For the years ended December 31, 2006, 2005 and 2004, we declared distributions of $3.26, $3.13 and $2.87 per unit, respectively. Under the terms of our partnership agreement, our distributions to unitholders for 2006 required incentive distributions to our general partner in the amount of $528.4 million. According to the provisions of the KMI Annual Incentive Plan, in order for the executive officers of our general partner and KMR, and for the employees of KMGP Services Company, Inc. and KMI who operate our business to earn a non-equity cash incentive (bonus) for 2006, both we and KMI were required to meet pre-established financial performance targets. The target for us was $3.28 in cash distributions per common unit for 2006. Due to the fact that we did not meet our 2006 budget target, we had no obligation to fund our 2006 bonus plan; however, the board of directors of KMI determined that it was in KMI's long-term interest to fund a partial payout of our bonuses through a reduction in the general partner's incentive distribution.

Accordingly, our general partner, with the approval of the compensation committees and boards of KMI and KMR, waived $20.1 million of its 2006 incentive distribution for the fourth quarter of 2006. The waived amount approximates an amount equal to our actual bonus payout for 2006, which is approximately 75% of our budgeted full bonus payout for 2006 of $26.5 million. Including the effect of this waiver, our distributions to unitholders for 2006 resulted in payments of incentive distributions to our general partner in the amount of $508.3 million. The waiver of $20.1 million of incentive payment in the fourth quarter of 2006 reduced our general partner's equity earnings by $19.9 million.

Our total distributions to unitholders for 2005 and 2004 required incentive distributions to our general partner in the amount of $473.9 million and $390.7 million, respectively. The increased incentive distributions paid for 2006 over 2005 and 2005 over 2004 reflect the increase in amounts distributed per unit as well as the issuance of additional units. Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.

On January 17, 2007, we declared a cash distribution of $0.83 per unit for the quarterly period ended December 31, 2006. This distribution was paid on February 14, 2007, to unitholders of record as of January 31, 2007. Our common unitholders and Class B unitholders received cash. KMR, our sole i-unitholder, received a distribution in the form of additional i-units based on the $0.83 distribution per common unit. The number of i-units distributed was 1,054,082. For each outstanding i-unit that KMR held, a fraction of an i-unit (0.016919) was issued. The fraction was determined by dividing:

o $0.83, the cash amount distributed per common unit

by

o $49.057, the average of KMR's limited liability shares' closing market prices from January 12-26, 2007, 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.

This February 14, 2007 distribution included an incentive distribution to our general partner in the amount of $118.0 million--including the effect of the $20.1 million waiver, described above. Since this distribution was declared after the end of the quarter, no amount is shown in our December 31, 2006 balance sheet as a distribution payable.

12. Related Party Transactions

General and Administrative Expenses

KMGP Services Company, Inc., a subsidiary of our general partner, provides employees and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR, provides centralized payroll and employee benefits services to us, our operating partnerships and subsidiaries, Kinder Morgan G.P., Inc. and KMR (collectively, the "Group"). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse Kinder Morgan Services LLC for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of KMI, and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to our limited partnership agreement, we provide reimbursement for our share of these administrative costs and such reimbursements will be accounted for as described above. Additionally, we reimburse KMR with respect to costs incurred or allocated to KMR in accordance with our limited partnership agreement, the delegation of control agreement among our general partner, KMR, us and others, and KMR's limited liability company agreement.

The named executive officers of our general partner and KMR and other employees that provide management or services to both KMI and the Group are employed by KMI. Additionally, other KMI employees assist in the operation of our Natural Gas Pipeline assets. These KMI employees' expenses are allocated without a profit component between KMI and the appropriate members of the Group.

Partnership Interests and Distributions

Kinder Morgan G.P., Inc.

Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to our partnership agreements, our general partner's interests represent a 1% ownership interest in us, and a direct 1.0101% ownership interest in each of our five operating partnerships. Collectively, our general partner owns an effective 2% interest in our operating partnerships, excluding incentive distributions rights as follows:

o its 1.0101% direct general partner ownership interest (accounted for as minority interest in our consolidated financial statements); and

o its 0.9899% ownership interest indirectly owned via its 1% ownership interest in us.

As of December 31, 2006, our general partner owned 1,724,000 common units, representing approximately 0.75% of our outstanding limited partner units.

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.

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 declared incentive distributions for the years ended December 31, 2006, 2005 and 2004 were $508.3 million, $473.9 million and $390.7 million, respectively.

Kinder Morgan, Inc.

KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of our general partner. As of December 31, 2006, KMI directly owned 8,838,095 common units, indirectly owned 5,313,400 Class B units and 5,517,640 common units through its consolidated affiliates, including our general partner, and owned 10,305,553 KMR shares, representing an indirect ownership interest of 10,305,553 i-units. Together, these units

represented approximately 13.0% of our outstanding limited partner units. Including both its general and limited partner interests in us, at the 2006 distribution level, KMI received approximately 49% of all quarterly distributions from us, of which approximately 42% was attributable to its general partner interest and 7% was attributable to its limited partner interest. The actual level of distributions KMI will receive in the future will vary with the level of distributions to the limited partners determined in accordance with our partnership agreement.

Kinder Morgan Management, LLC

As of December 31, 2006, KMR, our general partner's delegate, remained the sole owner of our 62,301,676 i-units.

Asset Acquisitions and Sales

From time to time in the ordinary course of business, we buy and sell pipeline and related services from KMI and its subsidiaries. Such transactions are conducted in accordance with all applicable laws and regulations and on an arms' length basis consistent with our policies governing such transactions.

2004 Kinder Morgan, Inc. Asset Sales and Contributions

In June 2004, we bought two LM6000 gas-fired turbines and two boilers from a subsidiary of KMI for their estimated fair market value of $21.1 million, which we paid in cash. This equipment was a portion of the equipment that became surplus as a result of KMI's decision to exit the power development business and is currently employed in conjunction with our CO2 business segment.

Effective November 1, 2004, we acquired all of the partnership interests in TransColorado Gas Transmission Company from two wholly-owned subsidiaries of KMI. TransColorado Gas Transmission Company, a Colorado general partnership referred to in this report as TransColorado, owned assets valued at approximately $284.5 million. As consideration for TransColorado, we paid to KMI $211.2 million in cash and approximately $64.0 million in units, consisting of 1,400,000 common units. We also assumed liabilities of approximately $9.3 million. The purchase price for this transaction was determined by the boards of directors of KMR and our general partner, and KMI based on valuation parameters used in the acquisition of similar assets. The transaction was approved unanimously by the independent members of the boards of directors of both KMR and our general partner, and KMI, with the benefit of advice of independent legal and financial advisors, including the receipt of fairness opinions from separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley & Co. Also, in conjunction with our acquisition of TransColorado Gas Transmission Company, KMI became a guarantor of approximately $210.8 million of our debt.

In November 2004, Kinder Morgan Operating L.P. "A" sold a natural gas gathering system to Kinder Morgan, Inc.'s retail division for $75,000. The gathering system primarily consisted of approximately 23,000 feet of 6-inch diameter pipeline located in Campbell County, Wyoming that was no longer being used by Kinder Morgan Operating L.P. "A".

1999 and 2000 Kinder Morgan, Inc. Asset Contributions

In conjunction with our acquisition of Natural Gas Pipelines assets from KMI on December 31, 1999 and 2000, KMI became a guarantor of approximately $522.7 million of our debt. Thus, taking into consideration the guarantee of debt associated with our TransColorado acquisition discussed above, KMI was a guarantor of a total of approximately $733.5 million of our debt as of December 31, 2006. KMI would be obligated to perform under this guarantee only if we and/or our assets were unable to satisfy our obligations.

Operations

Natural Gas Pipelines Business Segment

KMI or its subsidiaries operate and maintain for us the assets comprising our Natural Gas Pipelines business segment. Natural Gas Pipeline Company of America, a subsidiary of KMI, operates Trailblazer Pipeline Company's

assets under a long-term contract pursuant to which Trailblazer Pipeline Company incurs the costs and expenses related to NGPL's operating and maintaining the assets. Trailblazer Pipeline Company provides the funds for its own capital expenditures. NGPL does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company's assets.

The remaining assets comprising our Natural Gas Pipelines business segment as well as our North System and Cypress Pipeline, which are part of our Products Pipelines business segment, are operated under other agreements between KMI and us. Pursuant to the applicable underlying agreements, we pay KMI either a fixed amount or actual costs incurred as reimbursement for the corporate general and administrative expenses incurred in connection with the operation of these assets. The amounts paid to KMI for corporate general and administrative costs, including amounts related to Trailblazer Pipeline Company, were $1.0 million of fixed costs and $37.9 million of actual costs incurred for 2006, $5.5 million of fixed costs and $24.2 million of actual costs incurred for 2005, and $8.8 million of fixed costs and $13.1 million of actual costs incurred for 2004.

We believe the amounts paid to KMI for the services they provided each year fairly reflect the value of the services performed. However, due to the nature of the allocations, these reimbursements may not exactly match the actual time and overhead spent. We believe the fixed amounts that were agreed upon at the time the contracts were entered into were reasonable estimates of the corporate general and administrative expenses to be incurred by KMI and its subsidiaries in performing such services. We also reimburse KMI and its subsidiaries for operating and maintenance costs and capital expenditures incurred with respect to our assets.

CO2 Business Segment

KMI or its subsidiaries operate and maintain for us the power plant we constructed at the SACROC oil field unit, located in the Permian Basin area of West Texas. Kinder Morgan Production Company, a subsidiary of one of our operating limited partnerships, completed construction of the power plant in June 2005 at an approximate cost of $76 million. The power plant provides approximately half of SACROC's current electricity needs.

Kinder Morgan Power Company, a subsidiary of KMI, operates and maintains the power plant under a five-year contract expiring in June 2010. Pursuant to the contract, KMI incurs the costs and expenses related to operating and maintaining the power plant for the production of electrical energy at the SACROC field. Such costs include supervisory personnel and qualified operating and maintenance personnel in sufficient numbers to accomplish the services provided in accordance with good engineering, operating and maintenance practices. Kinder Morgan Production Company fully reimburses KMI's expenses, including all agreed-upon labor costs, and also pays to KMI an operating fee of $20,000 per month.

In addition, Kinder Morgan Production Company is responsible for processing and directly paying invoices for fuels utilized by the plant. Other materials, including but not limited to lubrication oil, hydraulic oils, chemicals, ammonia and any catalyst are purchased by KMI and invoiced monthly as provided by the contract, if not paid directly by Kinder Morgan Production Company. The amounts paid to KMI in 2006 and 2005 for operating and maintaining the power plant was $2.9 million and $0.8 million, respectively. We estimate the total reimbursement to be paid to KMI for operating and maintaining the plant for 2007 will be approximately $3.3 million. Furthermore, we believe the amounts paid to KMI for the services they provide each year fairly reflect the value of the services performed.

Risk Management

Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil. We 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 protect our profit margins.

Our risk management policies prohibit us from engaging in speculative trading. Our commodity-related risk management activities are monitored by our risk management committee, which is a separately designated standing committee whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. Our risk management committee is charged with the review and enforcement of

our management's risk management policy. The committee is comprised of 19 executive-level employees of KMI or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. The committee is chaired by our President and is charged with the following three responsibilities:

o establish and review risk limits consistent with our risk tolerance philosophy;

o recommend to the audit committee of our general partner's delegate any changes, modifications, or amendments to our risk management policy; and

o address and resolve any other high-level risk management issues.

For more information on our risk management activities see Note 14.

KM Insurance, Ltd.

KM Insurance, Ltd., referred to as KMIL, is a Bermuda insurance company and wholly-owned subsidiary of KMI. KMIL was formed during the second quarter of 2005 as a Class 2 Bermuda insurance company, the sole business of which is to issue policies for KMI and us to secure the deductible portion of our workers compensation, automobile liability, and general liability policies placed in the commercial insurance market. We accrue for the cost of insurance, which is included in the related party general and administrative expenses and which totaled approximately $5.8 million in 2006.

Notes Receivable

Plantation Pipe Line Company

We own a 51.17% equity interest in Plantation Pipe Line Company. An affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004, Plantation repaid a $10 million note outstanding and $175 million in outstanding commercial paper borrowings with funds of $190 million borrowed from its owners. We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership interest, in exchange for a seven year note receivable bearing interest at the rate of 4.72% per annum. The note provides for semiannual payments of principal and interest on December 31 and June 30 each year beginning on December 31, 2004 based on a 25 year amortization schedule, with a final principal payment of $157.9 million due July 20, 2011. We funded our loan of $97.2 million with borrowings under our commercial paper program. An affiliate of ExxonMobil owns the remaining 48.83% equity interest in Plantation and funded the remaining $92.8 million on similar terms.

In 2005, Plantation paid to us $2.1 million in principal amount under the note, and 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 consolidated balance sheet as of December 31, 2005, and we included the remaining $92.0 million balance within "Notes receivable-Related parties."

In 2006, Plantation paid to us $1.1 million in principal amount under the note, and as of December 31, 2006, the principal amount receivable from this note was $93.1 million. We included $3.4 million of this balance within "Accounts, notes and interest receivable, net-Related parties" on our consolidated balance sheet as of December 31, 2006, and we included the remaining $89.7 million balance within "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 transfer Coyote Gulch's notes payable to members' equity. Accordingly, we 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 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.

Accordingly, on September 1, 2006, 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 December 31, 2006.

Red Cedar Gathering Company

As described above in "--Coyote Gas Treating, LLC," we own a 49% equity interest in the Red Cedar Gathering Company and the Southern Ute Indian Tribe owns the remaining 51% equity interest. On December 22, 2004, we entered into a $10 million unsecured revolving credit facility due July 1, 2005, with the Southern Ute Indian Tribe and us, as lenders, and Red Cedar, as borrower. Subject to the terms of the agreement, the lenders agreed to make advances to Red Cedar up to a maximum outstanding principal amount of $10 million. On April 1, 2005, the maximum outstanding principal amount was automatically reduced to $5 million.

In January 2005, Red Cedar borrowed funds of $4 million from its owners pursuant to this credit agreement, and we loaned Red Cedar approximately $2.0 million, which corresponded to our 49% ownership interest. The interest on all advances made under this credit facility were calculated as simple interest on the combined outstanding balance of the credit agreement at 6% per annum based upon a 360 day year. In March 2005, Red Cedar paid the $4 million outstanding balance under this revolving credit facility, and the facility expired on July 1, 2005.

Other

Generally, KMR makes all decisions relating to the management and control of our business. Our general partner owns all of KMR's voting securities and is its sole managing member. KMI, through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our general partner. Certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us. The directors and officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the shareholders of KMI. In general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders. The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders, as well as provisions that

may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.

The partnership agreements provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties. The duty of the directors and officers of KMI to the shareholders of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders. The audit committee of KMR's board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand.

13. Leases and Commitments

Capital Leases

We acquired certain leases classified as capital leases as part of our acquisition of Kinder Morgan River Terminals LLC in October 2004. We lease our Memphis, Tennessee port facility under an agreement accounted for as a capital lease. The lease is for 24 years and expires in 2017. Additionally, we have two equipment leases accounted for as capital leases and each of these leases expire in 2007.

Amortization of assets recorded under capital leases is included with depreciation expense. The components of property, plant and equipment recorded under capital leases are as follows (in thousands):

                                    December 31,
                                        2006
                                    ------------
Leasehold improvements...........    $   4,089
Machinery and equipment..........           25
                                     ---------
                                         4,114
Less: Accumulated amortization...       (2,997)
                                     ---------
                                     $   1,117

Future commitments under capital lease obligations as of December 31, 2006 are as follows (in thousands):

  Year                                         Commitment
  ----                                         ----------
  2007.......................................  $      173
  2008.......................................         168
  2009.......................................         168
  2010.......................................         168
  2011.......................................         168
  Thereafter.................................         991
                                               ----------
Subtotal.....................................       1,836
  Less: Amount representing interest.........        (720)
                                               ----------
Present value of minimum capital lease
  payments...................................  $    1,116
                                               ==========

  Year                        Commitment
  ----                        ----------
  2007....................    $   47,709
  2008....................        30,050
  2009....................        20,192
  2010....................        16,877
  2011....................        13,126
  Thereafter..............        27,878
                              ----------
Total minimum payments....    $  155,832
                              ==========

The largest of these lease commitments, in terms of total obligations payable by December 31, 2008, include commitments supporting:

o crude oil drilling rig operations for the oil and gas activities of our CO2 business segment;

o natural gas liquids pipeline capacity and storage for our North System natural gas liquids pipeline;

o marine port terminal operations at our Nassau bulk product terminal, located in Fernandina Beach, Florida; and

o natural gas storage in underground salt dome caverns for our Texas intrastate natural gas pipeline group.

We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $6.2 million. Total lease and rental expenses were $54.1 million for 2006, $47.3 million for 2005 and $39.3 million for 2004.

Common Unit Option Plan

During 1998, we established a common unit option plan, which provides that key personnel of KMGP Services Company, Inc. and KMI are eligible to receive grants of options to acquire common units. The number of common units authorized under the option plan is 500,000. The option plan terminates in March 2008. The options granted generally have a term of seven years, vest 40% on the first anniversary of the date of grant and 20% on each of the next three anniversaries, and have exercise prices equal to the market price of the common units at the grant date.

During 2005, 90,100 options to purchase common units were exercised at an average price of $17.63 per unit. The common units underlying these options had an average fair market value of $47.56 per unit. As of December 31, 2005, outstanding options to purchase 15,300 common units were held by employees of KMI or KMGP Services Company, Inc. at an average exercise price of $17.82 per unit. Outstanding options to purchase 10,000 common units were held by one of Kinder Morgan G.P., Inc.'s three non-employee directors at an average exercise price of $21.44 per unit. As of December 31, 2005, all 25,300 outstanding options were fully vested.

During 2006, 4,200 options to purchase common units were cancelled or forfeited, and 21,100 options to purchase common units were exercised at an average price of $19.67 per unit. The common units underlying these options had an average fair market value of $46.43 per unit. As of December 31, 2006, there were no outstanding options.

We account for common unit options granted under our common unit option plan according to the provisions of SFAS No. 123R (revised 2004), "Share-Based Payment," which became effective for us January 1, 2006. 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. According to the provisions of SFAS No. 123R, 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. Companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects, and compensation cost for awards that vest would not be reversed if the awards expire without being exercised.

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.

Directors' Unit Appreciation Rights Plan

On April 1, 2003, KMR's compensation committee established our Directors' Unit Appreciation Rights Plan. Pursuant to this plan, each of KMR's three non-employee directors was eligible to receive common unit appreciation rights. Upon the exercise of unit appreciation rights, we will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation

rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one common unit on the New York Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a unit appreciation right granted under the plan will be payable only in cash (that is, no exercise will result in the issuance of additional common units) and will be evidenced by a unit appreciation rights agreement.

All unit appreciation rights granted vest on the six-month anniversary of the date of grant. If a unit appreciation right is not exercised in the ten year period following the date of grant, the unit appreciation right will expire and not be exercisable after the end of such period. In addition, if a participant ceases to serve on the board for any reason prior to the vesting date of a unit appreciation right, such unit appreciation right will immediately expire on the date of cessation of service and may not be exercised.

On April 1, 2003, the date of adoption of the plan, each of KMR's three non-employee directors were granted 7,500 unit appreciation rights. In addition, 10,000 unit appreciation rights were granted to each of KMR's three non-employee directors on January 21, 2004, at the first meeting of the board in 2004. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors, discussed following. All unexercised awards made under our Directors' Unit Appreciation Rights Plan remain outstanding. No unit appreciation rights were exercised during 2006, and as of December 31, 2006, 52,500 unit appreciation rights had been granted, vested and remained outstanding.

Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors

On January 18, 2005, KMR's compensation committee established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan. The plan is administered by KMR's compensation committee and KMR's board has sole discretion to terminate the plan at any time. The primary purpose of this plan was to promote our interests and the interests of our unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with unitholders' interests. Further, since KMR's success is dependent on its operation and management of our business and our resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of KMR's shareholders.

The plan recognizes that the compensation to be paid to each non-employee director is fixed by the KMR board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving cash compensation, each non-employee director may elect to receive common units. Each election shall be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. The initial election under this plan for service in 2005 was made effective January 20, 2005, the election for 2006 was made effective January 18, 2006, and the election for 2007 was made effective January 17, 2007. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000.

Each annual election shall be evidenced by an agreement, the Common Unit Compensation Agreement, between us and each non-employee director, and this agreement will contain the terms and conditions of each award. Pursuant to this agreement, all common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. Until the forfeiture restrictions lapse, common units issued under the plan may not be sold, assigned, transferred, exchanged, or pledged by a non-employee director. In the event the director's service as a director of KMR is terminated prior to the lapse of the forfeiture restriction either for cause, or voluntary resignation, each director shall, for no consideration, forfeit to us all common units to the extent then subject to the forfeiture restrictions. Common units with respect to which forfeiture restrictions have lapsed shall cease to be subject to any forfeiture restrictions, and we will provide each director a certificate representing the units as to which the forfeiture restrictions have lapsed. In addition, each non-employee director shall have the right to receive distributions with respect to the common units awarded to him under the plan, to vote such common units and to enjoy all other unitholder rights, including during the period prior to the lapse of the forfeiture restrictions.

The number of common units to be issued to a non-employee director electing to receive the cash compensation in the form of common units will equal the amount of such cash compensation awarded, divided by the closing price

of the common units on the New York Stock Exchange on the day the cash compensation is awarded (such price, the fair market value), rounded down to the nearest 50 common units. The common units will be issuable as specified in the Common Unit Compensation Agreement. A non-employee director electing to receive the cash compensation in the form of common units will receive cash equal to the difference between (i) the cash compensation awarded to such non-employee director and (ii) the number of common units to be issued to such non-employee director multiplied by the fair market value of a common unit. This cash payment shall be payable in four equal installments generally around March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded.

On January 18, 2005, the date of adoption of the plan, each of KMR's three non-employee directors was awarded cash compensation of $119,750 for board service during 2005. Effective January 20, 2005, each non-employee director elected to receive cash compensation of $79,750 in the form of our common units and was issued 1,750 common units pursuant to the plan and its agreements (based on the $45.55 closing market price of our common units on January 18, 2005, as reported on the New York Stock Exchange). Also, consistent with the plan, the remaining $40,000 cash compensation and the $37.50 of cash compensation that did not equate to a whole common unit, based on the January 18, 2005 $45.55 closing price, was paid to each of the non-employee directors as described above. No other compensation was paid to the non-employee directors during 2005.

On January 17, 2006, each of KMR's three non-employee directors was awarded cash compensation of $160,000 for board service during 2006. Effective January 17, 2006, each non-employee director elected to receive cash compensation of $87,780 in the form of our common units and was issued 1,750 common units pursuant to the plan and its agreements (based on the $50.16 closing market price of our common units on January 17, 2006, as reported on the New York Stock Exchange). The remaining $72,220 cash compensation was paid to each of the non-employee directors as described above. No other compensation was paid to the non-employee directors during 2006.

On January 17, 2007, each of KMR's three non-employee directors was awarded cash compensation of $160,000 for board service during 2007. Effective January 17, 2007, each non-employee director elected to receive certain amounts of cash compensation in the form of our common units and each were issued common units pursuant to the plan and its agreements (based on the $48.44 closing market price of our common units on January 17, 2007, as reported on the New York Stock Exchange). Mr. Gaylord elected to receive cash compensation of $95,911.20 in the form of our common units and was issued 1,980 common units; Mr. Waughtal elected to receive cash compensation of $159,852.00 in the form of our common units and was issued 3,300 common units; and Mr. Hultquist elected to receive cash compensation of $96,880.00 in the form of our common units and was issued 2,000 common units. All remaining cash compensation ($64,088.80 to Mr. Gaylord; $148.00 to Mr. Waughtal; and $63,120.00 to Mr. Hultquist) will be paid to each of the non-employee directors as described above, and no other compensation will be paid to the non-employee directors during 2007.

14. 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. Specifically, these risks are associated with unfavorable price volatility related to:

o pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales;

o natural gas purchases; and

o natural gas system use and storage.

The unfavorable price 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 derivative 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 loss of $1.3 million during 2006, a loss of $0.6 million during 2005 and a gain of $0.1 million during 2004. 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, and for each of the years ended December 31, 2006, 2005 and 2004, 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 years 2006, 2005 and 2004, we reclassified $428.1 million, $424.0 million and $192.3 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 2006, 2005 or 2004 resulted from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period 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).

Our consolidated "Accumulated other comprehensive loss" balance reported on our accompanying consolidated balance sheets was $841.6 million as of December 31, 2006 and $1,079.7 million as of December 31, 2005. Included in these consolidated totals were "Accumulated other comprehensive loss" amounts associated with our commodity price risk management activities of $838.7 million as of December 31, 2006 and $1,079.4 million as of December 31, 2005. Approximately $344.3 million of our $838.7 million "Accumulated other comprehensive loss" amount associated with our commodity price risk management activities as of December 31, 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 December 31, 2006 and December 31, 2005 (in thousands):

                                                            December 31,     December 31,
                                                                2006             2005
                                                            ------------     ------------
Derivatives-net asset/(liability)
  Other current assets..................................... $     91,939     $    109,437
  Deferred charges and other assets........................       12,729           47,682
  Accounts payable-Related parties.........................           --          (16,057)
  Accrued other current liabilities........................     (431,365)        (507,306)
  Other long-term liabilities and deferred credits......... $   (510,203)    $   (727,929)

Given our portfolio of businesses as of December 31, 2006, our principal use of energy commodity derivative contracts was to mitigate the risk associated with market movements in the price of energy commodities. Our net short natural gas derivatives position primarily represented our hedging of anticipated future natural gas purchases and sales. Our net short crude oil derivatives position represented our crude oil derivative purchases and sales made to hedge anticipated oil purchases and sales. Finally, our net short natural gas liquids derivatives position reflected the hedging of our forecasted natural gas liquids purchases and sales. As of December 31, 2006, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with commodity price risk is through December 2011.

As of December 31, 2006, our energy commodity derivative contracts and over-the-counter swaps and options (in thousands) consisted of the following:

                                                                            Over the
                                                                             Counter
                                                                            Swaps and
                                                            Commodity        Options
                                                            Contracts        Contracts       Total
                                                            ---------       -----------    ---------
                                                                     (Number of contracts(1))
Natural Gas
  Notional Volumetric Positions: Long...................        143            1,904          2,047
  Notional Volumetric Positions: Short..................       (216)          (1,616)        (1,832)
  Net Notional Totals to Occur in 2007..................        (73)             208            135
  Net Notional Totals to Occur in 2008 and Beyond.......         --               80             80
Crude Oil
  Notional Volumetric Positions: Long...................         --            2,985          2,985
  Notional Volumetric Positions: Short..................         --          (55,835)       (55,835)
  Net Notional Totals to Occur in 2007..................         --          (11,963)       (11,963)
  Net Notional Totals to Occur in 2008 and Beyond.......         --          (40,887)       (40,887)
Natural Gas Liquids
  Notional Volumetric Positions: Long...................         --               10             10
  Notional Volumetric Positions: Short..................         --             (360)          (360)
  Net Notional Totals to Occur in 2007..................         --             (350)          (350)
  Net Notional Totals to Occur in 2008 and Beyond.......         --               --             --

(1) A term of reference describing a unit of commodity trading. One natural gas contract equals 10,000 MMBtus. One crude oil or natural gas liquids contract equals 1,000 barrels.

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 December 31, 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 December 31, 2006, we had three outstanding letters of credit totaling $243.0 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 December 31, 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 $2.3 million, and we reported this amount within "Accrued other liabilities" in our accompanying consolidated balance sheet as of December 31, 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 December 31, 2006 and December 31, 2005, we were a party to interest rate swap agreements with notional principal amounts of $2.1 billion. We entered into these agreements for the purposes of:

o hedging the interest rate risk associated with our fixed rate debt obligations; and

o transforming a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt.

Since the fair value of fixed rate debt varies with changes in the market rate of interest, we enter into swap agreements to receive a fixed and pay a variable rate of 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 December 31, 2006, a notional principal amount of $2.1 billion of these agreements effectively converted 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 December 31, 2006, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.

The swap agreements related to our 7.40% senior notes contain mutual cash-out provisions at the then-current economic value every seven years. The swap agreements related to our 7.125% senior notes contain cash-out provisions at the then-current economic value in March 2009. The swap agreements related to our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out provisions at the then-current economic value every five or seven years.

Hedging effectiveness and ineffectiveness

Our interest rate swap contracts 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 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 swap contracts 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 contract. Accordingly, we adjust the carrying value of each swap contract 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 swap contracts. 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 December 31, 2006 and December 31, 2005 (in thousands):

                                                           December 31,     December 31,
                                                               2006             2005
                                                           ------------     ------------
Derivatives-net asset/(liability)
  Deferred charges and other assets.....................   $   65,183       $  112,386
  Other long-term liabilities and deferred credits......      (22,553)         (13,917)
                                                           -----------      -----------
    Market value of interest rate swaps.................   $   42,630       $   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 December 31, 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.

15. Reportable Segments

We divide our operations into four reportable business segments:

o Products Pipelines;

o Natural Gas Pipelines;

o CO2; and

o Terminals.

Each segment uses the same accounting policies as those described in the summary of significant accounting policies (see Note 2). 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 and sale of crude oil from fields in the Permian Basin of West Texas and from the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and chemicals.

Financial information by segment follows (in thousands):

                                                         2006               2005                2004
                                                    -------------       -------------       -------------
Revenues(a)
  Products Pipelines
    Revenues from external customers.............   $    776,268        $    711,886        $    645,249
    Intersegment revenues........................             --                  --                  --
  Natural Gas Pipelines
    Revenues from external customers.............      6,577,661           7,718,384           6,252,921
    Intersegment revenues........................             --                  --                  --
  CO2
    Revenues from external customers.............        736,524             657,594             492,834
    Intersegment revenues........................             --                  --                  --
  Terminals
    Revenues from external customers.............        864,130             699,264             541,857
    Intersegment revenues........................            714                  --                  --
                                                    -------------       -------------       -------------
  Total segment revenues.........................      8,955,297           9,787,128           7,932,861
  Less: Total intersegment revenues..............           (714)                 --                  --
                                                    -------------       -------------       -------------
  Total consolidated revenues....................   $  8,954,583        $  9,787,128        $  7,932,861
                                                    =============       =============       =============

Operating expenses(b)
  Products Pipelines.............................   $    308,296        $    366,048        $    191,425
  Natural Gas Pipelines..........................      6,057,753           7,254,979           5,862,159
  CO2............................................        268,111             212,636             173,382
  Terminals......................................        462,009             373,410             272,766
                                                    -------------       -------------       -------------
  Total segment operating expenses...............      7,096,169           8,207,073           6,499,732
  Less: Total intersegment operating expenses....           (714)                 --                  --
                                                    -------------       -------------       -------------
    Total consolidated operating expenses........   $  7,095,455        $  8,207,073        $  6,499,732
                                                    =============       =============       =============

Other expense (income)(c)
  Products Pipelines.............................   $         --        $         --        $         --
  Natural Gas Pipelines..........................        (15,114)                 --                  --
  CO2............................................             --                  --                  --
  Terminals......................................        (15,192)                 --                  --
                                                    -------------       -------------       -------------
    Total consolidated other expense (income)....   $    (30,306)       $         --        $         --
                                                    =============       =============       =============

Depreciation, depletion and amortization
  Products Pipelines.............................   $     82,888        $     79,199        $     71,263
  Natural Gas Pipelines..........................         65,374              61,661              53,112
  CO2............................................        190,922             149,890             121,361
  Terminals......................................         74,541              59,077              42,890
                                                    -------------       -------------       -------------
    Total consol. depreciation, depletion and
      amortization...............................   $    413,725        $    349,827        $    288,626
                                                    =============       =============       =============

Earnings from equity investments(d)
  Products Pipelines.............................   $     16,336        $     28,446        $     29,050
  Natural Gas Pipelines..........................         40,447              36,812              19,960
  CO2............................................         19,173              26,319              34,179
  Terminals......................................            214                  83                   1
                                                    -------------       -------------       -------------
    Total consolidated equity earnings...........   $     76,170        $     91,660        $     83,190
                                                    =============       =============       =============

Amortization of excess cost of equity investments
  Products Pipelines.............................   $      3,362        $      3,350        $      3,281
  Natural Gas Pipelines..........................            285                 277                 277
  CO2............................................          2,017               2,017               2,017
  Terminals......................................             --                  --                  --
                                                    -------------       -------------       -------------
   Total consol. amortization of excess cost of
     investments.................................   $      5,664        $      5,644        $      5,575
                                                    =============       =============       =============



                              196

                                                         2006               2005                2004
                                                    -------------       -------------       -------------
Interest income
  Products Pipelines.............................   $      4,481        $      4,595        $      2,091
  Natural Gas Pipelines..........................            150                 747                  --
  CO2............................................             --                  --                  --
  Terminals......................................             --                  --                  --
                                                    -------------       -------------       -------------
    Total segment interest income................          4,631               5,342               2,091
  Unallocated interest income....................          1,867               4,155               1,199
                                                    -------------       -------------       -------------
    Total consolidated interest income...........   $      6,498        $      9,497        $      3,290
                                                    =============       =============       =============

Other, net-income (expense)(e)
  Products Pipelines.............................   $      7,536        $      1,516        $    (28,025)
  Natural Gas Pipelines..........................            603               1,982               9,434
  CO2............................................            808                  (5)              4,152
  Terminals......................................          2,118                (220)             18,255
                                                    -------------       -------------       -------------
    Total segment other, net-income (expense)....         11,065               3,273               3,816
  Loss from early extinguishment of debt.........             --                  --              (1,562)
                                                    -------------       -------------       -------------
    Total consolidated other, net-income (expense)  $     11,065        $      3,273        $      2,254
                                                    =============       =============       =============

Income tax benefit (expense)(f)
  Products Pipelines.............................   $     (5,175)       $    (10,343)       $    (12,075)
  Natural Gas Pipelines..........................         (1,423)             (2,622)             (1,895)
  CO2............................................           (224)               (385)               (147)
  Terminals......................................        (12,226)            (11,111)             (5,609)
                                                    -------------       -------------       -------------
    Total consolidated income tax benefit
      (expense)..................................   $    (19,048)       $    (24,461)       $    (19,726)
                                                    =============       =============       =============

Segment earnings(g)
  Products Pipelines.............................   $    404,900        $    287,503        $    370,321
  Natural Gas Pipelines..........................        509,140             438,386             364,872
  CO2............................................        295,231             318,980             234,258
  Terminals......................................        333,592             255,529             238,848
                                                    -------------       -------------       -------------
    Total segment earnings.......................      1,542,863           1,300,398           1,208,299
  Interest and corporate administrative
    expenses(h)..................................       (570,720)           (488,171)           (376,721)
    Total consolidated net income................   $    972,143        $    812,227        $    831,578
                                                    =============       =============       =============

Segment earnings before depreciation, depletion,
  amortization and amortization of excess cost of
  equity investments(i)
  Products Pipelines.............................   $    491,150        $    370,052        $    444,865
  Natural Gas Pipelines..........................        574,799             500,324             418,261
  CO2............................................        488,170             470,887             357,636
  Terminals......................................        408,133             314,606             281,738
                                                    -------------       -------------       -------------
    Total segment earnings before DD&A...........      1,962,252           1,655,869           1,502,500
  Consolidated depreciation and amortization.....       (413,725)           (349,827)           (288,626)
  Consolidated amortization of excess cost of
    investments..................................         (5,664)             (5,644)             (5,575)
  Interest and corporate administrative expenses.       (570,720)           (488,171)           (376,721)
                                                    -------------       -------------       -------------
    Total consolidated net income................   $    972,143        $    812,227        $    831,578
                                                    =============       =============       =============

Capital expenditures(j)
  Products Pipelines.............................   $    195,949        $    271,506        $    213,746
  Natural Gas Pipelines..........................        271,624             102,914             106,358
  CO2............................................        283,014             302,032             302,935
  Terminals......................................        307,678             186,604             124,223
                                                    -------------       -------------       -------------
    Total consolidated capital expenditures......   $  1,058,265        $    863,056        $    747,262
                                                    =============       =============       =============

Investments at December 31
  Products Pipelines.............................   $    211,076        $    223,729        $    223,196
  Natural Gas Pipelines..........................        197,876             177,105             174,296
  CO2............................................         16,168              17,938              15,503
  Terminals......................................            480                 541                 260
                                                    -------------       -------------       -------------
    Total consolidated investments...............   $    425,600        $    419,313        $    413,255
                                                    =============       =============       =============



                              197

                                                         2006               2005                2004
                                                    -------------       -------------       -------------
 Assets at December 31
  Products Pipelines.............................   $  3,910,612        $  3,873,939        $  3,651,657
  Natural Gas Pipelines..........................      3,942,786           4,139,969           3,691,457
  CO2............................................      1,838,223           1,772,756           1,527,810
  Terminals......................................      2,364,001           2,052,457           1,576,333
                                                    -------------       -------------       -------------
    Total segment assets.........................     12,055,622          11,839,121          10,447,257
  Corporate assets(k)............................        190,772              84,341             105,685
                                                    -------------       -------------       -------------
    Total consolidated assets....................   $ 12,246,394        $ 11,923,462        $ 10,552,942
                                                    =============       =============       =============

(a) 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. 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. 2006 amounts also include 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, and a $2,792 increase in expense to our Terminals business segment related to hurricane clean-up and repair activities. 2005 amounts include a rate case liability adjustment resulting in a $105,000 expense to our Products Pipelines business segment, a North System liquids inventory reconciliation adjustment resulting in a $13,691 expense to our Products Pipelines business segment, and environmental liability adjustments resulting in a $19,600 expense to our Products Pipelines business segment, an $89 reduction in expense to our Natural Gas Pipelines business segment, a $298 expense to our CO2 business segment and a $3,535 expense to our Terminals business segment.

(c) 2006 amounts include 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, and a $15,192 gain to our Terminals business segment from property casualty indemnifications.

(d) 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) 2006 amounts include a $5,700 increase in income to our Products Pipelines business segment from the settlement of transmix processing contracts. 2004 amounts include environmental liability adjustments resulting in a $30,611 expense to our Products Pipelines business segment, a $7,602 earnings increase to our Natural Gas Pipelines business segment, a $4,126 earnings increase to our CO2 business segment and an $18,651 earnings increase to our Terminals business segment.

(f) 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 (c), and a $1,125 increase in expense to our Terminals business segment associated with hurricane expenses and casualty gain. 2004 amounts include an $80 increase in expense to our Terminals business segment related to environmental expense adjustments 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, minority interest expense and loss from early extinguishment of debt (2004 only).

(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 $125,360 in 2006, $140,805 in 2005 and $119,244 in 2004. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset.

(k) Includes cash, cash equivalents, certain unallocable deferred charges, and risk management assets related to the market value of interest rate swaps.

We do not attribute interest and debt expense to any of our reportable business segments. For each of the years ended December 31, 2006, 2005 and 2004, we reported (in thousands) total consolidated interest expense of $337,997, $268,358 and $196,172, respectively.

Our total operating revenues are derived from a wide customer base. For each of the years ended December 31, 2006 and 2005, no revenues from transactions with a single external customer amounted to 10% or more of our total consolidated revenues. For the year ended December 31, 2004, only one customer accounted for more than 10% of our total consolidated revenues. Total transactions within our Natural Gas Pipelines segment with CenterPoint Energy accounted for 14.3% of our total consolidated revenues during 2004.

16. Litigation, Environmental and Other Contingencies

Federal Energy Regulatory Commission Proceedings

SFPP, L.P.

SFPP, L.P. is the subsidiary limited partnership that owns our Pacific operations, excluding 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.

In this Note, we refer to SFPP, L.P. as SFPP; CALNEV Pipe Line LLC as Calnev; Chevron Products Company as Chevron; Navajo Refining Company, L.P. as Navajo; ARCO Products Company as ARCO; BP West Coast Products, LLC as BP WCP; Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western Refining; Mobil Oil Corporation as Mobil; ExxonMobil Oil Corporation as ExxonMobil; Tosco Corporation as Tosco; and ConocoPhillips Company as ConocoPhillips.

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, referred to in this report as D.C. Circuit. Certain of those petitions were dismissed by the D.C. Circuit as premature, and the remaining petitions were held in abeyance pending completion of agency action. However, in December 2002, the D.C. Circuit returned to its active docket all petitions to review the FERC's orders in the case through November 2001 and severed petitions regarding later FERC orders. The severed orders were held in abeyance for later consideration. In this Note, we refer to Ultramar Diamond Shamrock Corporation as Ultramar and we refer to Valero Energy Corporation as Valero.

Briefing in the D.C. Circuit was completed in August 2003, and oral argument took place on November 12, 2003. On July 20, 2004, the D.C. Circuit 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 (BP West Coast Products, LLC v. FERC), addressing in part the tariffs of SFPP. 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 D.C. Circuit 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 and was based on the record in that case.

The D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit 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 FERC'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 D.C. Circuit affirmed the FERC's rulings on reparations in all respects. It held the Arizona Grocery doctrine did not apply to orders requiring SFPP to file "interim" rates, and that "FERC only established a final rate at the completion of the OR92-8 proceedings." It held that the Energy Policy Act did not limit complainants' ability to seek reparations for up to two years prior to the filing of complaints against rates that are not grandfathered. It rejected SFPP's arguments that the FERC should not have used a "test period" to compute reparations, that it should have offset years in which there were underrecoveries against those in which there were overrecoveries, and that it should have exercised its discretion against awarding any reparations in this case.

The D.C. Circuit 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 WCP, Chevron, ConocoPhillips and ExxonMobil filed a petition for rehearing and rehearing en banc asking the D.C. Circuit 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 D.C. Circuit denied both petitions without further comment.

On November 2, 2004, the D.C. Circuit 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 D.C. Circuit'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 D.C. Circuit (discussed further below in relation to the OR96-2 proceedings). Oral argument was held on December 12, 2006, but the D.C. Circuit has not yet issued an opinion.

On December 17, 2004, the D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit's 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 WCP and ExxonMobil also filed a petition for certiorari, on December 30, 2004, seeking review of the D.C. Circuit's ruling that there was no pending investigation of West Line rates at the time of enactment of the Energy Policy Act (and thus that those rates remained grandfathered). On April 6, 2005, the Solicitor General filed a brief in opposition to both petitions on behalf of the FERC and United States, and Navajo, ConocoPhillips, Ultramar, Valero and Western Refining filed an opposition to SFPP's petition. SFPP filed a reply to those briefs on April 18, 2005. On May 16, 2005, the Supreme Court issued orders denying the petitions for certiorari filed by SFPP and by BP WCP and ExxonMobil.

On June 1, 2005, the FERC issued its Order on Remand and Rehearing, referred to in this report as the June 2005 Order, which addressed issues in both the OR92-8 and OR96-2 proceedings (discussed following).

With respect to the OR92-8 proceedings, the June 2005 Order ruled on several issues that had been remanded by the D.C. Circuit in BP West Coast Products, LLC v. FERC. 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 II 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 2005 Order by the D.C. Circuit have been filed by SFPP, Navajo, Western Refining, BP WCP, ExxonMobil, Chevron, ConocoPhillips, Ultramar, Inc. and Valero. SFPP moved to intervene in the review proceedings brought by the other parties. The proceedings before the D.C. Circuit are addressed further below.

On December 16, 2005, the FERC issued its Order on Initial Decision and on Certain Remanded Cost Issues, referred to in this report as the December 2005 Order, 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 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 the June 2005 Order regarding the allocation of litigation costs. SFPP filed 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 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 2005 Order.

Watson Station proceedings. The FERC's June 2005 Order 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 from 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 been paid and describing how the refund calculations were made. ExxonMobil protested the refund report (BP WCP also originally protested the report, but later withdrew its protest). On December 5, 2006, the FERC approved SFPP's refund report with respect to all shippers except ExxonMobil. On December 5, 2006, the FERC remanded the ExxonMobil refund issue to the administrative law judge for a determination as to whether additional funds were due ExxonMobil; the FERC accepted the refund report as to all other amounts and the recipients contained in the report. In February 2007, SFPP and ExxonMobil reached agreement regarding ExxonMobil's protest of the refund report, and the protest was withdrawn. As of December 31, 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 were filed on November 15, 2006. Reply briefs were due on February 8, 2007, with oral argument, if convened, to occur on March 1, 2007. The scheduled issuance date for the initial decision is March 29, 2007.

On January 16, 2007, SFPP and ExxonMobil informed the presiding judge that they had reached a settlement in principle regarding the ExxonMobil refund issue.

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.

On December 8, 2006, the FERC issued its order on the initial decision in the Sepulveda proceeding. The FERC affirmed the administrative law judge's decision that the Sepulveda rate should have been lower but disagreed with the administrative law judge's rulings on some aspects of the equity cost-of-capital, income tax allowances, and the recovery of SFPP's litigation costs. The December 8 order directed SFPP to file revised Sepulveda rates for 1995 and 1996 and to submit a compliance filing estimating reparations and refunds. The compliance filing, related tariff adjustments, and requests for rehearing were made on February 7, 2007.

OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar, Inc. 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 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 Refining filed complaints against SFPP's East Line rates and Ultramar filed an additional complaint updating its pre-existing challenges to SFPP's interstate pipeline rates. These complaints were consolidated with the ongoing proceeding in Docket No. OR96-2, et al.

A hearing in this consolidated proceeding was held from October 2001 to March 2002. A FERC administrative law judge issued his initial decision in June 2003. The initial decision found that, for the years at issue, the complainants had shown substantially changed circumstances for rates on SFPP's West, North and Oregon Lines

and for SFPP's fee for gathering enhancement service at Watson Station and thus found that those rates should not be "grandfathered" under the Energy Policy Act of 1992. The initial decision also found that most of SFPP's rates at issue were unjust and unreasonable.

On March 26, 2004, the FERC issued an order on the Phase I initial decision, referred to in this report as the March 2004 Order. The March 2004 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 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 March 2004 Order. The March 2004 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 2005 Order on Phase II issues. The March 2004 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 D.C. Circuit in its review of the FERC's Opinion No. 435 orders; as noted above, the FERC held in its June 2005 Order that the Watson Station fee is not grandfathered. Several of the participants in the proceeding requested rehearing of the March 2004 Order. The FERC denied those requests in its June 2005 Order. In addition, several participants, including SFPP, filed petitions with the D.C. Circuit for review of the March 2004 Order. In August 2005, the FERC and SFPP jointly moved that the D.C. Circuit hold the petitions for review of the March 2004 and June 2005 Orders in abeyance due to the pendency of further action before the FERC on income tax allowance issues. In December 2005, the D.C. Circuit 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 was held on December 12, 2006.

On July 24, 2006, the FERC filed with the D.C. Circuit a motion for voluntary partial remand, requesting that the portion of the March 2004 and June 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 D.C. Circuit 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.

In the June 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 II 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.

In the December 2005 Order, the FERC addressed issues remanded by the D.C. Circuit in the Docket No. OR92-8 proceeding (discussed above) and the cost of service issues arising from the initial decision in Phase II of OR96-2, including income tax allowance issues arising from the briefing directed by the FERC's June 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 2005 Order. ExxonMobil, BP WCP, Chevron, Ultramar, Inc. and ConocoPhillips have filed petitions for review of the December 2005 Order with the D.C. Circuit. On February 13, 2006, the FERC issued an order, referred to in this report as the February 2006 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 2005 and February 2006 Orders with the D.C. Circuit. On July 31, 2006, the D.C. Circuit 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.

In accordance with the FERC's December 2005 Order, rate reductions were implemented on May 1, 2006. We assume that reparations and accrued interest thereon will be paid no earlier than the second 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. Based on our review of the December 2005 Order and February 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. We estimate that the actual, partial year impact on 2006 distributable cash flow was approximately $15.7 million.

We are not able to predict with certainty the final outcome of the pending FERC proceedings involving SFPP, should they be carried through to their conclusion, or whether we can reach a settlement with some or all of the complainants. 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.

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 D.C. Circuit.

On July 2, 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 D.C. 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 D.C. Circuit, 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 D.C. Circuit 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 WCP and ExxonMobil, ConocoPhillips, Navajo and Chevron all filed timely motions to intervene in this proceeding. Valero Marketing and Supply Company, referred to in this Note as Valero Marketing, 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 WCP and ExxonMobil filed a complaint against SFPP at the FERC, which the FERC docketed as OR05-4. The complaint alleges that SFPP's interstate rates are not just and reasonable, that certain rates found grandfathered by the FERC are not entitled to such status, and, if so entitled, that "substantially changed circumstances" have occurred, removing such protection. The complainants seek rate reductions and reparations for two years prior to the filing of their complaint and ask that the complaint be consolidated with the Airlines' complaint in the OR04-3 proceeding. ConocoPhillips, Navajo, and Western Refining 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 WCP and ExxonMobil, Navajo, and Western Refining 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 WCP 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. A procedural schedule was 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 D.C. Circuit regarding various issues before the court that directly impact the Docket No. OR03-5 proceeding.

Docket No. OR07-1. On December 1, 2006, Tesoro Refining and Marketing Company, referred to in this Note as Tesoro, filed a complaint against SFPP challenging the rate that SFPP charges for interstate transportation on its North Line. Tesoro seeks rate reductions and reparations for two years prior to the filing of the complaint. SFPP filed an answer to the complaint on January 2, 2007. The FERC has not yet issued a ruling in Docket No. OR07-1.

Docket No. OR07-2. On December 12, 2006, Tesoro filed a complaint against SFPP alleging that SFPP's interstate West Line rates are unjust and unreasonable. Tesoro seeks rate reductions and reparations for two years prior to the filing of the complaint. SFPP filed an answer to the complaint on January 11, 2007. The FERC has not yet issued a ruling in Docket No. OR07-2.

Docket No. OR07-3. BP WCP, Chevron, ExxonMobil, Tesoro, and Valero Marketing filed a complaint and motion for summary disposition on December 20, 2006 in Docket No. OR07-3 that challenged the justness and reasonableness of SFPP's North Line index rate increase in Docket No. IS05-327. The complaint requests refunds and reparations for shipments made under the indexed rates from July 1, 2005. SFPP filed an answer to this complaint on January 9, 2007. The FERC has not yet issued a ruling in Docket No. OR07-3.

Docket No. OR07-4. On January 5, 2007, BP WCP, ExxonMobil, and Chevron filed a complaint against SFPP, Kinder Morgan GP, Inc., and Kinder Morgan, Inc. alleging that none of SFPP's current rates or terms of service are just and reasonable under the Interstate Commerce Act. Complainants seek reparations with interest for the two years prior to the filing of this complaint. The answer to this complaint was due on February 5, 2007.

Docket No. OR07-6. ConocoPhillips filed a complaint on January 9, 2007 that challenged the justness and reasonableness of SFPP's North Line index rate increases in Docket Nos. IS05-327 and IS06-356. The complaint requests refunds and reparations for shipments made under the indexed rates from July 1, 2005. SFPP filed an answer to ConocoPhillips' complaint, and the FERC has not yet issued a ruling in Docket No. OR07-6.

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, referred to in this Note as the Concord to Sacramento segment. 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 25, 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 D.C. Circuit's decision in BP West Coast Products, LLC v. FERC 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 were filed on October 25, 2006, and briefs opposing exceptions were filed on November 14, 2006. The FERC has not yet reviewed the initial decision, and it is not possible to predict the outcome of FERC or appellate review.

East Line rate case, IS06-283 proceeding. In May 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. On November 22, 2006, the chief judge suspended the procedural schedule in this docket pending resolution of certain issues pending before the D.C. Circuit.

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 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 WCP and ExxonMobil 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 D.C. Circuit. Initial and final briefs have been filed, and oral argument was held on February 15, 2007.

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 D.C. Circuit. On August 31, 2006, the FERC filed a motion with the D.C. Circuit to hold the case in abeyance, and SFPP and BP WCP subsequently intervened. The Court has not yet issued a ruling on the motions filed by the FERC, SFPP, and BP WCP. On December 6, 2006, the FERC rescinded the July 1, 2006 index increase to SFPP's East Line rates and ordered SFPP to refund the East Line index increase to shippers back to the effective date of July 1, 2006. On January 5, 2007, SFPP filed a request for rehearing of the FERC's December 6, 2006 order, but the FERC has not yet ruled on the request for rehearing.

ULSD Surcharge, IS06-508. On August 11, 2006, SFPP filed tariffs to include a per barrel Ultra Low Sulfur Diesel (referred to in this Note as ULSD) recovery fee on all diesel products. Various shippers protested the filing, and, on September 8, 2006, the FERC accepted the tariffs, subject to refund, and established hearing procedures. SFPP has withdrawn the tariffs containing the ULSD surcharge, and the FERC vacated the procedural schedule in this docket on October 17, 2006.

Motions to Compel Payment of Interim Damages. On November 21, 2006, a number of SFPP shippers filed a motion with the FERC to compel SFPP and/or Kinder Morgan GP, Inc. and/or Kinder Morgan, Inc. to pay interim damages to shippers or alternatively to put such damages in escrow pending FERC resolution of the various complaint and protest proceedings pending against SFPP. SFPP filed its response to this motion on December 6, 2006. Also on December 6, 2006, the complainants in Docket No. OR04-3 filed their own motion for interim damages and/or escrow, and SFPP filed a response to this second motion on December 21, 2006. The FERC has not yet taken any action with respect to these pending motions.

Calnev Pipe Line LLC

Docket No. IS06-296. On May 22, 2006, Calnev filed to increase its interstate rates pursuant to the FERC's indexing methodology applicable to oil pipelines. 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.

Docket No. OR07-5. On January 8, 2007, ExxonMobil filed a complaint against Calnev, Kinder Morgan GP, Inc., and Kinder Morgan, Inc. In the Calnev complaint, ExxonMobil alleges that none of Calnev's current rates or terms of service are just and reasonable under the Interstate Commerce Act. ExxonMobil seeks reparations with interest for the two years prior to the filing of the Calnev complaint. Calnev filed an answer to the Calnev complaint on February 7, 2007.

Trailblazer Pipeline Company

On March 22, 2005, Marathon Oil Company filed a formal complaint with the FERC alleging that Trailblazer Pipeline Company violated the FERC's Negotiated Rate Policy Statement and the Natural Gas Act by failing to offer a recourse rate option for its Expansion 2002 capacity and by charging negotiated rates higher than the applicable recourse rates. Marathon Oil Company, referred to in this Note as Marathon, requested that the FERC require Trailblazer Pipeline Company to refund all amounts paid by Marathon above Trailblazer Pipeline

Company's Expansion 2002 recourse rate since the facilities went into service in May 2002, with interest. In addition, Marathon asked the FERC to require Trailblazer Pipeline Company to bill Marathon the Expansion 2002 recourse rate for future billings. Marathon estimated that the amount of Trailblazer Pipeline Company's refund obligation at the time of the filing was over $15 million. Trailblazer Pipeline Company filed its response to Marathon's complaint on April 13, 2005. On May 20, 2005, the FERC issued an order denying the Marathon complaint and found that (i) Trailblazer Pipeline Company did not violate FERC policy and regulations and (ii) there is insufficient justification to initiate further action under Section 5 of the Natural Gas Act to invalidate and change the negotiated rate. On June 17, 2005, Marathon filed its Request for Rehearing of the May 20, 2005 order. On January 19, 2006, the FERC issued an order which denied Marathon's rehearing request.

California Public Utilities Commission Proceeding

ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission, referred to in this Note as the CPUC, 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 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, Ultramar Inc., BP WCP, ExxonMobil and Chevron. 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. We are not able 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, Ultramar Inc., BP WCP, ExxonMobil and Chevron. 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, BP WCP, ExxonMobil, Southwest Airlines Company, Valero Marketing, Ultramar Inc. and Chevron, 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 recover costs incurred to comply with revised ULSD 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, BP WCP, ExxonMobil, Southwest Airlines Company, Valero Marketing, Ultramar Inc. and Chevron, 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.

All of the referenced pending matters before the CPUC have been consolidated and assigned to a single Administrative Law Judge. The Administrative Law Judge has referred the matters to mediation, and the mediation process is pending.

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

Shores and First State Bank of Denton Lawsuits

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).

Armor/Reddy Lawsuit

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.

Bailey and Bridwell Oil Company Harris County/Southern District of Texas Lawsuit

Shell CO2 Company, Ltd., predecessor to Kinder Morgan CO2 Company, L.P., is among the named counter-claim defendants in the case originally filed as Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial District Court, Harris County, Texas filed June 17, 1998) (the "Bailey State Court Action"). The counter-claim plaintiffs are overriding royalty interest owners in the McElmo Dome Unit and have sued seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. In the Bailey State Court Action, the counter-claim plaintiffs asserted claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, negligence, negligence per se, unjust enrichment, violation of the Texas Securities Act, and open account. The trial court in the Bailey State Court Action granted a series of summary judgment motions filed by the counter-claim defendants on all of the counter-plaintiffs' counter-claims except for the fraud-based claims. In 2004, one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit to allege purported claims as a private relator under the False Claims Act and

antitrust claims. The federal government elected to not intervene in the False Claims Act counter-suit. On March 24, 2005, Bailey filed a notice of removal, and the case was transferred to federal court. Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company, No. H-05-1029 (S.D. Tex., Houston Division removed March 24, 2005) (the "Bailey Houston Federal Court Action"). Also on March 24, 2005, Bailey filed an instrument under seal in the Bailey Houston Federal Court Action that was later determined to be a motion to transfer venue of that case to the federal district court of Colorado, in which Bailey and two other plaintiffs 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, and the case is now styled Gerald O. Bailey et al. v. Shell Oil Company et al. 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.

Bridwell Oil Company Wichita County Lawsuit

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.

Ptasynski Colorado Federal District Court Lawsuit

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, 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 (voluntarily dismiss) the case. The Houston federal district court granted Ptasynski's request to non-suit. Ptasynski also filed an appeal in the Tenth Circuit seeking to overturn the Colorado court's order transferring the case to Houston federal district court. Harry Ptasynski v. Kinder Morgan G.P., Inc., No. 06-1231 (10th Cir.). Briefing in the appeal was completed on November 27, 2005. No oral argument has been set.

Grynberg Lawsuit

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.

CO2 Claims Arbitration

Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor 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 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. On October 25, 2006, defendants in the arbitration filed an application to confirm the arbitration decision in New Mexico federal district court. On November 6, 2006, the plaintiff in the arbitration filed a motion to vacate the arbitration award in Colorado federal district court. On that same day, the plaintiff in the arbitration filed a motion to dismiss the New Mexico federal district court application for lack of jurisdiction or, alternatively, asked the New Mexico court to stay consideration of the application in favor of its motion to vacate filed in the Colorado federal district court. On January 24, 2007, the Colorado federal district court denied the plaintiff's motion to vacate the arbitration award as moot in light of the pending application to confirm filed by defendants in New Mexico federal district court. On January 29, 2007, the New Mexico federal district court denied the plaintiff's motion to dismiss the New Mexico application to confirm or to stay the New Mexico application.

MMS Notice of Noncompliance and Civil Penalty

On December 20, 2006, Kinder Morgan CO2 Company, L.P. received a "Notice of Noncompliance and Civil Penalty: Knowing or Willful Submission of False, Inaccurate, or Misleading Information--Kinder Morgan CO2 Company, L.P., Case No. CP07-001" from the U.S. Department of the Interior, Minerals Management Service. This Notice, and the MMS' position that Kinder Morgan CO2 Company, L.P. has violated certain reporting obligations, relates to a disagreement between the MMS and Kinder Morgan CO2 Company, L.P. concerning the approved transportation allowance to be used in valuing McElmo Dome carbon dioxide for purposes of calculating federal royalties. In the Notice of Noncompliance and Civil Penalty, the MMS assesses civil penalties under section 109(d) of the Federal Oil and Gas Royalty Management Act of 1982, which provides that "[a]ny person who - (1) knowingly or willfully prepares, maintains, or submits false, inaccurate, or misleading reports, notices, affidavits,

records, data or other written information...shall be liable for a penalty of up to $25,000.00 per violation for each day such violation continues." The Notice of Noncompliance and Civil Penalty assesses a civil penalty of approximately $2.2 million as of December 15, 2006 (based on a penalty of $500.00 per day for each of seventeen alleged violations) for Kinder Morgan CO2 Company, L.P.'s alleged submission of false, inaccurate, or misleading information relating to the transportation allowance, and federal royalties for CO2 produced at McElmo Dome, during the period from June 2005 through October 2006. The MMS contends that false, inaccurate, or misleading information was submitted in the seventeen monthly Form 2014s containing remittance advice reflecting the royalty payments for the referenced period. The MMS contends that the 2014s were false, inaccurate or misleading because they reflected Kinder Morgan CO2 Company, L.P.'s use of the Cortez Pipeline tariff as the transportation allowance. The MMS claims that the Cortez Pipeline tariff is not the proper transportation allowance and that Kinder Morgan CO2 Company, L.P. should have used its "reasonable actual costs" calculated in accordance with certain federal product valuation regulations as amended effective June 1, 2005. The MMS has not, however, identified any royalty underpayment amount due or otherwise issued an appealable order directing that Kinder Morgan CO2 Company, L.P. pay additional royalties or calculate the federal government's royalties in a different manner. The MMS also stated that although it considers each line of each 2014 to constitute a separate "violation," it is limiting the violation count to the seventeen monthly 2014s submitted during the June 2005 through October 2006 period. The MMS stated that civil penalties will continue to accrue at the same rate until the alleged violations are corrected. The MMS set a due date of January 20, 2007 for Kinder Morgan CO2 Company, L.P.'s payment of the $2,234.500.00 in civil penalties, with interest to accrue daily on that amount in the event payment is not made by such date. Kinder Morgan CO2 Company, L.P. has not paid the penalty. On January 2, 2007, Kinder Morgan CO2 Company, L.P. submitted a response to the Notice of Noncompliance and Civil Penalty challenging the assessment in the Office of Hearings and Appeals of the Department of the Interior. On February 1, 2007, Kinder Morgan CO2 Company, L.P. filed a petition to stay the accrual of penalties until the dispute is resolved. On February 22, 2007, an administrative law judge of the U.S. Department of the Interior issued an order denying Kinder Morgan CO2 Company, L.P.'s petition to stay the accrual of penalties. Kinder Morgan CO2 Company, L.P. is reviewing the order of the administrative law judge and evaluating potential appellate options.

Kinder Morgan CO2 Company, L.P. disputes the Notice of Noncompliance and Civil Penalty for a number of reasons. Kinder Morgan CO2 Company, L.P. contends that use of the Cortez pipeline tariff as the transportation allowance for purposes of calculating federal royalties was approved by the MMS in 1984. This approval was later affirmed as open-ended by the Interior Board of Land Appeals in the 1990s. Accordingly, Kinder Morgan CO2 Company, L.P. has stated to the MMS that its use of the Cortez tariff as the approved federal transportation allowance is authorized and proper. Kinder Morgan CO2 Company, L.P. also disputes the allegation that it has knowingly or willfully submitted false, inaccurate, or misleading information to the MMS. Kinder Morgan CO2 Company, L.P.'s use of the Cortez Pipeline tariff as the approved federal transportation allowance has been the subject of extensive discussion between the parties. The MMS was, and is, fully apprised of that fact and of the royalty valuation and payment process followed by Kinder Morgan CO2 Company, L.P. generally.

As noted, the Notice of Noncompliance and Civil Penalty does not purport to identify a royalty underpayment. If, however, the MMS were to assert such a claim, the difference between the federal royalties actually paid in the June 2005 through October 2006 period and those it is thought that the government would urge as due is estimated at approximately $2.7 million. No pre-hearing hearing date or pre-hearing schedule has been set in this matter.

J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and on behalf of all other private royalty and overriding royalty owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New Mexico)

This case involves a purported class action against Kinder Morgan CO2 Company, L.P. alleging that it has failed to pay the full royalty and overriding royalty ("royalty interests") on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome Unit in the period beginning January 1, 2000. The complaint purports to assert claims for violation of the New Mexico Unfair Practices Act, constructive fraud, breach of contract and of the covenant of good faith and fair dealing, breach of the implied covenant to market, and claims for an accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome Unit. The plaintiffs allege that they were members of a class previously certified as a class action by the United States District Court for the District of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et al., USDC N.M. Civ. No. 95-

0012 (the "Feerer Class Action"). Plaintiffs allege that Kinder Morgan CO2 Company's method of paying royalty interests is contrary to the settlement of the Feerer Class Action. Kinder Morgan CO2 Company 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. Kinder Morgan filed its Brief in Chief in the New Mexico Supreme Court on December 12, 2006. No oral argument has been set.

In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO2 Company L.P.'s payments on carbon dioxide produced from the McElmo Dome Unit are currently ongoing. These audits and inquiries involve federal agencies and the State of Colorado.

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 to 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. The trial in this matter has commenced and is ongoing.

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 the judge determined in a preliminary statement of decision that we must pay for any relocations resulting from any legitimate business purpose of the UPRR. We expect to appeal any final statement of

decision to this effect. In addition, 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. On December 18, 2006, Plaintiff filed a Notice of Non-Suit with the Zapata County District Court Clerk. With the filing of the non-suit, this matter is concluded.

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.

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 May 9, 2006, the Kinder Morgan defendants filed a Motion to Dismiss and a Motion for Sanctions. 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. Grynberg has appealed this Order to the Tenth Circuit Court of Appeals. The mediation office for the Tenth Circuit Court of Appeals is involved and is consulting with the parties regarding possible settlement negotiations and will not issue a procedural schedule until these negotiations are complete. The Coordinated Defendants, which include the Kinder Morgan defendants, filed a Motion for Authorization of Taxation of Costs on December 18, 2006, and a Motion for Fees and Expenses on January 8, 2007. Grynberg filed his response brief to the Kinder Morgan Defendants' Motion to Dismiss and Motion for Sanctions on January 5, 2007. A hearing regarding the Motion for Authorization of Taxation of Costs, Motion for Fees and Expenses, and the Kinder Morgan Defendants' Motion to Dismiss and Motion for Sanctions is scheduled for April 24, 2007.

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 denied 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.

Cannon Interests-Houston v. Kinder Morgan Texas Pipeline, L.P., No. 2005-36174 (333rd Judicial District, Harris County, Texas).

On June 6, 2005, after unsuccessful mediation, Cannon Interests sued Kinder Morgan Texas Pipeline, L.P., referred to in this report as KMTP, and alleged breach of contract for the purchase of natural gas storage capacity and for failure to pay under a profit-sharing arrangement. KMTP counterclaimed that Cannon Interests failed to provide it with five billion cubic feet of winter storage capacity in breach of the contract. The plaintiff was claiming approximately $13 million in damages. In May 2006, the parties entered into a confidential settlement that resolved all claims in this matter. The case has been dismissed.

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 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 believe there is any basis for criminal charges, and we are engaged in discussions to resolve any possible criminal charges. 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. 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 final judgment, and certified a settlement class for Zones 1 and 2.

One member of the Zone 1 and 2 settlement class, the Estate of George W. Dameron, opted out of the settlement, and the Adminstratrix of the Dameron Estate filed a wrongful death lawsuit on November 15, 2006 in the Hamilton County Court of Common Pleas, Case No. A0609990. The complaint alleges that styrene exposure caused the death of Mr. Dameron. Kinder Morgan is not a named defendant in such lawsuit, but it is likely that Kinder Morgan will be joined as a defendant, in which case Kinder Morgan intends on vigorously defending against the estate's claim.

Certain claims by other residents and businesses remain pending. Specifically, the Zone 1 and 2 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. Settlement discussions are proceeding with such residents in outlying geographic zones. 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.

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. Oral argument on Kinder Morgan's motions was scheduled for December 8, 2006. At the hearing, the court referred the parties to mediation. The parties agreed to stay discovery until after the mediation, if necessary. No trial date has been established.

Leukemia Cluster Litigation

We are a party to two wrongful death 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.

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, 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 has been completed and the motions remain pending.

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 has been completed and the motions remain pending.

Pipeline Integrity and Releases

Walnut Creek, California Pipeline Rupture

On November 9, 2004, excavation equipment operated by 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 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. On June 27, 2005, the Office of the California State Fire Marshal, Pipeline Safety Division, referred to in this report as the CSFM, issued a notice of violation against us which also alleged 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 $0.5 million. 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.

CalOSHA, with the assistance of the Contra Costa County District Attorney's office, is continuing to investigate the facts and circumstances surrounding the incident for possible criminal violations. We have been notified by the Contra Costa District Attorney's office that it intends to pursue criminal charges against us in connection with the Walnut Creek pipeline rupture. We have responded by reiterating our belief that the facts and circumstances do not warrant criminal charges. We are currently engaged in discussions with the Contra Costa District Attorney's office in an effort to resolve any possible criminal charges. In the event that we are not able to reach a resolution, we anticipate that the Contra Costa District Attorney will pursue criminal charges, and we intend to defend such charges vigorously.

As a result of the accident, nineteen separate lawsuits have been filed. Each of these lawsuits is 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); Fuentes et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. C05-02286); Berry et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. C06-010524); Pena et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. C06-01051); Bower et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. MSC06-02129 (unserved)); and Ross et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. MSC06-02299 (unserved)). 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 sought compensatory and punitive damages. These complaints also alleged 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 named 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 named 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, among other things, 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.

Following court ordered mediation, the Kinder Morgan defendants have settled with plaintiffs in all of the wrongful death cases and many of the personal injury and property damages cases. These settlements have either become final by order of the court or are awaiting court approval. The cases which remain unsettled at present are the Bower, Ross, Chabot, Matamoros, and Mountain Cascade cases, as well as certain cross-claims for contribution and indemnity by and between various defendants. The parties are currently continuing discovery and court ordered mediation on the remaining cases.

Cordelia, California

On April 28, 2004, SFPP, L.P. discovered a spill of diesel fuel into a marsh near Cordelia, California from a section of SFPP's 14-inch Concord to Sacramento, California pipeline. Estimates indicated that the size of the spill was approximately 2,450 barrels. Upon discovery of the spill and notification to regulatory agencies, a unified response was implemented with the United States Coast Guard, the California Department of Fish and Game, the Office of Spill Prevention and Response and SFPP. The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on May 2, 2004. SFPP has completed recovery of diesel from the marsh and has completed an enhanced biodegradation program for removal of the remaining constituents bound up in soils. The property has been turned back to the owners for its stated purpose. There will be ongoing monitoring under the oversight of the California Regional Water Quality Control Board until the site conditions demonstrate there are no further actions required.

SFPP is currently in negotiations with the United States Environmental Protection Agency, the United States Fish & Wildlife Service, the California Department of Fish & Game and the San Francisco Regional Water Quality Control Board regarding potential civil penalties and natural resource damages assessments. Since the April 2004 release in the Suisun Marsh area near Cordelia, California, SFPP has cooperated fully with federal and state agencies and has worked diligently to remediate the affected areas. As of December 31, 2005, the remediation was substantially complete.

Oakland, California

In February 2005, we were contacted by the U.S. Coast Guard regarding a potential release of jet fuel in the Oakland, California area. Our northern California team responded and discovered that one of our product pipelines had been damaged by a third party, which resulted in a release of jet fuel which migrated to the storm drain system and the Oakland estuary. We have coordinated the remediation of the impacts from this release, and are investigating the identity of the third party who damaged the pipeline in order to obtain contribution, indemnity, and to recover any damages associated with the rupture. The United States Environmental Protection Agency, the San Francisco Bay Regional Water Quality Control Board, the California Department of Fish and Game, and possibly the County of Alameda are asserting civil penalty claims with respect to this release. We are currently in settlement negotiations with these agencies. We will vigorously contest any unsupported, duplicative or excessive civil penalty claims, but hope to be able to resolve the demands by each governmental entity through out-of-court settlements.

Donner Summit, California

In April 2005, our SFPP pipeline in Northern California, which transports refined petroleum products to Reno, Nevada, experienced a failure in the line from external damage, resulting in a release of product that affected a limited area adjacent to the pipeline near the summit of Donner Pass. The release was located on land administered by the Forest Service, an agency within the U.S. Department of Agriculture. Initial remediation has been conducted in the immediate vicinity of the pipeline. All agency requirements have been met and the site will be closed upon completion of the remediation. We have received civil penalty claims on behalf of the United States Environmental 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 Pipe Line Company, 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 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, referred to in this report as the VDEQ. In February 2007, the VDEQ proposed a civil penalty of approximately $0.8 million in this matter, and is also seeking reimbursement for oversight costs in amounts less than $0.1 million. Plantation is evaluating the VDEQ's penalty proposal and will engage the VDEQ in settlement discussions.

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 leak, 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.

Rockies Express Pipeline LLC Wyoming Construction Incident

On November 11, 2006, a bulldozer operated by an employee of Associated Pipeline Contractors, Inc, (a third-party contractor to Rockies Express Pipeline LLC, referred to in this report as REX, for construction of this segment of the new REX pipeline), struck an existing subsurface natural gas pipeline owned by Wyoming Interstate

Company and operated by Colorado Interstate Gas Company, both subsidiaries of El Paso Pipeline Group. The Wyoming Interstate Company pipeline was ruptured, resulting in an explosion and fire. The incident occurred in a rural area approximately nine miles southwest of Cheyenne, Wyoming. The incident resulted in one fatality (the operator of the bulldozer) and there were no other reported injuries.

The cause of the incident is under investigation by the PHMSA, as well as the Wyoming Occupational Safety and Health Administration. We are cooperating with both agencies. Immediately following the incident, REX and El Paso Pipeline Group reached an agreement on a set of additional enhanced safety protocols designed to prevent the reoccurrence of such an incident. We have been contacted by attorneys representing the estate and the family of the deceased bulldozer operator regarding potential claims related to the incident. Although the internal and external investigations are currently ongoing, based upon presently available information, we believe that REX acted appropriately and in compliance with all applicable laws and regulations.

Charlotte, North Carolina

On November 27, 2006, the Plantation Pipeline experienced a release of approximately four thousand gallons of gasoline from a Plantation Pipe Line Company block valve on a delivery line into a terminal owned by a third party company. Upon discovery of the release, Plantation immediately locked out the delivery of gasoline through that pipe to prevent further releases. Product had flowed onto the surface and into a nearby stream, which is a tributary of Paw Creek, and resulted in loss of fish and other biota. Product recovery and remediation efforts were implemented immediately, including removal of product from the stream. Remediation efforts are continuing under the direction of the North Carolina Department of Environment and Natural Resources, referred to in this report as the NCDENR, which issued a Notice of Violation and Recommendation of Enforcement against Plantation on January 8, 2007. Plantation continues to cooperate fully with the NCDENR, but does not believe that a penalty is warranted given the quality of Plantation's response efforts. The line was repaired and put back into service within a few days.

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. Subsequent to the 2004 inspection and order, most if not all findings have been addressed. We are currently waiting for the final report from PHMSA's 2006 reinspection of our Integrity Management Plan and we expect positive findings. This matter is not expected to have a material impact on our business, financial position, results of operations or cash flows.

Pipeline and Hazardous Materials Safety Administration Corrective Action Order

On August 26, 2005, we announced that we had received a corrective action order issued by the PHMSA. The corrective order instructs us to comprehensively address potential integrity threats along the pipelines that comprise our Pacific operations. The corrective order focused primarily on eight pipeline incidents, seven of which occurred in the State of California. The PHMSA attributed five of the eight incidents to "outside force damage," such as third-party damage caused by an excavator or damage caused during pipeline construction.

Following the issuance of the corrective order, we engaged in cooperative discussions with the PHMSA and we reached an agreement in principle on the terms of a consent agreement with the PHMSA, subject to the PHMSA's

obligation to provide notice and an opportunity to comment on the consent agreement to appropriate state officials pursuant to 49 USC Section 60112(c). This comment period closed on March 26, 2006.

On April 10, 2006, we announced the final consent agreement, which will, among other things, require us to perform a thorough analysis of recent pipeline incidents, provide for a third-party independent review of our operations and procedural practices, and restructure our internal inspections program. Furthermore, we have reviewed all of our policies and procedures and are currently implementing various measures to strengthen our integrity management program, including a comprehensive evaluation of internal inspection technologies and other methods to protect our pipelines. We expect to spend approximately $90 million on pipeline integrity activities for our Pacific operations' pipelines over the next five years. Of that amount, approximately $26 million is related to this consent agreement. Currently, we have made all submittals required by the agreement schedule and all submittals have been found to be acceptable. We do not expect that our compliance with the consent agreement will have a material adverse effect on our business, financial position, results of operations or cash flows.