*Item number corresponds to the similar item number in our Form 10-K for the year ended December 31, 2006.

The following tables set forth, for the periods and at the dates indicated, our summary historical financial and operating data. The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements. See also Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report for more information.

			Year Ended December 31,
	2006(5)			2005(6)			2004(7)			2003(8)			2002(9)
	(In millions, except per unit and ratio data)
Income and Cash Flow Data:
Revenues	$	9,048.7		$	9,745.9		$	7,893.0		$	6,583.6		$	4,200.2
Costs, Expenses and Other:
Gas purchases and other costs of sales		5,990.9			7,167.3			5,767.0			4,880.0			2,704.1
Operations and maintenance		777.0			719.5			488.6			388.6			366.4
Fuel and power		223.7			178.5			146.4			102.2			81.2
Depreciation, depletion and amortization		423.9			341.6			281.1			212.2			165.7
General and administrative		238.4			216.7			170.5			150.5			122.2
Taxes, other than income taxes		134.4			106.5			79.1			60.3			49.5
Other expense (income)		(31.2	)		—			—			—			—
		7,757.1			8,730.1			6,932.7			5,793.8			3,489.1

Operating income		1,291.6			1,015.8			960.3			789.8			711.1

Other income/(expense):
Earnings from equity investments		74.0			89.6			81.8			91.2			88.3
Amortization of excess cost of equity investments		(5.6	)		(5.5	)		(5.6	)		(5.5	)		(5.6	)
Interest, net		(337.8	)		(259.0	)		(192.9	)		(181.4	)		(176.5	)
Other, net		12.0			3.3			2.2			7.6			1.7
Minority interest		(15.4	)		(7.3	)		(9.6	)		(9.0	)		(9.5	)
Income tax provision		(29.0	)		(24.5	)		(19.7	)		(16.6	)		(15.3	)
Income from Continuing Operations		989.8			812.4			816.5			676.1			594.2
Income from Discontinued Operations		14.3			(0.2	)		15.1			17.8			14.2
Income before cumulative effect of a change in Accounting principle		1,004.1			812.2			831.6			693.9			608.4
Cumulative effect of a change in accounting principle		—			—			—			3.4			—
Net income	$	1,004.1		$	812.2		$	831.6		$	697.3		$	608.4
Less: General Partner’s interest in net income		(513.3	)		(477.3	)		(395.1	)		(326.5	)		(270.8	)
Limited Partners’ interest in net income	$	490.8		$	334.9		$	436.5		$	370.8		$	337.6

Basic Limited Partners’ Net Income per unit:
Income per unit from continuing operations and before cumulative effect of a change in accounting principle(1)	$	2.12		$	1.58		$	2.14		$	1.89		$	1.88
Income from Discontinued Operations		0.07			—			0.08			0.09			0.08
Cumulative effect of a change in accounting principle		—			—			—			0.02			—
Net income per unit	$	2.19		$	1.58		$	2.22		$	2.00		$	1.96
Diluted Limited Partners’ Net Income per unit:

Income per unit from continuing operations and before cumulative effect of a change in accounting principle(1)	$	2.12	$	1.58	$	2.14	$	1.89	$	1.88
Income from Discontinued Operations(10)		0.06		—		0.08		0.09		0.08
Cumulative effect of a change in accounting principle		—		—		—		0.02		—
Net income per unit	$	2.18	$	1.58	$	2.22	$	2.00	$	1.96

Per unit cash distribution declared(2)	$	3.26	$	3.13	$	2.87	$	2.63	$	2.435
Ratio of earnings to fixed charges(3)	$	3.64		3.76		4.84		4.68		4.29
Additions to property, plant and equipment	$	1,182.1	$	863.1	$	747.3	$	577.0	$	542.2

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations provides you with a narrative on our financial results. It contains a discussion and analysis of the results of operations for each segment of our business, followed by a discussion and analysis of our financial condition. The following discussion and analysis is based on our consolidated financial statements, which are included elsewhere in this report and were prepared in accordance with accounting principles generally accepted in the United States of America. You should read the following discussion and analysis in conjunction with our consolidated financial statements included elsewhere in this report.

As discussed in Notes 1 and 2 of the accompanying notes to consolidated financial statements, our consolidated financial statements have been restated to reflect the April 30, 2007 transfer of Trans Mountain as if such transfer had taken place on January 1, 2006. As a result, the financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations has also been restated and represents the combination of our previously reported results with those of Trans Mountain for all periods subsequent to January 1, 2006.

In addition, as discussed in Note 2 of the accompanying notes to consolidated financial statements, our consolidated financial statements contain the reclassifications necessary to reflect the results of our North System as discontinued operations, however, due to the fact that the sale of our North System does not change the structure of our internal organization in a manner that causes a change to our reportable business segments pursuant to the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” we have included the North System’s financial disclosures within our Products Pipelines business segment disclosures for all periods presented in this report.

We begin with a discussion of our Critical Accounting Polices and Estimates, those areas that are both very important to the portrayal of our financial condition and results and which require our management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.

Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of generally accepted accounting principles involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements.

We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining:

● the fair values used to allocate purchase price and to determine possible asset impairment charges;

● reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities;

We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed following.

With respect to our environmental exposure, 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. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. We do not discount environmental liabilities to a net present value, and we recognize receivables for

anticipated associated insurance recoveries when such recoveries are deemed to be probable.

The steps involved in the process of managing our environmental reporting include:

● identifying environmental regulatory issues that may affect us with respect to potential clean-up liabilities, and the necessary level of investigation in order to determine the potential cost associated with environmental exposures;

● completing a materiality analysis to determine the reporting necessary for each environmental issue; and

● evaluating alternatives to properly manage our environmental liabilities going forward, including items such as environmental insurance to help limit estimated costs, thereby assuring our unitholders that the volatility often associated with environmental estimates will not impair the value of their holdings.

Our recording of our environmental accruals often coincides with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. In both December 2005 and December 2004, after thorough reviews of any potential environmental issues and claims, we trued up (adjusted) our year-end environmental liabilities to reflect revisions to previously estimated costs. The adjustments, described more fully below, resulted in increases in environmental expenses.

In 2006, we made quarterly adjustments to our environmental liabilities to reflect changes in previous estimates. In addition to quarterly reviews of potential environmental issues and resulting environmental liability adjustments, we made supplemental liability adjustments in 2006 that were primarily related to newly identified and/or recently incurred environmental issues and claims (largely related to refined petroleum products pipeline releases of us and Plantation Pipe Line Company). These supplemental environmental liability adjustments were recorded pursuant to our management’s requirement to recognize contingent environmental liabilities whenever the associated environmental issue is likely to occur and the amount of our liability can be reasonably estimated. In making these liability estimations, we considered the 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 decrease in earnings associated with total environmental liability adjustments, including a $17.9 million decrease in earnings associated with supplemental liability adjustments. The total environmental expense adjustments (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.

The $17.9 million decrease in earnings related to supplemental environmental liability adjustments resulted in a $16.4 million increase in expense to our Products Pipelines business segment and a $1.5 million increase in expense to our Natural Gas Pipelines business segment. It consisted of a $14.9 million expense recorded within “Operations and maintenance,” a $4.9 million expense recorded within “Earnings from equity investments,” and a $1.9 million reduction in expense recorded within “Income Taxes” in our accompanying consolidated statement of income for 2006.

Our 2005 environmental liability adjustments resulted from both revisions to previously estimated costs and from the necessity of properly adjusting our environmental expenses and accrued liabilities between our reportable business segments, and combined, the adjustments resulted in a $23.3 million increase in environmental expense that primarily affected our Products Pipelines and 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. The adjustment included an $8.7 million increase in our estimated environmental receivables and reimbursables and a $32.0 million increase in our overall accrued environmental and related claim liabilities. We included the additional $23.3 million expense within “Operations and maintenance” in our accompanying consolidated statement of income for 2005.

In 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 $0.3 million expense item, including taxes, resulted from the necessity of properly adjusting our environmental expenses, liabilities and receivables between our four reportable business segments. The net impact of the $0.3 million expense item resulted in a $30.6 million increase in expense to our Products Pipelines business segment, a $7.6 million decrease in expense to our Natural Gas Pipelines business segment, a $4.1 million decrease in expense to our CO₂ business segment, and an $18.6 million decrease in expense to our Terminals business segment. 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.

For more information on our environmental disclosures, see Note 16 to our consolidated financial statements included elsewhere in this report.

We are subject to litigation and regulatory proceedings as a 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.

SFPP, L.P. is the subsidiary limited partnership that owns our Pacific operations’ pipelines, excluding CALNEV Pipe Line LLC. Tariffs charged by our Pacific operations’ pipeline systems are subject to certain proceedings at the FERC involving shippers’ complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services. Generally, the interstate rates on our Pacific operations’ pipeline systems are “grandfathered” under the Energy Policy Act of 1992 unless “substantially changed circumstances” are found to exist. To the extent “substantially changed circumstances” are found to exist, our Pacific operations may be subject to substantial exposure under these FERC complaints and could, therefore, owe reparations and/or refunds to complainants as mandated by FERC or the United States’ judicial system.

In December 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, and we included this amount within “Operations and maintenance” in our accompanying consolidated statement of income for 2005. The factors we considered when making this additional accrual included, among others: (i) the opinions and views of our legal counsel; (ii) our experience with reparations and refunds previously paid to complainants and other shippers as required by FERC (in 2003, we paid transportation rate reparation and refund payments in the amount of $44.9 million as mandated by the FERC); and (iii) the decision of our management as to how we intended to respond to the complaints, which included the compliance filing we submitted to the FERC on March 7, 2006.

In accordance with the FERC’s December 2005 Order and February 2006 Order on Rehearing, 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.

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 and February 2006 FERC Orders, 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. As of December 31, 2006, our total reserve related to various claims from lawsuits arising from our Pacific operations’ pipeline transportation rates amounted to $108.3 million.

In addition, in the third quarter of 2006, we made refund payments of $19.1 million to certain shippers on our Pacific operations’ pipelines and we reduced our rate case liability. The payment related to a settlement agreement reached in May 2006 that resolved certain challenges by complainants with regard to delivery tariffs and gathering enhancement fees at our Pacific operations’ Watson Station, located in Carson, California.

For more information on our Pacific operations’ regulatory proceedings, see Note 16 to our consolidated financial statements included elsewhere in this report.

Intangible assets are those assets which provide future economic benefit but have no physical substance. We account for our intangible assets according to the provisions of Statement of Financial Accounting Standards No. 141, “Business Combinations” and Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.” These accounting pronouncements introduced the concept of indefinite life intangible assets and provided that all identifiable intangible assets having indefinite useful economic lives, including goodwill, will not be subject to regular periodic amortization. Such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life 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.

As of January 1, 2007, our goodwill was $1,421.0 million. Included in the goodwill balance as of January 1, 2007, is $592.0 million related to Trans Mountain. On April 18, 2007, we announced that we would acquire the Trans Mountain pipeline system from Knight (formerly KMI), and this transaction was completed April 30, 2007 (discussed in Notes 1 and 2 to our consolidated financial statements included elsewhere in this report). Following the provisions of generally accepted accounting principles, this transaction caused Knight to consider the fair value of the Trans Mountain pipeline system, and to determine whether goodwill related to these assets was impaired. Based on supporting third-party information obtained regarding the fair values of the Trans Mountain pipeline system assets, Knight recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007.

Our remaining intangible assets, excluding goodwill, 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. As of December 31, 2006 and 2005, these intangibles totaled $213.2 million and $217.0 million, respectively.

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted or amortized into income and the presentation of supplemental information on oil and gas producing activities. The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas.

Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change.

We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in commodity prices and to balance our exposure to fixed and floating interest rates, and we believe that

these hedges are generally effective in realizing these objectives. However, the accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes.

According to the provisions of current accounting standards, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged. A perfectly effective hedge is one in which changes in the value of the derivative contract exactly offset changes in the value of the hedged item or expected cash flow of the future transactions in reporting periods covered by the derivative contract. The ineffective portion of the gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately; accordingly, our financial statements may reflect some volatility due to these hedges.

In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations. Even when we cannot enter into a completely effective hedge, we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all, but due to the fact that the part of the hedging transaction that is not effective in offsetting undesired changes in commodity prices (the ineffective portion) is required to be recognized currently in earnings, our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

● helping customers by providing energy, bulk commodity and liquids products transportation, storage and distribution; and

To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, bulk and liquids terminal facilities, and carbon dioxide and petroleum reserves. Our reportable business segments are based on the way our management organizes our enterprise, and each of our four segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.

	Year Ended December 31,
	2006			2005			2004
			(In millions)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments
Products Pipelines	$	491.2		$	370.1		$	444.9
Natural Gas Pipelines		574.8			500.3			418.3
CO₂		488.2			470.9			357.6
Terminals		408.1			314.6			281.7
Trans Mountain(a)		76.5			—			—
Segment earnings before depreciation, depletion and amortization of excess cost of equity investments(b)		2,038.8			1,655.9			1,502.5

Depreciation, depletion and amortization expense.		(432.8	)		(349.8	)		(288.6	)
Amortization of excess cost of investments		(5.7	)		(5.6	)		(5.6	)
Interest and corporate administrative expenses(c)		(596.2	)		(488.3	)		(376.7	)
Net income	$	1,004.1		$	812.2		$	831.6

Driven by the inclusion of Trans Mountain in our operating results, strong financial results from natural gas sales, storage and processing activities, and incremental earnings from both dry-bulk product and petroleum liquids terminal operations, we achieved a record level of net income in 2006. For the year 2006, our net income was $1,004.1 million ($2.18 per diluted unit) on revenues of $9,092.4 million. This compares with net income of $812.2 million ($1.58 per diluted unit) on revenues of $9,787.1 million in 2005, and net income of $831.6 million ($2.22 per diluted unit) on revenues of $7,932.9 million in 2004.

Because our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash consists primarily of all our cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. We also use segment earnings before depreciation, depletion and amortization expenses (defined in the table above) internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our four reportable business segments. Combined, our four business segments reported earnings before depreciation, depletion and amortization of $2038.8 million in 2006, $1,655.9 million in 2005 and $1,502.5 million in 2004.

The inclusion of Trans Mountain resulted in incremental earnings before depreciation, depletion, and amortization of $76.5 million in 2006. The remaining $306.4 million (19%) increase in total segment earnings before depreciation, depletion, and amortization in 2006 compared to 2005, and the $153.4 million (10%) increase

in 2005 compared to 2004 were attributable to internal growth and expansion and to incremental contributions from assets and operations acquired since the end of 2004. Combined, the net effect of the certain other items described in footnote (a) in the table above resulted in a $160.6 million (8%) increase in total segment earnings before depreciation, depletion and amortization expenses in 2006 relative to 2005, and a $141.7 million (8%) decrease in segment earnings in 2005 relative to 2004. The remaining increases of $145.8 million (3%) and $295.1 million (20%), respectively, in total segment earnings before depreciation, depletion and amortization in 2006 and 2005, relative to prior years, consisted of the following:

While it is difficult to predict change in demand for energy transportation, as well as future prices for energy commodity products and overall economic trends, we anticipated an approximate 12% increase in our total segment earnings before depreciation, depletion, and amortization expenses in 2007 compared to 2006, assuming our acquisition of Trans Mountain would occur in May 2007 and would have no impact on 2006. That is, the 12% increase in 2007 versus 2006 was determined before Trans Mountain was required to be included in our 2006 operating results. The key to our anticipated growth in 2007 will be the continued expansion of our businesses, principally through capital investments that will add throughput capacity to our refined products, natural gas, and crude oil pipeline systems; increase our natural gas storage capacity; expand and enhance our terminal services; and add infrastructure to our crude oil development and carbon dioxide flooding operations.

Additionally, we declared a cash distribution of $0.83 per unit for the fourth quarter of 2006 (an annualized rate of $3.32 per unit). This distribution was 4% higher than the $0.80 per unit distribution we made for the fourth quarter of 2005, and 12% higher than the $0.74 per unit distribution we made for the fourth quarter of 2004. We expect to declare cash distributions of at least $3.44 per unit for 2007; however, no assurance can be given that we will be able to achieve this level of distribution, and our expectation does not take into account any capital costs associated with financing the payment of reparations sought by shippers on our Pacific operations’ interstate pipelines. Our general partner and our common and Class B unitholders receive quarterly distributions in cash, while KMR, the sole owner of our i-units, receives quarterly distributions in additional i-units. The value of the quarterly per-share distribution of i-units is based on the value of the quarterly per-share cash distribution made to our common and Class B unitholders.

	Year Ended December 31,
	2006			2005			2004
	(In millions, except operating statistics)
Revenues	$	776.3		$	711.8		$	645.3
Operating expenses (including adjustments)(a)		(308.3	)		(366.0	)		(222.0	)
Earnings from equity investments(b)		16.3			28.5			29.0
Interest income and Other, net– income (expense)(c)		12.1			6.1			4.7
Income taxes(d)		(5.2	)		(10.3	)		(12.1	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		491.2			370.1			444.9

Depreciation, depletion and amortization expense		(82.9	)		(79.1	)		(71.3	)
Amortization of excess cost of equity investments		(3.4	)		(3.4	)		(3.3	)
Segment earnings	$	404.9		$	287.6		$	370.3

Gasoline (MMBbl)		455.2			457.8			459.1
Diesel fuel (MMBbl)		161.0			166.0			161.7
Jet fuel (MMBbl)		119.5			118.1			117.8
Total refined products volumes (MMBbl)		735.7			741.9			738.6
Natural gas liquids (MMBbl)		38.8			37.3			43.9
Total delivery volumes (MMBbl)(e)		774.5			779.2			782.5

Our Products Pipelines segment’s primary businesses include transporting refined petroleum products and natural gas liquids through pipelines and operating liquid petroleum products terminals and petroleum pipeline transmix processing facilities. The segment reported earnings before depreciation, depletion and amortization of $491.2 million on revenues of $776.3 million in 2006. This compares with earnings before depreciation, depletion and amortization of $370.1 million on revenues of $711.8 million in 2005, and earnings before depreciation, depletion and amortization of $444.9 million on revenues of $645.3 million in 2004.

The segment’s overall $121.1 million (33%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 and its $74.8 million (17%) decrease in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004 included an increase of $127.5 million and a decrease of $107.6 million, respectively, from the combined net effect of the certain other items described in the footnotes to the table above. These items consisted of the following:

The remaining $6.4 million (1%) decrease in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005, and the remaining $32.8 million (7%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004 consisted of the following items:

resulted from year-to-year decreases in both pipeline delivery volumes and pipeline repair costs. The decrease in expenses more than offset a 1% drop in operating revenues in 2006 versus 2005, due mainly to a decrease in transportation volumes resulting from pipeline operating pressure restrictions.

The decrease in earnings in 2005 resulted from both lower transportation revenues and higher operating expenses, when compared to 2004. The decrease in revenues was due to a drop in delivery volumes caused by extended pipeline testing and repair activities and by warmer winter weather, and the increase in operating expenses was due principally to higher pipeline repair, maintenance and testing costs;

The decrease in earnings in 2005 compared to 2004 was largely due to higher property tax expenses in 2005, due to expense reversals taken in the second quarter of 2004 pursuant to favorable property reassessments, and to lower product revenues resulting from the fourth quarter 2004 closure of our Gaffey Street products terminal located in San Pedro, California; and

The increase in earnings in 2005 relative to 2004 was mainly due to the recognition, in 2005, of incremental interest income of $2.5 million on our long-term note receivable from Plantation. In July 2004, we loaned $97.2 million to Plantation to allow it to pay all of its outstanding credit facility and commercial paper borrowings and in exchange for this funding, we received a seven year note receivable bearing interest at the rate of 4.72% per annum.

Revenues for the segment increased $64.4 million (9%) in 2006 compared to 2005, and increased $66.7 million (10%) in 2005 compared to 2004. The respective year-to-year increases in segment revenues were principally due to the following:

delivery revenues and a $6.4 million (7%) increase in refined products terminal revenues in 2006, compared to 2005. The increase from product deliveries reflect a 2% increase in mainline delivery volumes in 2006, and includes the impact of both rate reductions that went into effect on May 1, 2006, based on FERC filings associated with our Pacific operations’ rate litigation, and rate increases that went into effect July 1, 2006 and July 1, 2005, according to the FERC annual index rate increase (a producer price index-finished goods adjustment). The increase from terminal revenues was due to the higher transportation barrels and to incremental service revenues, including diesel lubricity-improving injection services that we began offering in May 2005.

Our Pacific operations’ $26.6 million increase in revenues in 2005 relative to 2004 included increases of $21.2 million (9%) from mainline refined products delivery revenues and $5.4 million (6%) from incremental terminal revenues. The increase from products delivery revenues was driven by a 2% increase in mainline delivery volumes and by increases in average mainline tariff rates; the increase from terminal operations was primarily due to increased terminal and ethanol blending services, largely as a result of the increase in pipeline throughput, and to incremental revenues from diesel lubricity-improving injection services.

The increase in mainline tariff rates included both FERC approved annual indexed interstate tariff increases in July 2004 and 2005, and a filed rate increase on our completed North Line expansion with the California Public Utility Commission. In November 2004, we filed an application with the CPUC requesting a $9 million increase in existing California intrastate transportation rates to reflect the in-service date of our $95 million North Line expansion project. Pursuant to CPUC regulations, this increase automatically became effective December 22, 2004, but is being collected subject to refund, pending resolution of protests to the application by certain shippers;

The 2005 increase was due to higher average tariff rates, which more than offset a drop in revenues caused by a decline in delivery volumes. The increase in tariff rates in 2005 over 2004 resulted from both a higher ratio of long haul shipments to shorter haul shipments and, to a lesser extent, higher published tariff rates that were approved by the FERC and became effective April 1, 2005. The new rates were associated with a cost of

service filing that was approved by the FERC. The decline in volumes was mainly related to lower propane demand due to warmer winter weather in the Midwest during 2005 relative to 2004; and

Combining all of the segment’s operations, total delivery volumes of refined petroleum products decreased 0.8% in 2006 compared to 2005, but increased 0.4% in 2005 compared to 2004. Compared to last year, our Pacific operations’ total delivery volumes were up 1.7%, due in part to the East Line expansion which was in service for the last seven months of 2006. The expansion project substantially increased pipeline capacity from El Paso, Texas to Tucson and Phoenix, Arizona. In addition, our CALNEV Pipeline delivery volumes were up 4.2% in 2006 versus 2005, due primarily to strong demand from the Southern California and Las Vegas, Nevada markets. The overall decrease in year-to-year segment deliveries of refined products was largely related to a 6.8% drop in volumes from the Plantation Pipeline in 2006, as described above. Compared to 2005, total deliveries of natural gas liquids increased 4.0% in 2006, driven by the higher volumes on our North System.

For 2005, the overall increase in delivery volumes compared with 2004 included increases on Pacific, Central Florida and CALNEV, offset by a decrease on Plantation. Excluding Plantation, which was impacted by Gulf Coast hurricanes and post-hurricane refinery disruptions in 2005, refined products delivery volumes increased 2.5% in 2005 compared to 2004. By product, deliveries of gasoline, diesel fuel and jet fuel increased 1.6%, 5.0% and 2.6%, respectively, in 2005 compared to 2004. Year-to-year deliveries of natural gas liquids were down 15% in 2005 versus 2004. The decrease was due to low demand for propane on both the North System and the Cypress Pipeline. The drop in demand on the North System was primarily due to a minimal grain drying season and to warmer weather in 2005; the drop on Cypress was chiefly due to reduced demand from a petrochemical plant located in Lake Charles, Louisiana, resulting from hurricane-related closures in 2005.

The segment’s operating expenses, which consist of all cost of sales expenses, operating and maintenance expenses, fuel and power expenses, and all tax expenses, excluding income taxes, decreased $57.8 million (16%) in 2006 versus 2005 and increased $144.0 million (65%) in 2005 versus 2004. Combined, the net effect attributable to four items previously discussed: (i) the expensing of pipeline integrity costs in 2006; (ii) the adjusting of segment environmental liability balances in 2006, 2005 and 2004; (iii) the adjusting of our Pacific operations’ pipeline rate case liability in 2005; and (iv) the expensing of inventory costs associated with the reconciliation of our North System’s inventory balances in 2005, resulted in a $104.7 million decrease in operating expenses in 2006 relative to 2005, and a $107.6 million increase in operating expenses in 2005 relative to 2004.

The remaining year-over-year increases of $46.9 million (21%) in 2006 compared to 2005 and $36.4 million (19%) in 2005 compared to 2004, primarily consisted of the following:

The $11.7 million increase in expenses in 2005 compared to 2004 was mainly due to higher labor and operating expenses, including incremental power expenses, associated with increased transportation volumes

and terminal operations. The segment also incurred higher maintenance and inspection expenses during 2005 as a result of environmental issues, clean-up, and pipeline repairs associated with wash-outs that were caused by flooding in the State of California in the first quarter of 2005;

Earnings from our Products Pipelines’ equity investments were $16.3 million in 2006, $28.4 million in 2005 and $29.1 million in 2004. Earnings from equity investments consist primarily of our approximate 51% interest in the pre-tax income of Plantation Pipe Line Company and our 50% interest in the net income of Heartland Pipeline Company and Johnston County Terminal, LLC. We include our proportionate share of Plantation’s income tax expenses within “Income taxes” in our accompanying statements of income, and the interest income we earn on loans to Plantation are reported within “Interest, net” in our accompanying statements of income.

The $12.1 million (43%) decrease in equity earnings in 2006 compared to 2005 was mainly due to lower equity earnings from Plantation, due to both a $6.6 million decrease for our proportionate share of Plantation’s pre-tax pipeline integrity expenses that were recognized in the second half of 2006, and a $4.9 million decrease for our proportionate share of pre-tax environmental expenses recognized by Plantation in the second quarter of 2006. This environmental expense was related to supplemental environmental and clean-up liability adjustments associated with an April 17, 2006 pipeline release of turbine fuel from Plantation’s 12-inch petroleum products pipeline located in Henrico County, Virginia.

The $0.7 million (2%) decrease in equity earnings in 2005 compared to 2004 primarily consisted of a $1.3 million (5%) decrease related to our investment in Plantation and a $0.8 million (55%) increase related to our investment in Heartland. For our investment in Plantation, the decrease was due to lower overall pre-tax income earned by Plantation, due to, among other things, higher operating expenses and higher interest expenses. For our investment in Heartland, the increase was due to Heartland’s higher net income, primarily due to higher pipeline delivery volumes in 2005 versus 2004.

The segment’s income from allocable interest income and other income and expense items increased $5.9 million (97%) in 2006 compared to 2005, and increased $1.4 million (31%) in 2005 compared to 2004. The 2006 increase was primarily due to the $5.7 million other income item from the favorable settlement of transmix processing contracts in the second quarter of 2006, and partly due to higher administrative overhead collected by our

West Coast terminals from reimbursable projects. For 2005, the increase primarily related to incremental interest income of $2.5 million on our long-term note receivable from Plantation, as discussed above.

Income tax expenses decreased $5.2 million (50%) in 2006 compared to 2005, and decreased $1.7 million (14%) in 2005 compared to 2004. The decrease in 2006 versus 2005 was related to the lower pre-tax earnings from Cochin and Plantation, and the decrease in 2005 versus 2004 was mainly due to lower income tax on Cochin due to the decrease in Canadian operating results in 2005.

Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments, were $86.3 million, $82.5 million and $74.6 million in each of the years ended December 31, 2006, 2005 and 2004, respectively. The $3.8 million (5%) increase in 2006 compared to 2005 was primarily due to higher depreciation expenses from our Pacific and Southeast terminal operations. The increase from our Pacific operations related to higher depreciable costs as a result of capital spending for both pipeline and storage expansion since the end of 2005 in order to strengthen and enhance our business operations on the West Coast. The increase from our Southeast terminal operations related to incremental depreciation charges resulting from final purchase price allocations, made in the fourth quarter of 2005, for depreciable terminal assets we acquired in November 2004 from Charter Terminal Company and Charter-Triad Terminals, LLC.

The overall $7.9 million (11%) increase in depreciation expenses in 2005 compared to 2004 was primarily due to higher depreciation expenses from our Pacific operations, related to the capital investments made since the end of 2004, as well as to incremental depreciation expenses of $1.8 million related to the Southeast terminal assets we acquired in March and November 2004.

	Year Ended December 31,
	2006			2005			2004
	(In millions, except operating statistics)
Revenues	$	6,577.7		$	7,718.4		$	6,252.9
Operating expenses (including environmental adjustments)(a)		(6,042.7	)		(7,255.0	)		(5,854.5	)
Earnings from equity investments		40.5			36.8			20.0
Interest income and Other, net – income (expense)		0.7			2.7			1.8
Income taxes		(1.4	)		(2.6	)		(1.9	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		574.8			500.3			418.3

Depreciation, depletion and amortization expense		(65.4	)		(61.7	)		(53.1	)
Amortization of excess cost of equity investments		(0.3	)		(0.2	)		(0.3	)
Segment earnings	$	509.1		$	438.4		$	364.9

Natural gas transport volumes (Trillion Btus)(b)		1,440.9			1,317.9			1,353.1
Natural gas sales volumes (Trillion Btus)(c)		909.3			924.6			992.4

Our Natural Gas Pipelines segment’s primary businesses involve marketing, transporting, storing, gathering and processing natural gas through both intrastate and interstate pipeline systems and related facilities. In 2006, the segment reported earnings before depreciation, depletion and amortization of $574.8 million on revenues of $6,577.7 million. This compares with earnings before depreciation, depletion and amortization of $500.3 million on

revenues of $7,718.4 million in 2005 and earnings before depreciation, depletion and amortization of $418.3 million on revenues of $6,252.9 million in 2004.

The segment’s overall $74.5 million (15%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 and its $82.0 million (20%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004 included an increase of $19.8 million and a decrease of $7.6 million, respectively, from the combined net effect of the certain other items described in footnote (a) to the table above. These items consisted of the following:

The segment’s remaining $54.7 million (11%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 was driven by higher earnings from our Texas intrastate natural gas pipeline group, primarily from improved margins resulting from the negotiation of renewal and incremental gas purchase and sales contracts, and by higher earnings from natural gas storage and processing activities. Our Texas intrastate group includes the operations of the following four natural gas pipeline systems: Kinder Morgan Tejas (including Kinder Morgan Border Pipeline), Kinder Morgan Texas Pipeline, Kinder Morgan North Texas Pipeline and our Mier-Monterrey Mexico Pipeline. Combined, the group accounted for 55% of the total increase in segment earnings before depreciation, depletion and amortization in 2006 versus 2005.

The segment’s remaining $89.6 million (22%) increase in earnings in 2005 compared with 2004 was mainly due to higher margins on recurring natural gas sales business and higher storage and service revenues from our Texas intrastate group, and to incremental contributions from the inclusion of our TransColorado Pipeline, a 300-mile interstate natural gas pipeline system that extends from the Western Slope of Colorado to the Blanco natural gas hub in northwestern New Mexico. We acquired the TransColorado Pipeline from KMI on November 1, 2004, and the incremental amounts above relate to TransColorado’s operations during the first ten months of 2005 and do not include increases or decreases during the same two months we owned the asset in both 2005 and 2004.

Specifically, the respective remaining changes in year-to-year segment earnings before depreciation, depletion and amortization expense in 2006 versus 2005, and 2005 versus 2004, consisted of the following:

Additionally, we manage price risk associated with unfavorable changes in natural gas prices by using energy derivative contracts, such as over-the-counter forward contracts and both fixed price and basis swaps, to help lock-in favorable margins from our natural gas purchase and sales activities, thereby generating more stable earnings during periods of fluctuating natural gas prices;

The increase in earnings in 2005 compared to 2004 was due mainly to higher revenues from both favorable fuel recovery volumes and prices and favorable imbalance valuation adjustments. In addition, KMIGT realized lower operating expenses in 2005 compared to 2004, primarily due to the expensing, in the fourth quarter of 2004, of certain capitalized project costs that no longer held realizable economic benefits. The increase in revenues in 2005 versus 2004 was partially offset by lower margins on operational gas sales and reduced cushion gas volumes sold;

The increase in earnings in 2005 compared to 2004 was largely due to incremental interest income from our long-term note receivable from Coyote. In 2005, we allocated this interest income to our Natural Gas Pipelines business segment, versus treating it as unallocated interest income in 2004. In March 2006, we contributed the principal amount of $17.0 million related to this note to our equity investment in Coyote. For more information on this note and on our equity contribution to Red Cedar, see Note 12 to our consolidated financial statements included elsewhere in this report.

In 2006, total segment operating revenues, including revenues from natural gas sales, decreased $1,140.7 million (15%) compared to 2005, and combined operating expenses, including natural gas purchase costs, decreased $1,212.3 million (17%). In 2005, the segment reported significant increases in both revenues and operating expenses when compared to the year-earlier period—revenues increased $1,465.5 million (23%) and operating expenses increased $1,400.4 million (24%). The year-to-year changes in total segment revenues and total segment operating expenses largely represented the respective changes in our Texas intrastate group’s natural gas sales revenues and natural gas purchase expenses, due primarily to year-over-year changes in natural gas prices.

Our Intrastate group’s purchase and sale activities result in considerably higher revenues and operating expenses compared to the interstate operations of our Rocky Mountain pipelines, which include our KMIGT, Trailblazer and TransColorado pipelines. All three pipelines charge a transportation fee for gas transmission service and have the authority to initiate natural gas sales primarily for operational purposes, but none engage in significant gas purchases for resale. We did, however, realize incremental revenues of $36.2 million and incremental operating expenses of $4.5 million from the ownership of our TransColorado Pipeline in the first ten months of 2005.

As discussed above, our Texas intrastate group both purchases and sells significant volumes of natural gas. Compared to the respective prior year, revenues from the sales of natural gas from our Intrastate group decreased $1,154.4 million (16%) in 2006, and increased $1,404.1 million (24%) in 2005; similarly, the group’s costs of sales expense, including natural gas purchase costs, decreased $1,202.4 million (17%) in 2006, and increased $1,373.4 million (24%) in 2005.

Since our Texas intrastate group sells natural gas in the same price environment in which it is purchased, any increases in its gas purchase costs are largely offset by corresponding increases in its sales revenues. Due to this offsetting of revenues and expenses, we believe that margin is a better comparative performance indicator than either revenues or cost of sales, and our objective is to match purchases and sales in the aggregate, and to lock-in an acceptable margin by capturing the difference between our average gas sales prices and our average gas purchase and cost of fuel prices. Our strategy involves relying mainly on long-term natural gas sales and purchase agreements, with some purchases and sales being made in the spot market in order to provide some flexibility to balance supply and demand in reaction to changing market conditions.

Our Texas intrastate groups’ natural gas sales margin increased $48.0 million (34%) and $30.7 million (28%), respectively, in 2006 and 2005, when compared to the year-earlier period. The variations in natural gas sales margin were driven by changes in natural gas prices and sales volumes—the $48.0 million margin increase in 2006 consisted of a $59.3 million increase from favorable changes in average sales versus average purchase prices (favorable price variance), and a $11.3 million decrease from lower volumes (unfavorable volume variance)—the $30.7 million margin increase in 2005 consisted of a $40.0 million increase from favorable changes in average sales prices versus average purchase prices, and a $9.3 million decrease from lower volumes. Also, the intrastate groups’ margins from natural gas processing activities increased $10.1 million (53%) in 2006 compared to 2005, and decreased $3.8 million (17%) in 2005 compared to 2004.

We account for the segment’s investments in Red Cedar Gathering Company, Thunder Creek Gas Services, LLC, and prior to September 1, 2006, Coyote Gas Treating, LLC under the equity method of accounting. Combined earnings from these three investees increased $3.6 million (10%) and $16.9 million (84%), respectively, in 2006 and 2005, when compared to year-earlier periods. The increases were chiefly due to higher net income earned by Red Cedar during 2006 and 2005, partially offset by lower net income from our combined investments in Coyote Gas Treating LLC and Thunder Creek Gas Services, LLC, all discussed above.

The segment’s combined interest income and earnings from other income items (Other, net) decreased $2.0 million (72%) in 2006 compared to 2005, and increased $0.9 million in 2005 compared to 2004. The 2006 decrease was chiefly due to a gain from a property disposal by our Kinder Morgan Tejas Pipeline in the third quarter of 2005. The 2005 increase was mainly due to the allocation of interest income earned, in 2005, on our note receivable from Coyote Gas Treating, LLC. Income tax expenses changed slightly over both 2006 and 2005—decreasing $1.2 million (46%) in 2006, and increasing $0.7 million (38%) in 2005, when compared to prior years. The changes primarily related to tax accrual adjustments related to the operations of our Mier-Monterrey Mexico Pipeline.

The segment’s non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments increased $3.7 million (6%) in 2006 compared to 2005, and increased $8.5 million (16%) in 2005 compared to 2004. The 2006 increase was largely attributable to higher year-to-year depreciation expenses from our Texas intrastate natural gas pipeline group, due both to incremental capital spending during 2006, and to additional depreciation charges related to the group’s acquisition of our North Dayton, Texas natural gas storage facility in August 2005. The 2005 increase was due to incremental depreciation expenses of $4.2 million from the inclusion of the acquired TransColorado Pipeline, and higher depreciation expenses on the assets of our Texas intrastate natural gas pipeline group, due to additional capital investments made since the end of 2004.

	Year Ended December 31,
	2006		2005		2004
	(In millions, except operating statistics)
Revenues(a)	$	736.5	$	657.6	$	492.8
Operating expenses (including environmental adjustments)(b)		(268.1)		(212.6)		(169.3)
Earnings from equity investments		19.2		26.3		34.2
Other, net – income (expense)		0.8		0.0		0.0
Income taxes		(0.2)		(0.4)		(0.1)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		488.2		470.9		357.6

Depreciation, depletion and amortization expense(c)		(190.9)		(149.9)		(121.4)
Amortization of excess cost of equity investments		(2.0)		(2.0)		(1.9)
Segment earnings	$	295.3	$	319.0	$	234.3

Carbon dioxide delivery volumes (Bcf)(d)		669.2		649.3		640.8
SACROC oil production (gross)(MBbl/d)(e)		30.8		32.1		28.3
SACROC oil production (net)(MBbl/d)(f)		25.7		26.7		23.6
Yates oil production (gross)(MBbl/d)(e)		26.1		24.2		19.5
Yates oil production (net)(MBbl/d)(f)		11.6		10.8		8.6
Natural gas liquids sales volumes (net)(MBbl/d)(f)		8.9		9.4		7.7
Realized weighted average oil price per Bbl(g)(h)	$	31.42	$	27.36	$	25.72
Realized weighted average natural gas liquids price per Bbl(h)(i)	$	43.90	$	38.98	$	31.33

Our CO₂ segment consists of Kinder Morgan CO₂ Company, L.P. and its consolidated affiliates. The segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO₂) and crude oil, and the production and marketing of natural gas and natural gas liquids. In 2006, our CO₂ segment reported earnings before depreciation, depletion and amortization of $488.2 million on revenues of $736.5 million. This compares with earnings before depreciation, depletion and amortization of $470.9 million on revenues of $657.6 million in 2005, and earnings before depreciation, depletion and amortization of $357.6 million on revenues of $492.8 million in 2004.

The segment’s overall $17.3 million (4%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 and its $113.3 million (32%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004 included decreases of $1.5 million and $4.4 million, respectively, from the combined net effect of the certain other items described in footnotes (a) and (b) to the table above. These items consisted of the following:

The segment’s remaining $18.8 million (4%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 was driven by higher earnings from the segment’s carbon dioxide sales and transportation activities; the remaining $117.7 million (33%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004 was primarily due to higher earnings from the segment’s oil and gas producing activities.

The segment’s carbon dioxide sales and transportation activities reported earnings before depreciation, depletion and amortization of $186.8 million in 2006, $162.4 million in 2005, and $123.6 million in 2004. The increases in earnings were driven by higher revenues—from both carbon dioxide sales and deliveries, and from crude oil pipeline transportation. The overall increases were partly offset by lower equity earnings from the segment’s 50% ownership interest in Cortez Pipeline Company.

The increases in carbon dioxide sales revenues were due to both higher average prices and higher sales volumes. Correlating closely with the increase in crude oil prices since the end of 2004, average carbon dioxide sales prices increased 18% and 44%, respectively, in 2006 and 2005, when compared to the prior year. In addition, we did not use derivative contracts to hedge or help manage the financial impacts associated with the increases in carbon dioxide prices, and as always, we did not recognize profits on carbon dioxide sales to ourselves.

The increases in volumes were largely attributable to the continued strong demand for carbon dioxide from tertiary oil recovery projects in the Permian Basin area since the end of 2004, and to increased carbon dioxide production from the McElmo Dome source field. We operate and own a 45% interest in McElmo Dome, which supplies carbon dioxide to oil recovery fields in the Permian Basin of southeastern New Mexico and West Texas. Combined deliveries of carbon dioxide on our Central Basin Pipeline, our majority-owned Canyon Reef Carriers

and Pecos Pipelines, our Centerline Pipeline, and our 50% owned Cortez Pipeline, which is accounted for under the equity method of accounting, increased 3% in 2006 and 1% in 2005, when compared to the respective prior years.

The increases in revenues from carbon dioxide and crude oil transportation were due to higher delivery volumes and higher rates. The increase in volumes was largely related to infrastructure expansions at the SACROC and Yates oil field units. The SACROC and Yates units are the two largest oil field units in which we hold ownership interests—these interests include our approximate 97% working interest in the SACROC unit, located in Scurry County, Texas, and our approximate 50% working interest in the Yates unit, located south of Midland, Texas.

In 2005, we also benefited from the acquisition of the Kinder Morgan Wink Pipeline, a 450-mile crude oil pipeline system originating in the Permian Basin of West Texas and providing throughput to a crude oil refinery located in El Paso, Texas. Effective August 31, 2004, we acquired all of the partnership interests in Kinder Morgan Wink Pipeline, L.P. for $89.9 million in cash and the assumption of $10.4 million in liabilities. The acquisition of the pipeline and associated storage facilities allowed us to better manage crude oil deliveries from our oil field interests in West Texas. During the first eight months of 2005, the Kinder Morgan Wink Pipeline accounted for incremental earnings before depreciation, depletion and amortization of $13.4 million, revenues of $16.7 million and operating expenses of $3.3 million.

The remaining changes in year-to-year segment earnings before depreciation, depletion and amortization—a decrease of $7.1 million (2%) in 2006 versus 2005, and an increase of $74.5 million (32%) in 2005 versus 2004, were attributable to the segment’s crude oil and natural gas producing activities, which also include its natural gas processing activities. These operations include all construction, drilling and production activities necessary to produce oil and gas from its natural reservoirs, and all of the activities where natural gas is processed to extract liquid hydrocarbons, called natural gas liquids or commonly referred to as gas plant products. Combined, our CO₂ segment’s oil and gas producing and gas processing activities reported earnings before depreciation, depletion and amortization of $301.4 million in 2006, $308.5 million in 2005, and $234.0 million in 2004.

In both 2006 and 2005, we made significant capital investments to increase the capacity and deliverability of carbon dioxide and crude oil in and around the Permian Basin. Our investments were made in order to benefit from rising price trends for energy commodity products and from continued strong demand for carbon dioxide from tertiary oil recovery projects, which commonly inject carbon dioxide into reservoirs adjacent to producing crude oil wells. Once injected into the reservoir, the carbon dioxide gas often enhances crude oil recovery in two ways—first, by expanding and pushing additional oil to the production wellbore, and secondly, by dissolving into the oil in order to lower its viscosity and improve its flow rate. In 2006, capital expenditures for our CO₂ business segment totaled $283.0 million; this compares with capital expenditures of $302.1 million in 2005 and $302.9 million in 2004. The expenditures primarily represent incremental spending for new well and injection compression facilities at the SACROC and, to a lesser extent, Yates oil field units.

The year-over-year $7.1 million (2%) decrease in earnings in 2006 compared to 2005 was primarily due to higher combined operating expenses and to a previously disclosed drop in crude oil production at the SACROC oil field unit. The higher operating expenses included higher field operating and maintenance expenses (including well workover expenses), higher property and severance taxes, and higher fuel and power expenses. The increases in expenses more than offset higher overall crude oil and natural gas plant product sales revenues, which increased primarily from higher realized sales prices and partly from higher crude oil production at the Yates oil field unit. The year-over-year increase in earnings of $74.5 million (32%) in 2005 compared to 2004 was primarily driven by increased crude oil and natural gas processing plant liquids production volumes, and by higher realized weighted average sale prices for crude oil and gas plant products.

The year-to-year decline in crude oil production at the SACROC unit in 2006 was announced in the first quarter of 2006. At that time, we used information obtained from production performance to change our previous estimates of proved crude oil reserves at SACROC; however, due to the fact that the decrease in production is largely specific to one section of the field that is underperforming, we do not expect this reserve revision to have a material impact on our financial statements or capital spending in future periods. For more information on our ownership interests in

the net quantities of proved oil and gas reserves and our measures of discounted future net cash flows from oil and gas reserves, please see Note 20 to our consolidated financial statements included elsewhere in this report.

As a result of our carbon dioxide and oil reserve ownership interests, we are exposed to commodity price risk associated with physical crude oil and natural gas liquids sales; however we mitigate this price risk through a long-term hedging strategy that uses derivative contracts to reduce the impact of unpredictable changes in crude oil and natural gas liquids sales prices. Our goal is to use derivative contracts in order to prevent or reduce the possibility of future losses, and to generate more stable realized prices. Our hedging strategy involves the use of financial derivative contracts to manage this price risk on certain activities, including firm commitments and anticipated transactions for the sale of crude oil and natural gas liquids. Our strategy, as it relates to our oil production business, primarily involves entering into a forward sale or, in some cases, buying a put option in order to establish a known price level. In this way, we use derivative contracts to lock in an acceptable margin between our production costs and our selling price, in an attempt to protect ourselves against the risk of adverse price changes and to maintain a more stable and predictable earnings stream.

Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $63.27 per barrel in 2006, $54.45 per barrel in 2005 and $40.91 per barrel in 2004. In periods of rising prices for crude oil and natural gas liquids, we often surrender profits that would result from period-to-period price increases. We believe, however, that our use of derivative contracts protects our unitholders from unpredictable adverse events. All of our hedge gains and losses for crude oil and natural gas liquids are included in our realized average price for oil; none are allocated to natural gas liquids. For more information on our hedging activities, see Note 14 to our consolidated financial statements included elsewhere in this report.

Including the $1.8 million hedge ineffectiveness loss in 2006, our CO₂ segment’s revenues increased $78.9 million (12%) in 2006 compared to 2005, and $164.8 million (33%) in 2005 compared to 2004. The respective year-over-year increases were primarily due to the following:

SACROC field and partly to natural gas volumes used at the power plant we constructed at the SACROC oil field unit and placed in service in June 2005.

Construction of the plant began in mid-2004, and the project was completed at a cost of approximately $76 million. We constructed the SACROC power plant in order to reduce our purchases of electricity from third-parties, but it reduces our sales of natural gas because some natural gas volumes are consumed by the plant. The power plant now provides approximately half of SACROC’s current electricity needs. KMI operates and maintains the power plant under a five-year contract expiring in June 2010, and we pay KMI an annual operating and maintenance fee.

Compared to the respective prior years, the segment’s operating expenses increased $55.5 million (26%) in 2006 and $43.4 million (26%) in 2005. The increases consisted of the following:

Our oil and gas operations, coupled with carbon dioxide flooding, often require a high level of investment, including ongoing expenses for facility upgrades, wellwork and drilling. We continue to aggressively pursue opportunities to drill new wells and/or expand existing wells for both carbon dioxide and crude oil in order to benefit from robust demand for energy commodities in and around the Permian Basin area. As discussed in Note 2 to our consolidated financial statements included elsewhere in this report, in some cases, the cost of carbon dioxide that is associated with enhanced oil recovery is capitalized as part of our development costs when it is injected. The carbon dioxide costs incurred and capitalized as development costs for our CO₂ segment were $100.5 million, $74.7 million and $70.6 million for the years ended December 31, 2006, 2005 and 2004, respectively;

Earnings from equity investments, representing equity earnings from our 50% ownership interest in the Cortez Pipeline Company, decreased $7.1 million (27%) in 2006 compared to 2005, and $7.9 million (23%) in 2005 compared to 2004. Cortez owns and operates an approximate 500-mile pipeline that carries carbon dioxide from the McElmo Dome source reservoir to the Denver City, Texas carbon dioxide hub. The decreases in equity earnings were due to lower year-over-year net income earned by Cortez since 2004, mainly as a result of lower carbon dioxide transportation revenues. The decreases in transportation revenues resulted from lower year-to-year average tariff rates, which more than offset incremental revenues realized as a result of higher carbon dioxide delivery volumes. The decreases in tariff rates were expected because we benefited from higher tariffs in prior years, when tariffs were set higher in order to make up for under-collected revenues.

Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of equity investments, increased $41.0 million (27%) in 2006 compared to 2005, and $28.5 million (23%) in 2005 compared to 2004. The increases were due to both higher depreciable costs, as a result of incremental capital spending since the end of 2004, and higher combined depreciation and depletion charges, related to year-over-year increases in crude oil production volumes. In 2006, we also realized incremental depreciation charges of $3.4 million attributable to the various oil and gas properties we acquired in April 2006 from Journey Acquisition – I, L.P. and Journey 2000, L.P.

The increase in depreciation expenses in 2006 compared to 2005 was also due to a higher unit-of-production depletion rate used in 2006, related to changes in estimated oil and gas reserves at the SACROC oil field unit. Our capitalized costs of proved oil and gas properties must be amortized by the unit of production method so that each unit produced is assigned a pro rata portion of the unamortized costs. These amortization rates must be revised at least annually, but are also adjusted if there is an indication that total estimated units are different than previously estimated.

		Year Ended December 31,
		2006			2005			2004
	(In millions, except operating statistics)
Revenues		$	864.8		$	699.3		$	541.9
Operating expenses (including environmental adjustments)(a)			(446.7	)		(373.4	)		(254.1	)
Earnings from equity investments			0.2			0.1			0.0
Other, net – income (expense)			2.1			(0.2	)		(0.5	)
Income taxes(b)			(12.3	)		(11.2	)		(5.6	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments			408.1			314.6			281.7

Depreciation, depletion and amortization expense			(74.6	)		(59.1	)		(42.9	)
Amortization of excess cost of equity investments			—			—			—
Segment earnings		$	333.5		$	255.5		$	238.8

Bulk transload tonnage (MMtons)(c)			89.5			85.5			84.1
Liquids leaseable capacity (MMBbl)			43.5			42.4			36.8
Liquids utilization %			96.3	%		95.4	%		96.0	%

Our Terminals segment includes the operations of our petroleum and petrochemical-related liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, steel and other dry-bulk material services facilities. Refining, manufacturing, mining and quarrying companies worldwide depend on these facilities to provide liquids and bulk handling services, transload, engineering, and other in-plant services to supply marine, rail, truck, temporary storage, and other distribution means needed to move dry-bulk, bulk petroleum, and chemicals across the United States. The segment reported earnings before depreciation, depletion and amortization of $408.1 million on revenues of $864.8 million in 2006. This compares with earnings before depreciation, depletion and amortization of $314.6 million on revenues of $699.3 million in 2005 and earnings before depreciation, depletion and amortization of $281.7 million on revenues of $541.9 million in 2004.

The segment’s overall $93.5 million (30%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 and its $32.9 million (12%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004, included an increase of $14.8 million and a decrease of $22.1 million, respectively, from the combined net effect of the certain other items described in footnotes (a) and (b) to the table above. These items consisted of the following:

The $11.3 million increase in segment earnings consisted of: (i) a $15.2 million property casualty gain; (ii) a $2.8 million increase in operating and maintenance expenses from hurricane repair and recovery activities; and (iii) a $1.1 million increase in income tax expense associated with the segment’s overall hurricane income and expense items. Including an additional $0.4 million decrease in general and administrative expenses, and a $3.1 million increase in minority interest expense, both related to hurricane activity and described below in “—Other,” total hurricane income and expense items increased our net income by $8.6 million in 2006. For more information on our property casualty gain, see Note 6 to our consolidated financial statements included elsewhere in this report; and

The segment’s remaining $78.7 million (4%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005, and its remaining $55.0 million (21%) increase in 2005 compared to 2004 were driven by a combination of internal expansions and strategic acquisitions. We make and continue to seek key terminal acquisitions in order to gain access to new markets, to complement and/or enlarge our existing terminal operations, and to benefit from the economies of scale resulting from increases in storage, handling and throughput capacity.

Our significant terminal acquisitions since the beginning of 2005 included the following:

We have invested approximately $305.5 million in cash and $49.6 million in common units to acquire these terminal assets and combined, these operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $33.5 million, revenues of $68.8 million and operating expenses of $35.3 million, respectively, in 2006. A majority of these increases in earnings, revenues and expenses from terminal acquisitions were attributable to the inclusion of our Texas petroleum coke terminals and repair shop assets, which we acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an aggregate consideration of approximately $247.2 million. The primary assets acquired included facilities and railway equipment located at the Port of Houston, the Port of Beaumont and the TGS Deepwater terminal located on the Houston Ship Channel. Combined, these operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $16.8 million, revenues of $31.0 million and operating expenses of $14.2 million, respectively, in 2006.

For 2005, we benefited significantly from the incremental contributions attributable to the bulk and liquids terminal businesses we acquired since the end of the third quarter of 2004. In addition to the 2005 acquisitions referred to above, these acquisitions included:

Combined, terminal operations acquired since the end of the third quarter of 2004 accounted for incremental amounts of earnings before depreciation, depletion and amortization of $45.5 million, revenues of $113.8 million and operating expenses of $65.0 million, respectively, in 2005. All of the incremental amounts listed above for both 2006 and 2005, represent the earnings, revenues and expenses from the acquired terminals’ operations during the additional months of ownership in 2006, and 2005, respectively, and do not include increases or decreases during the same months we owned the assets in 2005 and 2004, respectively. For more information in regard to our terminal acquisitions, see Note 3 to our consolidated financial statements included elsewhere in this report.

For all other terminal operations (those owned during the same months of both comparable years), earnings before depreciation, depletion and amortization increased $60.0 million (19%) in 2006 compared to 2005, and decreased $12.6 million (4%) in 2005 compared to 2004; however, as described above, the net effect of the property casualty gain, hurricane repair expenses (net of income tax), and environmental liability adjustments resulted in a $14.8 million increase in earnings before depreciation, depletion and amortization in 2006 relative to 2005, and a $22.1 million decrease in 2005 relative to 2004. The remaining change in the earnings before depreciation, depletion and amortization expenses from terminal operations owned during both years consisted of a $45.2 million (14%) increase in 2006 compared to 2005, and a $9.5 million (4%) increase in 2005 compared to 2004. These respective year-to-year increases in earnings primarily consisted of the following:

The year-over-year increase in earnings in 2006 versus 2005 was primarily revenue related, driven by increases from new and incremental customer agreements, additional liquids tank capacity from capital expansions at our Pasadena terminal since the end of 2005, higher truck loading rack service fees, higher ethanol throughput, and incremental revenues from customer deficiency charges.

Since the end of 2004, we have obtained additional customer contracts, extended existing customer contracts and remarketed expiring contracted capacity at competitive rates. For our Gulf Coast and other liquids

terminals, our existing contracts generally mature at various times and in varying amounts of throughput capacity, therefore, we continue to manage our recontracting process in order to limit the risk of significant impacts on our revenues. The increase in earnings in 2005 versus 2004 was also largely due to higher revenues, driven by higher sales of petroleum transmix, new customer agreements, and escalations in annual contract provisions;

The decrease in earnings in 2005 compared to 2004 included a $2.1 million decrease in earnings from our Pier IX bulk terminal, located in Newport News, Virginia, and a $2.0 million decrease in earnings from our Chesapeake Bay facility, located in Sparrows Point, Maryland. The decrease from Pier IX was primarily due to higher operating expenses in 2005 compared to 2004, due to incremental operating expenses associated with a new synfuel maintenance program and higher demurrage expenses associated with increased cement imports. The decrease from our Chesapeake terminal was mainly due to higher operating expenses associated with higher movements of petroleum coke;

The overall decrease in earnings from our Louisiana region terminals in 2005 compared to 2004 was largely related to the negative effects of the two Gulf Coast hurricanes in 2005, resulting in an overall general loss of business. In addition to property damage incurred, throughput at the facilities impacted by the storms decreased in 2005 compared to 2004 largely due to post-hurricane production issues at a number of Gulf Coast refineries. In 2005, our Terminals segment realized essentially all of our losses related to both hurricanes, and in total, the segment recognized $2.6 million in expense in 2005 in order to meet its insurance deductible for Hurricane Katrina. We also recognized another $0.8 million to repair damaged facilities following Hurricane Rita, but estimates of lost business at our terminal sites are difficult because of insurance complexities and the extended recovery time involved;

The decrease in 2005 compared to 2004 was driven by lower earnings from the dry-bulk services at our Port Newark, New Jersey facility. The decrease was largely due to lower salt tonnage, shipping activity, and stevedoring services, all primarily due to warmer winter weather in 2005; and

The overall increase in 2005 compared to 2004 included higher earnings from our Dakota bulk terminal, located along the Mississippi River near St. Paul, Minnesota; our Argo, Illinois liquids terminal, situated along the Chicago sanitary and ship channel; and our Milwaukee, Wisconsin bulk commodity terminal. The increase in earnings from Dakota was primarily due to higher revenues generated by a cement unloading and storage facility, which began operations in late 2004. The increase from our Argo terminal was mainly due to new customer contracts and higher ethanol handling revenues. The increase from our Milwaukee bulk terminal was mainly due to an increase in coal handling revenues related to higher coal truckage within the State of Wisconsin.

Segment revenues from terminal operations owned during identical periods of both 2006 and 2005 increased $96.7 million (14%) in 2006, when compared to the prior year. The overall increase was primarily due to the following:

For all bulk terminal facilities combined, total transloaded bulk tonnage volumes increased over 4.5% in 2006, when compared to 2005. The overall increase in bulk tonnage volumes included a 10% increase in coal transfer volumes and a 13% increase in ores/metals transload volumes. We also completed, in 2006, capital expansion and betterment projects at certain of our liquids terminal facilities that included the construction of additional petroleum

products storage tanks. The construction, when combined with increases from external acquisitions, increased our liquids storage capacity by approximately 1.1 million barrels (2.6%) in 2006. At the same time, we increased our liquids utilization capacity rate by 1%, compared to the prior year. Our liquids terminals utilization rate is the ratio of our actual leased capacity to our estimated potential capacity. Potential capacity is generally derived from measures of total capacity, taking into account periodic changes to our terminal facilities due to additions, disposals, obsolescence, or other factors.

Segment revenues for all terminals owned during identical periods of both 2005 and 2004 increased $43.6 million (8%) in 2005, when compared to the prior year. The increase was primarily due to the following:

Operating expenses from all terminals owned during identical periods of both 2006 and 2005 increased $38.1 million (10%) in 2006 compared to 2005. Combined, the net effect of the environmental liability adjustments, hurricane repair expenses, and the property casualty gain on terminals owned during the same portions of both comparable periods resulted in a $15.9 million decrease in segment operating expenses in 2006 relative to 2005. The remaining change in year-to-year operating expenses—an increase of $54.0 million (15%)—from all terminals owned during identical periods of both 2006 and 2005 primarily consisted of the following:

For terminal operations owned during the same months of both 2005 and 2004, operating expenses increased $54.3 million (21%) in 2005 compared to 2004. The overall increase included a $22.1 million increase in expense attributable to the 2005 and 2004 environmental liability adjustments. The remaining $32.2 million (12%) increase in operating expenses in 2005 versus 2004 from terminal operations owned during both years primarily consisted of the following:

The segment’s earnings from equity investments remained flat across both 2006 and 2005, when compared to prior years. Income from other items was essentially unchanged in 2005 versus 2004, but increased $2.3 million in 2006 compared to 2005. The increase in 2006 was chiefly due to the $1.8 million income item related to a settlement associated with our Kinder Morgan St. Gabriel terminal, discussed above, and to a $1.2 million increase related to a disposal loss, recognized in 2005, on warehouse property at our Elizabeth River bulk terminal, located in Chesapeake, Virginia.

Income tax expenses totaled $12.2 million in 2006, $11.1 million in 2005 and $5.6 million in 2004. The $1.1 million (10%) increase in 2006 versus 2005 reflects, among other things, incremental income tax expense associated with hurricane related income and expense items. The $5.5 million (98%) increase in 2005 compared to 2004 was mainly attributable to the year-to-year changes in both taxable income and certain permanent differences between taxable income and financial income of Kinder Morgan Bulk Terminals, Inc. and its consolidated subsidiaries. Kinder Morgan Bulk Terminals, Inc. is the tax-paying entity that owns many of our bulk terminal businesses which

handle non-qualifying products. In general, the segment’s income tax expenses will change period to period based on the classification of income before taxes between amounts earned by corporate subsidiaries and amounts earned by partnership subsidiaries.

Non-cash depreciation, depletion and amortization charges increased $15.5 million (26%) in 2006 compared to 2005 and $16.2 million (38%) in 2005 compared to 2004. The year-over-year increases in depreciation expenses reflect a rising depreciable capital base since the end of 2004, with growth due to a combination of business acquisitions and internal capital spending. Collectively, the terminal assets we acquired since the beginning of 2005 and listed above accounted for incremental depreciation expenses of $8.2 million in 2006, and the assets we acquired since the third quarter of 2004 and listed above accounted for incremental depreciation expenses of $12.4 million in 2005. The remaining increases in year-to-year depreciation expenses were associated with capital spending on numerous improvement projects completed since 2004 in order to expand and enhance our terminal services.

	Year Ended December 31,
	2006			2005		2004
	(In millions, except operating statistics)
Revenues	$	137.8		$	─	$	─
Operating expenses (including environmental adjustments)		(52.4	)		─		─
Earnings from equity investments		─			─		─
Other, net – income (expense)		1.0			─		─
Income taxes		(9.9	)		─		─
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		76.5			─		─

Depreciation, depletion and amortization expense		(19.0	)		─		─
Amortization of excess cost of equity investments		─			─		─
Segment earnings	$	57.5		$	─		─

Transport volumes (MMBbl)		83.7

Our Trans Mountain segment includes the operations of the Trans Mountain Pipeline, which we acquired from Knight effective April 30, 2007. Trans Mountain transports crude oil and refined products from Edmonton, Alberta to marketing terminals and refineries in British Columbia and the State of Washington. An additional expansion that will increase capacity on the pipeline to approximately 300,000 barrels per day is currently under construction and is expected to be in service by late 2008.

According to the provisions of generally accepted accounting principles that prescribe the standards used to account for business combinations, our acquisition of Trans Mountain from Knight represented a transfer of assets between entities under common control. As a result, Trans Mountain is reflected in our results as of January 1, 2006, the date on which Knight began consolidating us (the date of common control), and we recorded the assets and liabilities of Trans Mountain transferred to us from Knight at their carrying amounts in the accounts of Knight.

Items not attributable to any segment include general and administrative expenses, unallocable interest income, interest expense and minority interest. We also included the $1.6 million loss from our early extinguishment of debt in 2004 as an item not attributable to any business segment. The loss from the early extinguishment of debt represented the excess of the price we paid to repurchase and retire the principal amount of $87.9 million of tax-exempt industrial revenue bonds over the bonds’ carrying value. Pursuant to certain provisions that gave us the right to call and retire the bonds prior to maturity, we took advantage of the opportunity to refinance at lower rates, and we included the $1.6 million loss under the caption “Other, net” in our accompanying consolidated statement of income. For more information on this early extinguishment of debt, see Note 9 to our consolidated financial statements, included elsewhere in this report.

Our general and administrative expenses include such items as salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services—including accounting, information technology, human resources and legal services. Overall general and administrative expenses totaled $238.4 million in 2006, $216.7 million in 2005 and $170.5 million in 2004. Generally, the year-to-year increases in our general and administrative expenses reflect increased spending levels in support of our growth initiatives, and we continue to aggressively manage our infrastructure expense and to focus on our productivity and expense controls. As described in the footnotes to the table above, the 2006 expenses included incremental expenses of $18.8 million due to our inclusion of Trans Mountain.

The remaining $2.9 million (1%) increase in overall general and administrative expenses in 2006 compared to 2005 was primarily due to higher corporate service charges and higher corporate and employee-related insurance expenses in 2006, when compared to the prior year. The increase in corporate services was largely due to higher corporate overhead expenses associated with the business operations we acquired since the end of 2005. The increase in insurance expenses was partly due to incremental expenses related to the cancellation of certain commercial insurance polices in the second quarter of 2006, as well as to the overall variability in year-to-year commercial property and medical insurance costs. Pursuant to certain provisions that gave us the right to cancel certain commercial policies prior to maturity, we took advantage of the opportunity to reinsure at lower rates.

The overall increase in general and administrative expenses in 2006 compared to 2005 was partly offset a $33.4 million decrease in unallocated litigation and environmental settlement expenses and a $0.4 million decrease in expense from the allocation of general and administrative overhead expenses to hurricane related capital projects. The decrease in expense from unallocated litigation and environmental settlement expenses consisted of: (i) a $25.0 million expense in 2005 for a settlement reached between us and a former joint venture partner on our Kinder Morgan Tejas natural gas pipeline system; and (ii) a cumulative $8.4 million expense in 2005 related to settlements of environmental matters at certain of our operating sites located in the State of California. For more information on our litigation matters, see Note 16 to our consolidated financial statements, included elsewhere in this report.

The $46.2 million (27%) increase in general and administrative expenses in 2005 compared to 2004 was due to the incremental litigation and environmental settlement expenses of $33.4 million described above, as well as higher expenses incurred from KMI’s operation of our natural gas pipeline assets (associated with higher actual costs in 2005 versus lower negotiated costs in 2004), higher insurance expenses (largely due to higher workers compensation claims) and higher legal, benefits, and corporate secretary services expenses.

Interest expense, net of unallocable interest income, totaled $342.4 million in 2006, $264.3 million in 2005 and $194.9 million in 2004. We incurred incremental expenses of $6.3 million in 2006 due to the inclusion of Trans Mountain, and the remaining $71.8 million (27%) increase in net interest expense in 2006 compared to 2005 was due to both higher average debt levels and higher effective interest rates. In 2006, average borrowings (excluding the market value of interest rate swaps) increased 10% and the weighted average interest rate on all of our borrowings increased 17%, when compared to 2005 (the weighted average interest rate on all of our borrowings was

approximately 6.1779% during 2006 and 5.3019% during 2005). The increase in average borrowings was mainly due to higher capital spending in 2006, the acquisition of external assets and businesses since the end of 2005, and a net increase, since March 2005, of $300 million in principal amount of long-term senior notes.

Generally, we fund both our capital spending (including payments for pipeline project construction costs) and our acquisition outlays from borrowings under our commercial paper program. The net changes in the principal amount of our senior notes relate to changes occurring on March 15, 2005. On that date, we both closed a public offering of $500 million in principal amount of senior notes and retired a principal amount of $200 million. From time to time we issue senior notes in order to refinance our commercial paper borrowings. For more information on our capital expansion and acquisition expenditures, see “Liquidity and Capital Resources — Investing Activities”.

The increase in our average borrowing rate in 2006 reflects a general rise in variable interest rates since the end of 2005. We use interest rate swap agreements to help manage our interest rate risk. The swaps are contractual agreements we enter into in order to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. However, in a period of rising interest rates, these swaps will result in period-to-period increases in our interest expense. For more information on our interest rate swaps, see Note 14 to our consolidated financial statements, included elsewhere in this report.

The $69.4 million (36%) increase in net interest charges in 2005 versus 2004 was also due to both higher average debt borrowings and higher effective interest rates. Our average debt balance increased 10% in 2005 compared to 2004, partly due to incremental borrowings made in connection with both internal capital spending and external acquisitions, and partly due to the net increase of $300 million in principal amount of senior notes in March 2005. The weighted average interest rate on all of our borrowings increased 19% in 2005 compared to 2004, reflecting a general rise in interest rates since the end of 2004.

Minority interest, representing the deduction in our consolidated net income attributable to all outstanding ownership interests in our five operating limited partnerships and their consolidated subsidiaries that are not held by us, totaled $15.4 million in 2006, $7.3 million in 2005 and $9.7 million in 2004. The overall $8.1 million (111%) increase in 2006 compared to 2005 included a $3.1 million increase attributable to the 33 1/3% minority interest in the IMT Partnership’s hurricane related income and expense items, as described above in “—Terminals,” and a $1.6 million increase attributable to higher net income from overall net operating partnership income. The overall $2.4 million (25%) decrease in minority interest in 2005 compared to 2004 was chiefly due to lower net income allocated to the minority interest in the IMT Partnership in 2005, due to business interruption caused by Hurricane Katrina.

We attempt to maintain a conservative overall capital structure, with a long-term target mix of approximately 50% equity and 50% debt. In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.” The following table illustrates the sources of our invested capital (dollars in millions):

	December 31,
	2006			2005			2004
Long-term debt, excluding market value of interest rate swaps	$4,384.3			$5,220.9			$4,722.4
Minority interest		60.2			42.3			45.6
Partners’ capital, excluding accumulated other comprehensive loss		5,814.4			4,693.5			4,353.9
Total capitalization		10,258.9			9,956.7			9,121.9
Short-term debt, less cash and cash equivalents		1,352.4			(12.1	)		─
Total invested capital	$	11,611.3		$	9,944.6		$	9,121.9

Capitalization:
Long-term debt, excluding market value of interest rate swaps		42.7	%		52.4	%		51.8	%
Minority interest		0.6	%		0.4	%		0.5	%
Partners’ capital, excluding accumulated other comprehensive loss		56.7	%		47.2	%		47.7	%
		100.0	%		100.0	%		100.0	%

Invested Capital:
Total debt, less cash and cash equivalents and excluding market value
of interest rate swaps		49.4	%		52.4	%		51.8	%
Partners’ capital and minority interest, excluding accumulated other comprehensive loss		50.6	%		47.6	%		48.2	%
		100.0	%		100.0	%		100.0	%

Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements for expansion capital expenditures through borrowings under our credit facility, issuing short-term commercial paper, long-term notes or additional common units or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.

i-units rather than cash), additional borrowings, the issuance of additional common units or the proceeds from purchases of additional i-units by KMR;

As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations. We are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors.

As part of our financial strategy, we try to maintain an investment-grade credit rating, which involves, among other things, the issuance of additional limited partner units in connection with our acquisitions and internal growth activities in order to maintain acceptable financial ratios. On May 30, 2006, S&P and Moody’s each placed our ratings on credit watch pending resolution of a management buyout proposal for all of the outstanding shares of KMI. On January 5, 2007, in anticipation of the buyout closing, S&P downgraded us one level to BBB and removed our rating from credit watch with negative implications. Our debt credit ratings are currently rated BBB by Standard & Poor’s Rating Services, and Baa1 by Moody’s Investors Service. As noted by Moody’s in its credit opinion dated November 15, 2006, our rating is expected to be downgraded from Baa1 to Baa2 at the time Moody’s finalizes its

ratings for KMI. Additionally, as noted by Fitch in its press release dated August 28, 2006, our rating is expected to be downgraded from BBB+ to BBB at the time Fitch finalizes its ratings for KMI. At this time, neither Moody’s nor Fitch have changed their ratings on KMI or us. We are not able to predict with certainty the final outcome of the pending buyout proposal.

We employ a centralized cash management program that essentially concentrates the cash assets of our operating partnerships and their subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. Our centralized cash management program provides that funds in excess of the daily needs of our operating partnerships and their subsidiaries are concentrated, consolidated, or otherwise made available for use by other entities within our consolidated group. We place no restrictions on the ability to move cash between entities, payment of inter-company balances or the ability to upstream dividends to parent companies other than restrictions that may be contained in agreements governing the indebtedness of those entities; provided, however, that our cash and the cash of our subsidiaries is not concentrated into accounts of KMI or any company not in our consolidated group of companies, and KMI has no rights with respect to our cash except as permitted pursuant to our partnership agreement.

Furthermore, certain of our operating subsidiaries are subject to Federal Energy Regulatory Commission enacted reporting requirements for oil and natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC.

Borrowings under our credit facility can be used for general corporate purposes and as a backup for our commercial paper program. Effective August 28, 2006, we terminated our $250 million unsecured nine-month bank credit facility due November 21, 2006, and we increased our existing five-year bank credit facility from $1.60 billion to $1.85 billion. The five-year unsecured bank credit facility remains due August 18, 2010; however, the bank facility can now be amended to allow for borrowings up to $2.1 billion. There were no borrowings under our bank credit facility as of December 31, 2005 or as of December 31, 2006. As of December 31, 2006, we had $1,098.2 million of commercial paper outstanding.

We provide for additional liquidity by maintaining a sizable amount of excess borrowing capacity related to our commercial paper program and long-term revolving credit facility. After inclusion of our outstanding commercial paper borrowings and letters of credit, the remaining available borrowing capacity under our bank credit facility was $367.1 million as of December 31, 2006. As of December 31, 2006, our outstanding short-term debt was $1,359.1 million. Currently, we believe our liquidity to be adequate. For more information on our commercial paper program and our credit facility, see Note 9 to our consolidated financial statements included elsewhere in this report.

In addition to our principal sources of short-term liquidity listed above, we could meet our cash requirements (other than distributions to our common unitholders, Class B unitholders and general partner) through issuing long-term notes or additional common units, or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.

We are subject, however, to changes in the equity and debt markets for our limited partner units and long-term notes, and there can be no assurance we will be able or willing to access the public or private markets for our limited partner units and/or long-term notes in the future. If we were unable or unwilling to issue additional limited partner units, we would be required to either restrict potential future acquisitions or pursue other debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. Our ability to access the public and private debt markets is affected by our credit ratings. See “—Capital Structure” above for a discussion of our credit ratings.

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.

From time to time we issue long-term debt securities. All of our long-term debt securities issued to date, other than those issued under our long-term revolving credit facility or those issued by our subsidiaries and operating partnerships, generally have the same terms except for interest rates, maturity dates and prepayment premiums. All of our outstanding debt securities are unsecured obligations that rank equally with all of our other senior debt obligations; however, a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries. Our fixed rate notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium.

As of December 31, 2006, our total liability balance due on the various series of our senior notes was $4,490.7 million, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $154.5 million.

In addition, 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. For additional information regarding our debt securities, see Note 9 to our consolidated financial statements included elsewhere in this report.

During 2006, our cash outlays for the acquisition of assets totaled $387.2 million. We utilized our commercial paper program to fund our 2006 acquisitions. We then reduced our short-term borrowings with the proceeds from our August issuance of common units. We intend to refinance the remainder of our current short-term debt and any additional short-term debt incurred during 2007 through a combination of long-term debt, equity and the issuance of additional commercial paper to replace maturing commercial paper borrowings.

We are committed to maintaining a cost effective capital structure and we intend to finance new acquisitions using a mix of approximately 50% equity financing and 50% debt financing. For more information on our capital requirements during 2006 in regard to our acquisition expenditures, see Note 3 to our consolidated financial statements included elsewhere in this report.

We have invested in entities that are not consolidated in our financial statements. As of December 31, 2006, our obligations with respect to these investments, as well as our obligations with respect to a letter of credit, are summarized below (dollars in millions):

Further, pursuant to a Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company are required to contribute capital to Cortez in the event of a cash deficiency. The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital Corporation. The partners’ respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement.

We account for our investments in Cortez Pipeline Company, Red Cedar Gathering Company and West2East Pipeline LLC under the equity method of accounting. For the year ended December 31, 2006, our share of earnings,

based on our ownership percentage and before amortization of excess investment cost was $19.2 million from Cortez Pipeline Company, $36.3 million from Red Cedar Gathering Company, and $1.9 million from West2East Pipeline LLC. Additional information regarding the nature and business purpose of these investments is included in Notes 7 and 9 to our consolidated financial statements included elsewhere in this report.

	Amount of Commitment Expiration per Period
	Total		1 Year or Less		2-3 Years		4-5 Years		After 5 Years
	(In millions)
Contractual Obligations:
Commercial paper outstanding	$	1,098.2	$	1,098.2	$	—	$	—	$	—
Other debt borrowings-principal payments		4,654.5		260.9		267.8		969.5		3,156.3
Interest payments(a)		3,922.7		349.8		547.5		469.1		2,556.3
Lease obligations(b)		176.9		50.0		55.0		35.2		36.7
Pension and post-retirement welfare plans(c)		58.8		5.3		10.6		11.1		31.8
Other obligations(d)		155.2		47.4		60.8		40.0		7.0
Total	$	10,066.3	$	1,811.6	$	941.7	$	1,524.9	$	5,788.1

Other commercial commitments:
Standby letters of credit(e)	$	483.1	$	424.9	$	20.2	$	0.5	$	37.5
Capital expenditures(f)	$	86.0	$	86.0		—		—		—

Net cash provided by operating activities was $1,363.9 million in 2006, versus $1,289.4 million in 2005. The overall year-to-year increase of $74.5 million (6%) in cash flow from operations included incremental cash inflows of $106.5 million from the inclusion of Trans Mountain in 2006. The remaining year-to-year decrease of $32.0 million (2%) in cash flow from operations consisted of the following:

Net cash used in investing activities was $1,501.9 million for the year ended December 31, 2006, compared to $1,181.1 million for the prior year. The $320.8 million (27%) overall increase in funds utilized in investing activities included incremental spending of $113.6 million due to the inclusion of Trans Mountain in 2006; the remaining $207.2 million (18%) increase in cash used in 2006 versus 2005 was mainly attributable to:

Our sustaining capital expenditures totaled $125.4 million in 2006 and $140.8 million in 2005. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset. Beginning in the third quarter of 2006, our Products Pipelines and CO₂ business segments and our Texas intrastate natural gas pipeline group began recognizing certain costs incurred as part of their pipeline integrity management program as maintenance expense in the period incurred, and in addition, recorded an expense for costs previously capitalized as sustaining capital expenditures during the first six months of 2006. This change primarily affected our Products Pipelines business segment, reducing its earnings before depreciation, depletion and amortization expenses by $24.2 million and reducing its sustaining capital expenditures by $19.8 million, when compared to 2005.

Additionally, our forecasted expenditures for sustaining capital expenditures for 2007 are approximately $156.5 million. This amount has been forecasted primarily for the purchase of plant and equipment. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. None of the 2006 sustaining capital expenditure amounts and forecasted 2007 sustaining capital expenditure amounts discussed above includes Trans Mountain. For more information on our capital expenditures, see Note 15 to our consolidated financial statements included elsewhere in this report;

Net cash provided by financing activities was $132.4 million in 2006; while in the prior year, our financing activities used net cash of $96.0 million. The $228.4 million overall increase in cash inflows provided by financing activities was primarily due to:

During each of the years 2006 and 2005, we used our commercial paper borrowings to fund our asset acquisitions, capital expansion projects and other partnership activities. We subsequently raised funds to refinance a portion of those borrowings by issuing additional common units and, in 2005 only, completing public offerings of senior notes. We used the proceeds from these debt and equity issuances to reduce our borrowings under our commercial paper program. Furthermore, the increase in our commercial paper debt

includes net borrowings of $412.5 million under the commercial paper program of Rockies Express Pipeline LLC. We held a 66 2/3% ownership interest in Rockies Express Pipeline LLC until June 30, 2006, and according to the provisions of generally accepted accounting principles, we included its cash inflows and outflows in our consolidated statement of cash flows for the first six months of 2006.

On June 30, 2006, following ConocoPhillips’ acquisition of a 24% ownership interest in West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline LLC), we deconsolidated West2East Pipeline LLC and we have subsequently accounted for our investment under the equity method of accounting. Following the change to the equity method on June 30, 2006, Rockies Express’ debt balances were no longer included in our consolidated balance sheet and its cash inflows and outflows for all periods subsequent to June 2006 were not included in our consolidated statement of cash flows.

The decrease in cash inflows from changes in our senior notes related to debt activities occurring on March 15, 2005. On that date, we both closed a public offering of $500 million in principal amount of 5.80% senior notes and repaid $200 million of 8.0% senior notes that matured on that date. The 5.80% senior notes are due March 15, 2035. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $494.4 million, and we used the proceeds to repay the 8.0% senior notes and to reduce our commercial paper debt;

The overall increase in period-to-period distributions included minority interest distributions of $105.2 million paid from our Rockies Express Pipeline LLC subsidiary to Sempra Energy in the first half of 2006. The distributions to Sempra (and distributions to us for our proportionate ownership interest) were made in conjunction with Rockies Express’ establishment of and subsequent borrowings under its commercial paper program during the second quarter of 2006, as discussed above. During the second quarter of 2006, Rockies Express both issued a net amount of $412.5 million of commercial paper and distributed $315.5 million to its member owners. Prior to the establishment of its commercial paper program (supported by its five-year unsecured revolving credit agreement), Rockies Express funded its acquisition of Entrega Gas Pipeline LLC and its Rockies Express Pipeline construction costs with contributions from both us and Sempra.

Excluding the minority interest distributions to Sempra, overall distributions increased $116.4 million in 2006, when compared to 2005. The increase primarily resulted from higher distributions of “Available Cash,” as described below in “—Partnership Distributions.” The increase in “Available Cash” distributions in 2006 versus 2005 was due to an increase in the per unit cash distributions paid, an increase in the number of units outstanding and an increase in our general partner incentive distributions. We paid distributions of $3.23 per unit in 2006 compared to $3.07 per unit in 2005. The 5% increase in distributions paid per unit principally resulted from favorable operating results in 2006. The increase in our general partner incentive distributions resulted from both increased cash distributions per unit and an increase in the number of common units and i-units outstanding.

We also distributed 4,383,303 and 3,760,732 i-units in quarterly distributions during 2006 and 2005, respectively, to KMR, our sole i-unitholder. The amount of i-units distributed in each quarter was based upon

the amount of cash we distributed to the owners of our common and Class B units during that quarter of 2006 and 2005. For each outstanding i-unit that KMR held, a fraction of an i-unit was issued. The fraction was determined by dividing the cash amount distributed per common unit by the average of KMR’s shares’ closing market prices for the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange; and

In an August 2006 public offering, we issued an additional 5,750,000 of our common units at a price of $44.80, less commissions and underwriting expenses. After all fees, we received net proceeds of $248.0 million for the issuance of these common units. In 2005, we received aggregate proceeds of $413.7 million from two separate common unit equity issuances, consisting of the following (amounts are net of all commissions and underwriting expenses):

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. For 2006, 2005 and 2004, we distributed approximately 103%, 101% and 96%, respectively, of the total of cash receipts less cash disbursements (calculations assume that KMR unitholders received cash). The difference between these numbers and 100% of distributable cash flow reflects net changes in reserves.

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.

Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. Our general partner’s incentive distribution that we declared for 2006 was $508.3 million, while the incentive distribution paid to our general partner during 2006 was $515.9 million. The difference between declared and paid distributions is due to the fact that our distributions for the fourth quarter of each year are declared and paid in the first quarter of the following year.

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; however, due to the fact that we did not meet our 2006 budget target, we had no obligation to fund our 2006 bonus plan for the executive officers of our general partner and KMR, and for the employees of KMGP Services Company, Inc. and KMI who operate our businesses. 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 and 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.

On February 14, 2007, we paid a quarterly distribution of $0.83 per unit for the fourth quarter of 2006. This distribution was 4% greater than the $0.80 distribution per unit we paid for the fourth quarter of 2005 and 2% greater than the $0.81 distribution per unit we paid for the first quarter of 2006. We paid this distribution in cash to our common unitholders and to our Class B unitholders. KMR, our sole i-unitholder, received additional i-units based on the $0.83 cash distribution per common unit. We believe that future operating results will continue to support similar levels of quarterly cash and i-unit distributions; however, no assurance can be given that future distributions will continue at such levels.

As of December 31, 2006, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $64.2 million. In addition, we have recorded a receivable of $27.0 million for expected cost recoveries that have been deemed probable. The reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired or accidental spills or releases at facilities that we own. Reserves for each project are generally established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup and the costs associated with the effort. In assessing environmental risks in conjunction with proposed acquisitions, we review records relating to environmental issues, conduct site inspections, interview employees, and, if appropriate, collect soil and groundwater samples.

Additionally, as of December 31, 2006, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $112.0 million. The reserve is primarily related to various claims

from lawsuits arising from our Pacific operations’ pipeline transportation rates, and the contingent amount is based on both the circumstances of probability and reasonability of dollar estimates. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision. As of December 31, 2005, our total reserve for legal fees, transportation rate cases and other litigation liabilities amounted to $136.5 million.

Though no assurance can be given, we believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations.

Pursuant to our continuing commitment to operational excellence and our focus on safe, reliable operations, we have implemented, and intend to implement in the future, enhancements to certain of our operational practices in order to strengthen our environmental and asset integrity performance. These enhancements have resulted and may result in higher operating costs and sustaining capital expenditures; however, we believe these enhancements will provide us the greater long term benefits of improved environmental and asset integrity performance.

Please refer to Notes 16 and 17, respectively, to our consolidated financial statements included elsewhere in this report for additional information regarding pending litigation, environmental and asset integrity matters.

The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within ten years of December 17, 2002, the date of enactment, and must perform subsequent integrity tests on a seven year cycle. At least 50% of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing will consist of hydrostatic testing, internal electronic testing, or direct assessment of the piping. A similar integrity management rule for refined petroleum products pipelines became effective May 29, 2001. All baseline assessments for products pipelines must be completed by March 31, 2008. We have included all incremental expenditures estimated to occur during 2007 associated with the Pipeline Safety Improvement Act of 2002 and the integrity management of our products pipelines in our 2007 budget and capital expenditure plan.

Please refer to Note 17 to our consolidated financial statements included elsewhere in this report for additional information regarding regulatory matters.

Please refer to Note 18 to our consolidated financial statements included elsewhere in this report for information concerning recent accounting pronouncements.

This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

There is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements.

See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in “Risk Factors” above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Other than as required by applicable law, we disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.” Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual fluctuations in commodity prices or interest rates and the timing of transactions.

We are exposed to commodity market risk and other external risks, such as weather-related risk, in the ordinary course of business. However, we take steps to hedge, or limit our exposure to, these risks in order to maintain a more stable and predictable earnings stream. Stated another way, we execute a hedging strategy that seeks to protect our financial position against adverse price movements and serves to minimize potential losses. Our strategy involves the use of certain energy commodity derivative contracts to reduce and minimize the risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil. The derivative contracts we use include energy products traded on the New York Mercantile Exchange and over-the-counter markets, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps.

Fundamentally, our hedging strategy involves taking a simultaneous position in the futures market that is equal

and opposite to our position in the cash market (or physical product) in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil and natural gas, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby directly offsetting any change in prices, either positive or negative. A hedge is successful when gains or losses in the cash market are neutralized by losses or gains in the futures transaction.

Our risk management policies prohibit us from engaging in speculative trading and we are not a party to leveraged derivatives. Furthermore, our policies require that we only enter into derivative contracts with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future. The credit ratings of the primary parties from whom we purchase energy commodity derivative contracts are as follows:

We account for our energy commodity risk management derivative contracts according to the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (after amendment by SFAS No. 137, SFAS No. 138, and SFAS No. 149). According to the provisions of SFAS No. 133, derivatives are measured at fair value and recognized on the balance sheet as either assets or liabilities, and in general, gains and losses on derivatives are reported on the income statement. However, as discussed above, our principal use of energy commodity derivative contracts is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, natural gas liquids and crude oil. Using derivative contracts to help provide us certainty with regard to our operating cash flows helps us undertake further capital improvement projects, attain budget results and meet distribution targets to our partners.

SFAS No. 133 categorizes such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain. Cash flow hedges are defined as hedges made with the intention of decreasing the variability in cash flows related to future transactions, as opposed to the value of an asset, liability or firm commitment, and SFAS No. 133 prescribes special hedge accounting treatment for such derivatives.

In accounting for cash flow hedges, gains and losses on the derivative contracts are reported in other comprehensive income, outside “Net Income” reported in our consolidated statements of income, but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income. That is, for cash flow hedges, all effective components of the derivative contracts’ gains and losses goes to other comprehensive income, pending occurrence of the expected transaction. Other comprehensive income consists of those financial items that are included in “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets but not included in our net income. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings.

All remaining gains and losses on the derivative contracts (the ineffective portion) are included in current net income. The ineffective portion of the gain or loss on the derivative contracts is the difference between the gain or loss from the change in value of the derivative contract and the effective portion of that gain or loss. In addition, when the hedged forecasted transaction does take place and affects earnings, the effective part of the hedge is also recognized in the income statement, and the earlier recognized effective amounts are removed from “Accumulated other comprehensive loss.” If the forecasted transaction results in an asset or liability, amounts in “Accumulated other comprehensive loss” should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc.

Under current accounting rules, the accumulated components of other comprehensive income are to be reported separately as accumulated other comprehensive income or loss in the stockholders’ equity section of the balance sheet. Accordingly, our application of SFAS No. 133 has resulted in deferred net loss amounts of $838.7 million and $1,079.4 million being included within “Accumulated other comprehensive loss” in the Partners’ Capital section of our accompanying balance sheets as of December 31, 2006 and December 31, 2005, respectively.

For us, the gains and losses that are included in “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets are primarily related to the derivative contracts associated with our hedging of anticipated future cash flows from the sales and purchases of natural gas, natural gas liquids and crude oil and represent the effective portion of the gain or loss on these derivative contacts. In future periods, as the hedged cash flows from our actual purchases and sales of energy commodities affect our net income, the related gains and losses included in our accumulated other comprehensive loss as a result of our hedging are transferred to the income statement as well, effectively offsetting the changes in cash flows stemming from the hedged risk.

We measure the risk of price changes in the natural gas, natural gas liquids and crude oil markets utilizing a value-at-risk model. Value-at-risk is a statistical measure of how much the mark-to-market value of a portfolio could change during a period of time, within a certain level of statistical confidence. We utilize a closed form model to evaluate risk on a daily basis. The value-at-risk computations utilize a confidence level of 97.7% for the resultant price movement and a holding period of one day is chosen for the calculation. The confidence level used means that there is a 97.7% probability that the mark-to-market losses for a single day will not exceed the value-at-risk number presented. Derivative contracts evaluated by the model include commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options.

For each of the years ended December 31, 2006 and 2005, value-at-risk reached a high of $2.6 million and $21.5 million, respectively, and a low of $0.5 million and $7.6 million, respectively. Value-at-risk as of December 31, 2006, was $0.6 million and averaged $1.1 million for 2006. Value-at-risk as of December 31, 2005, was $9.1 million and averaged $12.7 million for 2005.

Our calculated value-at-risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio of derivative contracts assuming hypothetical movements in future market rates, and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year. In addition, as discussed above, we enter into these derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, the change in the market value of our portfolio of derivative contracts, with the exception of a minor amount of hedging inefficiency, is offset by changes in the value of the underlying physical transactions. For more information on our risk management activities, see Note 14 to our consolidated financial statements included elsewhere in this report.

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. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.

For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. We do not have an obligation to prepay fixed rate debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on our fixed rate debt until we would be required to refinance such debt.

As of December 31, 2006 and 2005, the carrying values of our fixed rate debt were approximately $4,551.2 million and $4,560.7 million, respectively. These amounts compare to, as of December 31, 2006 and 2005, fair values of $4,672.7 million and $4,805.0 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements.

A hypothetical 10% change (approximately 62 basis points) in the average interest rates applicable to such debt for 2006 and 2005, respectively, would result in changes of approximately $183.4 million and $193.8 million, respectively, in the fair values of these instruments.

The carrying value and fair value of our variable rate debt, including associated accrued interest and excluding market value of interest rate swaps, was $1,195.6 million as of December 31, 2006 and $655.9 million as of December 31, 2005. A hypothetical 10% change in the weighted average interest rate on all of our borrowings, when applied to our outstanding balance of variable rate debt as of December 31, 2006 and 2005, respectively, including adjustments for notional swap amounts, would result in changes of approximately $20.3 million and $13.9 million, respectively, in our 2006 and 2005 annual pre-tax earnings.

As of both December 31, 2006 and 2005, we were a party to interest rate swap agreements with notional principal amounts of $2.1 billion. An interest rate swap agreement is a contractual agreement entered into between two counterparties under which each agrees to make periodic interest payments to the other for an agreed period of time based upon a predetermined amount of principal, which is called the notional principal amount. Normally at each payment or settlement date, the party who owes more pays the net amount; so at any given settlement date only one party actually makes a payment. The principal amount is notional because there is no need to exchange actual amounts of principal.

Since the fair value of our 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 swap agreements 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, all of our interest rate swap agreements represented fixed-for-variable rate swaps, where we agreed to pay our counterparties a variable rate of interest on a notional principal amount of $2.1 billion, comprised of principal amounts from various series of our long-term fixed rate senior notes. In exchange, our counterparties agreed to pay us a fixed rate of interest, thereby allowing us to transform our fixed rate liabilities into variable rate obligations without the incurrence of additional loan origination or conversion costs.

We monitor our mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under our variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements. In general, we attempt to maintain an overall target mix of approximately 50% fixed rate debt and 50% variable rate debt.

As of December 31, 2006, our cash and investment portfolio did not include fixed-income securities. Due to the short-term nature of our investment portfolio, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio.

See Note 9 to our consolidated financial statements included elsewhere in this report for additional information related to our debt instruments; for more information on our interest rate swap agreements, see Note 14.

We have completed integrated audits of Kinder Morgan Energy Partners, L.P.’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. and its subsidiaries (collectively, the Partnership) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Partnership maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Partnership’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable

assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded:

(the “Acquired Businesses”), each acquired in separate transactions, from its assessment of internal control over financial reporting as of December 31, 2006 because these businesses were acquired by the Partnership in purchase business combinations during 2006. We have also excluded these Acquired Businesses from our audit of internal control over financial reporting. These Acquired Businesses’, in the aggregate, constituted 1.2% and 0.4%, respectively of total assets and total revenues, of the related consolidated financial statement amounts as of and for the year ended December 31, 2006.

March 1, 2007, except as to Note 2 (Trans Mountain Pipeline System), as to which the date is August 20, 2007 and Note 2 (North System Natural Gas Liquids Pipeline System), as to which the date is October 5, 2007

	Year Ended December 31,
	2006			2005			2004
	(In millions except per unit amounts)
Revenues
Natural gas sales	$	6,039.9		$	7,198.5		$	5,803.1
Services		2,177.6			1,810.5			1,531.6
Product sales and other		831.2			736.9			558.3
		9,048.7			9,745.9			7,893.0
Costs, Expenses and Other
Gas purchases and other costs of sales		5,990.9			7,167.3			5,767.0
Operations and maintenance		777.0			719.5			488.6
Fuel and power		223.7			178.5			146.4
Depreciation, depletion and amortization		423.9			341.6			281.1
General and administrative		238.4			216.7			170.5
Taxes, other than income taxes		134.4			106.5			79.1
Other expense (income)		(31.2	)		—			—
		7,757.1			8,730.1			6,932.7

Operating Income		1,291.6			1015.8			960.3

Other Income (Expense)
Earnings from equity investments		74.0			89.6			81.8
Amortization of excess cost of equity investments		(5.6	)		(5.5	)		(5.6	)
Interest, net		(337.8	)		(259.0	)		(192.9	)
Other, net		12.0			3.3			2.2
Minority Interest		(15.4	)		(7.3	)		(9.6	)

Income from Continuing Operations Before Income Taxes		1,018.8			836.9			836.2

Income Taxes		(29.0	)		(24.5	)		(19.7	)

Income from Continuing Operations		989.8			812.4			816.5

Income from Discontinued Operations		14.3			(0.2	)		15.1

Net Income	$	1,004.1		$	812.2		$	831.6

Calculation of Limited Partners’ interest in Net Income:
Income from Continuing Operations	$	989.8		$	812.4		$	816.5
Less: General Partner’s interest		(513.2	)		(477.3	)		(394.9	)
Limited Partners’ interest		476.6			335.1			421.6
Add: Limited Partners’ interest in Discontinued Operations		14.2			(0.2	)		14.9
Limited Partners’ interest in Net Income	$	490.8		$	334.9		$	436.5

Basic Limited Partners’ Net Income per Unit:
Income from Continuing Operations	$	2.12		$	1.58		$	2.14
Income from Discontinued Operations		0.07			—			0.08
Net Income	$	2.19		$	1.58		$	2.22
Weighted average number of units outstanding		224.6			212.2			197.0

Diluted Limited Partners’ Net Income per Unit:
Income from Continuing Operations	$	2.12		$	1.58		$	2.14
Income from Discontinued Operations		0.06			—			0.08
Net Income	$	2.18		$	1.58		$	2.22
Weighted average number of units outstanding		224.9			212.4			197.0

Per unit cash distribution declared	$	3.26		$	3.13		$	2.87

The accompanying notes are an integral part of these consolidated financial statements.

	December 31,
	2006			2005
ASSETS	(Dollars in millions)
Current Assets
Cash and cash equivalents	$	6.7		$	12.1
Accounts, notes and interest receivable, net
Trade		854.7			1,011.7
Related parties		7.9			2.5
Inventories
Products		20.4			18.8
Materials and supplies		16.6			13.3
Gas imbalances
Trade		7.8			18.2
Related parties		11.6			—
Gas in underground storage		8.4			7.1
Other current assets		102.7			131.5
		1,036.8			1,215.2
Property, Plant and Equipment, net		10,106.1			8,864.6
Investments		426.3			419.3
Notes receivable
Trade		1.2			1.5
Related parties		96.2			109.0
Goodwill		1,421.0			799.0
Other intangibles, net		213.2			217.0
Deferred charges and other assets		241.4			297.9
Total Assets	$	13,542.2		$	11,923.5
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts	$	46.2		$	30.4
Trade		784.1			996.2
Related parties		203.3			16.7
Current portion of long-term debt		1,359.1			—
Accrued interest		83.7			74.9
Accrued taxes		35.4			23.5
Deferred revenues		20.0			10.5
Gas imbalances
Trade		15.9			23.0
Related parties		—			1.6
Accrued other current liabilities		589.6			632.1
		3,137.3			1,808.9
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding		4,384.3			5,220.9
Market value of interest rate swaps		42.6			98.5
		4,426.9			5,319.4
Deferred revenues		18.8			6.7
Deferred income taxes		185.2			70.3
Asset retirement obligations		48.9			42.4
Other long-term liabilities and deferred credits		716.6			1,019.7
		5,396.4			6,458.5
Commitments and Contingencies (Notes 13 and 16)
Minority Interest		60.2			42.3
Partners’ Capital
Common Units (162,816,303 and 157,005,326 units issued and outstanding as of December 31, 2006 and 2005, respectively)		3,414.9			2,680.4
Class B Units (5,313,400 and 5,313,400 units issued and outstanding as of December 31, 2006 and 2005, respectively)		126.1			109.6
i-Units (62,301,676 and 57,918,373 units issued and outstanding as of December 31, 2006 and 2005, respectively)		2,154.2			1,783.6
General Partner		119.2			119.9
Accumulated other comprehensive loss		(866.1	)		(1,079.7	)
		4,948.3			3,613.8

The accompanying notes are an integral part of these consolidated financial statements.

	Year Ended December 31,
	2006			2005			2004
	(In millions)
Cash Flows From Operating Activities
Net income	$	1,004.1		$	812.2		$	831.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		432.8			349.8			288.6
Amortization of excess cost of equity investments		5.7			5.6			5.6
Gains and other non-cash income from the sale of property, plant and equipment		(15.2	)		(0.5	)		0.7
Gains from property casualty indemnifications		(15.2	)		—			—
Earnings from equity investments		(76.2	)		(91.7	)		(83.2	)
Distributions from equity investments		67.9			63.1			65.2
Changes in components of working capital:
Accounts receivable		15.8			(240.7	)		(172.4	)
Other current assets		13.8			(14.1	)		26.2
Inventories		0.9			(13.5	)		(7.4	)
Accounts payable		(48.8	)		294.9			222.4
Accrued interest		8.0			17.9			4.6
Accrued liabilities		(10.6	)		4.5			(23.0	)
Accrued taxes		14.2			(2.3	)		3.4
FERC rate reparations, refunds and reserve adjustments		(19.1	)		105.0			—
Other, net		(14.2	)		(0.8	)		(7.2	)
Net Cash Provided by Operating Activities		1,363.9			1,289.4			1,155.1

Cash Flows From Investing Activities
Acquisitions of assets		(387.2	)		(307.8	)		(478.8	)
Additions to property, plant and equip. for expansion and maintenance projects		(1,182.1	)		(863.1	)		(747.3	)
Sale of property, plant and equipment, and other net assets net of removal costs		70.8			9.9			1.1
Property casualty indemnifications		13.1			—			—
Net proceeds from margin deposits		2.3			—			—
Contributions to equity investments		(2.5	)		(1.2	)		(7.0	)
Natural gas stored underground and natural gas liquids line-fill		(12.9	)		(18.7	)		(19.2	)
Other		(3.4	)		(0.2	)		0.7
Net Cash Used in Investing Activities		(1,501.9	)		(1,181.1	)		(1,250.5	)

Cash Flows From Financing Activities
Issuance of debt		4,632.5			4,900.9			6,016.7
Payment of debt		(3,698.7	)		(4,463.2	)		(5,657.6	)
Repayments from (Loans to) related party		1.1			2.1			(96.3	)
Debt issue costs		(2.0	)		(6.0	)		(5.9	)
Increase in cash book overdrafts		15.8			0.6			29.9
Proceeds from issuance of common units		248.4			415.6			506.5
Proceeds from issuance of i-units		—			—			67.5
Contributions from minority interest		109.8			7.8			8.0
Distributions to partners:
Common units		(512.1	)		(460.6	)		(389.9	)
Class B units		(17.2	)		(16.3	)		(14.9	)
General Partner		(523.2	)		(460.9	)		(376.0	)
Minority interest		(119.0	)		(12.1	)		(10.1	)
Other, net		(3.0	)		(3.9	)		(5.8	)
Net Cash Provided by (Used in) Financing Activities		132.4			(96.0	)		72.1

Effect of exchange rate changes on cash and cash equivalents		0.2			(0.2	)		—


Increase (Decrease) in Cash and Cash Equivalents		(5.4	)		12.1		(23.3	)
Cash and Cash Equivalents, beginning of period		12.1			—		23.3
Cash and Cash Equivalents, end of period	$	6.7		$	12.1	$	—

Noncash Investing and Financing Activities:
Contribution of net assets to partnership investments	$	17.0		$	—	$	—
Assets acquired by the issuance of units		1.6			49.6		64.1
Assets acquired by the assumption or incurrence of liabilities		6.1			76.6		81.4
Assets acquired by the transfer of Trans Mountain		1,199.5			—		—
Liabilities assumed by the transfer of Trans Mountain		282.5			—		—

Supplemental disclosures of cash flow information:
Cash paid during the year for interest (net of capitalized interest)		329.2			245.6		186.9
Cash paid (received) during the year for income taxes		25.6			7.3		(0.8	)

The accompanying notes are an integral part of these consolidated financial statements.

	2006				2005				2004
	Units	Amount			Units	Amount			Units	Amount
	(Dollars in millions)
Common Units:
Beginning Balance	157,005,326	$	2,680.4		147,537,908	$	2,438.0		134,729,258	$	1,946.1
Net income	—		347.8		—		237.8		—		311.2
Units issued as consideration pursuant to common unit compensation plan for non-employee directors	5,250		0.3		5,250		0.3		—		—
Units issued as consideration in the acquisition of assets	34,627		1.6		1,022,068		49.6		1,400,000		64.1
Units issued for cash	5,771,100		248.2		8,440,100		415.3		11,408,650		506.5
Trans Mountain Acquisition	—		648.7		—		—		—		—
Distributions	—		(512.1	)	—		(460.6	)	—		(389.9	)
Ending Balance	162,816,303		3,414.9		157,005,326		2,680.4		147,537,908		2,438.0

Class B Units:
Beginning Balance	5,313,400		109.6		5,313,400		117.4		5,313,400		120.5
Net income	—		11.6		—		8.5		—		11.8
Trans Mountain Acquisition	—		22.1		—		—		—		—
Distributions	—		(17.2	)	—		(16.3	)	—		(14.9	)
Ending Balance	5,313,400		126.1		5,313,400		109.6		5,313,400		117.4

i-Units:
Beginning Balance	57,918,373		1,783.6		54,157,641		1,695.0		48,996,465		1,515.7
Net income	—		131.4		—		88.6		—		113.5
Units issued for cash	—		—		—		—		1,660,664		65.8
Trans Mountain Acquisition	—		239.2		—		—		—		—
Distributions	4,383,303		—		3,760,732		—		3,500,512		—
Ending Balance	62,301,676		2,154.2		57,918,373		1,783.6		54,157,641		1,695.0

General Partner:
Beginning Balance	—		119.9		—		103.5		—		84.4
Net income	—		513.3		—		477.3		—		395.1
Trans Mountain Acquisition	—		9.2		—		—		—		—
Distributions	—		(523.2	)	—		(460.9	)	—		(376.0	)
Ending Balance	—		119.2		—		119.9		—		103.5

Accum. other comprehensive income (loss):
Beginning Balance	—		(1,079.7	)	—		(457.4	)	—		(155.8	)
Change in fair value of derivatives Used for hedging purposes	—		(187.5	)	—		(1,045.6	)	—		(494.2	)
Reclassification of change in fair value of derivatives to net income	—		428.1		—		424.0		—		192.3
Foreign currency translation adjustments	—		(19.6	)	—		(0.7	)	—		0.3
Minimum pension liability adj.-net of tax	—		(1.8	)	—		—		—		—
Adj. to initially apply SFAS No. 158- pension and other post-retirement benefit acctg. changes	—		(5.6	)	—		—		—		—
Ending Balance	—		(866.1	)	—		(1,079.7	)	—		(457.4	)

Total Partners’ Capital	230,431,379	$	4,948.3		220,237,099	$	3,613.8		207,008,949	$	3,896.5

The accompanying notes are an integral part of these consolidated financial statements.

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:

We acquired our Trans Mountain pipeline system from Knight Inc., formerly Kinder Morgan, Inc., for $550 million on April 30, 2007; however, because this acquisition was accounted for as a transfer of net assets between entities under common control, our consolidated financial statements and financial summaries included in this report have been restated to assume that this acquisition occurred as of January 1, 2006. In addition, due to the fact that Trans Mountain’s operations are managed separately, involve different products and marketing strategies, and produce discrete financial information that is separately evaluated internally by our management, we have identified our Trans Mountain pipeline system as a separate reportable business segment. For more information on this acquisition, see Note 3; 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:

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.

Knight Inc. (formerly known as Kinder Morgan, Inc) and Kinder Morgan G.P., Inc

On August 28, 2006, Kinder Morgan, Inc., a Kansas corporation referred to as “KMI” in this report, entered into an agreement and plan of merger whereby investors led by Richard D. Kinder, Chairman and CEO of KMI, would acquire all of the outstanding shares of KMI (other than shares held by certain stockholders and investors) for $107.50 per share in cash. Additional investors in the going-private transaction included the following: other senior members of KMI management, most of whom are also senior officers of Kinder Morgan G.P., Inc. (our general partner) and of Kinder Morgan Management, LLC (our general partner’s delegate, discussed following); KMI co-founder William V. Morgan; KMI board members Fayez Sarofim and Michael C. Morgan; and affiliates of (i) Goldman Sachs Capital Partners; (ii) American International Group, Inc.; (iii) The Carlyle Group; and (iv) Riverstone Holdings LLC.

On May 30, 2007, this acquisition and merger closed, with KMI continuing as the surviving legal entity and renamed “Knight Inc.” Knight Inc., referred to as “Knight” in this report, is privately owned, and is the sole common stockholder of Kinder Morgan G.P., Inc., our general partner. Knight 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; and more than 155 terminals that store transfer and handle products like gasoline and coal. As of 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, 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).

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. Additionally, the information contained within this filing related to (i)Trans Mountain is accounted for as a transfer of net assets between entities under common control in accordance with SFAS 141 which required us to restate our consolidated financial statements to assume this acquisition occurred on January 1, 2006 and (ii) the North System is presented as discontinued operations for all income statements presented. With these two exceptions, events subsequent to the original 2006 10K filing have not been included. For a description of significant events subsequent to that filing, see our 10Q filing for the period ended September 30, 2007.

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:

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.

Effective January 1, 2006, Knight (formerly KMI), our ultimate parent as determined by the provisions of Emerging Issues Task Force Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” no longer accounted for its investment in us under the equity method of accounting, but instead included our accounts, balances and results of operations in its consolidated financial statements as of January 1, 2006, the date of common control. In addition, the purchase cost provisions (as they relate to purchase business combinations) of SFAS No. 141 explicitly do not apply to combinations of entities under common control; therefore, the assets we acquired and liabilities we assumed from our acquisition of the Trans Mountain pipeline system from Knight were excluded from the term “business combination” and were excluded from being accounted for under the purchase accounting method.

Instead, our acquisition of Trans Mountain was accounted for as a transfer of net assets between entities under common control, and the method of accounting prescribed by SFAS No. 141 for such transfers is similar to the pooling-of-interests method of accounting. Under this method, the carrying amount of net assets recognized in the balance sheets of each combining entity are carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination (that is, no recognition is made for a purchase premium or discount representing any difference between the cash consideration and the book value of the net assets acquired). This treatment is consistent with the concept of poolings as combinations of common stockholder (or unitholder) interests. Similarly, the income statement of the combined entity for the year of combination is presented as if the entities had been combined for the full year.

As a result, following our acquisition of Trans Mountain from Knight on April 30, 2007, the financial statements and financial information presented in this report for 2006 have been restated to assume that this acquisition had occurred at the date when both Trans Mountain and we met the accounting requirements for entities under common control (January 1, 2006), and we have recognized the Trans Mountain assets and liabilities acquired at their carrying amounts in the accounts of Knight (the transferring entity) at the date of transfer. The effect of this restatement is reflected below in Notes 3, 5, 6, 7, 8, 10, 12, 13, 15, and 19.

In addition, due to the fact that Trans Mountain’s operations are managed separately, involve different products and marketing strategies, and produce discrete financial information that is separately evaluated internally by our management, we have identified our Trans Mountain pipeline system as a separate reportable business segment.

On July 2, 2007, we announced that we have entered into an agreement to sell our North System and our 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $300 million in cash. The North System consists of an approximately 1,600-mile interstate common carrier pipeline system that delivers natural gas liquids and refined petroleum products from south central Kansas to the Chicago area. Also included in the sale are eight propane truck-loading terminals, located at various points in three states along the pipeline system, and one multi-product terminal complex located in Morris, Illinois. All of the assets are included in our Products Pipelines business segment.

This transaction closed in the fourth quarter of 2007. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we accounted for the North System business as a discontinued operation whereby the financial results of the North System have been reclassified to discontinued operations for all periods presented in this report. It is expected that the selling price described above, less our costs to sell, will exceed the carrying amount of the North System. The gain will be recognized in the fourth quarter of 2007. The effect of this reclassification is reflected below in Notes 7, 13, 15, and 19.

In addition, we also determined that presenting statements of cash flows that separately identified North System cash inflows and outflows would not be materially different from the information presented in our accompanying consolidated statements of cash flows. Accordingly, we did not separately present the operating and investing cash flows related to the activities of the North System in our accompanying consolidated statements of cash flows. And, due to the fact that the sale of our North System will not change the structure of our internal organization in a manner that causes a change to our reportable business segments pursuant to the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” we have included the North System’s financial disclosures within our Products Pipelines business segment disclosures for all periods presented in this report.

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

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.

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.

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.

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.

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.

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 $1,421.0 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.

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.

We capitalize interest expense during the construction or upgrade of qualifying assets. Interest expense capitalized in 2006, 2005 and 2004 was $20.3 million, $9.8 million and $6.4 million, respectively.

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.

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.

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.

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 pension and post-retirement benefit plans as an asset or liability in our statement of financial position. Accordingly, as of December 31, 2006, with regard to our SFPP, L.P. post-retirement benefit plan, 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.

In addition, as of December 31, 2006, we recognized a liability of $22.9 million for the unfunded portion of our Trans Mountain pension and post-retirement benefit plans. We included this amount within “Accrued other current liabilities” 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.

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.

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.

We account for all of the foreign operations described above in accordance with the provisions of SFAS No. 52, “Foreign Currency Translation.” We translate the assets and liabilities of each of these 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.

Statement of Financial Accounting Standards No. 130, “Accounting for Comprehensive Income,” requires that enterprises report a total for comprehensive income. For the year ended December 31, 2006, 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, foreign currency translation adjustments, and unrealized pension cost from minimum pension liability adjustments. For each of the years ended December 31, 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 millions):

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.

Emerging Issues Task Force Issue No. 03-6, or EITF 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No 128” addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its securities. For partnerships, under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed regardless of whether a general partner has discretion over the amount of distribution to be made for any particular period. EITF 03-6 does not impact our overall net income or other financial results because we do not have undistributed earnings in any period presented in this report.

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.

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.

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 millions):

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.

During 2006, 2005 and 2004, we completed or made adjustments for the following significant acquisitions. Except for our acquisition of the Trans Mountain pipeline system, discussed following, 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)
Ref.	Date	Acquisition	Purchase Price	Current Assets	Property Plant & Equipment	Deferred Charges & Other	Goodwill	Minority 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	$ —	$ —	$ —

Effective March 9, 2004, we acquired seven refined petroleum products terminals in the southeastern United States from Exxon Mobil 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 millions; amounts represent 100% of investee information):

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.

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.

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.

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.

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.

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.

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 accounted for under the purchase method of accounting, and all of the 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 millions, except for the per unit amounts:

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.

Trans Mountain Pipeline System (Transfer of net assets under common control)

As discussed more fully in Notes 1 and 2 above, on April 30, 2007, we acquired the Trans Mountain pipeline system from Knight (formerly KMI) for a payment of $550 million. The transaction was approved by the independent directors of both KMI and KMR following the receipt, by such directors, of separate fairness opinions from different investment banks. The Trans Mountain pipeline system, which transports crude oil and refined products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the State of Washington, recently completed a pump station expansion and currently transports approximately 260,000 barrels per day. An additional expansion that will increase capacity of the pipeline to 300,000 barrels per day is expected to be in service by late 2008.

With regard to our acquisition of Trans Mountain, the net assets transferred to us as of December 31, 2006 was as follows (in millions):

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 the net assets sold in this transaction, 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.

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 millions):

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

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

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

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.

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

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

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).

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.

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.

As discussed in Note 1, on July 2, 2007, we announced that we have entered into an agreement to sell our North System, which includes our 50% ownership interest in the Heartland Pipeline Company, to ONEOK Partners, L.P. for approximately $300 million in cash. In accordance with SFAS No. 144, we accounted for our equity investment in Heartland as a discontinued operation whereby our equity earnings in Heartland have been reclassified to discontinued operations for all periods presented in this report.

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

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.

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.

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.

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

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 millions):

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 millions):

	Products		Natural Gas						Trans
	Pipelines		Pipelines		CO₂		Terminals		Mountain(a)			Total
Balance as of December 31, 2004	$	263.2	$	250.3	$	46.1	$	173.3	$	─		$	732.9
Acquisitions and purchase price adjs.		─		38.1		─		28.0		─			66.1
Disposals.		─		─		─		─		─			─
Impairments				─		─		─		─			─
Balance as of December 31, 2005	$	263.2	$	288.4	$	46.1	$	201.3	$	─		$	799.0
Acquisitions and purchase price adjs.		─		─		─		30.0		593.2			623.2
Disposals.		─		─		─		─		─			─
Impairments		─		─		─		─		─			─
Currency translation adjustments		─		─		─		─		(1.2	)		(1.2	)
Balance as of December 31, 2006	$	263.2	$	288.4	$	46.1	$	231.3	$	592.0		$	1,421.0

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.

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 millions):

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

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.

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

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.

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 millions):

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:

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:

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

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:

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.

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.

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.

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.

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.

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.

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:

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.

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.

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.

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.

The scheduled maturities of our outstanding debt, excluding market value of interest rate swaps, as of December 31, 2006, are summarized as follows (in millions):

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.

Pursuant to a certain Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company (Kinder Morgan CO₂ Company, L.P. – 50% partner; a subsidiary of Exxon Mobil Corporation – 37% partner; and Cortez Vickers Pipeline Company – 13% partner) are required, on a several, percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The Throughput and Deficiency Agreement contractually supports the borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including cash deficiencies relating to the repayment of principal and interest on borrowings by Cortez Capital Corporation. Parent companies of the respective Cortez Pipeline Company partners further severally guarantee, on a percentage basis, the obligations of the Cortez Pipeline Company partners under the Throughput and Deficiency Agreement.

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

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.

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 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.

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).

Fair value as used in SFAS No. 107 “Disclosures About Fair Value of Financial Instruments” represents the amount at which an instrument could be exchanged in a current transaction between willing parties. The estimated fair value of our long-term debt, including its current portion and excluding market value of interest rate swaps, is based upon prevailing interest rates available to us as of December 31, 2006 and December 31, 2005 and is disclosed below.

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:

As of December 31, 2006, we estimate our overall net periodic post-retirement benefit cost for the SFPP post-retirement benefit plan 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 this post-retirement benefit plan in 2007.

Due to our acquisition of Trans Mountain (see Notes 1 and 2), we are a sponsor of pension plans for eligible Trans Mountain employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements, which provide pension benefits in excess of statutory limits, and defined contributory plans. We also provide post-retirement benefits other than pensions for retired employees. Our combined net periodic benefit costs for these Trans Mountain pension and post-retirement benefit plans for 2006 was approximately $4.3 million, recognized ratably over the period. As of December 31, 2006, we estimate our overall net periodic pension and post-retirement benefit costs for these plans for the year 2007 will be approximately $4.9 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. We expect to contribute approximately $2.6 million to these 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 our pension and post-retirement benefit plan obligations and previously unrecognized prior service credits and actuarial gains and losses. 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. Both the funded status and the recorded value of our combined pension and benefit obligation for the Trans Mountain pension and post-retirement benefit plans as of December 31, 2006 was $22.9 million.

The following table discloses the incremental effect on our consolidated balance sheet of applying SFAS No. 158 on December 31, 2006 (in millions):

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.

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 ½, death or disability. The employer contribution will still be considered taxable income at the time of withdrawal.

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.

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

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.

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.

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

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:

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.

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.

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:

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

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.

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.

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

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.

As discussed in Notes 1 and 2, on April 30, 2007, we acquired the Trans Mountain pipeline system from Knight (formerly KMI) for a payment of $550 million. The transaction was approved by the independent directors of both KMI and KMR following the receipt, by such directors, of separate fairness opinions from different investment banks. Pursuant to the provisions of generally accepted accounting principals, the financial statements and financial information presented in this report for 2006 have been restated to assume that this acquisition had occurred at the date when both Trans Mountain and we met the accounting requirements for entities under common control (January 1, 2006), and we have recognized the Trans Mountain assets and liabilities acquired at their carrying amounts in the accounts of Knight (the transferring entity) at the date of transfer.

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”.

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.

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.

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.

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:

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.

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 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.

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.

As of December 31, 2006, two separate affiliates of Knight owed to us a combined principal amount of $6.5 million in long term notes, and we included this balance within “Notes receivable—Related parties” on our consolidated balance sheet as of this date. The two notes are denominated in Canadian dollars, and the above amount represents the combined translated amount included in our consolidated financial statements in U.S. dollars.

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.

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 millions):

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

Including probable elections to exercise renewal options, the remaining terms on our operating leases range from one to 62 years. Future commitments related to these leases as of December 31, 2006 are as follows (in millions):

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

We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $8.7 million. Total lease and rental expenses were $54.2 million for 2006, $47.3 million for 2005 and $39.3 million for 2004.

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.

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

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.

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.

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:

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.

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 $866.1 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.

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 millions):

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	—		—		—

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.

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:

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:

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.

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.

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 millions):

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.

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.

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 other bulk chemicals. Our Trans Mountain business segment derives its revenues primarily from the transportation of crude oil and refined products from Edmonton, Alberta to marketing terminals and refineries in the Greater Vancouver area and Puget Sound in Washington State.

As discussed in Note 1, due to the sale of our North System, an approximate 1,600-mile interstate common carrier pipeline system whose operating results are included as part of our Products Pipelines business segment, we accounted for the North System business as a discontinued operation. Consistent with the management approach of identifying and reporting discrete financial information on operating segments, we have included the North System’s financial disclosures within our Products Pipelines business segment disclosures for all periods presented in this report and, as prescribed by SFAS No. 131, we have reconciled the total of our reportable segment’s financial results to our consolidated financial results by separately identifying, where applicable, the North System amounts as discontinued operations.

	2006			2005			2004
Revenues(a)
Products Pipelines
Revenues from external customers	$	776.3		$	711.8		$	645.3
Intersegment revenues		—			—			—
Natural Gas Pipelines
Revenues from external customers		6,577.7			7,718.4			6,252.9
Intersegment revenues		—			—			—
CO2
Revenues from external customers		736.5			657.6			492.8
Intersegment revenues		—			—			—
Terminals
Revenues from external customers		864.1			699.3			541.9
Intersegment revenues		0.7			—			—
Trans Mountain
Revenues from external customers		137.8			—			—
Intersegment revenues		—			—			—
Total segment revenues		9,093.1			9,787.1			7,932.9
Less: Total intersegment revenues		(0.7	)		—			—
		9,092.4			9,787.1			7,932.9
Less: Discontinued operations		(43.7	)		(41.2	)		(39.9	)
Total consolidated revenues	$	9,048.7		$	9,745.9		$	7,893.0

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 millions) total consolidated interest expense of $345.5 million, $268.4 million and $196.2 million, 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.

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.

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.

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.

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.

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.

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.

Kinder Morgan CO₂ Company, L.P., Kinder Morgan G.P., Inc., and Cortez Pipeline Company were among the named defendants in Shores, et al. v. Mobil Oil Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed March 29, 2001). These cases were originally filed as class actions on behalf of classes of overriding royalty interest owners (Shores) and royalty interest owners (Bank of Denton) for damages relating to alleged underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes were initially certified at the trial court level, appeals resulted in the decertification and/or abandonment of the class claims. On February 22, 2005, the trial judge dismissed both cases for lack of jurisdiction. Some of the individual plaintiffs in these cases re-filed their claims in new lawsuits (discussed below).

On May 13, 2004, William Armor, one of the former plaintiffs in the Shores matter whose claims were dismissed by the Court of Appeals for improper venue, filed a new case alleging the same claims for underpayment of royalties against the same defendants previously sued in the Shores case, including Kinder Morgan CO₂ Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas filed May 13, 2004). Defendants filed their answers and special exceptions on June 4, 2004. The case is currently set for trial on June 11, 2007.

On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd., two of the former plaintiffs in the Bank of Denton matter, filed a new case in Dallas state district court alleging the same claims for underpayment of royalties. Reddy and Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial District Court, Dallas County, Texas filed May 20, 2005). The defendants include Kinder Morgan CO₂ Company, L.P. and Kinder Morgan Energy Partners, L.P. On June 23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the court in the Armor lawsuit granted the motion to transfer and consolidate and ordered that the Reddy lawsuit be transferred and consolidated into the Armor lawsuit. The defendants filed their answer and special exceptions on August 10, 2005. The consolidated Armor/Reddy case is currently set for trial on June 11, 2007.

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.

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 (78^th Judicial District Court, Wichita County, Texas filed March 1, 2004). The defendants in this action include Kinder Morgan CO₂ Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell entities, ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004, defendants filed answers, special exceptions, pleas in abatement, and motions to transfer venue back to the Harris County District Court. On January 31, 2005, the Wichita County judge abated the case pending resolution of the Bailey State Court Action. The case remains abated.

On April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Colorado federal action filed by Bailey under the False Claims Act (which was transferred to the Bailey Houston Federal Court Action as described above), filed suit against Kinder Morgan G.P., Inc. in Colorado federal district court. Harry Ptasynski v. Kinder Morgan G.P., Inc., No. 06-CV-00651 (LTB) (U.S. District Court for the District of Colorado). Ptasynski, who holds an overriding royalty interest at McElmo Dome, asserted claims for civil conspiracy, violation of the Colorado Organized Crime Control Act, violation of Colorado antitrust laws, violation of the Colorado Unfair Practices Act, breach of fiduciary duty and confidential relationship, violation of the Colorado Payment of Proceeds Act, fraudulent concealment, 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 (10^th Cir.). Briefing in the appeal was completed on November 27, 2005. No oral argument has been set.

Kinder Morgan CO₂ Company, L.P. and Cortez Pipeline Company were among the named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case involved claims by overriding royalty interest owners in the McElmo Dome and Doe Canyon Units seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome and Doe Canyon. The plaintiffs also possess a small working interest at Doe Canyon. Plaintiffs claimed breaches of contractual and potential fiduciary duties owed by the defendants and also alleged other theories of liability including breach of covenants, civil theft, conversion, fraud/fraudulent concealment, violation of the Colorado Organized Crime Control Act, deceptive trade practices, and violation of the Colorado Antitrust Act. In addition to actual or compensatory damages, plaintiffs sought treble damages, punitive damages, and declaratory relief relating to the Cortez Pipeline tariff and the method of calculating and paying royalties on McElmo Dome carbon dioxide. The Court denied plaintiffs’ motion for summary judgment concerning alleged underpayment of McElmo Dome overriding royalties on March 2, 2005. In August 2006, plaintiffs and defendants reached a settlement of all claims. Pursuant to the settlement, the case was dismissed with prejudice on September 27, 2006.

Cortez Pipeline Company and Kinder Morgan CO₂ Company, L.P., successor 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.

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 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’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 (8^th 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.

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 10^th 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 (333^rd 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

On December 29, 2006, we received and executed an order of abatement by consent and settlement in the amount of $0.2 million with Maricopa County Air Quality Department relating to a several notices of violations associated with our Pacific operations’ pipeline terminal in Phoenix, Arizona.

Although no assurances can be given, we believe that we have meritorious defenses to all of these actions. Furthermore, to the extent an assessment of the matter is possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability. We also believe that these matters will not have a material adverse effect on our business, financial position, results of operations or cash flows.

Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, Inc. and ST Services, Inc.

On April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New Jersey, Gloucester County. We filed our answer to the complaint on June 27, 2003, in which we denied ExxonMobil’s claims and allegations as well as included counterclaims against ExxonMobil. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, and owned currently by ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil performed the environmental site assessment of the terminal required prior to sale pursuant to state law. During the site assessment, ExxonMobil discovered items that required remediation and the New Jersey Department of Environmental Protection issued an order that required ExxonMobil to perform various remediation activities to remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is still remediating the site and has not been removed as a responsible party from the state’s cleanup order; however, ExxonMobil claims that the remediation continues because of GATX

Terminals’ storage of a fuel additive, MTBE, at the terminal during GATX Terminals’ ownership of the terminal. When GATX Terminals sold the terminal to ST Services, the parties indemnified one another for certain environmental matters. When GATX Terminals was sold to us, GATX Terminals’ indemnification obligations, if any, to ST Services may have passed to us. Consequently, at issue is any indemnification obligation we may owe to ST Services for environmental remediation of MTBE at the terminal. The complaint seeks any and all damages related to remediating MTBE at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit for remediating MTBE at the terminal. The parties have completed limited discovery. In October 2004, the judge assigned to the case dismissed himself from the case based on a conflict, and the new judge has ordered the parties to participate in mandatory mediation. The parties participated in a mediation session on November 2, 2005 but no resolution was reached regarding the claims set out in the lawsuit. At this time, the mediation judge is working with a technical consultant and reviewing reports of scientific studies conducted at the site. We anticipate that there will be another mediation session during the second quarter of 2007.

The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC; Continental Oil Company; Chevron Corporation, California Superior Court, County of Los Angeles, Case No. NC041463.

We are and some of our subsidiaries are defendants in a lawsuit filed in 2005 captioned The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC; Continental Oil Company; Chevron Corporation, California Superior Court, County of Los Angeles, Case No. NC041463. The suit involves claims for environmental cleanup costs and rent at the former Los Angeles Marine Terminal in the Port of Los Angeles. Plaintiff alleges that terminal cleanup costs could approach $18 million; however, Kinder Morgan believes that the clean up costs should be substantially less and that cleanup costs must be apportioned among all the parties to the litigation. Plaintiff also alleges that it is owed approximately $2.8 million in past rent and an unspecified amount for future rent; however, we believe that previously paid rents will offset some of the plaintiff’s rent claim and that we have certain defenses to the payment of rent allegedly owed. The lawsuit is set for trial in October 2007.

Currently, this lawsuit is still in a preliminary stage of discovery, and the parties to the lawsuit have engaged environmental consultants to investigate environmental conditions at the terminal and to consider remedial options for those conditions. The California Regional Water Quality Control Board is the regulatory agency overseeing the environmental investigation and expected remedial work at the terminal, having issued formal directives to Kinder Morgan, plaintiff and the other defendants in the lawsuit to investigate terminal contamination and to propose a remedial action plan to address that contamination. We are supporting a lower cost cleanup that will meet state and federal regulatory requirements. We will vigorously defend these matters and believe that the outcome will not have a material adverse effect on us.

Our Kinder Morgan Transmix Company has been in discussions with the United States Environmental Protection Agency regarding allegations by the EPA that it violated certain provisions of the Clean Air Act and the Resource Conservation & Recovery Act. Specifically, the EPA claims that we failed to comply with certain sampling protocols at our Indianola, Pennsylvania transmix facility in violation of the Clean Air Act’s provisions governing fuel. The EPA further claims that we improperly accepted hazardous waste at our transmix facility in Indianola. Finally, the EPA claims that we failed to obtain batch samples of gasoline produced at our Hartford (Wood River), Illinois facility in 2004. In addition to injunctive relief that would require us to maintain additional oversight of our quality assurance program at all of our transmix facilities, the EPA is seeking monetary penalties of $0.6 million.

We are subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current or predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we

will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.

We are currently involved in several governmental proceedings involving air, water and waste violations issued by various governmental authorities related to compliance with environmental regulations. As we receive notices of non-compliance, we negotiate and settle these matters. We do not believe that these violations will have a material adverse affect on our business.

We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory authorities related to compliance with environmental regulations associated with our assets. We have established a reserve to address the costs associated with the cleanup.

In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide.

See “—Pipeline Integrity and Ruptures” above for information with respect to the environmental impact of recent ruptures of some of our pipelines.

Although no assurance can be given, we believe that the ultimate resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, we are not able to reasonably estimate when the eventual settlements of these claims will occur. Many factors may change in the future affecting our reserve estimates, such as regulatory changes, groundwater and land use near our sites, and changes in cleanup technology. As of December 31, 2006, we have accrued an environmental reserve of $64.2 million.

We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows.

The tariffs we charge for transportation on our interstate common carrier pipelines are subject to rate regulation by the Federal Energy Regulatory Commission, referred to in this report as the FERC, under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that interstate petroleum products pipeline rates be just and reasonable and nondiscriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, interstate petroleum products pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expanded the circumstances under which interstate petroleum products pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. For each of the years ended December 31, 2006, 2005 and 2004, the application of the indexing methodology did not significantly affect tariff rates on our interstate petroleum products pipelines.

On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards of Conduct to become effective February 9, 2004. Every interstate natural gas pipeline was required to file a compliance plan by that date and was required to be in full compliance with the Standards of Conduct by June 1, 2004. The primary change from existing regulation was to make such standards applicable to an interstate natural gas pipeline’s interaction with

many more affiliates (referred to as “energy affiliates”), including intrastate/Hinshaw natural gas pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or within a state boundary, is regulated by an agency of that state, and all the gas it transports is consumed within that state), processors and gatherers and any company involved in natural gas or electric markets (including natural gas marketers) even if they do not ship on the affiliated interstate natural gas pipeline. Local distribution companies were excluded, however, if they do not make sales to customers not physically attached to their system. The Standards of Conduct require, among other things, separate staffing of interstate pipelines and their energy affiliates (but support functions and senior management at the central corporate level may be shared) and strict limitations on communications from an interstate pipeline to an energy affiliate.

On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the effective date of the new Standards of Conduct from June 1, 2004, to September 1, 2004, and provided further clarification in several areas.

On February 19, 2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company and the affiliated interstate pipelines owned by KMI filed exemption requests with the FERC so that affiliated Hinshaw and intrastate pipelines would not be considered energy affiliates. On July 21, 2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company filed an alternative approach with respect to its exemption requests, seeking relief from the independent functioning and information disclosure requirements of Order 2004, subject to the separation of the commodity related functions of the intrastate pipelines and KMI’s retail operations from the transportation functions of the intrastate pipelines/retail operations and the interstate pipelines that were shared. The exemption requests proposed to treat as energy affiliates, within the meaning of Order 2004, two groups of employees:

Order 2004 regulations governing relationships between interstate pipelines and their energy affiliates would apply to relationships with these two discrete groups. Under these proposals, certain critical operating functions could continue to be shared.

On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the FERC extended the effective date of the new Standards of Conduct from September 1, 2004 to September 22, 2004.

On September 20, 2004, the FERC issued an order which conditionally granted the July 21, 2004 joint requests for limited exemptions from the requirements of the Standardsof Conduct described above. In that order, the FERC directed Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company and the affiliated interstate pipelines owned by KMI to submit compliance plans regarding these exemptions within 30 days. These compliance plans were filed on October 19, 2004, and set out certain steps taken by us to assure that employees in the Choice Gas Commodity Group of KMI and the commodity sales and purchase personnel of our Texas intrastate organizations do not have access to restricted interstate natural gas pipeline information or receive preferential treatment as to interstate natural gas pipeline services.

We have implemented compliance with the Standards of Conduct as of September 22, 2004, subject to the exemptions described above. Compliance includes, among other things, the posting of compliance procedures and organizational information for each interstate pipeline on its Internet website, the posting of discount and tariff discretion information and the implementation of independent functioning for energy affiliates not covered by the prior paragraph (electric and gas gathering, processing or production affiliates).

On December 21, 2004, the FERC issued Order No. 2004-C. In this order, the FERC granted rehearing on certain issues and also clarified certain provisions in the previous FERC 2004 orders. The primary impact on us from Order 2004-C is the granting of rehearing allowing local distribution companies to participate in hedging activity related to on-system sales and still qualify for exemption from being an energy affiliate.

By an order issued on April 19, 2005, the FERC accepted the compliance plans filed by us without modification, but subject to further clarification as to the intrastate group in three areas:

The Kinder Morgan interstate pipelines made a compliance filing on May 18, 2005. On July 20, 2006, the FERC accepted our May 19, 2005 compliance filing under Order No. 2004. On November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit, in Docket No. 04-1183, vacated FERC Orders 2004, 2004-A, 2004-B, 2004-C, and 2004-D as applied to natural gas pipelines, and remanded these same orders back to the FERC.

On January 9, 2007, the FERC issued an Interim Rule, effective January 9, 2007, in response to the court’s action. In the Interim Rule, the FERC readopted the Standards of Conduct, but revised or clarified with respect to issues which had been appealed to the court. Specifically, the following changes were made:

The FERC clarified that all exemptions and waivers issued under Order 2004 remain in effect. On January 18, 2007, the FERC issued a notice of proposed rulemaking seeking comments regarding whether or not the Interim Rule should be made permanent for natural gas transmission providers.

On July 25, 2003, the FERC issued a Modification to Policy Statement stating that FERC regulated natural gas pipelines will, on a prospective basis, no longer be permitted to use gas basis differentials to price negotiated rate transactions. Effectively, we will no longer be permitted to use commodity price indices to structure transactions on our FERC regulated natural gas pipelines. Negotiated rates based on commodity price indices in existing contracts will be permitted to remain in effect until the end of the contract period for which such rates were negotiated. Moreover, in subsequent orders in individual pipeline cases, the FERC has allowed negotiated rate transactions using pricing indices so long as revenue is capped by the applicable maximum rate(s). In a FERC order on rehearing and clarification issued January 19, 2006, the FERC modified its previous policy statement and now will again permit the use of gas commodity basis differentials in negotiated rate transactions without regard to rate or revenue caps. On March 23, 2006, the FERC dismissed rehearing requests and denied requests for clarification—all related to the January 19, 2006 order.

On November 5, 2004, the FERC issued a notice of proposed accounting release that would require FERC jurisdictional entities to recognize costs incurred in performing pipeline assessments that are a part of a pipeline

integrity management program as maintenance expense in the period incurred. The proposed accounting ruling was in response to the FERC’s finding of diverse practices within the pipeline industry in accounting for pipeline assessment activities. The proposed ruling would standardize these practices. Specifically, the proposed ruling clarifies the distinction between costs for a “one-time rehabilitation project to extend the useful life of the system,” which could be capitalized, and costs for an “on-going inspection and testing or maintenance program,” which would be accounted for as maintenance and charged to expense in the period incurred.

On June 30, 2005, the FERC issued an order providing guidance to the industry on accounting for costs associated with pipeline integrity management requirements. The order is effective prospectively from January 1, 2006. Under the order, the costs to be expensed as incurred include those to:

The costs of modifying the pipeline to permit in-line inspections, such as installing pig launchers and receivers, are to be capitalized, as are certain costs associated with developing or enhancing computer software or to add or replace other items of plant.

The Interstate Natural Gas Association of America, referred to in this report as INGAA, sought rehearing of the FERC’s June 30, 2005 order. The FERC denied INGAA’s request for rehearing on September 19, 2005. On December 15, 2005, INGAA filed with the United States Court of Appeals for the District of Columbia Circuit, in Docket No. 05-1426, a petition for review asking the court whether the FERC lawfully ordered that interstate pipelines subject to FERC rate regulation and related accounting rules must treat certain costs incurred in complying with the Pipeline Safety Improvement Act of 2002, along with related pipeline testing costs, as expenses rather than capital items for purposes of complying with the FERC’s regulatory accounting regulations. On May 10, 2006, the court issued an order establishing a briefing schedule. Under the schedule, INGAA filed its initial brief on June 23, 2006. Both the FERC’s and INGAA’s reply briefs have been filed. Oral argument at the Court of Appeals was held January 16, 2007.

Due to the implementation of this FERC order on January 1, 2006, our FERC-regulated natural gas pipelines expensed certain pipeline integrity management program costs that would have been capitalized. Also, beginning in the third quarter of 2006, our Texas intrastate natural gas pipeline group and the operations included in our Products Pipelines and CO₂ business segments began recognizing certain costs incurred as part of their pipeline integrity management program as operating expense in the period incurred, and in addition, recorded an expense for costs previously capitalized during the first six months of 2006. For the year 2006 compared to 2005, this change resulted in operating expense increases of approximately $4.4 million for our Texas intrastate gas group, $20.1 million for our Products Pipelines business segment, and $1.7 million for our CO₂ business segment. Combined, this change did not have a material impact on our financial position, results of operations, or cash flows for the 2006 annual period and did not have any material effect to prior periods. In addition, due to the fact that these amounts were not capitalized, but instead charged to expense, our 2006 sustaining capital expenditures were reduced by similar amounts.

On November 22, 2004, the FERC issued a notice of inquiry seeking comments on its policy of selective discounting. Specifically, the FERC requested parties to submit comments and respond to inquiries regarding the FERC’s practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons – when the discount is given to meet competition from another gas pipeline. By an order issued on May 31, 2005, the FERC reaffirmed its existing policy on selective discounting by interstate pipelines without change. Several entities filed for rehearing; however, by an order issued on November 17, 2005, the FERC denied all requests for rehearing. On January 9, 2006, a petition for judicial review

of the FERC’s May 31, 2005 and November 17, 2005 orders was filed by the Northern Municipal District Group/Midwest Region Gas Task Force Association.

On July 14, 2005, the FERC commenced an audit of TransColorado Gas Transmission Company, as well as a number of other interstate gas pipelines, to test compliance with the FERC’s requirements related to the filing and posting of the Index of Customers report. On September 21, 2005, the FERC’s staff issued a draft audit report which cited two minor issues with TransColorado’s Index of Customers filings and postings. Subsequently, on October 11, 2005, the FERC issued a final order which closed its examination, citing the minor issues contained in its draft report and approving the corrective actions planned or already taken by TransColorado. TransColorado has implemented corrective actions and has applied those actions to its most recent Index of Customer filing, dated October 1, 2005. No further compliance action is expected and TransColorado anticipates operating in compliance with applicable FERC rules regarding the filing and posting of its future Index of Customers reports.

On December 22, 2005, the FERC issued a notice of proposed rulemaking to amend its regulations by establishing two new methods for obtaining market based rates for underground natural gas storage services. First, the FERC proposed to modify its market power analysis to better reflect competitive alternatives to storage. Doing so would allow a storage applicant to include other storage services as well as non-storage products such as pipeline capacity, local production, or liquefied natural gas supply in its calculation of market concentration and its analysis of market share. Secondly, the FERC proposed to modify its regulations to permit the FERC to allow market based rates for new storage facilities even if the storage provider is unable to show that it lacks market power. Such modifications would be allowed provided the FERC finds that the market based rates are in the public interest, are necessary to encourage the construction of needed storage capacity, and that customers are adequately protected from the abuse of market power.

On June 19, 2006, FERC issued Order No. 678 allowing for broader market-based pricing of storage services. The rule expands the alternatives that can be considered in evaluating competition, provides that market-based pricing may be available even when market power is present (if market-based pricing is needed to stimulate development), and treats expansions of existing storage facilities similar to new storage facilities. The order became effective July 27, 2006.

On November 16, 2006, the FERC issued its order on rehearing, clarifying that it would consider whether additional reporting is appropriate on a case-by-case basis to ensure that customer protections remain adequate over time, but denying rehearing in all other respects.

On February 15, 2007, the FERC issued a notice of inquiry seeking comment on the need for changes or revisions to the FERC’s reporting requirements contained in the financial forms for gas and oil pipelines and electric utilities.

On June 23, 2006, in FERC Docket No. CP06-401-000, TransColorado Gas Transmission Company filed an application for authorization to construct and operate certain facilities comprising its proposed “Blanco-Meeker Expansion Project.” Upon implementation, this project will facilitate the transportation of up to approximately 250 million cubic feet per day of natural gas from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing interstate pipeline for delivery to the Rockies Express Pipeline at an existing point of interconnection located in the Meeker Hub in Rio Blanco County, Colorado.

On September 8, 2006, in FERC Docket No. CP06-449-000, we filed an application with the FERC requesting approval to construct and operate our Kinder Morgan Louisiana Pipeline. The pipeline will extend approximately 135 miles from Cheniere’s Sabine Pass liquefied natural gas terminal in Cameron Parish, Louisiana, to various delivery points in Louisiana and will provide interconnects with many other natural gas pipelines, including KMI’s Natural Gas Pipeline Company of America. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total. The entire approximately $500 million project is expected to be in service in the second quarter of 2009.

On December 16, 2004, the Financial Accounting Standards Board issued SFAS No. 123R (revised 2004), “Share-Based Payment.” This Statement amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and requires companies to expense the value of employee stock options and similar awards. Significant provisions of SFAS No. 123R include the following:

For us, this Statement became effective January 1, 2006. However, we have not granted common unit options or made any other share-based payment awards since May 2000, and as of December 31, 2005, all outstanding options to purchase our common units were fully vested. Therefore, the adoption of this Statement did not have an effect on our consolidated financial statements due to the fact that we have reached the end of the requisite service period for any compensation cost resulting from share-based payments made under our common unit option plan.

In March 2005, the Financial Accounting Standards Board issued Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143”. This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event.

Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred-generally upon acquisition, construction, or development and (or) through the normal operation of the asset. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably

estimate the fair value of an asset retirement obligation. This Interpretation was effective December 31, 2005, for us, and the adoption of this Interpretation had no effect on our consolidated financial statements.

On June 1, 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This Statement replaces Accounting Principles Board Opinion No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS No. 154 applies to all voluntary changes in accounting principle, and changes the requirements for accounting for and reporting of a change in accounting principle.

SFAS No. 154 requires retrospective application to prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. In contrast, APB No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. The FASB believes the provisions of SFAS No. 154 will improve financial reporting because its requirement to report voluntary changes in accounting principles via retrospective application, unless impracticable, will enhance the consistency of financial information between periods.

The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (January 1, 2006 for us). The Statement does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of the effective date of this Statement. Adoption of this Statement did not have any immediate effect on our consolidated financial statements, and we will apply this guidance prospectively.

In June 2005, the Emerging Issues Task Force reached a consensus on Issue No. 04-5, or EITF 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” EITF 04-5 provides guidance for purposes of assessing whether certain limited partners rights might preclude a general partner from controlling a limited partnership.

For general partners of all new limited partnerships formed, and for existing limited partnerships for which the partnership agreements are modified, the guidance in EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 did not have an effect on our consolidated financial statements.

Nonetheless, as a result of EITF 04-5, as of January 1, 2006, our financial statements are consolidated into the consolidated financial statements of KMI. Notwithstanding the consolidation of our financial statements into the consolidated financial statements of KMI pursuant to EITF 04-5, KMI is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or KMI’s financial statements is a legal determination based on the entity that incurs the liability. The determination of responsibility for payment among entities in our consolidated group of subsidiaries was not impacted by the adoption of EITF 04-5.

On February 16, 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments.” This Statement amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” The Statement improves the financial reporting of certain hybrid financial instruments by requiring more consistent accounting that eliminates exemptions and provides a means to simplify the accounting for these instruments. Specifically, it allows financial instruments that have embedded derivatives to be accounted for as a whole

(eliminating the need to bifurcate the derivative from its host) if the holder elects to account for the whole instrument on a fair value basis.

The provisions of this Statement are effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006 (January 1, 2007 for us). Adoption of this Statement did not have an effect on our consolidated financial statements.

On March 17, 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets.” This Statement amends SFAS No. 140 and simplifies the accounting for servicing assets and liabilities, such as those common with mortgage securitization activities. Specifically, this Statement addresses the recognition and measurement of separately recognized servicing assets and liabilities, and provides an approach to simplify efforts to obtain hedge-like (offset) accounting by permitting a servicer that uses derivative financial instruments to offset risks on servicing to report both the derivative financial instrument and related servicing asset or liability by using a consistent measurement attribute—fair value. For us, this Statement became effective January 1, 2007. Adoption of this Statement did not have an effect on our consolidated financial statements.

On June 28, 2006, the FASB ratified the consensuses reached by the Emerging Issues Task Force on EITF 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation).” According to the provisions of EITF 06-3:

EITF 06-3 should be applied to financial reports for interim and annual reporting periods beginning after December 15, 2006 (January 1, 2007 for us). Because the provisions of EITF 06-3 require only the presentation of additional disclosures on a prospective basis, the adoption of EITF 06-3 did not have an effect on our consolidated financial statements.

In June 2006, the FASB issued Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. For us, this Interpretation was effective January 1, 2007, and the adoption of this Interpretation had no effect on our consolidated financial statements.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108. This Bulletin requires a “dual approach” for quantifications of errors using both a method that focuses on the income statement impact, including the cumulative effect of prior years’ misstatements, and a method that focuses on the

period-end balance sheet. For us, SAB No. 108 was effective January 1, 2007. The adoption of this Bulletin did not have a material impact on our consolidated financial statements, and we will apply this guidance prospectively.

On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This Statement defines fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles and, as a result, there is now a common definition of fair value to be used throughout generally accepted accounting principles.

This Statement applies to other accounting pronouncements that require or permit fair value measurements; the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements; however, for some entities the application of this Statement will change current practice. The changes to current practice resulting from the application of this Statement relate to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 (January 1, 2008 for us), and interim periods within those fiscal years. This Statement is to be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, with certain exceptions. The disclosure requirements of this Statement are to be applied in the first interim period of the fiscal year in which this Statement is initially applied. We are currently reviewing the effects of this Statement.

Past accounting standards only required an employer to disclose the complete funded status of its plans in the notes to the financial statements. Recognizing the funded status of a company’s benefit plans as a net liability or asset on its balance sheet will require an offsetting adjustment to “Accumulated other comprehensive income/loss” in shareholders’ equity (“Partners’ Capital” for us). SFAS No. 158 does not change how pensions and other postretirement benefits are accounted for and reported in the income statement—companies will continue to follow the existing guidance in previous accounting standards. Accordingly, the amounts to be recognized in “Accumulated other comprehensive income/loss” representing unrecognized gains/losses, prior service costs/credits, and transition assets/obligations will continue to be amortized under the existing guidance. Those amortized amounts will continue to be reported as net periodic benefit cost in the income statement. Prior to SFAS No. 158, those unrecognized amounts were only disclosed in the notes to the financial statements.

According to the provisions of this Statement, an employer with publicly traded equity securities is required to initially recognize the funded status of a defined benefit pension plan or postretirement benefit plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006 (December 31, 2006 for us). In the year that the recognition provisions of this Statement are initially applied, an employer is required to disclose,

in the notes to the annual financial statements, the incremental effect of applying this Statement on individual line items in the year-end statement of financial position. For us, the adoption of this part of SFAS No. 158 did not have a material effect on our statement of financial position as of December 31, 2006. For more information on our pensions and other post-retirement benefit plans, and our disclosures regarding the provisions of this Statement, please see Note 10.

In addition, the requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008 (December 31, 2008 for us). In the year that the measurement date provisions of this Statement are initially applied, a business entity is required to disclose the separate adjustments of retained earnings (“Partners’ Capital” for us) and “Accumulated other comprehensive income/loss” from applying this Statement. While earlier application of the recognition of measurement date provisions is allowed, we have opted not to adopt this part of the Statement early.

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement provides companies with an option to report selected financial assets and liabilities at fair value. The Statement’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. The Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities.

SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. The Statement does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS No. 157, discussed above, and SFAS No. 107 “Disclosures about Fair Value of Financial Instruments.”

This Statement is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007 (January 1, 2008 for us). Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes that choice in the first 120 days of that fiscal year and also elects to apply the provisions of SFAS No. 157. We are currently reviewing the effects of this Statement.

					Income from		Income from
	Operating		Operating		Continuing		Discontinued
	Revenues		Income		Operations		Operation(c)			Net Income
					(In millions)
2006(a)
First Quarter	$	2,413.3	$	314.0	$	249.9	$	3.0		$	252.9
Second Quarter		2,216.1		317.7		251.0		3.4			254.4
Third Quarter		2,296.8		311.4		227.1		2.4			229.5
Fourth Quarter		2,122.5		348.5		261.8		5.5			267.3
2005
First Quarter	$	1,961.8	$	265.9	$	219.9	$	3.7		$	223.6
Second Quarter		2,118.5		273.8		220.4		1.4			221.8
Third Quarter		2,623.3		302.4		248.7		(3.3	)		245.4
Fourth Quarter(b)		3,042.3		173.7		123.4		(2.0	)		121.4

	Income from			Income from
	Continuing			Discontinued
	Operations			Operations(c)			Net Income
Basic Limited Partners’ income (loss) per Unit:
2006(a)
First Quarter	$	0.54		$	0.02		$	0.56
Second Quarter		0.55			0.01			0.56
Third Quarter		0.41			0.01			0.42
Fourth Quarter		0.62			0.02			0.64
2005
First Quarter	$	0.52		$	0.02		$	0.54
Second Quarter		0.49			0.01			0.50
Third Quarter		0.59			(0.01	)		0.58
Fourth Quarter(b)		(0.01	)		(0.01	)		(0.02	)

Diluted Limited Partners’ income (loss) per Unit:
2006(a)
First Quarter		0.54			0.02			0.56
Second Quarter		0.54			0.02			0.56
Third Quarter		0.41			0.01			0.42
Fourth Quarter		0.62			0.02			0.64
2005
First Quarter		0.52			0.02			0.54
Second Quarter		0.49			0.01			0.50
Third Quarter		0.59			(0.02	)		0.57
Fourth Quarter(b)		(0.01	)		(0.01	)		(0.02	)

The Supplementary Information on Oil and Gas Producing Activities is presented as required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” The supplemental information includes capitalized costs related to oil and gas producing activities; costs incurred for the acquisition of oil and gas producing activities, exploration and development activities; and the results of operations from oil and gas producing activities.

Supplemental information is also provided for per unit production costs; oil and gas production and average sales prices; the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

(a) Amounts relate to Kinder Morgan CO₂ Company, L.P. and its consolidated subsidaries. Includes capitalized asset retirement costs and associated accumulated depreciation. There are no capitalized costs associated with unproved oil and gas properties for the periods reported.

Our costs incurred for property acquisition, exploration and development were as follows (in millions):

(a) Amounts relate to Kinder Morgan CO₂ Company, L.P. and its consolidated subsidaries. There are no capitalized costs associated with unproved oil and gas properties for the periods reported. All capital expenditures were made to develop our proved oil and gas properties and no exploration costs were incurred for the periods reported.

Our results of operations from oil and gas producing activities for each of the years 2006, 2005 and 2004 are shown in the following table (in millions):

The table below represents estimates, as of December 31, 2006, of proved crude oil, natural gas liquids and natural gas reserves prepared by Netherland, Sewell and Associates, Inc. (independent oil and gas consultants) of Kinder Morgan CO₂ Company, L.P. and its consolidated subsidiaries’ interests in oil and gas properties, all of which are located in the State of Texas. This data has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this document. The estimates of reserves and future revenue in this document conforms to the guidelines of the United States Securities and Exchange Commission.

We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations or declines based upon future conditions. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.

During 2006, we filed estimates of our oil and gas reserves for the year 2005 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil reserves reported on Form EIA-23 and those reported in this report exceeds 5%.

Reserve Quantity Information
		Consolidated Companies(a)
	Crude Oil)			NGLs		Nat. Gas
		(MBbls)		(MBbls)		(MMcf)(b)
Proved developed and undeveloped reserves:
As of December 31, 2003		116,608		16,263		3,293
Revisions of previous estimates		19,030		5,350		(120	)
Production		(11,907	)	(1,368	)	(1,583	)
As of December 31, 2004		123,731		20,245		1,590
Revisions of previous estimates		9,807		(4,278	)	1,608
Improved Recovery		21,715		4,847		242
Production		(13,815	)	(1,920	)	(1,335	)
Purchases of reserves in place		513		89		48
As of December 31, 2005		141,951		18,983		2,153
Revisions of previous estimates		(4,615	)	(6,858	)	(1,408	)
Production		(13,811	)	(1,817	)	(461	)
Purchases of reserves in place		453		25		7
As of December 31, 2006		123,978		10,333		291

Proved developed reserves:
As of December 31, 2003		64,879		8,160		2,551
As of December 31, 2004		71,307		8,873		1,357
As of December 31, 2005		78,755		9,918		1,650
As of December 31, 2006		69,073		5,877		291

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year-to-year are prepared in accordance with SFAS No. 69. The assumptions that underly the computation of the standardized measure of discounted cash flows may be summarized as follows:

Our standardized measure of discounted future net cash flows from proved reserves were as follows (in millions):

The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in millions):

Changes in the Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves

Consolidated Companies(a)		2006			2005			2004
Present value as of January 1	$	3,075.0		$	2,045.0		$	1,407.8
Changes during the year:
Revenues less production and other costs(b)		(690.0	)		(624.4	)		(368.1	)
Net changes in prices, production and other costs(b)		(123.0	)		1,013.4			506.1
Development costs incurred		261.8			281.7			293.7
Net changes in future development costs		(446.0	)		(492.3	)		(270.1	)
Purchases of reserves in place		3.2			9.4			—
Revisions of previous quantity estimates		(179.5	)		51.1			397.0
Improved Recovery		—			587.5			—
Accretion of discount		307.4			204.4			136.9
Timing differences and other		(1.1	)		(0.8	)		(58.3	)
Net change for the year		(867.2	)		1,030.0			637.2
Present value as of December 31	$	2,207.8		$	3,075.0		$	2,045.0

	KINDER MORGAN ENERGY PARTNERS, L.P.

	By:	KINDER MORGAN G.P., INC.,
		its general partner

		By:	KINDER MORGAN MANAGEMENT, LLC,
			its delegate

Dated: November 21, 2007			By:	/s/ Kimberly A. Dang
				Kimberly A. Dang
				Vice President and Chief Financial Officer

Exhibit Number		Description

12.1	Statement re: computation of ratio of earnings to fixed charges.

23.1	Consent of PricewaterhouseCoopers LLP.

99.1	Revised financial statements as of and for the year ended December 31, 2006, including selected financial data as of and for the year ended December 31, 2006, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures about Market Risk.

	Year Ended
	December 31,
		2006
Earnings:
Pre-tax income from continuing operations before cumulative effect of a change in accounting principle and before adjustment for minority interest and equity earnings (including amortization of excess cost of equity investments) per statements of income	$	977,966
Add:
Fixed charges Services		383,854
Amortization of capitalized interest		1,258
Distributed income of equity investees		67,865
Less:
Interest capitalized from continuing operations		(20,267	)
Minority interest in pre-tax income of subsidiaries with no fixed charges		(503	)
Income as adjusted	$	1,410,173


Fixed charges:
Interest and debt expense, net per statements of income (includes amortization of debt discount, premium, and debt issuance costs; excludes capitalized interest)	$	365,792
Add:
Portion of rents representative of the interest factor Services		18,062
Fixed charges	$	383,854


Ratio of earnings to fixed charges		3.67

Item*	Description	Page

6.	Selected Financial Data	1-3
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	3-49
7A.	Quantitative and Qualitative Disclosures about Market Risk	50-53
8.	Financial Statements and Supplementary Data	54-165

	Year Ended December 31,
	2006			2005			2004
	(In millions – income/(expense))
General and administrative expenses(a)	$	(238.4	)	$	(216.7	)	$	(170.5	)
Unallocable interest, net(b)		(342.4	)		(264.3	)		(194.9	)
Minority interest(c)		(15.4	)		(7.3	)		(9.7	)
Loss from early extinguishment of debt		─			─			(1.6	)
Interest and corporate administrative expenses	$	(596.2	)	$	(488.3	)	$	(376.7	)

Entity	Investment Type	Our Ownership Interest	Remaining Interest(s) Ownership	Total Entity Assets(5)	Total Entity Debt	Our Contingent Share of Entity Debt(6)
	General
Cortez Pipeline Company	Partner	50%	(1)	$73.7	$148.9	$74.5(2)

Red Cedar Gathering	General		Southern Ute
Company	Partner	49%	Indian Tribe	$247.5	$31.4	$15.4

	Limited		ConocoPhillips and
West2East Pipeline LLC(3)	Liability	51%	Sempra Energy	$850.5	$790.1	$403.0

			Nassau County,
Nassau County,			Florida Ocean
Florida Ocean Highway			Highway and
and Port Authority (4)	N/A	N/A	Port Authority	N/A	N/A	$23.9

	Credit Rating
Morgan Stanley	A+
J. Aron & Company / Goldman Sachs	AA–
BNP Paribas	AA

	Page

Report of Independent Registered Public Accounting Firm	54-55
Consolidated Statements of Income	56
Consolidated Statements of Comprehensive Income	57
Consolidated Balance Sheets	58
Consolidated Statements of Cash Flows	59
Consolidated Statements of Partners’ Capital	60
Notes to Consolidated Financial Statements	61-160
Selected Quarterly Financial Data (Unaudited)	160-161
Supplementary Information on Oil and Gas Producing Activities (Unaudited)	161-164

	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	$	6.5	$	0.3	$	0.3	$	(0.3	)	$	6.8

Year ended December 31, 2005	$	8.6	$	0.2	$	—	$	(2.3	)	$	6.5

Year ended December 31, 2004	$	8.8	$	1.5	$	0.4	$	(2.1	)	$	8.6

	Net unrealized			Foreign			Pension and 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	$	(457.7	)	$	0.3		$	—		$	(457.4	)
Change for period		(621.6	)		(0.7	)		—			(622.3	)
December 31, 2005		(1,079.3	)		(0.4	)		—			(1,079.7	)
Change for period		240.6			(19.6	)		(7.4	)		213.6
December 31, 2006	$	(838.7	)	$	(20.0	)	$	(7.4	)	$	(866.1	)

	As of December 31,
Regulated Assets:	2006		2005
Employee benefit costs	$	0.4	$	0.3
Fuel Tracker		1.6		—
Deferred regulatory expenses		3.2		3.4
Total regulatory assets		5.2		3.7

Regulated Liabilities:
Deferred income taxes		0.9		1.9
Fuel Tracker		—		(1.3	)
Total regulatory liabilities		0.9		0.6

Net regulatory assets	$	4.3	$	3.1

	December 31,
Balance Sheet	2006
Current assets	$	3.5
Non-current assets		847.0
Current liabilities		68.5
Non-current liabilities		790.1
Accumulated other comprehensive income	$	(8.1	)

	Pro Forma Year Ended
	December 31,
	2006		2005
	(Unaudited)
Revenues	$	9,117.7	$	9,882.4
Operating Income		1,310.0		1,040.8
Net Income	$	1,006.5	$	823.0
Basic Limited Partners’ Net Income per unit	$	2.20	$	1.63
Diluted Limited Partners’ Net Income per unit	$	2.19	$	1.62

Cash acquired	$	(10.2	)
Accumulated other comprehensive loss		(1.4	)
Liabilities assumed		282.5
Minority interest		9.4
Partners’ capital		919.2
	$	1,199.5

Allocation of assets:
Current assets	$	18.3
Property, plant and equipment		566.9
Goodwill		593.2
Deferred charges and other assets		21.1
	$	1,199.5

	Year Ended December 31,
Income Statement	2006		2005		2004
Revenues	$	449.7	$	448.4	$		418.2
Costs and expenses		303.4		282.3		265.8
Earnings before extraordinary items and cumulative effect of a change in accounting principle		146.3		166.1		152.4
Net income	$	146.3	$	166.1	$	152.4

	December 30,			December 31,
	2006			2005
Goodwill
Gross carrying amount	$	1,435.1		$	813.1
Accumulated amortization		(14.1	)		(14.1	)
Net carrying amount		1,421.0			799.0

Subsidiary borrowings:
Central Florida Pipe Line LLC-7.840% senior notes due July 23, 2008		10.0			15.0
Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010		5.3			5.3
Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014		49.1			54.7
Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due Jan. 15, 2018		25.0			25.0
Kinder Morgan Operating L.P. “B”-Jackson-Union Cos. IL Revenue Bonds due April 1, 2024		23.7			23.7
International Marine Terminals-Plaquemines, LA Revenue Bonds due March 15, 2025		40.0			40.0
Other miscellaneous subsidiary debt		1.4			1.5
Unamortized debt discount on senior notes		(9.3	)		(10.5	)
Current portion of long-term debt		(1,359.1	)		—
Total Long-term debt	$	4,384.3		$	5,220.9

2007	$	1,359.1
2008		11.2
2009		256.4
2010		261.6
2011		706.4
Thereafter		3,148.7
Total	$	5,743.4

	December 31, 2006		December 31, 2005
	Carrying Value	Estimated Fair Value	Carrying Value	Estimated Fair Value
	(In millions)
Total Debt	$ 5,743.4	$ 5,865.0	$ 5,220.9	$ 5,465.2

		Before Application			Adjustments			After Application 2005
Prepaid benefit cost	$	─		$	─		$	─
Accrued benefit liability		30.3			(1.9	)		28.4
Intangible asset		─			─			─
Deferred income tax liability		(6.4	)		(1.2	)		(7.6	)
Minority interest		─			─			─
Accumulated other comprehensive income		─			3.1			3.1

	December 31,
		2006
Leasehold improvements	$	4.1
Machinery and equipment.		—
		4.1
Less: Accumulated amortization		(3.0	)
	$	1.1

Year	Commitment
2007	$	0.2
2008		0.2
2009		0.2
2010		0.2
2011		0.2
Thereafter		0.8
Subtotal		1.8
Less: Amount representing interest		(0.7	)
Present value of minimum capital lease payments	$	1.1

Operating expenses(b)
Products Pipelines	$	308.3		$	366.0		$	191.4
Natural Gas Pipelines		6,057.8			7,255.0			5,862.2
CO2		268.1			212.6			173.5
Terminals		461.9			373.4			272.8
Trans Mountain		53.3			—			—
Total segment operating expenses		7,149.4			8,207.0			6,499.9
Less: Total intersegment operating expenses		(0.7	)		—			—
		7,148.7			8,207.0			6,499.9
Less: Discontinued operations		(22.7	)		(35.2	)		(18.8	)
Total consolidated operating expenses	$	7,126.0		$	8,171.8		$	6,481.1

Other expense (income)(c)
Products Pipelines	$	—		$	—	$	—
Natural Gas Pipelines		(15.1	)		—		—
CO2		—			—		—
Terminals		(15.2	)		—		—
Trans Mountain		(0.9	)		—		—
Total consolidated other expense (income)	$	(31.2	)	$	—	$	—

Depreciation, depletion and amortization
Products Pipelines	$	82.9		$	79.1		$	71.3
Natural Gas Pipelines		65.4			61.7			53.1
CO2		190.9			149.9			121.3
Terminals		74.6			59.1			42.9
Trans Mountain		19.0			—			—
Total segment depreciation, depletion and amortiz..		432.8			349.8			288.6
Less: Discontinued operations		(8.9	)		(8.2	)		(7.5	)
Total consol. depreciation, depletion and amortiz..	$	423.9		$	341.6		$	281.1

Earnings from equity investments(d)
Products Pipelines	$	16.3		$	28.5		$	29.0
Natural Gas Pipelines		40.5			36.8			20.0
CO2		19.2			26.3			34.2
Terminals		0.2			0.1			—
Trans Mountain		—			—			—
Total segment earnings from equity investments.		76.2			91.7			83.2
Less: Discontinued operations		(2.2	)		(2.1	)		(1.4	)
Total consolidated equity earnings.	$	74.0		$	89.6		$	81.8

Other, net-income (expense)(e)
Products Pipelines	$	7.6		$	1.5		$	(28.0	)
Natural Gas Pipelines		0.6			2.0			9.4
CO2		0.8			—			4.2
Terminals		2.1			(0.2	)		18.3
Trans Mountain		1.0			—			—
Total segment other, net-income (expense)		12.1			3.3			3.9
Loss from early extinguishment of debt		—			—			(1.6	)
Less: Discontinued operations		(0.1	)		—			(0.1	)
Total consolidated other, net-income (expense)	$	12.0		$	3.3		$	2.2

Income tax benefit (expense)(f)
Products Pipelines	$	(5.2	)	$	(10.3	)	$	(12.1	)
Natural Gas Pipelines		(1.4	)		(2.6	)		(1.9	)
CO2		(0.2	)		(0.4	)		(0.1	)
Terminals		(12.3	)		(11.2	)		(5.6	)
Trans Mountain		(9.9	)		—			—
Total consolidated income tax benefit (expense)	$	(29.0	)	$	(24.5	)	$	(19.7	)

Segment earnings(g)
Products Pipelines	$	404.9		$	287.6		$	370.3
Natural Gas Pipelines		509.1			438.4			364.9
CO2		295.3			319.0			234.3
Terminals		333.5			255.5			238.8
Trans Mountain		57.5			—			—
Total segment earnings		1,600.3			1,300.5			1,208.3
Interest and corporate administrative expenses(h)		(596.2	)		(488.3	)		(376.7	)
Total consolidated net income	$	1,004.1		$	812.2		$	831.6

Capital expenditures(j)
Products Pipelines	$	196.0	$	271.5	$	213.8
Natural Gas Pipelines		271.6		102.9		106.4
CO2		283.0		302.1		302.9
Terminals		307.7		186.6		124.2
Trans Mountain		123.8		—		—
Total consolidated capital expenditures	$	1,182.1	$	863.1	$	747.3

Assets at December 31
Products Pipelines	$	3,910.5	$	3,873.9	$	3,651.7
Natural Gas Pipelines		3,946.6		4,140.0		3,691.4
CO2		1,870.8		1,772.8		1,527.8
Terminals		2,397.5		2,052.5		1,576.3
Trans Mountain		1,314.0		—		—
Total segment assets		13,439.4		11,839.2		10,447.2
Corporate assets(k)		102.8		84.3		105.7
Total consolidated assets	$	13,542.2	$	11,923.5	$	10,552.9

Capitalized Costs Related to Oil and Gas Producing Activities
	December 31,
Consolidated Companies(a)		2006			2005			2004
Wells and equipment, facilities and other	$	1.4		$	1.1		$	0.8
Leasehold		0.3			0.3			0.3
Total proved oil and gas properties		1.7			1.4			1.1
Accumulated depreciation and depletion		(0.5	)		(0.3	)		(0.1	)
Net capitalized costs	$	1.2		$	1.1		$	1.0

Costs Incurred in Exploration, Property Acquisitions and Development
	Year Ended December 31,
Consolidated Companies(a)		2006		2005		2004
Property Acquisition
Proved oil and gas properties	$	36.6	$	6.4	$	–
Development		261.8		281.7		293.7

Results of Operations for Oil and Gas Producing Activities
	Year Ended December 31,
Consolidated Companies(a)			2006		2005		2004
Revenues(b)		$	524.7	$	469.1	$	361.8
Expenses:
Production costs			208.9		159.6		131.5
Other operating expenses(c)			66.4		59.0		44.0
Depreciation, depletion and amortization expenses			169.4		130.5		104.2
Total expenses			444.7		349.1		279.7
Results of operations for oil and gas producing activities		$	80.0	$	120.0	$	82.1

Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves
	As of December 31,
Consolidated Companies(a)		2006			2005			2004
Future cash inflows from production	$	7,534.7		$	9,150.6		$	5,799.7
Future production costs		(2,617.9	)		(2,756.6	)		(1,935.6	)
Future development costs(b)		(1,256.8	)		(869.0	)		(502.2	)
Undiscounted future net cash flows		3,660.0			5,525.0			3,361.9
10% annual discount		(1,452.2	)		(2,450.0	)		(1,316.9	)
Standardized measure of discounted future net cash flows	$	2,207.8		$	3,075.0		$	2,045.0