Kinder Morgan Energy Partners L P 10-K/A 2010 FY Annual report (amended)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

Form 10-K/A

(Amendment No. 1)

[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)           OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

or

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)            OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 1-11234

Kinder Morgan Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware	76-0380342
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

500 Dallas Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

Registrant’s telephone number, including area code: 713-369-9000

_______________

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Units	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.  Yes [X]    No [   ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.  Yes [   ]   No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes [X]   No [   ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes [X]   No [   ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [   ]

1

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer [X]   Accelerated filer [   ]     Non-accelerated filer [   ]     Smaller reporting company [   ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).  Yes [   ]   No [X]

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 2010 was approximately $12,836,486,727.  As of January 31, 2011, the registrant had 218,993,455 Common Units outstanding.

2

EXPLANATORY NOTE

The sole purpose of this amendment is to file to correct the signature line of the Report of Independent Registered Public Accounting Firm included in Item 8 "Financial Statements and Supplementary Data." The report had been signed by the Independent Registered Public Accounting Firm, but the signature line was inadvertently omitted when the Form 10-K was originally filed. As part of this amendment and as required, we are refiling "Item 8. Financial Statements and Supplementary Data" in its entirety. Other than correcting the signature line of the Report of Independent Registered Public Accounting Firm, we have made no changes to Item 8.

Item 8.  Financial Statements and Supplementary Data.

The information required in this Item 8 is included in this report as set forth in the “Index to Financial Statements” on page 114.

3

INDEX TO FINANCIAL STATEMENTS

	Page Number
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Registered Public Accounting Firm	115
Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008	116
Consolidated Statements of Comprehensive Income for the years ended December 31, 2010, 2009 and 2008	117
Consolidated Balance Sheets as of December 31, 2010 and 2009                                                                                                                                   & #160;	118
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008	119
Consolidated Statements of Partners’ Capital for the years ended December 31, 2010, 2009 and 2008	121
Notes to Consolidated Financial Statements                                                                                                                                      & #160;	123

114

Report of Independent Registered Public Accounting Firm

To the Partners of

Kinder Morgan Energy Partners, L.P.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of partners' capital and of cash flows present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. and its subsidiaries (the "Partnership") at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010 based on criteria established in Internal Control - Integrated Fram ework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing in Item 9A of the Partnership's 2010 Annual Report on Form 10-K.  Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal cont rol over financial reporting was maintained in all material respects.  Our audits of the financial statements included 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.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 18, 2011

115

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2010			2009			2008
Revenues	(In millions except per unit amounts)
Natural gas sales	$	3,614.4		$	3,137.2		$	7,705.2
Services		3,024.7			2,739.1			2,770.3
Product sales and other		1,438.6			1,127.1			1,264.8
Total Revenues		8,077.7			7,003.4			11,740.3
Operating Costs, Expenses and Other
Gas purchases and other costs of sales		3,606.3			3,068.8			7,716.1
Operations and maintenance		1,415.0			1,136.2			1,282.8
Depreciation, depletion and amortization		904.8			850.8			702.7
General and administrative		375.2			330.3			297.9
Taxes, other than income taxes		171.4			137.0			186.7
Other expense (income)		(0.1	)		(34.8	)		2.6
Total Operating Costs, Expenses and Other		6,472.6			5,488.3			10,188.8
Operating Income		1,605.1			1,515.1			1,551.5
Other Income (Expense)
Earnings from equity investments		223.1			189.7			160.8
Amortization of excess cost of equity investments		(5.8	)		(5.8	)		(5.7	)
Interest expense		(507.6	)		(431.5	)		(398.2	)
Interest income		22.7			22.5			10.0
Other, net		24.2			49.5			19.2
Total Other Income (Expense)		(243.4	)		(175.6	)		(213.9	)
Income from Continuing Operations Before Income Taxes		1,361.7			1,339.5			1,337.6
Income Taxes		(34.6	)		(55.7	)		(20.4	)
Income from Continuing Operations		1,327.1			1,283.8			1,317.2
Discontinued Operations (Note 3):
Gain on disposal of North System		-			-			1.3
Income from Discontinued Operations		-			-			1.3
Net Income		1,327.1			1,283.8			1,318.5
Net Income Attributable to Noncontrolling Interests		(10.8	)		(16.3	)		(13.7	)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.	$	1,316.3		$	1,267.5		$	1,304.8
Calculation of Limited Partners’ Interest in Net Income Attributable to Kinder Morgan Energy Partners, L.P.:
Income from Continuing Operations	$	1,316.3		$	1,267.5		$	1,303.5
Less: General Partner’s interest		(884.9	)		(935.8	)		(805.8	)
Limited Partners’ interest		431.4			331.7			497.7
Add: Limited Partners’ interest in discontinued operations		-			-			1.3
Limited Partners’ Interest in Net Income	$	431.4		$	331.7		$	499.0
Limited Partners’ Net Income per Unit:
Income from continuing operations	$	1.40		$	1.18		$	1.94
Income from discontinued operations		-			-			-
Net Income	$	1.40		$	1.18		$	1.94
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income Per Unit		307.1			281.5			257.2
Per Unit Cash Distribution Declared	$	4.40		$	4.20		$	4.02

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

116

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2010			2009			2008
	(In millions)
Net Income	$	1,327.1		$	1,283.8		$	1,318.5
Other Comprehensive Income (Loss):
Change in fair value of derivatives utilized for hedging purposes		(76.1	)		(458.2	)		658.0
Reclassification of change in fair value of derivatives to net income		188.4			100.3			670.5
Foreign currency translation adjustments		100.6			252.2			(333.2	)
Adjustments to pension and other postretirement benefit plan liabilities		(2.3	)		(2.5	)		3.7
Total Other Comprehensive Income (Loss)		210.6			(108.2	)		999.0
Comprehensive Income		1,537.7			1,175.6			2,317.5
Comprehensive Income Attributable to Noncontrolling Interests		(13.0	)		(15.2	)		(23.8	)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.	$	1,524.7		$	1,160.4		$	2,293.7

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

117

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009
	(Dollars in millions)
ASSETS
Current assets
Cash and cash equivalents	$	129.1		$	146.6
Restricted deposits		50.0			15.2
Accounts, notes and interest receivable, net		951.8			902.1
Inventories		92.0			71.9
Gas in underground storage		2.2			43.5
Fair value of derivative contracts		24.0			20.8
Other current assets		37.6			44.6
Total current assets		1,286.7			1,244.7
Property, plant and equipment, net		14,603.9			14,153.8
Investments		3,886.0			2,845.2
Notes receivable		115.0			190.6
Goodwill		1,233.6			1,149.2
Other intangibles, net		302.2			218.7
Fair value of derivative contracts		260.7			279.8
Deferred charges and other assets		173.0			180.2
Total Assets	$	21,861.1		$	20,262.2
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	1,262.4	��	$	594.7
Cash book overdrafts		32.5			34.8
Accounts payable		630.9			614.8
Accrued interest		239.6			222.4
Accrued taxes		44.7			57.8
Deferred revenues		96.6			76.0
Fair value of derivative contracts		281.5			272.0
Accrued other current liabilities		176.0			145.1
Total current liabilities		2,764.2			2,017.6
Long-term liabilities and deferred credits
Long-term debt
Outstanding		10,277.4			9,997.7
Value of interest rate swaps		604.9			332.5
Total Long-term debt		10,882.3			10,330.2
Deferred income taxes		248.3			216.8
Fair value of derivative contracts		172.2			460.1
Other long-term liabilities and deferred credits		501.6			513.4
Total long-term liabilities and deferred credits		11,804.4			11,520.5
Total Liabilities		14,568.6			13,538.1
Commitments and contingencies (Notes 8, 12 and 16)
Partners’ Capital
Common units (218,880,103 and 206,020,826 units issued and outstanding   as of December 31, 2010 and 2009, respectively)		4,282.2			4,057.9
Class B units (5,313,400 and 5,313,400 units issued and outstanding   as of December 31, 2010 and 2009, respectively)		63.1			78.6
i-units (91,907,987 and 85,538,263 units issued and outstanding   as of December 31, 2010 and 2009, respectively)		2,807.5			2,681.7
General partner		244.3			221.1
Accumulated other comprehensive loss		(186.4	)		(394.8	)
Total Kinder Morgan Energy Partners, L.P. partners’ capital		7,210.7			6,644.5
Noncontrolling interests		81.8			79.6
Total Partners’ Capital		7,292.5			6,724.1
Total Liabilities and Partners’ Capital	$	21,861.1		$	20,262.2

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

118

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2010			2009			2008
	(In millions)
Cash Flows From Operating Activities
Net Income	$	1,327.1		$	1,283.8		$	1,318.5
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		904.8			850.8			702.7
Amortization of excess cost of equity investments		5.8			5.8			5.7
Income from the allowance for equity funds used during construction		(0.7	)		(22.7	)		(10.6	)
Income from the sale or casualty of property, plant and equipment and other net assets		(8.9	)		(34.8	)		(11.7	)
Earnings from equity investments		(223.1	)		(189.7	)		(160.8	)
Distributions from equity investments		219.8			234.5			158.4
Proceeds from termination of interest rate swap agreements		157.6			144.4			194.3
Changes in components of working capital:
Accounts receivable		17.7			54.5			105.4
Inventories		(20.8	)		(20.0	)		(7.3	)
Other current assets		31.6			(75.9	)		(9.1	)
Accounts payable		(9.4	)		(184.6	)		(100.6	)
Accrued interest		17.1			50.2			41.1
Accrued taxes		(12.9	)		5.3			(22.3	)
Accrued liabilities		12.8			(24.1	)		57.4
Rate reparations, refunds and other litigation reserve adjustments		(34.3	)		2.5			(13.7	)
Other, net		34.8			37.1			(11.5	)
Net Cash Provided by Operating Activities		2,419.0			2,117.1			2,235.9
Cash Flows From Investing Activities
Acquisitions of equity investments		(925.7	)		(36.0	)		-
Acquisitions of assets		(287.5	)		(292.9	)		(40.2	)
Repayment (Payment) for Trans Mountain Pipeline		-			-			23.4
Repayments (Loans) from customers		-			109.6			(109.6	)
Capital expenditures		(1,000.9	)		(1,323.8	)		(2,533.0	)
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs		34.3			47.4			47.8
(Investments in) Net proceeds from margin and restricted deposits		(32.2	)		(18.5	)		71.0
Contributions to investments		(299.3	)		(2,051.8	)		(366.7	)
Distributions from equity investments in excess of cumulative earnings		189.8			112.0			89.1
Other, net		7.0			-			(7.2	)
Net Cash Used in Investing Activities		(2,314.5	)		(3,454.0	)		(2,825.4	)
Cash Flows From Financing Activities
Issuance of debt		7,140.1			6,891.9			9,028.6
Payment of debt		(6,186.4	)		(4,857.1	)		(7,525.0	)
Repayments from related party		2.7			3.7			1.8
Debt issue costs		(22.9	)		(13.7	)		(12.7	)
(Decrease) Increase in cash book overdrafts		(2.2	)		(8.0	)		23.8
Proceeds from issuance of common units		758.7			1,155.6			560.9
Contributions from noncontrolling interests		12.5			15.4			9.3
Distributions to partners and noncontrolling interests:
Common units		(918.7	)		(809.2	)		(684.5	)
Class B units		(22.9	)		(22.3	)		(20.7	)
General Partner		(861.7	)		(918.4	)		(764.7	)
Noncontrolling interests		(23.3	)		(22.0	)		(18.8	)
Other, net		(0.2	)		(0.9	)		3.3
Net Cash (Used in) Provided by Financing Activities		(124.3	)		1,415.0			601.3
Effect of Exchange Rate Changes on Cash and Cash Equivalents		2.3			6.0			(8.2	)
Net (decrease) increase in Cash and Cash Equivalents		(17.5	)		84.1			3.6
Cash and Cash Equivalents, beginning of period		146.6			62.5			58.9
Cash and Cash Equivalents, end of period	$	129.1		$	146.6		$	62.5

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS   (continued)

	Year Ended December 31,
	2010			2009		2008
	(In millions)
Noncash Investing and Financing Activities
Assets acquired by the issuance of units	$	81.7		$	5.0	$	-
Related party assets acquired by the issuance of units	$	-		$	-	$	116.0
Assets acquired by the assumption or incurrence of liabilities	$	13.8		$	7.7	$	4.8
Contribution of net assets to investments	$	20.0		$	-	$	-
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	472.8		$	400.3	$	373.3
Cash (received) paid during the period for income taxes	$	(2.2	)	$	3.4	$	35.7

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

120

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

	2010					2009					2008
	Units		Amount			Units		Amount			Units		Amount
	(Dollars in millions)
Common Units:
Beginning Balance		206,020,826	$	4,057.9			182,969,427	$	3,458.9			170,220,396	$	3,048.4
Net income		-		299.5			-		229.0			-		343.4
Units issued as consideration pursuant to common unit compensation plan for non-employee directors		2,450		0.2			3,200		0.2			4,338		0.3
Units issued as consideration in the acquisition of assets		1,287,287		81.7			105,752		5.0			2,014,693		116.0
Units issued for cash		11,569,540		758.7			22,942,447		1,155.6			10,730,000		560.9
Adjustments to capital resulting from related party
acquisitions		-		-			-		15.5			-		69.1
Distributions		-		(918.7	)		-		(809.2	)		-		(684.5	)
Other Adjustments		-		2.9			-		2.9			-		5.3
Ending Balance		218,880,103		4,282.2			206,020,826		4,057.9			182,969,427		3,458.9
Class B Units:
Beginning Balance		5,313,400		78.6			5,313,400		94.0			5,313,400		102.0
Net income		-		7.4			-		6.3			-		10.4
Adjustments to capital resulting from related party
acquisitions		-		-			-		0.5			-		2.1
Distributions		-		(22.9	)		-		(22.3	)		-		(20.7	)
Other Adjustments		-		-			-		0.1			-		0.2
Ending Balance		5,313,400		63.1			5,313,400		78.6			5,313,400		94.0
i-Units:
Beginning Balance		85,538,263		2,681.7			77,997,906		2,577.1			72,432,482		2,400.8
Net income		-		124.5			-		96.4			-		145.2
Adjustments to capital resulting from related party
Acquisitions		-		-			-		6.6			-		28.6
Distributions		6,369,724		-			7,540,357		-			5,565,424		-
Other Adjustments		-		1.3			-		1.6			-		2.5
Ending Balance		91,907,987		2,807.5			85,538,263		2,681.7			77,997,906		2,577.1
General Partner:
Beginning Balance		-		221.1			-		203.3			-		161.1
Net income		-		884.9			-		935.8			-		805.8
Adjustments to capital resulting from related party
acquisitions		-		-			-		0.3			-		1.0
Distributions		-		(861.7	)		-		(918.4	)		-		(764.7	)
Other Adjustments		-		-			-		0.1			-		0.1
Ending Balance		-		244.3			-		221.1			-		203.3
Accumulated other comprehensive loss:
Beginning Balance		-		(394.8	)		-		(287.7	)		-		(1,276.6	)
Change in fair value of derivatives utilized for hedging purposes		-		(75.3	)		-		(453.6	)		-		651.4
Reclassification of change in fair value of derivatives to net income		-		186.5			-		99.3			-		663.7
Foreign currency translation adjustments		-		99.5			-		249.7			-		(329.8	)
Adjustments to pension and other postretirement benefit plan liabilities		-		(2.3	)		-		(2.5	)		-		3.6
Ending Balance		-		(186.4	)		-		(394.8	)		-		(287.7	)
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital		316,101,490	$	7,210.7			296,872,489	$	6,644.5			266,280,733	$	6,045.6

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

121

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL   (continued)

	2010					2009					2008
	Units		Amount			Units		Amount			Units		Amount
	(Dollars in millions)
Noncontrolling interests:
Beginning Balance		-	$	79.6			-	$	70.7			-	$	54.2
Net income		-		10.8			-		16.3			-		13.7
Adjustments to capital resulting from related party
acquisitions		-		-			-		0.3			-		2.2
Contributions		-		12.5			-		15.4			-		9.2
Distributions		-		(23.3	)		-		(22.0	)		-		(18.8	)
Change in fair value of derivatives utilized for hedging purposes		-		(0.8	)		-		(4.6	)		-		6.6
Reclassification of change in fair value of derivatives to net income		-		1.9			-		1.0			-		6.8
Foreign currency translation adjustments		-		1.1			-		2.5			-		(3.4	)
Adjustments to pension and other postretirement  benefit plan liabilities		-		-			-		-			-		0.1
Other Adjustments		-		-			-		-			-		0.1
Ending Balance		-		81.8			-		79.6			-		70.7
Total Partners’ Capital		316,101,490	$	7,292.5			296,872,489	$	6,724.1			266,280,733	$	6,116.3

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  General

Organization

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,” “KMP,” 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 five reportable business segments.

These segments and the activities performed to provide services to our customers and create value for our unitholders are as follows:

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

▪ Natural Gas Pipelines - transporting, storing, buying, selling, gathering, treating and processing natural gas;

▪ CO2 – transporting oil, producing, transporting and selling carbon dioxide, commonly called CO2, for use in, and selling crude oil, natural gas and natural gas liquids produced from, enhanced oil recovery operations;

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

▪ Kinder Morgan Canada – transporting crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington, and owning a one-third interest in an integrated oil transportation network that connects Canadian and United States producers to refineries in the U.S. Rocky Mountain and Midwest regions.

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 limited partnerships: (i) Kinder Morgan Operating L.P. “A”; (ii) Kinder Morgan Operating L.P. “B”; (iii) Kinder Morgan Operating L.P. “C”; (iv) Kinder Morgan Operating L.P. “D”; and (v) Kinder Morgan CO2 Company, L.P.

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

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

Kinder Morgan, Inc., a Delaware corporation and referred to as KMI in this report, indirectly owns all the common stock of Kinder Morgan Kansas, Inc.  Kinder Morgan Kansas, Inc. is a Kansas corporation and indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation; however, in July 2007, our general partner issued and sold 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057.  The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us or two of our subsidiaries, SFPP, L.P. and Calnev Pipe Line LLC.  As of December 31, 2010, KMI and its consolidated subsidiaries owned, through KMI’s general and limit ed partner interests in us and its ownership of shares issued by its subsidiary Kinder Morgan Management, LLC (discussed following), an approximate 12.8% interest in us.

Prior to May 30, 2007, Kinder Morgan Kansas, Inc. was known as Kinder Morgan, Inc., and on that date, it merged with a wholly-owned subsidiary of its parent, Knight Holdco LLC, a private company owned by investors led by Richard D. Kinder, Chairman and Chief Executive Officer of both our general partner and Kinder Morgan Management, LLC.  This merger is referred to in this report as the going-private transaction, and following the merger, Kinder Morgan, Inc. (the surviving legal entity from the merger) was renamed Knight, Inc.  On July 15, 2009, Knight Inc. changed its name back to Kinder Morgan, Inc., and subsequently, Knight Holdco LLC was renamed Kinder Morgan Holdco LLC.

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On November 23, 2010, Kinder Morgan Holdco LLC filed a registration statement on Form S-1 with the Securities and Exchange Commission for a proposed initial public offering of its common stock.  The registration statement became effective on February 10, 2011, and the initial public offering closed on February 16, 2011.  In connection with the offering, Kinder Morgan Holdco LLC converted from a Delaware limited liability company to a Delaware corporation named Kinder Morgan, Inc. (KMI), and the former Kinder Morgan, Inc. was renamed Kinder Morgan Kansas, Inc.  All of the common stock that was sold in the offering was sold by existing investors, consisting of funds advised by or affiliated with Goldman, Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC.  KMI did not receive any proceeds from the offering.  On February 11, 2011, KMI’s common stock began trading on the New York Stock Exchange under the symbol “KMI.”

Kinder Morgan Management, LLC

Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company that 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.”  Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, has 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, 2010, KMR owned approximately 29.1% of our outstanding limited partner units (which are in the form of i-units that are issued only to KMR).

2.  Summary of Significant Accounting Policies

Basis of Presentation

Our accounting records are maintained in United States dollars, and all references to dollars are United States dollars, except where stated otherwise.  Canadian dollars are designated as C$.

Our accompanying consolidated financial statements include our accounts and those of our operating partnerships and their majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation.  Our accompanying consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States, and certain amounts from prior years have been reclassified to conform to the current presentation.  Effective September 30, 2009, the Financial Accounting Standards Boards’ Accounting Standards Codification became the single source of generally accepted accounting principles, and in this report, we refer to the Financial Accounting Standards Board as the FASB and the FASB Accounting Standards Codification as the Codification.

Additionally, our financial statements are consolidated into the consolidated financial statements of KMI; however, our financial statements reflect amounts on a historical cost basis, and, accordingly, do not reflect any purchase accounting adjustments related to KMI’s May 30, 2007 going-private transaction (discussed above in Note 1).  Also, except for the related party transactions described in Note 11 “Related Party Transactions—Asset Acquisitions and Sales,” 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.  Furthermore, the determinat ion of responsibility for payment among entities in our consolidated group of subsidiaries is not impacted by the consolidation of our financial statements into the consolidated financial statements of KMI.

Use of Estimates

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 our 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.  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, fina ncial 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 addition, we believe that certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.

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Cash Equivalents

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

Restricted Deposits

Cash held in escrow is restricted cash and as of December 31, 2010, we deposited $50.0 million into a third-party escrow account to comply with contractual stipulations related to an equity investment in Watco Companies, LLC.  In January 2011, the funds were released from escrow and we used the cash for our investment.  For additional information on this investment, see Note 3 “Acquisitions and Divestitures—Acquisition Subsequent to December 31, 2010.”  As of December 31, 2009, our restricted deposits totaled $15.2 million and consisted of cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners.

Accounts Receivable

The amounts reported as “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheets as of December 31, 2010 and 2009 primarily consist of amounts due from third party payors (unrelated entities).  For information on receivables due to us from related parties, see Note 11.

Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served.  Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments 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 table shows the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2010, 2009 and 2008 (in millions):

Valuation and Qualifying Accounts

Allowance for doubtful accounts	Balance at beginning of period		Additions charged to costs and expenses		Additions charged to other accounts		Deductions(a)			Balance at end of period
Year ended December 31, 2010	$	5.4	$	2.3	$	-	$	(0.9	)	$	6.8
Year ended December 31, 2009	$	6.1	$	0.5	$	-	$	(1.2	)	$	5.4
Year ended December 31, 2008	$	7.0	$	0.6	$	-	$	(1.5	)	$	6.1

____________

(a) Deductions represent the write-off of receivables and currency translation adjustments.  

In addition, the balances of “Accrued other current liabilities” in our accompanying consolidated balance sheets include amounts related to customer prepayments of approximately $7.1 million as of December 31, 2010 and $10.9 million as of December 31, 2009.

Inventories

Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas, carbon dioxide and coal.  We report these assets at the lower of weighted-average cost or market, and in December 2008, we recognized a lower of cost or market adjustment of $12.9 million in our CO2 business segment.  We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.

As of December 31, 2010 and 2009, the value of natural gas in our underground storage facilities under the weighted-average cost method was $2.2 million and $43.5 million, respectively, and we reported these amounts separately as “Gas in underground storage” in our accompanying consolidated balance sheets.

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Gas Imbalances

We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market, per our quarterly imbalance valuation procedures.  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.  As of December 31, 2010 and 2009, our gas imbalance receivables—including both trade and related party receivables—totaled $18.8 million and $14.0 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets.   As of December 31, 2010 and 2009, our gas imbalance payables—including both trade and related party payables—totaled $7.7 million and $7.4 million, respectively, and we included these amounts within “Accrued other current liabilities” on our accompanying consolidated balance sheets.

Property, Plant and Equipment

Capitalization, Depreciation and Depletion and Disposals

We report property, plant and equipment at its acquisition cost.  We expense costs for maintenance and repairs in the period incurred.  As discussed below, for assets used in our oil and gas producing activities or in our unregulated bulk and liquids terminal activities, 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, and we record any related gains and losses from sales or retirements to income or expense accounts.  For our pipeline system assets, we generally 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 retiremen ts 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 generally compute depreciation using the straight-line method based on estimated economic lives; however, for certain depreciable assets, we employ the composite depreciation method, applying a single depreciation rate for a group of assets.  Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics.  The rates range from 1.6% 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 requir ements, 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 or in our bulk and liquids terminal 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.

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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 deter mined by field.

As discussed in “—Inventories” above, we own and 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.  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 economical ly 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.

Impairments

We measure long-lived assets that are to be disposed of by sale at the lower of book value or fair value less the cost to sell, and 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.  For the purpose of impairment testing, we use the forward curve prices as observed at the test date; however, due to differences between the forward curve and spot prices, the forward curve cash flows may differ from the amounts presented in our supplemental information on oil and gas producing activities disclosed in Note 20.

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.  Due to the decline in crude oil and natural gas prices during 2008, on December 31, 2008, we conducted an impairment test on our oil and gas producing properties in our CO2 business segment and determined that no impairment was necessary.

Allowance for Funds Used During Construction/Capitalized Interest

Included in the cost of our qualifying property, plant and equipment is (i) an allowance for funds used during construction (AFUDC) or upgrade for assets regulated by the Federal Energy Regulatory Commission; or (ii) capitalized interest.  The primary difference between AFUDC and capitalized interest is that AFUDC may include a component for equity funds, while capitalized interest does not.  AFUDC on debt, as well as capitalized interest, represents the estimated cost of capital, from borrowed funds, during the construction period that is not immediately expensed, but instead is treated as an asset (capitalized) and amortized to expense over time in our income statements.  Total AFUDC on debt and capitalized interest in 2010, 2009 and 2008 was $12.5 million, $32.9 million and $48.6 million, respectively. &# 160;Similarly, AFUDC on equity represents an estimate of the cost of capital funded by equity contributions, and in the years ended December 31, 2010, 2009 and 2008, we also capitalized approximately $0.7 million, $22.7 million and $10.6 million, respectively, of equity AFUDC.

Asset Retirement Obligations

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses.  We record, as liabilities, the fair value of asset retirement obligations 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 increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets.  The liabilities are eventually extinguished when the asset is taken out of service.  ] ] [ For more information on our asset retirement obligations, see Note 5 “Property, Plant and Equipment—Asset Retirement Ob ligations.”

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Equity Method of Accounting

We account for investments greater than 20% in affiliates—which we do not control but do have the ability to exercise significant influence—by the equity method of accounting.  Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.

Goodwill

Goodwill represents the excess of the cost of an acquisition price over the fair value of acquired net assets, and such amounts are reported separately as “Goodwill” on our accompanying consolidated balance sheets.  Our total goodwill was $1,233.6 million as of December 31, 2010, and $1,149.2 million as of December 31, 2009.  Goodwill cannot be amortized, but instead 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 perform our goodwill impairment test on May 31 of each year.  There were no impairment charges resulting from our May 31, 2010, 2009 or 2008 impairment testing, and no event indicating an impairment has occurred subsequent to May 31, 2010.  For more information on our goodwill, see Note 7.

Revenue Recognition Policies

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, generally based on Houston Ship Channel index posted prices.  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 a nd 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.

In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we provide various types of natural gas storage and transportation services for third-party 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 po int, 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.  In addition to our firm and interruptible transportation services, we also provide natural gas balancing services to assist customers in managing short-term gas surpluses or deficits.  Revenues are recognized based on the terms negotiated under these contracts.

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.

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Revenues from the sale of crude 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.

Environmental Matters

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

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations.  These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts.  We also routinely adjust our environmental liabilities to reflect changes in previous estimates.  In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims.  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.  For more information on o ur environmental disclosures, see Note 16.

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions.  We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements.  When we identify specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for such amounts.  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.  In general, we expense legal costs as incurred and all recorded legal liabilit ies are revised as better information becomes available.  For more information on our legal disclosures, see Note 16.

Pensions and Other Postretirement Benefits  

We fully recognize the overfunded or underfunded status of our consolidating subsidiaries’ pension and postretirement benefit plans as either assets or liabilities on our balance sheet.  A plan’s funded status is the difference between the fair value of plan assets and the plan’s benefit obligation.  We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—in accumulated other comprehensive income, until they are amortized to expense.  For more information on our pension and postretirement benefit disclosures, see Note 9.

Noncontrolling Interests

Noncontrolling interests represents the outstanding ownership interests in our five operating limited partnerships and their consolidated subsidiaries that are not owned by us.  In our accompanying consolidated income statements, the noncontrolling interest in the net income (or loss) of our consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net income attributable to noncontrolling interests.”  In our accompanying consolidated balance sheets, noncontrolling interests represents the ownership interests in our consolidated subsidiaries’ net assets held by parties other than us.  It is presented separately as “Noncontrolling interests” within “Partners’ Capital.”

As of December 31, 2010, our noncontrolling interests consisted of the following: (i) the 1.0101% general partner interest in each of our five operating partnerships; (ii) the 0.5% special limited partner interest in SFPP, L.P.; (iii) the 50% interest in Globalplex Partners, a Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.; (iv) the 33 1/3% interest in International Marine Terminals Partnership, a Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P. “C”; (v) the approximate 31% interest in the Pecos Carbon Dioxide Company, a Texas general partnership owned approximately 69% and controlled by Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries; and (vi) the 35% interest i n Guilford County Terminal Company, LLC, a limited liability company owned 65% and controlled by Kinder Morgan Southeast Terminals LLC.

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Income Taxes

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

Some of our corporate subsidiaries and corporations in which we have an equity investment do pay U.S. federal, state, and foreign 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.  For more information on our income tax disclosures, see Note 4.

Foreign Currency Transactions and Translation

Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which our reporting subsidiary operates, also referred to as its functional currency.  Transaction gains or losses result from a change in exchange rates between (i) the functional currency, for example the Canadian dollar for a Canadian subsidiary; and (ii) the currency in which a foreign currency transaction is denominated, for example the U.S. dollar for a Canadian subsidiary.  In our accompanying consolidated income statements, gains and losses from our foreign currency transactions are included within “Other Income (Expense)—Other, net.”

We translate the assets and liabilities of each of our consolidating foreign subsidiaries that have a local functional currency 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 partners’ capital equity accounts are translated by using historical exchange rates.  Translation adjustments result from translating all assets and liabilities at current year-end rates, while partners’ capital equity is translated by using historical and weighted-average rates.  The cumulative translation adjustments balance is reported as a component of “Accumulated other comprehensive loss” within “Partners’ Capital” in our consolidated balance sheets.

Comprehensive Income

For each of the years ended December 31, 2010, 2009 and 2008, the difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivative contracts utilized for hedging our exposure to fluctuating expected future cash flows produced by both energy commodity price risk and interest rate risk; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other postretirement benefit plan liabilities.  For more information on our risk management activities, see Note 13.

Cumulative revenues, expenses, gains and losses that under generally accepted accounting principals are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Partners’ Capital” in our consolidated balance sheets.  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, 2010 and 2009 (in millions):

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	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjs.			Total Accumulated other comprehensive income/(loss)
December 31, 2008	$	(64.6	)	$	(217.3	)	$	(5.8	)	$	(287.7	)
Change for period		(354.3	)		249.7			(2.5	)		(107.1	)
December 31, 2009		(418.9	)		32.4			(8.3	)		(394.8	)
Change for period		111.2			99.5			(2.3	)		208.4
December 31, 2010	$	(307.7	)	$	131.9		$	(10.6	)	$	(186.4	)

Limited Partners’ Net Income per Unit

We compute 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.  The overall computation, presentation, and disclosure requirements for our Limited Partners’ Net Income per Unit  are made in accordance with the “Earnings per Share” Topic of the Codification.

Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids and crude oil.  In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations.  We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability.  If the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from fair value accounting and is accounted for using traditional accrual accounting.

Furthermore, changes in our derivative contracts’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  If a derivative contract meets those criteria, the contract’s gains and losses is allowed to offset related results on the hedged item in our income statement, and we are required to both formally designate the derivative contract as a hedge and document and assess the effectiveness of the contract associated with the transaction that receives hedge accounting.  Only designated qualifying items that are effectively offset by changes in fair value or cash flows during the term of the hedge are eligible to use the special accounting for hedging.

Our derivative contracts that hedge our energy commodity price risks involve our normal business activities, which include the sale of natural gas, natural gas liquids and crude oil, and we have designated these derivative contracts as cash flow hedges—derivative contracts that hedge exposure to variable cash flows of forecasted transactions—and the effective portion of these derivative contracts’ 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 13 for more information on our risk management activities and disclosures.

Accounting for Regulatory Activities

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 amount of regulatory assets and liabilities 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, 2010 and 2009 are not material to our consolidated balance sheets.

3.  Acquisitions and Divestitures

Acquisitions from Unrelated Entities

During 2010, 2009 and 2008, we completed the following acquisitions from unrelated entities.  For each of these acquisitions, we recorded all the acquired assets and assumed liabilities at their estimated fair market values (not the acquired entity’s book values) as of the acquisition date.  The results of operations from these acquisitions accounted for as business combinations are included in our consolidated financial statements from the acquisition date.

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						Assignment of Purchase Price
						(in millions)
Ref.			Date		Acquisition	Purchase Price		Current Assets		Property Plant & Equipment		Deferred Charges & Other		Goodwill
	(1	)		8/08	Wilmington, North Carolina Liquids Terminal	$	12.7	$	-	$	5.9	$	-	$	6.8
	(2	)		12/08	Phoenix, Arizona Products Terminal		27.5		-		27.5		-		-
	(3	)		4/09	Megafleet Towing Co., Inc. Assets		21.7		-		7.1		4.0		10.6
	(4	)		7/09	Portland Airport Pipeline		9.0		-		9.0		-		-
	(5	)		10/09	Crosstex Energy, L.P. Natural Gas Treating Business		270.7		15.0		181.7		25.4		48.6
	(6	)		11/09	Endeavor Gathering LLC		36.0		-		-		36.0		-
	(7	)		1/10	USD Terminal Acquisition		201.1		-		43.1		100.0		58.0
	(8	)		3/10	Mission Valley, California Products Terminal		13.5		-		13.5		-		-
	(9	)		3/10	Slay Industries Terminal Acquisition		101.6		-		67.9		32.8		0.9
	(10	)		5/10	KinderHawk Field Services LLC		917.4		-		-		917.4		-
	(11	)		7/10	Direct Fuels Terminal Acquisition		16.0		-		5.3		-		10.7
	(12	)		9/10	Gas-Chill, Inc. Natural Gas Treating Assets		13.1		-		8.0		5.1		-
	(13	)		10/10	Allied Concrete Terminal Acquisition		8.6		-		3.9		4.7		-
	(14	)		10/10	Chevron Refined Products Terminals		32.3		-		32.1		0.2		-

(1) Wilmington, North Carolina Liquids Terminal

On August 15, 2008, we purchased certain terminal assets from Chemserve, Inc. for an aggregate consideration of $12.7 million, consisting of $11.8 million in cash and $0.9 million in assumed liabilities.  The liquids terminal facility is located in Wilmington, North Carolina and stores petroleum products and chemicals.   The acquisition both expanded and complemented our existing Southeast region terminal operations, and all of the acquired assets are included in our Terminals business segment.  We assigned $6.8 million of our purchase price to “Goodwill,” and the entire amount is expected to be deductible for tax purposes.  We believe this acquisition resulted in the recognition of goodwill primarily because of certain advantageous factors (including the synergies provided by incr easing our liquids storage capacity in the Southeast region of the U.S.) that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.

(2) Phoenix, Arizona Products Terminal

Effective December 10, 2008, our West Coast Products Pipelines operations acquired a refined petroleum products terminal located in Phoenix, Arizona from ConocoPhillips for approximately $27.5 million in cash.  The terminal has storage capacity of approximately 200,000 barrels for gasoline, diesel fuel and ethanol.  The acquisition complemented our existing Phoenix liquids assets, and the acquired incremental storage increased our combined storage capacity in the Phoenix market by approximately 13%.  The acquired terminal is included as part our Products Pipelines business segment.

(3) Megafleet Towing Co., Inc. Assets

Effective April 23, 2009, we acquired certain terminals assets from Megafleet Towing Co., Inc. for an aggregate consideration of approximately $21.7 million.  Our consideration included $18.0 million in cash and an obligation to pay additional cash consideration on April 23, 2014 (five years from the acquisition date) contingent upon the purchased assets providing us an agreed-upon amount of earnings, as defined by the purchase and sale agreement, during the five year period.  The contingent consideration had a fair value of $3.7 million as of the acquisition date.

The acquired assets primarily consisted of nine marine vessels that provide towing and harbor boat services along the Gulf coast, the intracoastal waterway, and the Houston Ship Channel, and the acquisition complemented and expanded our existing Gulf Coast and Texas petroleum coke terminal operations.  We assigned $10.6 million of our purchase price to “Goodwill,” and we expect that approximately $5.0 million of goodwill will be deductible for tax purposes.  We believe the primary item that generated the goodwill is the value of the synergies created between the acquired assets and our pre-existing terminal assets (resulting from the increase in services now offered by our Texas petroleum coke operations).  In February 2010, the JR Nicholls , one of the acquired vessels, overturned and sank in the Houston Ship Channel.  For further information about the JR Nicholls incident, see Note 16.  For information about events occurring subsequent to December 31, 2010, see“—Divestiture Subsequent to December 31, 2010” below.

(4) Portland Airport Pipeline

On July 31, 2009, we acquired a refined products pipeline, as well as associated valves, equipment and other fixtures, from Chevron Pipe Line Company for $9.0 million in cash.  The approximate 8.5 mile, 8-inch diameter pipeline is located in Multnomah County, Oregon.  The line transports commercial jet fuel from our Willbridge liquids terminal facility to the Portland International Airport, both located in Portland, Oregon.  It has an estimated system capacity of approximately 26,000 barrels per day.  The acquisition enhanced our West Coast terminal operations, and the acquired assets are included in our Products Pipelines business segment.

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(5) Crosstex Energy, L.P. Natural Gas Treating Business

On October 1, 2009, we acquired the natural gas treating business from Crosstex Energy, L.P. and Crosstex Energy, Inc. for an aggregate consideration of $270.7 million, consisting of $265.3 million in cash and assumed liabilities of $5.4 million.  The acquired assets primarily consisted of approximately 290 natural gas amine-treating and hydrocarbon dew-point control plants and related equipment, and are used to remove impurities and liquids from natural gas in order to meet pipeline quality specifications.  The assets are predominantly located in Texas and Louisiana, with additional facilities located in Mississippi, Oklahoma, Arkansas and Kansas.  The acquisition complemented and expanded the existing natural gas treating operations offered by our Texas intrastate natural gas pipeline group, and all of the acquired assets are included in our Natural Gas Pipelines business segment.

We measured the identifiable intangible assets acquired at fair value on the acquisition date, and accordingly, we recognized $25.4 million in “Deferred charges and other assets,” representing the purchased fair value of separate and identifiable relationships with existing natural gas producing customers.  We estimate the remaining useful life of these existing customer relationships to be between approximately eight and nine years.  After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, we recognized $48.6 million of “Goodwill,” an intangible asset representing the future economic benefits expected to be derived from this acquisition that are not assigned to other identifiable, separately recognizable asse ts acquired.  We believe the primary item that generated the goodwill is our ability to grow the business by leveraging our pre-existing natural gas operations (resulting from the increase in services now offered by our natural gas processing and treating operations in the state of Texas), and we believe that this value contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.  Furthermore, this entire amount of goodwill is expected to be deductible for tax purposes.

(6) Endeavor Gathering LLC

On November 1, 2009, we acquired a 40% membership interest in Endeavor Gathering LLC for $36.0 million in cash.  Endeavor Gathering LLC owns the natural gas gathering and compression business previously owned by GMX Resources Inc. and its wholly-owned subsidiary, Endeavor Pipeline, Inc.  Endeavor Gathering LLC provides natural gas gathering service to GMX Resources’ exploration and production activities in its Cotton Valley Sands and Haynesville/Bossier Shale horizontal well developments located in East Texas.  The remaining 60% interest in Endeavor Gathering LLC is owned by GMX Resources, Inc., and Endeavor Pipeline Inc. remained operator of the business.  The acquired investment complemented our existing natural gas gathering and transportation business located in the state of Texas. & #160;We account for this investment under the equity method of accounting, and the investment is included in our Natural Gas Pipelines business segment.  For more information on our investments, see Note 6.

(7) USD Terminal Acquisition

On January 15, 2010, we acquired three ethanol handling train terminals from US Development Group LLC for an aggregate consideration of $201.1 million, consisting of $114.3 million in cash, $81.7 million in common units, and$5.1 million in assumed liabilities.  The three train terminals are located in Linden, New Jersey; Baltimore, Maryland; and Euless, Texas.  As part of the transaction, we announced the formation of a joint venture with US Development Group LLC to optimize and coordinate customer access to the three acquired terminals, other ethanol terminal assets we already own and operate, and other terminal projects currently under development by both parties.  The acquisition complemented and expanded the ethanol and rail terminal operation s we previously owned, and all of the acquired assets are included in our Terminals business segment.

Based on our measurement of fair values for all of the identifiable tangible and intangible assets acquired and liabilities assumed on the acquisition date, we assigned $94.6 million of our combined purchase price to “Other intangibles, net,” and a combined $5.4 million to “Other current assets” and “Deferred charges and other assets.”  The acquired intangible amount represented the fair value of customer relationships, and we estimated the remaining useful life of these customer relationships to be 10 years.  After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, we recognized $58.0 million of “Goodwill,” an intangible asset representing the future economic benefits expected to be de rived from this acquisition that are not assigned to other identifiable, separately recognizable assets.  We believe the primary items that generated the goodwill are the value of the synergies created between the acquired assets and our pre-existing ethanol handling assets, and our expected ability to grow the business by leveraging our pre-existing experience in ethanol handling operations.  We expect that the entire amount of goodwill will be deductible for tax purposes.

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(8) Mission Valley Terminal Acquisition

On March 1, 2010, we acquired the refined products terminal assets at Mission Valley, California from Equilon Enterprises LLC (d/b/a Shell Oil Products US) for $13.5 million in cash.  The acquired assets included buildings, equipment, delivery facilities (including two truck loading racks), and storage tanks with a total capacity of approximately 170,000 barrels for gasoline, diesel fuel and jet fuel.  The terminal operates under a long-term terminaling agreement with Tesoro Refining and Marketing Company.  The acquisition enhanced our Pacific operations and complemented our existing West Coast terminal operations, and the acquired assets are included in our Products Pipelines business segment.

(9) Slay Industries Terminal Acquisition                       

On March 5, 2010, we acquired certain bulk and liquids terminal assets from Slay Industries for an aggregate consideration of $101.6 million, consisting of $97.0 million in cash, assumed liabilities of $1.6 million, and an obligation to pay additional cash consideration of $3.0 million in years 2013 through 2019, contingent upon the purchased assets providing us an agreed-upon amount of earnings during the three years following the acquisition.  Including accrued interest, we expect to pay approximately $2.0 million of this contingent consideration in the first half of 2013.

The acquired assets included (i) a marine terminal located in Sauget, Illinois; (ii) a transload liquid operation located in Muscatine, Iowa; (iii) a liquid bulk terminal located in St. Louis, Missouri; and (iv) a warehousing distribution center located in St. Louis.  All of the acquired terminals have long-term contracts with large creditworthy shippers.  As part of the transaction, we and Slay Industries entered into joint venture agreements at both the Kellogg Dock coal bulk terminal, located in Modoc, Illinois, and at the newly created North Cahokia terminal, located in Sauget and which has approximately 175 acres of land ready for development.  All of the assets located in Sauget have access to the Mississippi River and are served by five rail carriers.  The acquisition complemented and expand ed our pre-existing Midwest terminal operations by adding a diverse mix of liquid and bulk capabilities, and all of the acquired assets are included in our Terminals business segment.

Based on our measurement of fair values for all of the identifiable tangible and intangible assets acquired and liabilities assumed, we assigned $24.6 million of our combined purchase price to “Other intangibles, net” (representing customer contracts with an estimated remaining useful life of 20 years), and $8.2 million to “Investments.”  We also recorded $0.9 million of our combined purchase price as “Goodwill,” representing certain advantageous factors that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets.  In the aggregate, these factors represented goodwill, and we expect to deduct the entire amount of goodwill for tax purposes.

(10) KinderHawk Field Services LLC

On May 21, 2010, we purchased a 50% ownership interest in Petrohawk Energy Corporation’s natural gas gathering and treating business in the Haynesville shale gas formation located in northwest Louisiana.  We paid an aggregate consideration of $917.4 million in cash for our 50% equity ownership interest, consisting of $921.4 million we paid on closing, and $4.0 million we received in the fourth quarter of 2010 for the final settlement of estimated capital expenditures and estimated net cash outflows from operating activities for the period January 1, 2010 through May 21, 2010.

During a short transition period, Petrohawk continued to operate the business, and effective October 1, 2010, a newly formed company named KinderHawk Field Services LLC, owned 50% by us and 50% by Petrohawk, assumed the joint venture operations.  The acquisition complemented and expanded our existing natural gas gathering and treating businesses, and we assigned our entire purchase price to “Investments” (including $144.8 million of equity method goodwill, representing the excess of our investment cost over our proportionate share of the fair value of the joint venture’s identifiable net assets).  Our investment and our pro rata share of the joint venture’s operating results are included as part of our Natural Gas Pipelines business segment.

(11) Direct Fuels Terminal Acquisition

On July 22, 2010, we acquired a terminal with ethanol tanks, a truck rack and additional acreage in Dallas, Texas, from Direct Fuels Partners, L.P. for an aggregate consideration of $16 million, consisting of $15.9 million in cash and an assumed property tax liability of $0.1 million.  The acquired terminal facility is connected to and complements the Dallas, Texas unit train terminal we acquired from USD Development Group LLC in January 2010 (described above in “—(7) USD Terminal Acquisition).  All of the acquired assets are included in our Terminals business segment.  After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, we recognized $10.7 million of “Goodwill,” an intangible asset representing the future economic benefits expected to be derived from the acquisition that was not assigned to other identifiable, separately recognizable assets acquired.  We believe the primary items that generated the goodwill are the value of the synergies created between the acquired assets and our pre-existing ethanol handling assets, and our expected ability to grow the business by leveraging our pre-existing experience in ethanol handling operations.  We expect that the entire amount of goodwill will be deductible for tax purposes.

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(12) Gas-Chill, Inc. Asset Acquisition

On September 1, 2010, we acquired the natural gas treating assets of Gas-Chill, Inc. for an aggregate consideration of $13.1 million, consisting of $10.5 million in cash paid on closing, and an obligation to pay a holdback amount of $2.6 million within eighteen months from closing.  The acquired assets primarily consist of more than 100 mechanical refrigeration natural gas hydrocarbon dew point control units that are used to remove hydrocarbon liquids from natural gas streams prior to entering transmission pipelines.  The acquisition complemented and expanded the existing natural gas treating operations offered by our Texas intrastate natural gas pipeline group, and all of the acquired assets are included in our Natural Gas Pipelines business segment.  We assigned $8.0 million of our purchase price to “ ;Property, Plant and Equipment, net” and the remaining $5.1 million to “Other intangibles, net” (representing both a technology-based asset and customer-related contract values).

(13) Allied Concrete Bulk Terminal Assets                                                                       

On October 1, 2010, we acquired certain bulk terminal assets and real property located in Chesapeake, Virginia, from Allied Concrete Products, LLC and Southern Concrete Products, LLC for an aggregate consideration of $8.6 million, consisting of $8.1 million in cash and an assumed environmental liability of $0.5 million.  The acquired terminal facility is situated on 42 acres of land and can handle approximately 250,000 tons of material annually, including pumice, aggregates and sand.  The acquisition complemented the bulk commodity handling operations at our nearby Elizabeth River terminal, also located in Chesapeake, and all of the acquired assets are included in our Terminals business segment.  We assigned $3.9 million of our purchase price to “Property, Plant and Equipment, net” and the remain ing $4.7 million to “Other intangibles, net” (representing customer-related contract values).

(14) Chevron Refined Products Terminal Assets                                                                                 

On October 8, 2010, we acquired four separate refined petroleum products terminals from Chevron U.S.A. Inc. for an aggregate consideration of $32.3 million, consisting of $31.5 million in cash and an assumed environmental liability of $0.8 million.  Combined, the terminals have storage capacity of approximately 650,000 barrels for gasoline, diesel fuel and jet fuel.  Chevron has entered into long-term contracts with us to terminal product at the terminals.  The acquisition complemented and expanded our existing refined petroleum products assets, and all of the acquired assets are included in our Products Pipelines business segment.  We assigned $32.1 million of our purchase price to “Property, Plant and Equipment, net” and the remaining $0.2 million to “Deferred charges and other assets” (representing the fair value of petroleum pipeline product additives).

Pro Forma Information

Pro forma consolidated income statement information that gives effect to all of the acquisitions we have made and all of the joint ventures we have entered into since January 1, 2009 as if they had occurred as of January 1, 2009 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.

Acquisitions from KMI

According to the provisions of the Codification’s “Control of Partnerships and Similar Entities” Subtopic, effective January 1, 2006, KMI (which indirectly owns all the common stock of our general partner) was deemed to have control over us and no longer accounted for its investment in us under the equity method of accounting.  Instead, as of this date, KMI included our accounts, balances and results of operations in its consolidated financial statements.

Accordingly, we accounted for each of the two separate acquisitions discussed below as transfers of net assets between entities under common control.  When accounting for transfers of net assets between entities under common control, the acquisition cost provisions (as they relate to purchase business combinations involving unrelated entities) explicitly do not apply; instead, 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 consideration paid and the book value of the net assets acquired.

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Therefore, for each of the two separate acquisitions from KMI discussed below, we recognized the assets and liabilities acquired at their carrying amounts (historical cost) in the accounts of KMI (the transferring entity) at the date of transfer.  Description of the consideration we paid or received for these net assets is also described below.

Trans Mountain Pipeline System

On April 30, 2007, we acquired the Trans Mountain pipeline system from KMI for $549.1 million in cash.  The Trans Mountain pipeline system transports crude oil and refined products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington.  In April 2008, as a result of finalizing certain “true-up” provisions in our acquisition agreement related to Trans Mountain pipeline expansion spending, we received a cash contribution of $23.4 million from KMI.  Pursuant to the accounting provisions concerning transfers of net assets between entities under common control, and consistent with our treatment of cash payments made to KMI for Trans Mountain net assets in 2007, we accounted for this 2008 cash contribution as an adjustment to equity—p rimarily as an increase in “Partners’ Capital”—and we also included this $23.4 million receipt as a cash inflow item from investing activities in our accompanying consolidated statement of cash flows.

Express and Jet Fuel Pipeline Systems

Effective August 28, 2008, we acquired KMI’s 33 1/3% ownership interest in the Express pipeline system.  The pipeline system is a batch-mode, common-carrier, crude oil pipeline system consisting of both the Express Pipeline and the Platte Pipeline (collectively referred to in this report as the Express pipeline system).  We also acquired KMI’s full ownership of an approximately 25-mile jet fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada (referred to in this report as the Jet Fuel pipeline system).  As consideration for these assets, we paid to KMI approximately 2.0 million common units, valued at $116.0 million. The acquisition complemented our Trans Mountain pipeline system, and all of the acquired assets (including an acquired cash b alance of $7.4 million) are included in our Kinder Morgan Canada business segment.

We operate the Express pipeline system, and we account for our 33 1/3% ownership in the system under the equity method of accounting.  In addition to our 33 1/3% equity ownership, our investment in Express includes an investment in unsecured debenture bonds denominated in Canadian dollars and issued by Express Holdings U.S. L.P., the partnership that maintains ownership of the U.S. portion of the Express pipeline system.  For more information on this long-term note receivable, see Note 11 “Related Party Transactions—Notes Receivable.”

Additionally, based upon our management’s consideration of all of the quantitative and qualitative aspects of the transfer of the interests in the Express and Jet Fuel pipeline system net assets from KMI to us, we determined that the presentation of combined financial statements which include the financial information of the Express and Jet Fuel pipeline systems would not be materially different from financial statements which did not include such information and accordingly, we elected not to include the financial information of the Express and Jet Fuel pipeline systems in our consolidated financial statements for any periods prior to the transfer date of August 28, 2008.  Our consolidated financial statements and all other financial information included in this report therefore, have been prepared assuming that the tran sfer of both the 33 1/3% interest in the Express pipeline system net assets and the Jet Fuel pipeline system net assets from KMI to us had occurred at the date of transfer (August 28, 2008).

Divestitures

North System Natural Gas Liquids Pipeline System – Discontinued Operations

On July 2, 2007, we announced that we entered into an agreement to sell the North System natural gas liquids pipeline and our 50% ownership interest in the Heartland Pipeline Company (collectively referred to in this report as our North System) to ONEOK Partners, L.P. for approximately $298.6 million in cash.  Our investment in net assets, including all transaction related accruals, was approximately $145.8 million, most of which represented property, plant and equipment, and we recognized approximately $152.8 million of gain in the fourth quarter of 2007 from the sale of these net assets.

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In the first half of 2008, following final account and inventory reconciliations, we paid a net amount of $2.4 million to ONEOK to fully settle amounts related to (i) working capital items; (ii) total physical product liquids inventory and inventory obligations for certain liquids products; and (iii) the allocation of pre-acquisition investee distributions.  Based primarily upon these adjustments, which were below the amounts reserved, we recognized an additional gain of $1.3 million in 2008.  We accounted for the North System business as a discontinued operation and we reported the gain amount separately as “Gain on disposal of North System” within the discontinued operations section of our accompanying consolidated statement of income for the year ended December 31, 2008.  Prior to the sale, we included the financial results of the North System within our Products Pipelines business segment and, because the sale of the North System did not change the structure of our internal organization in a manner that caused a change to our reportable business segments, we included the incremental gain within our Products Pipelines business segment disclosures for 2008.

Thunder Creek Gas Services, LLC

Effective April 1, 2008, we sold our 25% ownership interest in Thunder Creek Gas Services, LLC, referred to in this report as Thunder Creek, to PVR Midstream LLC, a subsidiary of Penn Virginia Corporation.  Prior to the sale, we accounted for our investment in Thunder Creek under the equity method of accounting and included its financial results within our Natural Gas Pipelines business segment.  In the second quarter of 2008, we received cash proceeds, net of closing costs and settlements, of approximately $50.7 million for our investment, and we recognized a gain of $13.0 million with respect to this transaction.  We included the amount of the gain within the caption “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2008.

Cypress Interstate Pipeline LLC            

Effective October 1, 2010, Westlake Petrochemicals LLC, a wholly-owned subsidiary of Westlake Chemical Corporation, exercised an option it held to purchase a 50% ownership interest in our Cypress Pipeline.  Accordingly, we sold a 50% interest in our subsidiary, Cypress Interstate Pipeline LLC, to Westlake and we received proceeds of $10.2 million.  At the time of the sale, the carrying value of the net assets of Cypress Interstate Pipeline LLC totaled $20.0 million and consisted mostly of property, plant and equipment.  In the fourth quarter of 2010, we recognized an $8.8 million gain from this sale, including an $8.6 million gain amount related to the remeasurement of our retained investment to its fair value.  Due to the loss of control of Cypress Interstate Pipeline LLC, we recognized the retain ed investment at its fair value, and the gain amount related to remeasurement represents the excess of the fair value of our retained investment ($18.6 million as of October 1, 2010) over its carrying value ($10.0 million).  This fair value of our retained investment was determined by applying a multiple to the future annual cash flows expected from our retained 50% interest.  The $10.2 million value of the transaction with Westlake Chemical Corporation was based on a contract price and does not represent the fair value of a 50% interest in the Cypress Pipeline in an orderly transaction between market participants.  We now account for our retained investment under the equity method of accounting.  We included the entire gain within the caption “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2010.

Acquisition Subsequent to December 31, 2010

On January 3, 2011, we purchased 50,000 Class A preferred shares of Watco Companies, LLC for $50.0 million in cash in a private transaction.  In connection with our purchase of these preferred shares, the most senior equity security of Watco, we entered into a limited liability company agreement with Watco that provides us certain priority and participating cash distribution and liquidation rights.  We will receive priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter, and we will participate partially in additional profit distributions at a rate equal to 0.5%.  The preferred shares have no conversion features and hold no voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers.
60; As of December 31, 2010, we placed our $50.0 million investment in a cash escrow account and we included this amount within “Restricted Deposits” on our accompanying balance sheet.  The acquired investment complements our existing rail transload operations and we will account for our investment under the equity method of accounting and include it in our Terminals business segment.

Watco Companies, LLC is a privately owned, Pittsburg, Kansas based transportation company that was formed in 1983.  It is the largest privately held short line railroad company in the United States, operating 22 short line railroads on approximately 3,500 miles of leased and owned track.  Its services include (i) rail freight transportation; (ii) industrial switching services; (iii) railcar and locomotive repair; (iv) track construction, maintenance and repair; (v) freight railroad specific transloading and intermodal services; (vi) freight railroad specific warehouse logistics activities; and (vii) port terminal freight railroads and associated operations.

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Divestiture Subsequent to December 31, 2010

On February 9, 2011, we sold a marine vessel to Kirby Inland Marine, L.P., and additionally, we and Kirby formed a joint venture named Greens Bayou Fleeting, LLC.  Pursuant to the joint venture agreement, we both sold a 51% ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009 (discussed above in “—Acquisitions from Unrelated Entities—(3) Megafleet Towing Co., Inc. Assets”) to the joint venture for $4.1 million in cash, and we contributed the remaining business to the joint venture for a 49% ownership interest.  Kirby then made cash contributions to the joint venture in exchange for the remaining 51% ownership interest.  Related to the above transactions, in the fourth quarter of 2010, we recorded a combined loss amount of $5.5 mill ion to write down the carrying value of the net assets to be sold to their estimated fair values as of December 31, 2010.  We included this loss within the caption “Other expense (income)” in our accompanying consolidated statement of income for the year ended December 31, 2010.

4.  Income Taxes

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

	Year Ended December 31,
	2010			2009			2008
Taxes current expense:
Federal	$	4.8		$	2.7		$	24.4
State		1.2			6.7			8.5
Foreign		3.6			(1.0	)		(4.5	)
Total		9.6			8.4			28.4
Taxes deferred expense:
Federal		4.7			7.3			6.0
State		9.7			9.4			1.5
Foreign		10.6			30.6			(15.5	)
Total		25.0			47.3			(8.0	)
Total tax provision	$	34.6		$	55.7		$	20.4
Effective tax rate		2.5	%		4.2	%		1.5	%

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

	Year Ended December 31,
	2010			2009			2008
Federal income tax rate		35.0	%		35.0	%		35.0	%
Increase (decrease) as a result of:
Partnership earnings not subject to tax		(35.0	) %		(35.0	) %		(35.0	) %
Corporate subsidiary earnings subject to tax		-	%		-	%		1.6	%
Income tax expense attributable to corporate equity earnings		0.7	%		0.8	%		0.6	%
Income tax expense attributable to foreign corporate earnings		1.0	%		2.2	%		(1.2	) %
State taxes		0.8	%		1.2	%		0.5	%
Effective tax rate		2.5	%		4.2	%		1.5	%

Our deferred tax assets and liabilities as of December 31, 2010 and 2009 resulted from the following (in millions):

	December 31,
	2010		2009
Deferred tax assets:
Book accruals	$	2.1	$	16.6
Net Operating Loss/Alternative minimum tax credits		17.8		11.4
Other		1.3		1.3
Total deferred tax assets		21.2		29.3
Deferred tax liabilities:
Property, plant and equipment		263.9		239.3
Other		5.6		6.8
Total deferred tax liabilities		269.5		246.1
Net deferred tax liabilities	$	248.3	$	216.8

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We account for uncertainty in income taxes in accordance with the “Income Taxes” Topic of the Codification.  Pursuant to these provisions, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also on the past administrative practices and precedents of the taxing authority.  The tax benefits recognized in our financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

A reconciliation of our beginning and ending gross unrecognized tax benefits for each of the years ended December 31, 2010 and 2009 is as follows (in millions):

	Year Ended December 31,
	2010			2009
Balance at beginning of period	$	23.3		$	14.9
Additions based on current year tax positions		-			-
Additions based on prior year tax positions		10.2			8.5
Reductions based on settlements with taxing authority		-			-
Reductions due to lapse in statute of limitations		(0.1	)		(0.1	)
Balance at end of period	$	33.4		$	23.3

Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense.  During the year ended December 31, 2010, we recognized a reduction in interest expense of approximately $0.5 million, and during each of the years ended December 31, 2009 and 2008, we recognized approximately $1.1 million and $0.5 million, respectively, in interest expense.

As of December 31, 2010 (i) we had $1.8 million of accrued interest and no accrued penalties; (ii) we believe it is reasonably possible that our $33.4 million liability for unrecognized tax benefits will increase by approximately $7.6 million during the next twelve months; and (iii) we believe the full amount of $33.4 million of unrecognized tax benefits, if recognized, would favorably affect our effective income tax rate in future periods.  As of December 31, 2009, we had $2.3 million of accrued interest and no accrued penalties.  In addition, we have U.S. and state tax years open to examination for the periods 2006 through 2010.

5.  Property, Plant and Equipment

Classes and Depreciation

As of December 31, 2010 and 2009, our property, plant and equipment consisted of the following (in millions):

	December 31,
	2010			2009
Natural gas, liquids, crude oil and carbon dioxide pipelines	$	7,071.1		$	6,883.3
Natural gas, liquids, carbon dioxide, and terminals station equipment.		8,976.2			8,131.9
Natural gas, liquids (including linefill), and transmix processing		233.7			220.3
Other		1,322.7			1,113.0
Accumulated depreciation, depletion, and amortization		(4,150.6	)		(3,365.6	)
		13,453.1			12,982.9
Land and land right-of-way		638.5			596.6
Construction work in process		512.3			574.3
Property, plant and equipment, net	$	14,603.9		$	14,153.8

Depreciation, depletion, and amortization expense charged against property, plant and equipment was $852.8 million in 2010, $829.6 million in 2009 and $684.2 million in 2008.

Asset Retirement Obligations

As of December 31, 2010 and 2009, we recognized asset retirement obligations in the aggregate amount of $122.0 million and $100.9 million, respectively.  The majority of our asset retirement obligations are associated with our CO2 business segment, where 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.  We have included $2.5 million of our total asset retirement obligations as of both December 31, 2010 and 2009 within “Accrued other current liabilities” in our accompanying consolidated balance sheets.  The remaining amounts are included within “Other long-term liabilities and deferred credits” at each reporting date.

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A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for each of the years ended December 31, 2010 and 2009 is as follows (in millions):

	Year Ended December 31,
	2010			2009
Balance at beginning of period	$	100.9		$	76.5
Liabilities incurred/revised		23.7			26.0
Liabilities settled		(9.1	)		(6.2	)
Accretion expense		6.5			4.6
Balance at end of period	$	122.0		$	100.9

We have various other obligations throughout our businesses to remove facilities and equipment on rights-of-way and other leased facilities.  We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives.  These assets include pipelines, certain processing plants and distribution facilities, and certain bulk and liquids terminal facilities.  An asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.

6.  Investments

We reported a combined $3,886.0 million as “Investments” in our accompanying consolidated balance sheet as of December 31, 2010.  As of December 31, 2009, our investments totaled $2,845.2 million.  Our investments primarily consist of equity investments where we hold significant influence over investee actions and which we account for under the equity method of accounting.

As of December 31, 2010 and 2009, our investments consisted of the following (in millions):

	December 31,
	2010		2009
Rockies Express Pipeline LLC	$	1,703.0	$	1,693.4
KinderHawk Field Services LLC		924.6		-
Midcontinent Express Pipeline LLC		706.4		662.3
Plantation Pipe Line Company		190.3		197.3
Red Cedar Gathering Company		163.2		145.8
Express pipeline system		68.5		68.0
Endeavor Gathering LLC		36.1		36.2
Eagle Ford Gathering LLC		29.9		-
Cortez Pipeline Company		9.9		11.2
All others		45.9		17.8
Total equity investments		3,877.8		2,832.0
Bond investments		8.2		13.2
Total investments	$	3,886.0	$	2,845.2

The increase in the carrying amount of our equity investments since December 31, 2009 was primarily due to our acquisition of a 50% ownership interest in KinderHawk Field Services LLC in May 2010.  For further information pertaining to our KinderHawk acquisition, see Note 3 “Acquisitions and Divestitures—Acquisitions from Unrelated Entities—(10) KinderHawk Field Services LLC.”

As shown in the table above, in addition to our investment in KinderHawk Field Services LLC, our significant equity investments as of December 31, 2010 consisted of the following:

▪ Rockies Express Pipeline LLC—we operate and own a 50% ownership interest in Rockies Express Pipeline LLC, the sole owner of the Rockies Express natural gas pipeline system.  The Rockies Express pipeline system began full operations on November 12, 2009 following the completion of its final pipeline segment, Rockies Express-East.  The remaining ownership interests in Rockies Express Pipeline LLC are owned by subsidiaries of Sempra Energy and ConocoPhillips.

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Effective December 1, 2009, our ownership interest in Rockies Express Pipeline LLC was reduced to 50% (from 51%), ConocoPhillips’ interest was increased to 25% (from 24%), and minimum voting requirements for most matters was increased to 75% (from 51%) of the member interests.  We received $31.9 million for the 1% reduction in our ownership interest and we included this amount within “Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs” on our accompanying consolidated statement of cash flows for the year ended December 31, 2009.  Sempra Energy continues to own the remaining 25% ownership interest in Rockies Express Pipeline LLC.

Additionally, in 2010 and 2009, we made capital contributions of $130.5 million and $1,273.1 million, respectively, to Rockies Express Pipeline LLC, and we received cash distributions of $208.6 million and $148.8 million, respectively.  Our 2009 contributions were primarily made to partially fund both the construction costs for the Rockies Express pipeline system and the repayment of senior notes (which matured in August 2009);

▪ Midcontinent Express Pipeline LLC—we operate and own a 50% ownership interest in Midcontinent Express Pipeline LLC.  It is the sole owner of the Midcontinent Express natural gas pipeline system.  The remaining ownership interests in Midcontinent Express Pipeline LLC are owned by Regency Energy Partners LP and Energy Transfer Partners, L.P.  Effective May 26, 2010, Energy Transfer Partners, L.P. transferred to Regency Energy Partners LP (i) a 49.9% ownership interest in Midcontinent Express Pipeline LLC; and (ii) a one-time right to purchase its remaining 0.1% ownership interest in Midcontinent Express Pipeline LLC on May 26, 2011.  As a result of this transfer, Energy Transfer Partners, L.P. now owns a 0.1% ownership interest in Midcontinent Express Pipeline LLC.  We continue to own the remaining 50% ownership interest in Midcontinent Express Pipeline LLC, and since there was no change in our ownership interest, we did not record any equity method adjustments as a result of the ownership change between Regency Energy Partners LP and Energy Transfer Partners, L.P.

Additionally, in 2010 and 2009, we made capital contributions of $86.0 million and $664.5 million, respectively, to Midcontinent Express Pipeline LLC to partially fund its pipeline construction and expansion costs.  In 2010 and 2009, we also received, from Midcontinent Express Pipeline LLC, cash distributions of $72.0 million and $16.2 million, respectively;

▪ Plantation Pipe Line Company—we operate and own a 51.17% ownership interest in Plantation Pipe Line Company, the sole owner of the Plantation refined petroleum products pipeline system.  An affiliate of ExxonMobil owns the remaining 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;

▪ Red Cedar Gathering Company—we own a 49% ownership interest in the Red Cedar Gathering Company.  The remaining 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe.  Red Cedar is the sole owner of the Red Cedar natural gas gathering, compression and treating system;

▪ Express pipeline system—we acquired a 33 1/3% ownership interest in the Express pipeline system from KMI effective August 28, 2008 (discussed in Note 3 “Acquisitions and Divestitures—Acquisitions from KMI—Express and Jet Fuel Pipeline Systems”);

▪ Endeavor Gathering LLC—we acquired a 40% ownership interest in Endeavor Gathering LLC from GMX Resources Inc. effective November 1, 2009 (discussed in Note 3 “Acquisitions and Divestitures—Acquisitions from Unrelated Entities—(6) Endeavor Gathering LLC”); and

▪ Eagle Ford Gathering LLC—on May 14, 2010, we and Copano Energy, L.L.C. entered into formal agreements for a joint venture to provide natural gas gathering, transportation and processing services to natural gas producers in the Eagle Ford Shale formation in south Texas.  We named the joint venture Eagle Ford Gathering LLC, and we own a 50% member interest in Eagle Ford Gathering LLC.  Copano owns the remaining 50% interest and serves as operator and managing member of Eagle Ford Gathering LLC.  For more information on our investment in Eagle Ford, see Items 1 and 2 “Business and Properties—(a) General Development of Business—Recent Developments—Natural Gas Pipelines” included in our Annual Report on Form 10-K for the year ended December 31, 2010; and

▪ Cortez Pipeline Company—we operate and own a 50% ownership interest in the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system.  A subsidiary of Exxon Mobil Corporation owns a 37% ownership interest and Cortez Vickers Pipeline Company owns the remaining 13% ownership interest.

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We also own a 50% ownership interest in Fayetteville Express Pipeline LLC, which was formed in August 2008.  Fayetteville Express Pipeline LLC is the sole owner of the Fayetteville Express natural gas pipeline system.  Energy Transfer Partners, L.P. operates the Fayetteville Express pipeline system and owns the remaining 50% ownership interest in Fayetteville Express Pipeline LLC.  The Fayetteville Express system began interim transportation service on October 12, 2010, and began full operations on January 1, 2011.  In 2009, we made capital contributions of $103.2 million to Fayetteville Express Pipeline LLC to partially fund its pipeline construction costs.  As of December 31, 2010 and 2009, however, we had no material net investment in Fayetteville Express Pipeline LLC because in Novemb er 2009, Fayetteville Express Pipeline LLC established and made borrowings under its own revolving bank credit facility in order to fund its pipeline development and construction costs and to make distributions to its member owners to reimburse them for prior contributions (including contributions made in 2008).  Accordingly, we received cash distributions of $115.6 million from Fayetteville Express Pipeline LLC in 2009.

In addition to the investments listed above, our significant equity investments included a 25% ownership interest in Thunder Creek Gas Services, LLC, until we sold our ownership interest to PVR Midstream LLC on April 1, 2008.  The divestiture of our investment in Thunder Creek is discussed in Note 3 “Acquisitions and Divestitures—Divestitures—Thunder Creek Gas Services, LLC.”

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

	Year Ended December 31,
	2010				2009			2008
Rockies Express Pipeline LLC	$	87.6			$	98.5		$	84.9
Plantation Pipe Line Company		30.3				26.8			22.3
Midcontinent Express Pipeline LLC		30.1				14.7			0.5
Red Cedar Gathering Company		28.7				24.9			26.7
Cortez Pipeline Company		22.5				22.3			20.8
KinderHawk Field Services LLC		19.5				-			-
Endeavor Gathering LLC		3.2				0.1			-
Express pipeline system		(3.3	)	��		(4.1	)		(0.5	)
Eagle Ford Gathering LLC		-				-			-
Thunder Creek Gas Services, LLC		-				-			1.3
All others		4.5				6.5			4.8
Total	$	223.1			$	189.7		$	160.8
Amortization of excess costs	$	(5.8	)		$	(5.8	)	$	(5.7	)

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

	Year Ended December 31,
Income Statement	2010		2009		2008
Revenues	$	1,654.2	$	1,216.6	$	1,015.0
Costs and expenses		1,215.1		832.6		681.6
Earnings before extraordinary items and cumulative effect of a change in accounting principle		439.1		384.0		333.4
Net income	$	439.1	$	384.0	$	333.4

	December 31,
Balance Sheet	2010		2009
Current assets	$	485.2	$	294.3
Non-current assets		11,807.6		9,895.9
Current liabilities		599.4		2,162.6
Non-current liabilities		4,510.9		2,905.9
Partners’/Owners’ equity		7,182.5		5,121.7

For information on regulatory matters affecting certain of our equity investments, see Note 17.

As of December 31, 2010 and 2009, our investment amounts also included bond investments totaling $8.2 million and $13.2 million, respectively.  These bond investments consisted of certain tax exempt, fixed-income development revenue bonds we acquired in the fourth quarter of 2008.  Because we have both the ability and the intent to hold these debt securities to maturity, we account for these investments at historical cost.  We acquired our bond investments by issuing notes under the Gulf Opportunity Zone Act of 2005, which are further discussed in Note 8 “Debt—Subsidiary Debt—Gulf Opportunity Zone Bonds.”

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7.  Goodwill and Other Intangibles

Goodwill and Excess Investment Cost

We record the excess of the cost of an acquisition price over the fair value of acquired net assets as an asset on our balance sheet.  This amount is referred to and reported separately as “Goodwill” in our accompanying consolidated balance sheets.  Goodwill is not subject to amortization but must be tested for impairment at least annually.  This test requires us to assign goodwill 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.

We evaluate goodwill for impairment on May 31 of each year.  For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines; (iv) CO2; (v) Terminals; and (vi) Kinder Morgan Canada.  There were no impairment charges resulting from our May 31, 2010 impairment testing, and no event indicating an impairment has occurred subsequent to that date.

The fair value of each reporting unit was determined from the present value of the expected future cash flows from the applicable reporting unit (inclusive of a terminal value calculated using market multiples between six and ten times cash flows) discounted at a rate of 9.0%.  The value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date.

Changes in the gross amounts of our goodwill and accumulated impairment losses for each of the two years ended December 31, 2010 and 2009 are summarized as follows (in millions):

	Products Pipelines		Natural Gas Pipelines		CO2		Terminals		Kinder Morgan Canada			Total
Historical Goodwill.	$	263.2	$	288.4	$	46.1	$	257.6	$	580.7		$	1,436.0
Accumulated impairment losses(a).		-		-		-		-		(377.1	)		(377.1	)
Balance as of December 31, 2008		263.2		288.4		46.1		257.6		203.6			1,058.9
Acquisitions and purchase price adjs.		-		48.6		-		9.3		-			57.9
Currency translation adjustments		-		-		-		-		32.4			32.4
Balance as of December 31, 2009	$	263.2	$	337.0	$	46.1	$	266.9	$	236.0		$	1,149.2
Acquisitions.		-		-		-		71.0		-			71.0
Currency translation adjustments		-		-		-		-		13.4			13.4
Balance as of December 31, 2010	$	263.2	$	337.0	$	46.1	$	337.9	$	249.4		$	1,233.6

__________

(a) On April 18, 2007, we announced that we would acquire the Trans Mountain pipeline system from KMI, and we completed this transaction on April 30, 2007.  Following the provisions of generally accepted accounting principles, the consideration of this transaction caused KMI to consider the fair value of the Trans Mountain pipeline system, and to determine whether goodwill related to these assets was impaired.  Based on this determination, KMI recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007, and because we have included all of the historical results of Trans Mountain as though the net assets had been transferred to us on January 1, 2006, this impairment is now included in our accumulated impairment losses. We have no other goodwill impairment losses.  

For more information on our accounting for goodwill, see Note 2 “Summary of Significant Accounting Policies—Goodwill.”

With regard to our equity investments in unconsolidated affiliates, in almost all cases, either (i) the price we paid to acquire our share of the net assets of such equity investees; or (ii) the revaluation of our share of the net assets of any retained noncontrolling equity investment (from the sale of a portion of our ownership interest in a consolidating subsidiary, thereby losing our controlling financial interest in the subsidiary) differed from the underlying carrying value of such net assets.  This differential consists of two pieces.  First, an amount related to the difference 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 (referred to as equity m ethod goodwill) we paid to acquire the investment.  We include both amounts within “Investments” on our accompanying consolidated balance sheets.

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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 either the date of acquisition or the date of the loss of control totaled $166.0 million and $163.2 million as of December 31, 2010 and 2009, respectively.  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.  As of December 31, 2010, this excess investment cost is being amortized over a weighted average life of approximately 27 .6 years.

The second differential, representing total unamortized excess cost over underlying fair value of net assets acquired (equity method goodwill) was $283.0 million as of December 31, 2010 and $138.2 million as of December 31, 2009.  This differential is not subject to amortization but rather to impairment testing.  Accordingly, 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.  Our impairment test considers whether the fair value of the equity investment as a whole, not the unde rlying net assets, has declined and whether that decline is other than temporary.  As of December 31, 2010, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted.

Other Intangibles

Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, technology-based assets, and lease value.  These intangible assets have definite lives and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets.  Following is information, as of December 31, 2010 and 2009, related to our intangible assets subject to amortization (in millions):

	December 31,
	2010			2009
Customer relationships, contracts and agreements
Gross carrying amount	$	399.8		$	273.0
Accumulated amortization		(112.0	)		(67.1	)
Net carrying amount		287.8			205.9
Technology-based assets, lease value and other
Gross carrying amount		17.9			15.7
Accumulated amortization		(3.5	)		(2.9	)
Net carrying amount		14.4			12.8
Total Other intangibles, net	$	302.2		$	218.7

Our customer relationships, contracts and agreements relate primarily to our Terminals business segment, and include relationships and contracts for handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline and other refined petroleum products, coal, petroleum coke, fertilizer, steel and ores.  The values of these intangible assets were determined by us (often in conjunction with third party valuation specialists) by first, estimating the revenues derived from a customer relationship or contract (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.  The increase in the carrying amount of our customer relationships, contracts and agreements since December 31, 2009 was mainly due to the acq uisition of intangibles included in our purchase of terminal assets from US Development Group LLC and Slay Industries, discussed in Note 3.

We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives.  Among the factors we weigh, depending on the nature of the asset, are the effect of obsolescence, new technology, and competition.  For each of the years ended December 31, 2010, 2009 and 2008, the amortization expense on our intangibles totaled $45.5 million, $16.5 million and $14.7 million, respectively.  These expense amounts primarily consisted of amortization of our customer relationships, contracts and agreements.  Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2011 – 2015) is approximately $39.3 million, $33.9 million, $30.0 million, $26.6 million and $23.7 million, respectively.

The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship.  As of December 31, 2010, the weighted average amortization period for our intangible assets was approximately 13.8 years.

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8.  Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments.  We defer costs associated with debt issuance over the applicable term.  These costs are then amortized as interest expense in our consolidated statements of income.  The net carrying amount of our debt (including both short-term and long-term amounts and excluding the value of interest rate swap agreements) as of December 31, 2010 and 2009 was $11,539.8 million and $10,592.4 million, respectively.  The weighted average interest rate on all of our borrowings was approximately4.35% during 2010 and 4.57% during 2009.

Short-Term Debt

Our outstanding short-term debt as of December 31, 2010 was $1,262.4 million.  The balance consisted of (i) $700.0 million in principal amount of 6.75% senior notes due March 15, 2011; (ii) $522.1 million of commercial paper borrowings; (iii) $23.7 million in principal amount of tax-exempt bonds that mature on April 1, 2024, but are due on demand pursuant to certain standby purchase agreement provisions contained in the bond indenture (our subsidiary Kinder Morgan Operating L.P. “B” is the obligor on the bonds); (iv) a $9.4 million portion of a 5.40% long-term note payable (our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note); and (v) a $7.2 million portion of 5.23% long-term senior notes (our subsidiary Kinder Morgan Texas Pipeline, L.P. is the obligor on the notes).

Our outstanding short-term debt as of December 31, 2009 was $594.7 million.  The balance consisted of(i) $300 million in outstanding borrowings under our bank credit facility (discussed following); (ii) $250 million in principal amount of 7.50% senior notes that matured on November 1, 2010; (iii) $23.7 million in principal amount of tax-exempt bonds due from our subsidiary Kinder Morgan Operating L.P. “B”; (iv) an $8.9 million portion of the 5.40% long-term note payable due from our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company; (v) a $6.8 million portion of the 5.23% senior notes due from our subsidiary Kinder Morgan Texas Pipeline, L.P.; and (vi) $5.3 million in principal amount of adjustable rate industrial development revenue bonds that matured on January 1, 2010 (the bonds were issued by the Illinois Development Finance Authority and our subsidiary Arrow Terminals L.P. is the obligor on the bonds).

Credit Facility

On June 23, 2010, we successfully renegotiated our previous $1.79 billion five-year unsecured revolving bank credit facility that was due August 18, 2010, replacing it with a new $2.0 billion three-year, senior unsecured revolving credit facility that expires June 23, 2013.  Similar to our previous facility, our $2.0 billion credit facility is with a syndicate of financial institutions, and the facility permits us to obtain bids for fixed rate loans from members of the lending syndicate. Wells Fargo Bank, National Association is the administrative agent, and borrowings under the credit facility can be used for general partnership purposes and as a backup for our commercial paper program.  We had no borrowings under the credit facility as of December 31, 2010.  As of December 31, 2009, the outstanding balance under our previous $1.79 billion credit facility was $300 million, and the weighted average interest rate on these borrowings was 0.59%.

The covenants of our $2.0 billion, senior unsecured revolving credit facility are substantially similar to the covenants of our previous facility; however, the interest rates for borrowings under this facility have increased from our previous facility.  Interest on the credit facility accrues at our option at a floating rate equal to either (i) the administrative agent’s base rate (but not less than the Federal Funds Rate, plus 0.5%); or (ii) LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.  The credit facility can be amended to allow for borrowings of up to $2.3 billion.

As of December 31, 2010, the amount available for borrowing under our credit facility was reduced bya combined amount of $758.9 million, consisting of $522.1 million of commercial paper borrowings and $236.8 million of letters of credit, consisting of: (i) a $100.0 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (ii) a combined $87.9 million in three letters of credit that support tax-exempt bonds; (iii) a $16.2 million letter of credit that supports debt securities issued by the Express pipeline system; (iv) a $16.1 million letter of credit that supports our indem nification obligations on the Series D note borrowings of Cortez Capital Corporation; and (v) a combined $16.6 million in other letters of credit supporting other obligations of us and our subsidiaries.

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Additionally, our $2.0 billion credit facility included the following restrictive covenants as of December 31, 2010:

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

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

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

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

▪ limitations on granting liens; and

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

In addition to normal repayment covenants, under the terms of our credit facility, the occurrence at any time of any of the following would constitute an event of default (i) our failure to make required payments of any item of indebtedness or any payment in respect of any hedging agreement, provided that the aggregate outstanding principal amount for all such indebtedness or payment obligations in respect of all hedging agreements is equal to or exceeds $75 million; (ii) our general partner’s failure to make required payments of any item of indebtedness, provided that the aggregate outstanding principal amount for all such indebtedness is equal to or exceeds $75 million; (iii) adverse judgments rendered against us for the payment of money in an aggregate amount in excess of $75 million, if this same amount remains undischarged for a period of thirty consecutive days during which execution shall not be effectively stayed; and (iv) voluntary or involuntary commencements of any proceedings or petitions seeking our liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law.

Other than the relatively non-restrictive negative covenants and events of default in our credit facility, there are no provisions protecting against a situation where we are unable to terminate an agreement with a counterparty who is facing an impending financial collapse and such collapse may be hastened due to cross-defaults.  Also, 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 credit rating.  None of our debt is subject to payment acceleration as a result of any change to our credit ratings.

Commercial Paper Program

Our commercial paper program provides for the issuance of $2 billion of commercial paper.  On October 13, 2008, Standard & Poor’s Ratings Services lowered our short-term credit rating to A-3 from A-2, and on May 6, 2009, Moody’s Investors Service, Inc. downgraded our commercial paper rating to Prime-3 from Prime-2 and assigned a negative outlook to our long-term credit rating.  As a result of these revisions and the commercial paper market conditions, we were unable to access commercial paper borrowings throughout 2009.

However, on February 25, 2010, Standard & Poor’s revised its outlook on our long-term credit rating to stable from negative, affirmed our long-term credit rating at BBB, and raised our short-term credit rating to A-2 from A-3.  The rating agency’s revisions reflected its expectations that our financial profile will improve due to lower guaranteed debt obligations and higher expected cash flows associated with the completion and start-up of our 50%-owned Rockies Express and Midcontinent Express natural gas pipeline systems and our fully-owned Kinder Morgan Louisiana natural gas pipeline system.  Due to this favorable change in our short-term credit rating, we resumed issuing commercial paper in March 2010, and as of December 31, 2010, we had $522.1 million of commercial paper outstanding with an average interest rate of 0.67%.  In the near term, we expect that our short-term liquidity and financing needs will be met through a combination of borrowings made under our bank credit facility and our commercial paper program.

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Long-Term Debt

Our outstanding long-term debt, excluding the value of interest rate swaps, as of December 31, 2010 and 2009 was $10,277.4 million and $9,997.7 million, respectively.  The balances consisted of the following (in millions):

	December 31,
	2010			2009
Kinder Morgan Energy Partners, L.P. borrowings:
7.50% senior notes due November 1, 2010	$	-		$	250.0
6.75% senior notes due March 15, 2011		700.0			700.0
7.125% senior notes due March 15, 2012		450.0			450.0
5.85% senior notes due September 15, 2012		500.0			500.0
5.00% senior notes due December 15, 2013		500.0			500.0
5.125% senior notes due November 15, 2014		500.0			500.0
5.625% senior notes due February 15, 2015		300.0			300.0
6.00% senior notes due February 1, 2017		600.0			600.0
5.95% senior notes due February 15, 2018		975.0			975.0
9.00% senior notes due February 1, 2019(a)		500.0			500.0
6.85% senior notes due February 15, 2020		700.0			700.0
5.30% senior notes due September 15, 2020		600.0			-
5.80% senior notes due March 1, 2021		400.0			400.0
7.40% senior notes due March 15, 2031		300.0			300.0
7.75% senior notes due March 15, 2032		300.0			300.0
7.30% senior notes due August 15, 2033		500.0			500.0
5.80% senior notes due March 15, 2035		500.0			500.0
6.50% senior notes due February 1, 2037		400.0			400.0
6.95% senior notes due January 15, 2038		1,175.0			1,175.0
6.50% senior notes due September 1, 2039		600.0			600.0
6.55% senior notes due September 15, 2040		400.0			-
Commercial paper borrowings		522.1			-
Bank credit facility borrowings		-			300.0
Subsidiary borrowings:
Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010		-			5.3
Kinder Morgan Louisiana Pipeline LLC-6.0% LA Development Revenue note due Jan. 1, 2011		-			5.0
Kinder Morgan Operating L.P. “A”-5.40% BP note, due March 31, 2012		10.2			14.9
Kinder Morgan Canada Company-5.40% BP note, due March 31, 2012		9.0			13.2
Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014		23.6			30.5
Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due Jan. 15, 2018		25.0			25.0
Kinder Morgan Columbus LLC-5.50% MS Development Revenue note due Sept. 1, 2022		8.2			8.2
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		1.3			1.3
Unamortized debt discount on senior notes		(23.3	)		(24.7	)
Current portion of long-term debt		(1,262.4	)		(594.7	)
Total long-term debt	$	10,277.4		$	9,997.7

__________

(a) We issued our $500 million in principal amount of 9.00% senior notes due February 1, 2019 in December 2008.  Each holder of the notes has the right to require us to repurchase all or a portion of the notes owned by such holder on February 1, 2012 at a purchase price equal to 100% of the principal amount of the notes tendered by the holder plus accrued and unpaid interest to, but excluding, the repurchase date.  On and after February 1, 2012, interest will cease to accrue on the notes tendered for repayment.  A holder’s exercise of the repurchase option is irrevocable.  

Kinder Morgan Energy Partners, L.P. Senior Notes

As of December 31, 2010 and 2009, the net carrying value of the various series of our senior notes was $10,876.7 million and $10,125.3 million, respectively.  For a listing of the various outstanding series of our senior notes, see the table above included in “—Long-Term Debt.”  All of our fixed rate senior 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.

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On May 19, 2010, we completed a public offering of senior notes.  We issued a total of $1 billion in principal amount of senior notes in two separate series, consisting of $600 million of 5.30% notes due September 15, 2020, and $400 million of 6.55% notes due September 15, 2040.  We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $993.1 million, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.

In addition, on November 1, 2010, we paid $250 million to retire the principal amount of our 7.50% senior notes that matured on that date.  We borrowed the necessary funds under our commercial paper program.

During 2009, we completed two separate public offerings of senior notes.  With regard to these offerings, we received proceeds, net of underwriting discounts and commissions, as follows (i) $993.3 million from a May 14, 2009 public offering of a total of $1 billion in principal amount of senior notes, consisting of $300 million of 5.625% notes due February 15, 2015, and $700 million of 6.85% notes due February 15, 2020; and (ii) $987.4 million from a September 16, 2009 public offering of a total of $1 billion in principal amount of senior notes, consisting of $400 million of 5.80% notes due March 1, 2021 and $600 million of 6.50% notes due September 1, 2039.  We used the proceeds from all of our 2009 debt offerings to reduce the borrowings under our bank credit facility.

In addition, on February 1, 2009, we paid $250 million to retire the principal amount of our 6.30% senior notes that matured on that date.  We borrowed the necessary funds under our bank credit facility.

Interest Rate Swaps

Information on our interest rate swaps is contained in Note 13 “Risk Management—Interest Rate Risk Management.”

Subsidiary Debt

Our subsidiaries are obligors on the following debt.  The agreements governing these obligations contain various affirmative and negative covenants and events of default.  We do not believe that these provisions will materially affect distributions to our partners.

Arrow Terminals L.P. Debt

On January 1, 2010, our subsidiary Arrow Terminals L.P. paid the $5.3 million outstanding principal amount of its Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois Development Finance Authority that matured on that date, and following its repayment, Arrow Terminals L.P. had no outstanding debt.

Kinder Morgan Operating L.P. “A” Debt

Effective January 1, 2007, we acquired the remaining approximately 50.2% interest in the Cochin pipeline system that we did not already own.  As part of our purchase price consideration, two of our subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million.  We valued the debt equal to the present value of amounts to be paid, determined using an annual interest rate of 5.40%.  Our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note, and the principal amount of the note, along with interest, is due in five annual installments of $10.0 million beginning March 31, 2008.  We paid the third installment on March 31, 2010, and as of December 31, 2010, the net present value of the note (representing the outstanding balance included as debt on our accompanying consolidated balance sheet) was $19.2 million.  As of December 31, 2009, the net present value of the note was $28.1 million.

Kinder Morgan Texas Pipeline, L.P. Debt

Our subsidiary, Kinder Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior notes, which were assumed on August 1, 2005 when we acquired a natural gas storage facility located in Liberty County, Texas from a third party.  The notes have a fixed annual stated interest rate of 8.85%; however, we valued the debt equal to the present value of amounts to be paid determined using an approximate interest rate of 5.23%.  The assumed principal amount, along with interest, is due in monthly installments of approximately $0.7 million, and the final payment is due January 2, 2014.  During 2010, we paid a combined principal amount of $6.9 million, and as of December 31, 2010 and 2009, Kinder Morgan Texas Pipeline L.P.’s outstanding balance under the senior notes was $23.6 million and $30.5 mil lion, respectively.  Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million and 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.

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Kinder Morgan Liquids Terminals LLC Debt

Our subsidiary Kinder Morgan Liquids Terminals LLC is the obligor on $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, 2010, the interest rate was 0.29%.  We have an outstanding letter of credit issued by Citibank in the amount of $25.4 million that backs-up the $25.0 million principal amount of the bonds and $0.4 million of interest on the bonds for up to 46 days computed at 12 % on a per annum basis on the principal thereof.

Kinder Morgan Operating L.P. “B” Debt

Our subsidiary Kinder Morgan Operating L.P. “B” is the obligor of a principal amount of $23.7 million of tax-exempt bonds due April 1, 2024.  The bonds were issued by the Jackson-Union Counties Regional Port District, a political subdivision embracing the territories of Jackson County and Union County in the state of Illinois.  These variable rate demand bonds bear interest at a weekly floating market rate and are backed-up by a letter of credit issued by Wells Fargo.  The bond indenture also contains certain standby purchase agreement provisions which allow investors to put (sell) back their bonds at par plus accrued interest.  As of December 31, 2010, the interest rate on these bonds was 0.38%.  Our outstanding letter of credit issued by Wells Fargo totaled $24.1 million, wh ich backs-up a principal amount of $23.7 million and $0.4 million of interest on the bonds for up to 55 days computed at 12% per annum on the principal amount thereof.

International Marine Terminals Debt

We own a 66 2/3% interest in the International Marine Terminals (IMT) partnership.  The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40.0 million Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B.  As of December 31, 2010, the interest rate on these bonds was 1.20%.

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 Wells Fargo.  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.

Gulf Opportunity Zone Bonds

To help fund our business growth in the states of Mississippi and Louisiana, we completed the purchase of a combined $13.2 million in principal amount of tax exempt revenue bonds in two separate transactions in December 2008.  To acquire our investment, two of our subsidiaries issued notes with identical terms under the Gulf Opportunity Zone Act of 2005.  The notes consisted of the following: (i) $8.2 million in principal amount of 5.5% Development Revenue Bonds issued by the Mississippi Business Finance Corporation (MBFC), a public, non-profit corporation that coordinates a variety of resources used to assist business and industry in the state of Mississippi; and (ii) $5.0 million in principal amount of 6.0% Development Revenue Bonds issued by the Louisiana Community Development Authority (LCDA ), a political subdivision of the state of Louisiana.

The Mississippi revenue bonds mature on September 1, 2022, and both principal and interest is due in full at maturity.  We also hold an option to redeem in full (and settle the note payable to MBFC) the principal amount of bonds held by us without penalty after one year.  We redeemed the Louisiana revenue bonds in December 2010 (by settling our $5.0 million note payable to LCDA), and we replaced this investment with a new investment of $100.0 million in principal amount of Development Revenue Bonds that mature on December 1, 2040 and pay interest at a rate equal to one-month LIBOR plus 1.75%.  We paid for this investment by issuing a $100.0 million note payable to LCDA with identical terms, and for this bond issuance, we elected to offset our borrowing against the investment we acquire d.

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Maturities of Debt

The scheduled maturities of our outstanding debt, excluding the value of interest rate swaps, as of December 31, 2010, are summarized as follows (in millions):

Year	Commitment
2011	$	1,262.4
2012		1,467.0
2013		507.1
2014		500.5
2015		299.9
Thereafter		7,502.9
Total	$	11,539.8

Subsequent Event

In January 2011, we terminated a previously issued $55.0 million letter of credit issued by Deutsche Bank to support our pipeline and terminal operations in Canada.  Specifically, this letter of credit supported the operations of our Kinder Morgan Canada business segment owned by our subsidiary KMEP Canada ULC.  To replace this letter of credit, on January 6, 2011, we entered into a credit agreement with The Toronto-Dominion Bank that allows us to obtain the issuance of letters of credit up to a limit of C$70.0 million to support our Canadian operations.  Each letter of credit issued pursuant to this credit agreement will expire one year after issuance or, in the case of any renewal or extension, one year after such renewal or extension.  As of February 14, 2011, letters of credit having a combined face amount of C$50.7 million have been issued pursuant to this credit agreement.

9.  Employee Benefits

Pension and Postretirement Benefit Plans

In connection with our acquisition of the Trans Mountain pipeline system in 2007 from KMI, we acquired certain liabilities for pension and postretirement benefits.  Two of our subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partner of Trans Mountain Pipeline L.P.) are sponsors 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 postretirement benefits other than pensions for retired employees.

Our combined net periodic benefit costs for these Trans Mountain pension and postretirement benefit plans for 2010, 2009 and 2008 were approximately $3.9 million, $2.9 million, and $3.5 million, respectively, recognized ratably over each year.  As of December 31, 2010, we estimate our overall net periodic pension and postretirement benefit costs for these plans for the year 2011 will be approximately $6.6 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 $7.1 million to these benefit plans in 2011.

Additionally, in connection with our acquisition of SFPP, L.P. in 1998, we acquired certain liabilities for pension and postretirement benefits.  We provide medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP.  We also provide the same benefits to former salaried employees of SFPP and we will continue to fund these costs for those employees currently in the plan during their retirement years.

SFPP’s postretirement benefit plan is frozen and no additional participants may join the plan.  Benefits under the SFPP postretirement benefit plan are provided by the Burlington Northern Santa Fe railroad and we reimburse BNSF for the costs of the plan.  As of the date of this report, we have not received our 2010 actuarial valuation report for the SFPP postretirement benefit plan; however, in 2010, we recorded a credit of less than $0.1 million for net periodic benefit costs related to this plan, and for each of the years ended December 31, 2009 and 2008, our net periodic benefit cost for the SFPP postretirement benefit plan was acredit ofless than$0.1 million.  The credits in all three years resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost.  As of December 31, 2010, we estimate our overall net periodic postretirement benefit cost for the SFPP postretirement benefit plan for the year 2011 will again be a credit of less than $0.1 million; however, this estimate could change if a future significant event would require a remeasurement of liabilities.  In addition, we expect to contribute approximately $0.3 million to this postretirement benefit plan in 2011.

As of December 31, 2010 and 2009, the recorded value of our pension and postretirement benefit obligations for both the Trans Mountain pension and postretirement benefit plans and the SFPP postretirement benefit plan was a combined $44.8 million and $37.4 million, respectively.  We consider our overall pension and postretirement benefit liability exposure and the fair value of our pension and postretirement plan assets to be minimal in relation to the value of our total consolidated assets and net income.  

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Multiemployer Plans

As a result of acquiring several terminal operations, primarily our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in several multi-employer pension plans for the benefit of employees who are union members.  We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts.  Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs.  Amounts charged to expense for these plans for each of the years ended December 31, 2010, 2009 and 2008 were approximately $10.3 million, $8.4 million and $7.8 million, respectively.

Kinder Morgan Savings Plan    

The Kinder Morgan Savings Plan is a defined contribution 401(k) plan.  The plan permits all full-time employees of KMI and KMGP Services Company, Inc. to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts.  As an additional benefit to all participants, an option also exits to make after-tax “Roth” contributions (Roth 401(k) option) to a separate Savings Plan participant account, and certain employees’ contributions are based on collective bargaining agreements.  Our general partner contributes an amount equal to 4% of base compensation per year for most plan participants and in addition, may make special discretionary contributions (described below).  The contributions are made each pay period on behalf of each eligible employee.

Participants may direct the investment of their contributions and all employer contributions, including discretionary contributions, into a variety of investments.  Plan assets are held and distributed pursuant to a trust agreement.  The total amount charged to expense for the Kinder Morgan Savings Plan was $13.3 million during 2010, $12.1 million during 2009, and $13.3 million during 2008.

Employer contributions for employees 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 Terminals employees hired after October 1, 2005 vest on the third anniversary of the date of hire.

At its July 2010 meeting, Mr. Richard D. Kinder and KMR’s compensation committee 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 2010 and continuing through the last pay period of July 2011.  The additional 1% contribution does not change or otherwise impact the annual 4% contribution that eligible employees currently receive, and it vests according to the same vesting schedule described in the preceding paragraph.  During the first quarter of 2011, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individu al accounts for 2010.

At its January 2011 meeting, Mr. Richard D. Kinder and KMR’s compensation committee decided to make this special contribution of an additional 1% of base pay a permanent contribution into the Savings Plan for each eligible employee.  Accordingly, beginning with the first pay period of August 2011, our general partner will contribute an amount equal to 5% of base compensation per year on behalf of each eligible employee.  This change was made to assist employees in providing financial security for retirement without the risk of the 1% variable factor.  For employees of our Terminals business segment, the tiered employer contributions described above will also increase by 1% beginning with the first pay period of August 2011.

Cash Balance Retirement Plan

Employees of KMGP Services Company, Inc. and KMI are also eligible to participate in a Cash Balance Retirement Plan.  Certain employees continue to accrue benefits through a career-pay formula (“grandfathered” according to age and years of service on December 31, 2000), or collective bargaining arrangements.  All other employees accrue benefits through a personal retirement account in the Cash Balance Retirement Plan.  Under the plan, KMI credits each participating employee’s personal retirement account an amount 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 three years, and they may take a lump sum distribution upon termination of employment or retirement.

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In February 2009, KMI amended the plan in order to reduce its rate of future benefit accruals effective April 12, 2009.  Beginning on that date, and continuing through the last pay period of December 2009, KMI ceased making contribution credits to the accounts of all participating employees of KMGP Services, Inc. and KMI under the cash balance portion of the plan, except to the extent the terms of an applicable collective bargaining agreement required contribution credits be made.  KMI continued to credit interest to employees’ personal retirement accounts as described above.  Effective January 1, 2010, all contribution credits on behalf of participating employees resumed.

Effective January 1, 2011, KMI amended the plan and began crediting each participating employee’s personal retirement account for interest at a rate equal to the five-year U.S. Treasury note rate plus 0.25%.  This interest rate credit change allows KMI to invest the plan’s assets in a manner that preserves capital and controls volatility.  The new interest rate complies with the safe harbor regulations as defined by the U.S. Department of Labor and is expected to reduce the plan’s long-term cost.  KMI continues to credit 3% of employees’ eligible compensation to their personal retirement accounts.

10.  Partners’ Capital

Limited Partner Units

As of December 31, 2010 and 2009, our partners’ capital included the following limited partner units:

	December 31,
	2010		2009
Common units		218,880,103		206,020,826
Class B units		5,313,400		5,313,400
i-units		91,907,987		85,538,263
Total limited partner units		316,101,490		296,872,489

The total limited partner units represent our limited partners’ interest and an effective 98% 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, 2010, our total common units consisted of 202,509,675 units held by third parties, 14,646,428 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, 2009, our total common units consisted of 189,650,398 units held by third parties, 14,646,428 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner.

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, 2010 and 2009, all of our i-units were held 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 our 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 units.  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, during the year ended December 31, 2010, KMR received distributions of 6,369,724 i-units.  These additional i-units distributed were based on the $4.32 per unit distributed to our common unitholders during 2010.  During the year ended December 31, 2009, KMR received distributions of 7,540,357 i-units.  These additional i-units distributed were based on the $4.20 per unit distributed to our common unitholders during 2009.  During the year ended December 31, 2008, KMR received distributions of 5,565,424 i-units.  These additional i-units distributed were based on the $3.89 per unit distributed to our common unitholders during 2008.

152

Equity Issuances

2010 Issuances

On January 16, 2009, we entered into an equity distribution agreement with UBS Securities LLC (UBS).  According to the provisions of this agreement, which was amended and restated on October 1, 2009, we may offer and sell from time to time common units having an aggregate offering value of up to $600 million through UBS, as sales agent.  Sales of the units will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions or as otherwise agreed between us and UBS.  Under the terms of this agreement, we also may sell common units to UBS as principal for its own account at a price agreed upon at the time of the sale.  Any sale of common units to UBS as principal would be pursuant to the terms of a separate agreement between us and UBS.

This equity distribution agreement provides us the right, but not the obligation, to sell common units in the future, at prices we deem appropriate.  We retain at all times complete control over the amount and the timing of each sale, and we will designate the maximum number of common units to be sold through UBS, on a daily basis or otherwise as we and UBS agree.  UBS will then use its reasonable efforts to sell, as our sales agent and on our behalf, all of the designated common units.  We may instruct UBS not to sell common units if the sales cannot be effected at or above the price designated by us in any such instruction.  Either we or UBS may suspend the offering of common units pursuant to the agreement by notifying the other party.

In 2010, we issued 3,902,225 of our common units pursuant to our equity distribution agreement.  After commissions of $2.0 million, we received net proceeds from the issuance of these common units of $266.3 million.  We used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.

We also completed the following equity issuances in 2010:

▪ On January 15, 2010, we issued 1,287,287 common units—valued at $81.7 million—as a portion of our purchase price for additional ethanol handling terminal assets we acquired from US Development Group LLC (for more information on this acquisition, see Note 3 “Acquisitions and Divestitures—Acquisitions from Unrelated Entities—(7) USD Terminal Acquisition;”

▪ On May 7, 2010, we issued, in a public offering, 6,500,000 of our common units at a price of $66.25 per unit, less commissions and underwriting expenses.  After commissions and underwriting expenses, we received net proceeds of $417.4 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility; and

▪ On July 2, 2010, we completed an offering of 1,167,315 of our common units at a price of $64.25 per unit in a privately negotiated transaction.  We received net proceeds of $75.0 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.

2009 Issuances

In 2009, we issued 5,488,947 of our common units pursuant to our equity distribution agreement with UBS.  After commissions of $4.0 million, we received net proceeds from the issuance of these common units of $281.2 million.  We used the proceeds to reduce the borrowings under our bank credit facility.

We also completed three separate underwritten public offerings of our common units in 2009—receiving net proceeds of $874.4 million as discussed following—and in April 2009, we issued 105,752 common units—valued at $5.0 million—as the purchase price for additional ownership interests in certain oil and gas properties.

In our first 2009 underwritten public offering, completed in March, we issued 5,666,000 of our common units at a price of $46.95 per unit, less underwriting commissions and expenses.  We received net proceeds of $258.0 million for the issuance of these common units.  In our second offering, completed in July, we issued 6,612,500 common units at a price of $51.50 per unit, less underwriting commissions and expenses, and we received net proceeds of $329.9 million.  In our final 2009 public offering, completed in December, we issued 5,175,000 common units at a price of $57.15 per unit, less underwriting commissions and expenses, and we received net proceeds of $286.5 million for the issuance of these common units.  We used the proceeds from each of these three public offerings to reduce the borrowings under our bank credit facility.

153

Income Allocation and Declared Distributions

For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests.  Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner.  Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed, and we determine the allocation of incentive distributions to our general partner by the amount quarterly distributions to unitholders exceed certain specified target lev els, according to the provisions of our partnership agreement.

For each of the years ended December 31, 2010, 2009 and 2008, we declared distributions of $4.40, $4.20 and $4.02 per unit, respectively.  Cash distributions paid to all partners, consisting of our common and Class B unitholders, our general partner and noncontrolling interests, totaled $1,826.6 million in 2010, $1,771.9 million in 2009 and $1,488.7 million in 2008.  In addition, we made distributions of additional i-units in each of these years to KMR as discussed under “—Limited Partner Units” above.  Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.  The year-to-year increases in distributions paid reflect the increase in amounts distributed per unit as well as the issuance of additional units; however, the o verall increase in distributions paid in 2010 versus 2009 was partially offset by a decrease in incentive distributions paid to our general partner, as discussed following.

Our general partner’s incentive distribution that we declared for each of the years 2010, 2009 and 2008 was $880.5 million, $932.3 million and $800.8 million, respectively, while the incentive distribution we paid to our general partner during 2010, 2009 and 2008 was $848.2 million, $906.5 million and $754.6 million, respectively.  The general partner’s incentive distribution we paid in 2010 was affected by (i) a reduced incentive amount of $168.3 million due to a portion of our available cash distribution for the second quarter of 2010 being a distribution of cash from interim capital transactions, rather than a distribution of cash from operations (including the general partner’s 2% general partner interest, its total cash distribut ions were reduced by $170.0 million); and (ii) a waived incentive amount equal to $11.1 million related to common units issued to finance a portion of our acquisition of a 50% interest in KinderHawk Field Services LLC joint venture (our general partner has agreed not to take incentive distributions related to this acquisition through year-end 2011).

Our distribution of cash for the second quarter of 2010 (which we paid in the third quarter of 2010) from interim capital transactions totaled $177.1 million (approximately $0.56 per limited partner unit).  As provided in our partnership agreement, our general partner receives no incentive distribution on distributions of cash from interim capital transactions; accordingly, this distribution from interim capital transactions helped preserve our cumulative excess cash coverage.  Cumulative excess cash coverage is cash from operations generated since our inception in excess of cash distributions paid.

In addition, there was no practical impact to our limited partners from this distribution of cash from interim capital transactions because (i) the cash distribution to our limited partners for the quarter did not change; (ii) fewer dollars in the aggregate were distributed (because there was no incentive distribution paid to our general partner related to the portion of the quarterly distribution that was a distribution of cash from interim capital transactions); and (iii) our general partner, in this instance, agreed to waive any resetting of the incentive distribution target levels, as would otherwise occur according to our partnership agreement.

For further information on our partnership distributions, see Note 11 “Related Party Transactions—Partnership Interests and Distributions.”

Subsequent Events

In early January 2011, we issued 110,902 of our common units for the settlement of sales made on or before December 31, 2010 pursuant to our equity distribution agreement with UBS.  After commissions of $0.1 million, we received net proceeds of $7.7 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.

154

On January 19, 2011, we declared a cash distribution of $1.13 per unit for the quarterly period ended December 31, 2010.  This distribution was paid on February 14, 2011, to unitholders of record as of January 31, 2011.  Our common unitholders and our Class B unitholder received cash.  KMR, our sole i-unitholder, received a distribution in the form of additional i-units based on the $1.13 distribution per common unit.  The number of i-units distributed was 1,598,556.  For each outstanding i-unit that KMR held, a fraction of an i-unit (0.017393) was issued.  The fraction was determined by dividing:

▪ $1.13, the cash amount distributed per common unit

by

▪ $64.969, the average of KMR’s limited liability shares’ closing market prices from January 12-26, 2011, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange.

This February 14, 2011 distribution included an incentive distribution to our general partner in the amount of $274.6 million.  Since this distribution was declared after the end of the quarter, no amount is shown in our December 31, 2010 balance sheet as a distribution payable.

11.  Related Party Transactions

General and Administrative Expenses

KMGP Services Company, Inc., a subsidiary of our general partner, provides employees and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR, provides centralized payroll and employee benefits services to (i) us; (ii) our operating partnerships and subsidiaries; (iii) our general partner; and (iv) KMR (collectively referred to in this note as 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 profi t 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 certain of our assets (discussed below in “—Operations”).  These employees’ expenses are allocated without a profit component between KMI on the one hand, and the appropriate members of the Group, on the other hand.

Additionally, for accounting purposes, KMI was required to allocate to us a portion of its 2007 going-private transaction-related amounts, and it is required to recognize compensation expense in connection with their Class A-1 and Class B units over the expected life of such units and allocate to us a portion of these going-private transaction-related amounts.  These units were issued prior to the conversion of Kinder Morgan Holdco LLC to KMI.  As a subsidiary of KMI, we are required to recognize the allocated amounts as expense on our income statements; however, we have no obligation and we do not expect to pay any amounts related to these going-private transaction-related expenses.  Accordingly, we recognize the unpaid amounts as contributions to “Total Partners’ Capital” on our balance s heet.  For each of the years 2010, 2009 and 2008, we recognized non-cash compensation expense of $4.6 million, $5.7 million and $5.6 million, respectively, due to certain going-private transaction expenses allocated to us from KMI in connection with KMI’s May 2007 going-private transaction.

155

Partnership Interests and Distributions

General

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.  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 the proper conduct of our business, which might include reserves for matters such as future operating expenses, debt service, sustaining capital expenditures and rate refunds, and for distributions for the next four quarters.  These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated.  When KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, the sole owner of our i-units, receives distributions in additional i-units.  We do not distribute cash to i-unit owners (KMR) but instead 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.

Pursuant to our partnership agreement, distributions to unitholders are characterized either as distributions of cash from operations or as distributions of cash from interim capital transactions.  This distinction affects the distributions to owners of common units, Class B units and i-units relative to the distributions to our general partner.

Cash from Operations.  Cash from operations generally refers to our cash balance on the date we commenced operations, plus all cash generated by the operation of our business, after deducting related cash expenditures, net additions to or reductions in reserves, debt service and various other items.

Cash from Interim Capital Transactions.  Cash from interim capital transactions will generally result only from distributions that are funded from borrowings, sales of debt and equity securities and sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets and assets disposed of in the ordinary course of business.

Rule for Characterizing Distributions.  Generally, all available cash distributed by us from any source will be treated as distributions of cash from operations until the sum of all available cash distributed equals the cumulative amount of cash from operations actually generated from the date we commenced operations through the end of the calendar quarter prior to that distribution.  Any distribution of available cash which, when added to the sum of all prior distributions, is in excess of the cumulative amount of cash from operations, will be considered a distribution of cash from interim capital transactions until the initial common unit price is fully recovered as described below under “—Allocation of Distributions from Interim Capital Transactio ns.”  For purposes of calculating the sum of all distributions of available cash, the total equivalent cash amount of all distributions of i-units to KMR, as the holder of all i-units, will be treated as distributions of available cash, even though the distributions to KMR are made in additional i-units rather than cash and we retain this cash and use it in our business.  To date, all of our available cash distributions, other than a $177.1 million distribution of cash from interim capital transactions for the second quarter of 2010 (paid in the third quarter of 2010), have been treated as distributions of cash from operations.

Allocation of Distributions from Operations.  Cash from operations for each quarter will be distributed effectively as follows:

▪ first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter;

▪ second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter;

▪ third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and

▪ fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to owners of i-units in the equivalent number of i-units, and 50% to our general partner.

156

Allocation of Distributions from Interim Capital Transactions.  Any distribution by us of available cash that would constitute cash from interim capital transactions would be distributed effectively as follows:

▪ 98% to all owners of common units and Class B units pro rata in cash and to the holders of i-units in equivalent i-units; and

▪ 2% to our general partner, until we have distributed cash from this source in respect of a common unit outstanding since our original public offering in an aggregate amount per unit equal to the initial common unit price of $5.75, as adjusted for splits.

As cash from interim capital transactions is distributed, it would be treated as if it were a repayment of the initial public offering price of the common units.  To reflect that repayment, the first three distribution target levels of cash from operations (described above) would be adjusted downward proportionately by multiplying each distribution target level amount by a fraction, the numerator of which is the unrecovered initial common unit price immediately after giving effect to that distribution and the denominator of which is the unrecovered initial common unit price immediately prior to giving effect to that distribution.  When the initial common unit price is fully recovered, then each of the first three distribution target levels will have been reduced to zero, and thereafter, all distributions of available cash from all sources will be treated as if they were cash from operations and available cash will be distributed 50% to all classes of units pro rata (with the distribution to i-units being made instead in the form of i-units), and 50% to our general partner.  With respect to the portion of our distribution of available cash for the second quarter of 2010 that was from interim capital transactions, our general partner waived this resetting of the distribution target levels.

Kinder Morgan G.P., Inc.

Kinder Morgan G.P., Inc. serves as our sole general partner.  Pursuant to our partnership agreement, 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:

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

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

As of December 31, 2010, our general partner owned 1,724,000 common units, representing approximately 0.55% of our outstanding limited partner units.  For information on distributions paid to our general partner, see Note 10 “Partners’ Capital—Income Allocation and Declared Distributions.”

Kinder Morgan, Inc.

KMI remains the sole indirect common stockholder of our general partner.  Also, as of December 31, 2010, KMI directly owned 10,852,788 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 13,113,533 KMR shares, representing an indirect ownership interest of 13,113,533 i-units.  Together, these units represented approximately 11.0% of our outstanding limited partner units.

Including both its general and limited partner interests in us, at the 2010 distribution level, KMI received approximately 47% of all quarterly distributions of available cash from us, with approximately 40% attributable to its general partner interest and the remaining 7% attributable to its limited partner interest.  These percentages were impacted due to a portion of our available cash distribution for the second quarter of 2010 being a distribution of cash from interim capital transactions, rather than a distribution of cash from operations.  For our fourth quarter 2010 distribution of available cash, KMI received approximately 50% of the total distribution, with approximately 44% attributable to its general partner interests and 6% attributable to its limited partner interests.  The actual level of dist ributions KMI will receive in the future will vary with the level of distributions to our limited partners determined in accordance with our partnership agreement.

Kinder Morgan Management, LLC

As of December 31, 2010, KMR, our general partner’s delegate, remained the sole owner of our 91,907,987 i-units.

157

Asset Acquisitions and Sales

In March 2008, our subsidiary Kinder Morgan CO2 Company, L.P. sold certain pipeline meter equipment to Cortez Pipeline Company, its 50% equity investee, for its current fair value of $5.7 million.  The meter equipment is still being employed in conjunction with our CO2 business segment.

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.  In conjunction with our acquisition of (i) certain Natural Gas Pipelines assets and partnership interests from KMI in December 1999 and December 2000; and (ii) all of the ownership interest in TransColorado Gas Transmission Company LLC from two wholly-owned subsidiaries of KMI on November 1, 2004, KMI agreed to indemnify us and our general partner with respect to approximately $733.5 million of our debt.  KMI would be obligated to perform under this indemnity only if we are unable, and/or our assets w ere insufficient to satisfy our obligations.

Operations

Natural Gas Pipelines and Products Pipelines Business Segments

KMI (or its subsidiaries) operates and maintain for us the assets comprising our Natural Gas Pipelines business segment.  KMI operates Trailblazer Pipeline Company LLC’s assets, which is part of our Natural Gas Pipelines business segment, under a long-term contract pursuant to which Trailblazer (i) incurs the costs and expenses related to KMI’s operating and maintaining the assets; and (ii) provides the funds for its own capital expenditures.  KMI does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company LLC’s assets.

The remaining assets comprising our Natural Gas Pipelines business segment, as well as our Products Pipelines business segment’s 50%-owned Cypress Pipeline (we sold a 50% ownership interest in the Cypress Pipeline on October 1, 2010, described in Note 3 “Acquisitions and Divestitures—Divestitures—Cypress Interstate Pipeline LLC”), are operated under other agreements between KMI and us.  Pursuant to the applicable underlying agreements, we pay (reimburse) KMI for the actual corporate general and administrative expenses incurred in connection with the operation of these assets.  The combined amounts paid to KMI for corporate general and administrative costs incurred, including amounts related to Trailblazer Pipeline Company LLC, were $55.6 million for 2010, $46.5 million for 2009 and $45.0 million for 2008.  We believe the amounts paid to KMI for the services it 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 also reimburse KMI for operating and maintenance costs and capital expenditures incurred with respect to our assets.

Our subsidiary Kinder Morgan NatGas Operator LLC operates the Rockies Express and the Midcontinent Express natural gas pipeline systems pursuant to two separate operating agreements.  It entered into the Rockies Express agreement in April 2008, and according to the provisions of the agreement, it is reimbursed for its costs and it receives a management fee of 1%, based on Rockies Express’ operating income, less all depreciation, depletion and amortization expenses.  In 2010 and 2009, it received management fees of $5.4 million and $4.0 million, respectively.  Kinder Morgan NatGas Operator LLC operates the Midcontinent Express pipeline system according to the provisions of an operating agreement entered into in March 2007.  It is reimbursed for its operating costs; however, it receives no spec ial management fees according to this agreement.

In addition, we purchase natural gas transportation and storage services from Natural Gas Pipeline Company of America LLC and certain affiliates, collectively referred to in this report as NGPL.  KMI owns a 20% ownership interest in NGPL and accounts for its investment under the equity method of accounting.  Pursuant to the provisions of a 15-year operating agreement that was entered into in 2008, KMI continues to operate NGPL’s assets.  For each of the years 2010, 2009 and 2008, expenses related to NGPL totaled $7.8 million, $8.8 million and $8.1 million, respectively, and we included these expense amounts within the caption “Gas purchases and other costs of sales” in our accompanying consolidated statements of income.

158

CO2 Business Segment

During 2010, Kinder Morgan Power Company, a subsidiary of KMI, operated and maintained for us the power plant we constructed at the SACROC oil field unit, located in the Permian Basin area of West Texas.  The power plant provides nearly half of SACROC’s current electricity needs.  Pursuant to the contract, Kinder Morgan Power Company incurred the costs and expenses related to operating and maintaining the power plant for the production of electrical energy at the SACROC field.  Such costs included 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.  Our subsidiary Kinder Morgan Production Company fully reimbursed Kinder Morgan Power Company 217;s expenses, including all agreed-upon labor costs.

In addition, Kinder Morgan Production Company was 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 were purchased by Kinder Morgan Power Company and invoiced monthly as provided by the contract, if not paid directly by Kinder Morgan Production Company.  The amounts paid to Kinder Morgan Power Company in 2010, 2009 and 2008 for operating and maintaining the power plant were $7.6 million, $5.4 million and $3.1 million, respectively.  Furthermore, we believe the amounts paid to Kinder Morgan Power Company for the services they provided each year fairly reflected the value of the services performed.  Our operating contract with Kinder Morgan Power C ompany expired on December 31, 2010, and effective January 1, 2011, Kinder Morgan Production Company fully operates the power plant.

Terminals Business Segment

Mr. C. Berdon Lawrence, a non-management director on the boards of our general partner and KMR, is also Chairman of the Board of Kirby Corporation.  For services in the ordinary course of Kirby Corporation’s and our Terminals segment’s businesses, Kirby Corporation received payments from our subsidiaries totaling $39,828, $18,878 and $430,835 in 2010, 2009 and 2008, respectively, and Kirby made payments, in 2008, to our subsidiaries totaling $144,300.

Subsequent Event

On February 9, 2011, we sold a marine vessel to Kirby Corporation’s subsidiary Kirby Inland Marine, L.P., and additionally, we and Kirby Inland Marine L.P. formed a joint venture named Greens Bayou Fleeting, LLC.  For more information about these transactions, see Note 3 “Acquisitions and Divestitures—Divestiture Subsequent to December 31, 2010.”

Risk Management

Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil.  We also have exposure to interest rate risk as a result of the issuance of our fixed rate debt obligations.  Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to these risks and protect our profit margins.

Our 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 18 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 our businesses.  The committee is chaired by our President and is charged with the following three responsibilities: (i) establish and review risk limits consistent with our risk tolerance philosophy; (ii) recommend to the audit committee of our general partner’s delegate any changes, modifications, or amendments to our risk management policy; and (iii) address and resolve any other high-level risk management issues.

For more information on our risk management activities see Note 13.

KM Insurance, Ltd.

KM Insurance, Ltd. is a Bermuda insurance company and wholly-owned subsidiary of KMI.  KM Insurance, Ltd. 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 and include these costs within our related party general and administrative expenses.  For each of the years 2010, 2009 and 2008, these expenses totaled $8.6 million, $8.4 million and $7.6 million, respectively.

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Derivative Counterparties

As a result of KMI’s going-private transaction in May 2007, a number of individuals and entities became significant investors in KMI, and by virtue of the size of its ownership interest in KMI, one of those investors—Goldman Sachs Capital Partners and certain of its affiliates—remains a “related party” (as that term is defined in authoritative accounting literature) to us as of December 31, 2010.  Goldman Sachs has also acted in the past, and may act in the future, as an underwriter for equity and/or debt issuances for us, and Goldman Sachs effectively owned 49% of the terminal assets we acquired from US Development Group LLC in January 2010.

In addition, we conduct energy commodity risk management activities in the ordinary course of implementing our risk management strategies in which the counterparty to certain of our derivative transactions is an affiliate of Goldman Sachs, and in conjunction with these activities, we are a party (through one of our subsidiaries engaged in the production of crude oil) to a hedging facility with J. Aron & Company/Goldman Sachs.  The hedging facility requires us to provide certain periodic information, but does not require the posting of margin.  As a result of changes in the market value of our derivative positions, we have created both amounts receivable from and payable to Goldman Sachs affiliates.

The following table summarizes the fair values of our energy commodity derivative contracts that are (i) associated with commodity price risk management activities with J. Aron & Company/Goldman Sachs; and (ii) included within “Fair value of derivative contracts” on our accompanying consolidated balance sheets as of December 31, 2010 and 2009 (in millions):

	December 31, 2010			December 31, 2009
Derivatives – asset/(liability)
Current assets	$	-		$	4.3
Noncurrent assets	$	12.7		$	18.4
Current liabilities	$	(221.4	)	$	(96.8	)
Noncurrent liabilities	$	(57.5	)	$	(190.8	)

Notes Receivable

Plantation Pipe Line Company

We have a long-term note receivable bearing interest at the rate of 4.72% per annum from Plantation Pipe Line Company, our 51.17%-owned equity investee.  The note provides for semiannual payments of principal and interest on June 30 and December 31 each year, with a final principal payment due July 20, 2011.  We received principal repayment amounts of $2.7 million in 2010.  As of December 31, 2010, the outstanding note receivable balance was $82.1 million, and we included this amount within “Accounts, notes and interest receivable, net,” on our accompanying consolidated balance sheet.  As of December 31, 2009, the note receivable balance was $84.8 million, and we included $2.6 million within “Accounts, notes and interest receivable, net” on our accompanying consolidated bala nce sheet, and the remaining outstanding balance within “Notes receivable.”

Express US Holdings LP

In conjunction with the acquisition of our 33 1/3% equity ownership interest in the Express pipeline system from KMI on August 28, 2008, we acquired a long-term investment in a C$113.6 million debt security issued by Express US Holdings LP (the obligor), the partnership that maintains ownership of the U.S. portion of the Express pipeline system.  The debenture is denominated in Canadian dollars, due in full on January 9, 2023, bears interest at the rate of 12.0% per annum, and provides for quarterly payments of interest in Canadian dollars on March 31, June 30, September 30 and December 31 each year.  As of December 31, 2010 and 2009, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was $114.2 million and $108.1 million, resp ectively, and we included these amounts within “Notes receivable” on our accompanying consolidated balance sheets.

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Other Receivables and Payables

As of December 31, 2010 and 2009, our related party receivables (other than notes receivable discussed above in “—Notes Receivable”) totaled $15.4 million and $13.8 million, respectively.  The December 31, 2010 receivables amount consisted of (i) $8.2 million included within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet; and (ii) $7.2 million of natural gas imbalance receivables included within “Other current assets.”  The $8.2 million amount primarily related to accounts and interest receivables due from (i) the Express pipeline system; (ii) NGPL; and (iii) Plantation Pipe Line Company.  Our related party natural gas imbalance receivables consisted of amounts due from NGPL.  The December 31, 2009 amount consi sted of (i) $10.7 million included within “Accounts, notes and interest receivable, net” and primarily related to receivables due from the Express pipeline system and NGPL; and (ii) $3.1 million of natural gas imbalance receivables included within “Other current assets” and consisting primarily of amounts due from NGPL.

As of December 31, 2010 and 2009, our related party payables totaled $8.8 million and $13.4 million, respectively.  The December 31, 2010 amount consisted of (i) $5.1 million included within “Accounts payable” and primarily related to amounts due to KMI; and (ii) $3.7 million of natural gas imbalance payables included within “Accrued other current liabilities” and consisting of amounts due to the Rockies Express pipeline system.  The December 31, 2009 related party payable amounts are included within “Accounts payable” on our accompanying balance sheet, and primarily consisted of amounts we owed to KMI.

Other

Generally, KMR makes all decisions relating to the management and control of our business, and in general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders.  Our general partner owns all of KMR’s voting securities and elects all of KMR’s directors.  KMI, through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our general partner, and the 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 owners of KMI.  Accordingly, certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us.

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 also 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 officers 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.

12.  Commitments and Contingent Liabilities

Leases

The table below depicts future gross minimum rental commitments under our operating leases as of December 31, 2010 (in millions):

Year	Commitment
2011	$	43.5
2012		32.1
2013		23.1
2014		17.5
2015		13.2
Thereafter		25.9
Total minimum payments	$	155.3

The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to 38 years.  We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $0.6 million.  Total lease and rental expenses were$64.4 million for 2010, $55.6 million for 2009 and $61.7 million for 2008.  The amount of capital leases included within “Property, Plant and Equipment, net” in our accompanying consolidated balance sheets as of December 31, 2010 and 2009 are not material to our consolidated balance sheets.

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Directors’ Unit Appreciation Rights Plan

On April 1, 2003, KMR’s compensation committee established our Directors’ Unit Appreciation Rights Plan.  Pursuant to this plan, and on this date of adoption, each of KMR’s then three non-employee directors was granted 7,500 common unit appreciation rights.  In addition, 10,000 common unit appreciation rights were granted to each of KMR’s then 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); however, all unexercised awards made under the plan remain outstanding.

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 issuanc e 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.

In 2008, Mr. Hultquist exercised his remaining 10,000 unit appreciation rights at an aggregate fair value of $60.32 per unit, and he received a cash amount of $123,100.  In 2009, Mr. Gaylord’s estate exercised his 17,500 unit appreciation rights at an aggregate fair value of $53.75 per unit, and it received a cash amount of $179,275 (Mr. Edward O. Gaylord served as a KMR director until his death on September 28, 2008).  As of December 31, 2010, 17,500 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 is to promote our interests and the interests of our unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with unitholders’ interests.  Further, since KMR’s success is dependent on its operation and management of our business and our resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of KMR’s sh areholders.

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 is made generally at or around the first board meeting in January of each calendar year and is effective for the entire calendar year.  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.

The elections under this plan for 2008 were made effective January 16, 2008.  The elections for 2009 were made effective January 21, 2009 by Messrs. Hultquist and Waughtal, and January 28, 2009 by Mr. Lawrence.  The elections for 2010 and 2011 were made effective January 20, 2010, and January 18, 2011, respectively.

Each annual election is evidenced by an agreement, the Common Unit Compensation Agreement, between us and each non-employee director, and this agreement contains 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 will, for no consideration, forfeit to us all common units to the extent then subject to the forfeiture res trictions.  Common units with respect to which forfeiture restrictions have lapsed 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 has 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.

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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 un it.  This cash payment is 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 16, 2008, each of KMR’s then three non-employee directors was awarded cash compensation of $160,000 for board service during 2008; however, during a plan audit it was determined that each director was inadvertently paid an additional dividend in 2007.  As a result, each director’s cash compensation for service during 2008 was adjusted downward to reflect this error.  The correction results in cash compensation awarded for 2008 in the amounts of $158,380.00 for Mr. Hultquist; $158,396.20 for Mr. Gaylord; and $157,327.00 for Mr. Waughtal.  Effective January 16, 2008, two of the three non-employee directors elected to receive certain amounts of compensation in the form of our common units and each was issued common units pursuant to the plan and its agreements (based on the $55.81 closing market price of our common units on January 16, 2008, as reported on the New York Stock Exchange).  Mr. Gaylord elected to receive compensation of $84,831.20 in the form of our common units and was issued 1,520 common units; and Mr. Waughtal elected to receive compensation of $157,272.58 in the form of our common units and was issued 2,818 common units.  All remaining cash compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal; and $158,380.00 to Mr. Hultquist) was paid to each of the non-employee directors as described above, and no other compensation was paid to the non-employee directors during 2008.

On January 21, 2009, each of KMR’s three non-employee directors (with Mr. Lawrence replacing Mr. Gaylord after Mr. Gaylord’s death) was awarded cash compensation of $160,000 for board service during 2009.  Effective January 21, 2009, Mr. Hultquist and Mr. Waughtal elected to receive the full amount of their compensation in the form of cash only.  Effective January 28, 2009, Mr. Lawrence elected to receive compensation of $159,136.00 in the form of our common units and was issued 3,200 common units.  His remaining compensation ($864.00) was paid in cash as described above.  No other compensation was paid to the non-employee directors during 2009.

On January 20, 2010, each of KMR’s three non-employee directors was awarded cash compensation of $160,000 for board service during 2010.  Effective January 20, 2010, Mr. Hultquist and Mr. Waughtal elected to receive the full amount of their compensation in the form of cash only.  Mr. Lawrence elected to receive compensation of $159,495.00 in the form of our common units and was issued 2,450 common units.  His remaining compensation ($505.00) was paid in cash as described above.  No other compensation was paid to the non-employee directors during 2010.

On January 18, 2011, each of KMR’s three non-employee directors was awarded cash compensation of $180,000 for board service during 2011.  Effective January 18, 2011, Mr. Hultquist and Mr. Waughtal elected to receive the full amount of their compensation in the form of cash only.  Mr. Lawrence elected to receive compensation of $176,963.50 in the form of our common units and was issued 2,450 common units.  His remaining compensation ($3,036.50) will be paid in cash as described above.  No other compensation will be paid to the non-employee directors during 2011.

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Contingent Debt     

Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote.  Most of these agreements are with entities that are not consolidated in our financial statements; however, we have invested in and hold equity ownership interests in these entities.

As of December 31, 2010, our contingent debt obligations with respect to these investments, as well as our obligations with respect to related letters of credit, are summarized below (dollars in millions):

Entity	Our Ownership Interest			Investment Type	Total Entity Debt			Our Contingent Share of Entity Debt		(a)
Fayetteville Express Pipeline LLC(b)		50	%	Limited Liability	$	940.0	(c)	$	470.0
Cortez Pipeline Company(d)		50	%	General Partner	$	142.4	(e)	$	87.3	(f)
Midcontinent Express Pipeline LLC(g)		50	%	Limited Liability	$	799.0	(h)	$	16.7	(i)
Nassau County, Florida Ocean Highway and Port Authority(j)		N/A		N/A		N/A		$	18.3	(k)

_________

(a)	Represents the portion of the entity’s debt that we may be responsible for if the entity cannot satisfy its obligations.
(b)	Fayetteville Express Pipeline LLC is a limited liability company and the owner of the Fayetteville Express natural gas pipeline system.  The remaining limited liability company member interest in Fayetteville Express Pipeline LLC is owned by Energy Transfer Partners, L.P.
(c)	Amount represents borrowings under a $1.1 billion, unsecured revolving bank credit facility that is due May 11, 2012.
(d)	Cortez Pipeline Company is a Texas general partnership that owns and operates a common carrier carbon dioxide pipeline system. The remaining general partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil Corporation, and Cortez Vickers Pipeline Company, an indirect subsidiary of M.E. Zuckerman Energy Investors Incorporated.
(e)	Amount consists of (i) $32.1 million of fixed rate Series D notes due May 15, 2013 (interest on the Series D notes is paid annually and based on an average interest rate of 7.14% per annum); (ii) $100.0 million of variable rate Series E notes due December 11, 2012 (interest on the Series E notes is paid quarterly and based on an interest rate of three-month LIBOR plus a spread); and (iii) $10.3 million of outstanding borrowings under a $40.0 million committed revolving bank credit facility that is also due December 11, 2012.
(f)	We are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt ($71.2 million).  In addition, as of December 31, 2010, Shell Oil Company shares our several guaranty obligations jointly and severally for $32.1 million of Cortez’s debt balance related to the Series D notes; however, we are obligated to indemnify Shell for the liabilities it incurs in connection with such guaranty.  Accordingly, as of December 31, 2010, we have a letter of credit in the amount of $16.1 million issued by JP Morgan Chase, in order to secure our indemnification obligations to Shell for 50% of the Cortez debt balance of $32.1 million related to the Series D notes. 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.
(g)	Midcontinent Express Pipeline LLC is a limited liability company and the owner of the Midcontinent Express natural gas pipeline system.  The remaining limited liability company member interests in Midcontinent Express Pipeline LLC are owned by Regency Energy Partners, L.P. and Energy Transfer Partners, L.P.
(h)	Amount consists of an aggregate carrying value of $799.0 million in fixed rate senior notes issued by Midcontinent Express Pipeline LLC in a private offering in September 2009.  All payments of principal and interest in respect of these senior notes are the sole obligation of Midcontinent Express.  Noteholders have no recourse against us or the other member owners of Midcontinent Express Pipeline LLC for any failure by Midcontinent Express to perform or comply with its obligations pursuant to the notes or the indenture.
(i)	As of December 31, 2010, Midcontinent Express had no outstanding borrowings under its $175.4 million, unsecured revolving bank credit facility that is due February 28, 2011.  However, its credit facility can be used for the issuance of letters of credit to support the operation of its pipeline system, and as of December 31, 2010, a letter of credit having a face amount of $33.3 million was issued under the credit facility by the Bank of Tokyo-Mitsubishi UFJ, Ltd.  Our contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).
(j)	Arose from our Vopak terminal acquisition in July 2001.  Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the state of Florida.
(k)	We have posted a letter of credit as security for borrowings under Adjustable Demand Revenue Bonds issued by the Nassau County, Florida Ocean Highway and Port Authority.  The bonds were issued for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida.  Our subsidiary, Nassau Terminals LLC is the operator of the marine port facilities.  The bond indenture is for 30 years and allows the bonds to remain outstanding until December 1, 2020.  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, 2010, this letter of credit had a face amount of $18.3 million.

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We also hold a 50% equity ownership interest in Rockies Express Pipeline LLC, a limited liability company and the owner of the Rockies Express natural gas pipeline system.  Subsidiaries of Sempra Energy and ConocoPhillips own the remaining member interests, and pursuant to certain guaranty agreements remaining in effect on December 31, 2009, all three member owners of Rockies Express Pipeline LLC had agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Rockies Express Pipeline LLC, borrowings under its $2.0 billion five-year, unsecured revolving bank credit facility that is due April 28, 2011.On April 8, 2010, Rockies Express Pipeline LLC amended its bank credit facility to allow for borrowings up to $200 million (a reduction from $2.0 billion), and on this same date, each of its three member owners were released from their respective debt obligations under the previous guaranty agreements.  Accordingly, we no longer have a contingent debt obligation with respect to Rockies Express Pipeline LLC.

We account for our investments in Fayetteville Express Pipeline LLC, Cortez Pipeline Company, and Midcontinent Express Pipeline LLC under the equity method of accounting.  For the year ended December 31, 2010, our share of earnings, based on our ownership percentage and before amortization of excess investment cost, if any, was $22.5 million from Cortez Pipeline Company and $30.1 million from Midcontinent Express Pipeline LLC.  We had no equity earnings from our investment in Fayetteville Express Pipeline LLC during 2010.

13.  Risk Management

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil.  We also have exposure to interest rate risk as a result of the issuance of our debt obligations.  Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks.

Energy Commodity Price Risk Management

We are exposed to risks associated with 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 primarily associated with price volatility related to (i) pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; (ii) natural gas purchases; and (iii) natural gas system use and storage.  Price changes are often caused by shifts in the supply and demand for these commodities, as well as their locations.

Our principal use of energy commodity derivative contracts is to mitigate the risk associated with unfavorable market movements in the price of energy commodities.  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.

For derivative contracts that are designated and qualify as cash flow hedges pursuant to generally accepted accounting principles, the portion of the gain or loss on the derivative contract that is effective in offsetting the variable cash flows associated with the hedged forecasted transaction is reported as a component of other comprehensive income and reclassified into earnings in the same line item associated with the forecasted transaction and in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are commodity sales).  The remaining gain or loss on the derivative contract in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion), is recognized in earnings d uring the current period.  The effectiveness of hedges using an option contract may be assessed based on changes in the option’s intrinsic value with the change in the time value of the contract being excluded from the assessment of hedge effectiveness.  Changes in the excluded component of the change in an option’s time value are included currently in earnings.  During 2010, we recognized a net gain of $5.3 million related to crude oil and natural gas hedges and resulting from both hedge ineffectiveness and amounts excluded from effectiveness testing.  During 2009, we recognized a net loss of $13.5 million from crude oil hedges that resulted from hedge ineffectiveness and amounts excluded from effectiveness testing.

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Additionally, during each of the two years ended December 31, 2010 and 2009, we reclassified losses of $188.4 million and $100.3 million, respectively, from “Accumulated other comprehensive loss” into earnings.  No material amounts were reclassified into earnings as a result of the discontinuance of cash flow hedges because it was probable that the original 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, were reclassified as a result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchase actually occurred).  The proceeds or payments resulting from the settlement of our cash flow hedges are reflected in the operating section of our statement of cash flows as changes to net income and working capital.

The “Accumulated other comprehensive loss” balance included in our Partners’ Capital was $186.4 million as of December 31, 2010, and $394.8 million as of December 31, 2009.  These totals included “Accumulated other comprehensive loss” amounts associated with energy commodity price risk management activities of $307.1 million as of December 31, 2010 and $418.2 million as of December 31, 2009.  Approximately $248.5 million of the total loss amount associated with energy commodity price risk management activities and included in our Partners’ Capital as of December 31, 2010 is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur), and as of December 31, 2010, the maximum length of time ove r which we have hedged our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2015.

As of December 31, 2010, we had entered into the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:

	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil	(23.2) million barrels
Natural gas fixed price	(19.0) billion cubic feet
Natural gas basis	(13.9) billion cubic feet
Derivatives not designated as hedging contracts
Natural gas basis	0.5 billion cubic feet

For derivative contracts that are not designated as a hedge for accounting purposes, all realized and unrealized gains and losses are recognized in the statement of income during the current period.  These types of transactions include basis spreads, basis-only positions and gas daily swap positions.  We primarily enter into these positions to economically hedge an exposure through a relationship that does not qualify for hedge accounting.  Until settlement occurs, this will result in non-cash gains or losses being reported in our operating results.

Interest Rate Risk Management

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt.  We use interest rate swap agreements to manage the interest rate risk associated with the fair value of our fixed rate borrowings and to effectively convert a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate cash flows in order to achieve our desired mix of fixed and variable rate debt.

Since the fair value of fixed rate debt varies inversely with changes in the market rate of interest, we enter into swap agreements to receive a fixed and pay a variable rate of interest in order to convert the interest expense associated with certain of our senior notes from fixed rates to variable rates, resulting in future cash flows that vary with the market rate of interest.  These swaps, therefore, hedge against changes in the fair value of our fixed rate debt that result from market interest rate changes.  For derivative contracts that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings.

As of December 31, 2010 and 2009, we had a combined notional principal amount of$4,775 million and $5,200 million, respectively, of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread.  All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of December 31, 2010, 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 January 15, 2038.

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In May 2010, we entered into three separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $400 million.  Each agreement effectively converts a portion of the interest expense associated with our 5.30% senior notes due September 15, 2020 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.  In November 2010, we terminated five of our existing fixed-to-variable swap agreements in separate transactions.  These swap agreements had a combined notional principal amount of $825 million, and we received combined proceeds of $157.6 million from the early termination of these swap agreements.

Fair Value of Derivative Contracts

The fair values of our current and non-current asset and liability derivative contracts are each reported separately as “Fair value of derivative contracts” on our accompanying consolidated balance sheets.  The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of December 31, 2010 and 2009 (in millions):

Fair Value of Derivative Contracts
		Asset derivatives				Liability derivatives
		December 31,		December 31,		December 31,			December 31,
		2010		2009		2010			2009
	Balance sheet location	Fair value		Fair value		Fair value			Fair value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Current	$	20.1	$	19.1	$	(275.9	)	$	(270.8	)
	Non-current		43.1		57.3		(103.0	)		(241.5	)
Subtotal			63.2		76.4		(378.9	)		(512.3	)
Interest rate swap agreements	Non-current		217.6		222.5		(69.2	)		(218.6	)
Total			280.8		298.9		(448.1	)		(730.9	)
Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current		3.9		1.7		(5.6	)		(1.2	)
Total			3.9		1.7		(5.6	)		(1.2	)
Total derivatives		$	284.7	$	300.6	$	(453.7	)	$	(732.1	)

____________

The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Value of interest rate swaps” on our accompanying consolidated balance sheets, which also includes any unamortized portion of proceeds received from the early termination of interest rate swap agreements.  As of December 31, 2010 and 2009, this unamortized premium totaled $456.5 million and $328.6 million, respectively, and as of December 31, 2010, the weighted average amortization period for this premium was approximately 17.1 years.

Effect of Derivative Contracts on the Income Statement

The following three tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the years ended December 31, 2010 and 2009 (in millions):

Derivatives in fair value hedging relationships	Location of gain/(loss) recognized in income on derivative	Amount of gain/(loss) recognized in income on derivative(a)					Hedged items in fair value hedging relationships	Location of gain/(loss) recognized in income on related hedged item	Amount of gain/(loss) recognized in income on related hedged items(a)
		Year Ended December 31,							Year Ended December 31,
		2010		2009					2010			2009
Interest rate swap agreements	Interest, net – income/(expense)	$	302.0	$	(598.7	)	Fixed rate debt	Interest, net – income/(expense)	$	(302.0	)	$	598.7
Total		$	302.0	$	(598.7	)	Total		$	(302.0	)	$	598.7

____________

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(a) Amounts reflect the change in the fair value of interest rate swap agreements and the change in the fair value of the associated fixed rate debt which exactly offset each other as a result of no hedge ineffectiveness.  Amounts do not reflect the impact on interest expense from the interest rate swap agreements under which we pay variable rate interest and receive fixed rate interest.  

Derivatives in cash flow hedging relationships	Amount of gain/(loss) recognized in OCI on derivative (effective portion)								Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)	Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)								Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Year Ended December 31,									Year Ended December 31,									Year Ended December 31,
	2010				2009					2010				2009					2010			2009
Energy commodity derivative contracts		$	(76.1	)		$	(458.2	)	Revenues-natural gas sales		$	8.2			$	14.9		Revenues		$	5.3		$	(13.5	)
									Revenues-product sales and other			(211.3	)			(139.2	)
									Gas purchases and other costs of sales			14.7				24.0		Gas purchases and other costs of sales			-			-
Total		$	(76.1	)		$	(458.2	)	Total		$	(188.4	)		$	(100.3	)	Total		$	5.3		$	(13.5	)

____________

Derivatives not designated as  hedging contracts	Location of gain/(loss) recognized in income on derivative	Amount of gain/(loss) recognized in income on derivative
		Year Ended December 31,
		2010		2009
Energy commodity derivative contracts	Gas purchases and other costs of sales	$	2.3	$	(4.2	)
Total		$	2.3	$	(4.2	)

Credit Risks

We have counterparty credit risk as a result of our use of financial derivative contracts.  Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies.  This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk.  These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings); (ii) collateral requirements under certain circumstances; and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty.  Based on our policies, exposure, credit and other reserves, our management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.

Our over-the-counter swaps and options are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges.  These contracts are with a number of parties, all of which have investment grade credit ratings.  While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.

The maximum potential exposure to credit losses on our derivative contracts as of December 31, 2010 was (in millions):

	Asset position
Interest rate swap agreements	$	217.6
Energy commodity derivative contracts		67.1
Gross exposure		284.7
Netting agreement impact		(58.8	)
Net exposure	$	225.9

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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, 2010, we had no outstanding letters of credit supporting our hedging activities; however, as of December 31, 2009, we had outstanding letters of credit totaling $55.0 million in support of our hedging of energy commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil.

Additionally, as of December 31, 2010, our counterparties associated with our energy commodity contract positions and over-the–counter swap agreements had margin deposits with us totaling $2.4 million, and we reported this amount within “Accrued other liabilities” in our accompanying consolidated balance sheet.  As of December 31, 2009, we had cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners totaling $15.2 million, and we reported this amount as “Restricted deposits” in our accompanying consolidated balance sheet.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring us to post additional collateral upon a decrease in our credit rating.  Based on contractual provisions as of December 31, 2010, we estimate that if our credit rating was downgraded, we would have the following additional collateral obligations (in millions):

Credit ratings downgraded (a)	Incremental obligations		Cumulative obligations(b)
One notch to BBB-/Baa3	$	-	$	-
Two notches to below BBB-/Baa3 (below investment grade)	$	65.2	$	65.2

_________

(a)	If there are split ratings among the independent credit rating agencies, most counterparties use the higher credit rating to determine our incremental collateral obligations, while the remaining use the lower credit rating.  Therefore, a two notch downgrade to below BBB-/Baa3 by one agency would not trigger the entire $65.2 million incremental obligation.
(b)	Includes current posting at current rating.

14.  Fair Value

The Codification emphasizes that fair value is a market-based measurement that should be determined based on assumptions (inputs) that market participants would use in pricing an asset or liability.  Inputs may be observable or unobservable, and valuation techniques used to measure fair value should maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Accordingly, the Codification establishes a hierarchal disclosure framework that ranks the quality and reliability of information used to determine fair values.  The hierarchy is associated with the level of pricing observability utilized in measuring fair value and defines three levels of inputs to the fair value measurement process—quoted prices are the most reliable valuation inputs, whereas model values that include i nputs based on unobservable data are the least reliable.  Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.

The three broad levels of inputs defined by the fair value hierarchy are as follows:

▪ Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;

▪ Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and

▪ Level 3 Inputs—unobservable inputs for the asset or liability.  These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).

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Fair Value of Derivative Contracts

The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; and (ii) interest rate swap agreements as of December 31, 2010 and 2009, based on the three levels established by the Codification (in millions).  The fair value measurements as of December 31, 2009 in the two tables below do not include our cash margin deposits of $15.2 million, which are reported separately as “Restricted deposits” in our accompanying consolidated balance sheet.

	Asset fair value measurements using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
As of December 31, 2010
Energy commodity derivative contracts(a)	$	67.1	$	-	$	23.5	$	43.6
Interest rate swap agreements	$	217.6	$	-	$	217.6	$	-
As of December 31, 2009
Energy commodity derivative contracts(a)	$	78.1	$	-	$	14.4	$	63.7
Interest rate swap agreements	$	222.5	$	-	$	222.5	$	-

____________

	Liability fair value measurements using
	Total			Quoted prices in active markets for identical liabilities (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
As of December 31, 2010
Energy commodity derivative contracts(b)	$	(384.5	)	$	-	$	(359.7	)	$	(24.8	)
Interest rate swap agreements	$	(69.2	)	$	-	$	(69.2	)	$	-
As of December 31, 2009
Energy commodity derivative contracts(b)	$	(513.5	)	$	-	$	(462.8	)	$	(50.7	)
Interest rate swap agreements	$	(218.6	)	$	-	$	(218.6	)	$	-

____________

(a)	Level 2 consists primarily of OTC natural gas hedges that are settled on NYMEX.  Level 3 consists primarily of natural gas options and West Texas Intermediate options.
(b)	Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on NYMEX. Level 3 consists primarily of natural gas basis swaps and West Texas Intermediate options.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the years ended December 31, 2010 and 2009 (in millions):

Significant unobservable inputs (Level 3)

	Year Ended December 31,
	2010			2009
Derivatives-net asset (liability)
Beginning of period	$	13.0		$	44.1
Realized and unrealized net gains (losses)		1.7			(48.4	)
Purchases and settlements		4.1			17.3
Transfers in (out) of Level 3		-			-
End of period	$	18.8		$	13.0
Change in unrealized net losses relating to contracts still held at end of period	$	(10.7	)	$	(42.1	)

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Fair Value of Financial Instruments

Fair value as used in the disclosure of financial instruments represents the amount at which an instrument could be exchanged in a current transaction between willing parties.  As of each reporting date, the estimated fair value of our outstanding publicly-traded debt is based upon quoted market prices, if available, and for all other debt, fair value is based upon prevailing interest rates currently available to us.  In addition, we adjust (discount) the fair value measurement of our long-term debt for the effect of credit risk.

The estimated fair value of our outstanding debt balance as of December 31, 2010 and 2009 (both short-term and long-term, but excluding the value of interest rate swaps), is disclosed below (in millions):

	December 31, 2010				December 31, 2009
	Carrying Value		Estimated fair value		Carrying Value		Estimated fair value
Total debt	$	11,539.8	$	12,443.4	$	10,592.4	$	11,265.7

15.  Reportable Segments

We divide our operations into five reportable business segments.  These segments and their principal source of revenues are as follows:

▪ Products Pipelines— the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids;

▪ Natural Gas Pipelines—the sale, transport, processing, treating, storage and gathering of natural gas;

▪ CO2—the production and sale of crude oil from fields in the Permian Basin of West Texas and the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields;

▪ Terminals—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; and

▪ Kinder Morgan Canada—the transportation of crude oil and refined products from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the United States.

We evaluate performance principally based on each segments’ earnings before depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income, and unallocable income tax expense.  Our reportable segments are strategic business units that offer different products and services, and they are based on the way our chief operating decision maker organizes the operations within our enterprise for assessing performance and allocating resources.  Each segment is managed separately because each segment involves different products and marketing strategies.

171

Financial information by segment follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Revenues
Products Pipelines
Revenues from external customers	$	883.0		$	826.6		$	815.9
Intersegment revenues		-			-			-
Natural Gas Pipelines
Revenues from external customers		4,416.5			3,806.9			8,422.0
Intersegment revenues		-			-			-
CO2
Revenues from external customers		1,245.7			1,035.7			1,133.0
Intersegment revenues		-			-			-
Terminals
Revenues from external customers		1,264.0			1,108.1			1,172.7
Intersegment revenues		1.1			0.9			0.9
Kinder Morgan Canada
Revenues from external customers		268.5			226.1			196.7
Intersegment revenues		-			-			-
Total segment revenues		8,078.8			7,004.3			11,741.2
Less: Total intersegment revenues		(1.1	)		(0.9	)		(0.9	)
Total consolidated revenues	$	8,077.7		$	7,003.4		$	11,740.3

Operating expenses(a)
Products Pipelines	$	414.6		$	269.5		$	291.0
Natural Gas Pipelines		3,750.3			3,193.0			7,804.0
CO2		308.1			271.1			391.8
Terminals		629.2			536.8			631.8
Kinder Morgan Canada		91.6			72.5			67.9
Total segment operating expenses		5,193.8			4,342.9			9,186.5
Less: Total intersegment operating expenses		(1.1	)		(0.9	)		(0.9	)
Total consolidated operating expenses	$	5,192.7		$	4,342.0		$	9,185.6

Other expense (income)
Products Pipelines	$	4.2		$	0.6		$	1.3
Natural Gas Pipelines		-			(7.8	)		(2.7	)
CO2		-			-			-
Terminals		(4.3	)		(27.6	)		2.7
Kinder Morgan Canada		-			-			-
Total segment Other expense (income)		(0.1	)		(34.8	)		1.3
Less: Discontinued operations(b)		-			-			1.3
Total consolidated Other expense (income)	$	(0.1	)	$	(34.8	)	$	2.6

Depreciation, depletion and amortization
Products Pipelines	$	100.7	$	94.1	$	89.4
Natural Gas Pipelines		124.2		93.4		68.5
CO2		452.9		487.9		385.8
Terminals		184.1		136.9		122.6
Kinder Morgan Canada		42.9		38.5		36.4
Total consol. depreciation, depletion and amortization	$	904.8	$	850.8	$	702.7

Earnings from equity investments
Products Pipelines	$	33.1		$	29.0		$	24.4
Natural Gas Pipelines		169.1			141.8			113.4
CO2		22.5			22.3			20.7
Terminals		1.7			0.7			2.7
Kinder Morgan Canada		(3.3	)		(4.1	)		(0.4	)
Total consolidated equity earnings.	$	223.1		$	189.7		$	160.8

172

	Year Ended December 31,
	2010		2009		2008
Amortization of excess cost of equity investments
Products Pipelines	$	3.4	$	3.4	$	3.3
Natural Gas Pipelines		0.4		0.4		0.4
CO2		2.0		2.0		2.0
Terminals		-		-		-
Kinder Morgan Canada		-		-		-
Total consol. amortization of excess cost of equity investments	$	5.8	$	5.8	$	5.7

Interest income
Products Pipelines	$	4.0	$	4.1	$	4.3
Natural Gas Pipelines		2.3		6.2		1.2
CO2		2.0		-		-
Terminals		-		-		-
Kinder Morgan Canada		13.2		12.0		3.9
Total segment interest income		21.5		22.3		9.4
Unallocated interest income		1.2		0.2		0.6
Total consolidated interest income	$	22.7	$	22.5	$	10.0

Other, net-income (expense)
Products Pipelines	$	12.4	$	8.3	$	(2.3	)
Natural Gas Pipelines		2.0		25.6		28.0
CO2		2.5		-		1.9
Terminals		4.7		3.7		1.7
Kinder Morgan Canada		2.6		11.9		(10.1	)
Total consolidated other, net-income (expense)	$	24.2	$	49.5	$	19.2

Income tax benefit (expense)
Products Pipelines	$	(9.2	)	$	(13.4	)	$	(3.8	)
Natural Gas Pipelines		(3.3	)		(5.7	)		(2.7	)
CO2		0.9			(4.0	)		(3.9	)
Terminals		(5.3	)		(5.2	)		(19.7	)
Kinder Morgan Canada		(7.8	)		(18.9	)		19.0
Total segment income tax benefit (expense)		(24.7	)		(47.2	)		(11.1	)
Unallocated income tax benefit (expense)		(9.9	)		(8.5	)		(9.3	)
Total consolidated income tax benefit (expense)	$	(34.6	)	$	(55.7	)	$	(20.4	)

Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(c)
Products Pipelines	$	504.5		$	584.5		$	546.2
Natural Gas Pipelines		836.3			789.6			760.6
CO2		965.5			782.9			759.9
Terminals		641.3			599.0			523.8
Kinder Morgan Canada		181.6			154.5			141.2
Total segment earnings before DD&A		3,129.2			2,910.5			2,731.7
Total segment depreciation, depletion and amortization		(904.8	)		(850.8	)		(702.7	)
Total segment amortization of excess cost of equity investments.		(5.8	)		(5.8	)		(5.7	)
General and administrative expenses		(375.2	)		(330.3	)		(297.9	)
Unallocable interest expense, net of interest income		(506.4	)		(431.3	)		(397.6	)
Unallocable income tax expense		(9.9	)		(8.5	)		(9.3	)
Total consolidated net income	$	1,327.1		$	1,283.8		$	1,318.5

173

	Year Ended December 31,
	2010		2009		2008
Capital expenditures(d)
Products Pipelines	$	144.2	$	199.8	$	221.7
Natural Gas Pipelines		135.4		372.0		946.5
CO2		372.8		341.8		542.6
Terminals		326.3		378.2		454.1
Kinder Morgan Canada		22.2		32.0		368.1
Total consolidated capital expenditures	$	1,000.9	$	1,323.8	$	2,533.0

Investments at December 31
Products Pipelines	$	215.6	$	203.7	$	202.6
Natural Gas Pipelines		3,563.3		2,542.9		654.0
CO2		9.9		11.2		13.6
Terminals		27.4		18.7		18.6
Kinder Morgan Canada		69.8		68.7		65.5
Total consolidated investments	$	3,886.0	$	2,845.2	$	954.3

Assets at December 31
Products Pipelines	$	4,369.1	$	4,299.0	$	4,183.0
Natural Gas Pipelines		8,809.7		7,772.7		5,535.9
CO2		2,141.2		2,224.5		2,339.9
Terminals		4,138.6		3,636.6		3,347.6
Kinder Morgan Canada		1,870.0		1,797.7		1,583.9
Total segment assets		21,328.6		19,730.5		16,990.3
Corporate assets(e)		532.5		531.7		895.5
Total consolidated assets	$	21,861.1	$	20,262.2	$	17,885.8

____________

(a)	Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes.
(b)	As discussed in Note 3, due to the October 2007 sale of our North System, we accounted for the North System business as a discontinued operation.  In 2008, we recorded incremental gain adjustments of $1.3 million related to our sale of the North System, and consistent with the management approach of identifying and reporting discrete financial information on operating segments, we have included this gain within our Products Pipelines business segment disclosures for 2008.  Except for this gain adjustment on our disposal of the North System, we recorded no other financial results from the operations of the North System during 2008.
(c)	Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
(d)	Sustaining capital expenditures, including our share of the sustaining capital expenditures of the following four joint ventures: Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, KinderHawk Field Services LLC and Cypress Interstate Pipeline LLC, totaled $179.2 million in 2010, $172.2 million in 2009 and $180.6 million in 2008.  Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset.
(e)	Includes cash and cash equivalents; margin and restricted deposits; unallocable interest receivable, prepaid assets and deferred charges; and risk management assets related to the fair value of interest rate swaps.

174

We do not attribute interest and debt expense to any of our reportable business segments.  For each of the years ended December 31, 2010, 2009 and 2008, we reported total consolidated interest expense of $507.6 million, $431.5 million and $398.2 million, respectively.

Our total operating revenues are derived from a wide customer base.For each of the years ended December 31, 2010, 2009 and 2008, no revenues from transactions with a single external customer amounted to 10% or more of our total consolidated revenues.

Following is geographic information regarding the revenues and long-lived assets of our business segments (in millions):

	Year Ended December 31,
	2010		2009		2008
Revenues from external customers
United States	$	7,701.7	$	6,680.5	$	11,452.0
Canada		356.5		301.9		267.0
Mexico and other(a)		19.5		21.0		21.3
Total consolidated revenues from external customers.	$	8,077.7	$	7,003.4	$	11,740.3

Long-lived assets at December 31(b)	2010		2009		2008
United States	$	16,929.5	$	15,556.6	$	13,563.2
Canada		1,908.5		1,813.6		1,547.6
Mexico and other(a)		86.4		89.1		87.8
Total consolidated long-lived assets	$	18,924.4	$	17,459.3	$	15,198.6

____________

(a)	Includes operations in Mexico and the Netherlands.
(b)	Long-lived assets exclude (i) goodwill; (ii) other intangibles, net; and (iii) long-term note receivables from related parties.

175

16.  Litigation, Environmental and Other Contingencies

Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during 2010.  This note also contains a description of any material legal proceedings that were initiated against us during 2010, and a description of any material events occurring subsequent to December 31, 2010 but before the filing of this report.

In this note, we refer to our subsidiary SFPP, L.P. as SFPP; our subsidiary Calnev Pipe Line LLC as Calnev; Chevron Products Company as Chevron; Navajo Refining Company, L.P. as Navajo; BP West Coast Products, LLC as BP; ConocoPhillips Company as ConocoPhillips; Tesoro Refining and Marketing Company as Tesoro; Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western Refining; ExxonMobil Oil Corporation as ExxonMobil; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the Airlines; our subsidiary Kinder Morgan CO2 Company, L.P. (the successor to Shell CO2 Company, Ltd.) as Kinder Morgan CO2; the United States Court of Appeals for the District of Columbia Circuit as the D.C. Circuit; the Federal Energy Regulatory Commission as the FERC; the California Public Utilities Commission as the CPUC; the United States Department of the Interior, Minerals Management Service as the MMS; the Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company) as UPRR;  the Texas Commission of Environmental Quality as the TCEQ; The Premcor Refining Group, Inc. as Premcor; Port Arthur Coker Company as PACC; our subsidiary Kinder Morgan Bulk Terminals, Inc. as KMBT; our subsidiary Kinder Morgan Liquids Terminals LLC as KMLT; Rockies Express Pipeline LLC as Rockies Express; and Plantation Pipe Line Company as Plantation.  “OR” dockets designate complaint proceedings, and “IS” dockets design ate protest proceedings.

Federal Energy Regulatory Commission Proceedings

The tariffs and rates charged by SFPP and Calnev are subject to numerous ongoing proceedings at the FERC, including the shippers' complaints and protests regarding interstate rates on the pipeline systems listed below.  These complaints and protests have been filed over numerous years beginning in 1992 through and including 2009.  In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable.  If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach up to two years prior to the filing of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward.  These proceedings tend to be protracted, with decisions of the FERC often appealed to the fed eral courts.

As to SFPP, the issues involved in these proceedings include, among others: (i) whether certain of our Pacific operations’ rates are “grandfathered” under the Energy Policy Act of 1992, and therefore deemed to be just and reasonable; (ii) whether “substantially changed circumstances” have occurred with respect to any grandfathered rates such that those rates could be challenged; (iii) whether indexed rate increases are justified; and (iv) the appropriate level of return and income tax allowance we may include in our rates.  The issues involving Calnev are similar.

SFPP

As a result of FERC’s approval in May 2010 of a settlement agreement with eleven of twelve shipper litigants, a wide range of rate challenges dating back to 1992 were resolved (Historical Cases Settlement).  The Historical Cases Settlement resolved all but two of the cases outstanding between SFPP and the eleven shippers, and SFPP does not expect any material adverse impacts from the remaining two unsettled cases with the eleven shippers.

The Historical Cases Settlement and other legal reserves related to SFPP rate litigation resulted in a $158.0 million charge to earnings in the first quarter of 2010, and in June 2010, we made settlement payments of $206.3 million to the eleven shippers.  However, because a portion of our partnership distributions for the second quarter of 2010 (which we paid in August 2010) was a distribution of cash from interim capital transactions (rather than a distribution of cash from operations) our general partner’s cash distributions for the second quarter of 2010 were reduced by $170.0 million.  We expect that our second quarter 2010 interim capital transaction distribution will allow us to resolve our remaining FERC rate cases (discussed above) and CPUC rate cases (discussed below) without impacting future distributi ons, and due to the support of our general partner, we still distributed $4.40 in distributions per unit to our limited partners for 2010. 

Furthermore, (i) our declared cash distributions for both the third and fourth quarters of 2010 contain no distributions of cash from interim capital transactions, but instead consist entirely of distributions of cash from operations; and (ii) we recognized a $14.0 million increase in expense in December 2010 associated with overall adjustments to our rate case liabilities.  For more information on our partnership distributions, see Note 10 “Partners’ Capital—Income Allocation and Declared Distributions.”

Chevron is the only shipper who was not a party to the Historical Cases Settlement.  In December 2010, an agreement in principle was reached with Chevron, and in February 2011, an uncontested settlement was filed at the FERC which the chief judge certified to the FERC.  The FERC has not yet acted on the certified settlement.  Upon approval by the FERC, the settlement will resolve the following dockets now pending only as to Chevron:

▪ FERC Docket Nos. OR92-8, et al. (West and East Line Rates)—Chevron protests of compliance filings pending with FERC and appeals pending at the D.C. Circuit;

▪ FERC Docket Nos. OR96-2, et al. (All SFPP Rates)—Chevron (as a successor-in-interest to Texaco) protests of compliance filings pending with FERC;

▪ FERC Docket No. OR02-4 (All SFPP Rates)—Chevron appeal of complaint dismissal pending at the D.C. Circuit;

▪ FERC Docket No. OR03-5 (West, East, North, and Oregon Line Rates)—Chevron exceptions to initial decision pending at FERC;

▪ FERC Docket No. OR07-4 (All SFPP Rates)—Chevron complaint held in abeyance;

▪ FERC Docket No. OR09-8 (consolidated) (2008 Index Increases)—Hearing regarding Chevron complaint held in abeyance pending settlement discussions;

▪ FERC Docket No. IS98-1 (Sepulveda Line Rates)—Chevron protests to compliance filing pending at FERC;

▪ FERC Docket No. IS05-230 (North Line Rates)—Chevron exceptions to initial decision pending at FERC;

▪ FERC Docket No. IS07-116 (Sepulveda Line Rates)—Chevron protest subject to resolution of IS98-1 proceeding;

▪ FERC Docket No. IS08-137 (West and East Line Rates)—Chevron protest subject to resolution of the OR92-8/OR96-2 proceeding;

▪ FERC Docket No. IS08-302 (2008 Index Rate Increases)—Chevron protest subject to the resolution of proceedings regarding the West, North and Sepulveda Lines; and

▪ FERC Docket No. IS09-375 (2009 Index Rate Increases)—Chevron protest subject to resolution of proceedings regarding the North, West and Sepulveda Lines.

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The following dockets, which pertain to all protesting shippers, are either pending or recently resolved, as noted below:

▪ FERC Docket No. IS08-390 (West Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, the Airlines—Status: FERC order issued on February 17, 2011.  While the order made certain findings that were adverse to SFPP, it ruled in favor of SFPP on many significant issues.  SFPP will file a rehearing request on certain adverse findings.  It is not possible to predict the outcome of the FERC review of the rehearing request or appellate review of this order; and

▪ FERC Docket No. IS09-437 (East Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero, Chevron, Western Refining, and Southwest Airlines—Status: Initial decision issued on February 10, 2011.  A FERC administrative law judge generally made findings adverse to SFPP, found that East Line rates should have been lower, and recommended that SFPP pay refunds for alleged over-collections.  SFPP will file a brief with the FERC taking exception to these and other portions of the initial decision.  The FERC will review the initial decision, and while the initial decision is inconsistent with a number of the issues ruled on in FERC’s  February 17, 2011 Order on IS08-390, it is not possible to predict the outcome of FERC or appellate review.

Calnev

▪ FERC Docket Nos. OR07-7, OR07-18, OR07-19 & OR07-22 (not consolidated) (Calnev Rates)—Complainants: Tesoro, Airlines, BP, Chevron, ConocoPhillips and Valero Marketing—Status:  Complaint amendments pending before FERC;

▪ FERC Docket No. IS09-377 (2009 Index Rate Increases)—Protestants: BP, Chevron, and Tesoro—Status:  Requests for rehearing of FERC dismissal pending before FERC;

▪ FERC Docket Nos. OR09-11/OR09-14 (not consolidated) (2007 and 2008 Page 700 Audit Request)—Complainants: BP/Tesoro—Status:  BP petition for review at D.C. Circuit dismissed, mandate issued in June 2010;

▪ FERC Docket Nos. OR09-15/OR09-20 (not consolidated) (Calnev Rates)—Complainants: Tesoro/BP—Status:  Complaints pending at FERC; and

▪ FERC Docket Nos. OR09-18/OR09-22 (not consolidated) (2009 Index Increases)—Complainants: Tesoro/BP—Status:  BP petition for review at D.C. Circuit dismissed, mandate issued in June 2010.

Trailblazer Pipeline Company LLC

On July 7, 2010, our subsidiary Trailblazer Pipeline Company LLC refunded a total of approximately $0.7 million to natural gas shippers covering the period January 1, 2010 through May 31, 2010 as part of a settlement reached with shippers to eliminate the December 1, 2009 rate filing obligation contained in its Docket No. RP03-162 rate case settlement.  As part of the agreement with shippers, Trailblazer commenced billing reduced tariff rates as of June 1, 2010 with an additional reduction in tariff rates to take effect January 1, 2011.

Kinder Morgan Interstate Gas Transmission LLC Section 5 Proceeding

On November 18, 2010, our subsidiary Kinder Morgan Interstate Gas Transmission LLC (KMIGT) was notified by the FERC of a proceeding against it pursuant to Section 5 of the Natural Gas Act.  The proceeding will set the matter for hearing and determine whether KMIGT’s current rates, which were approved by the FERC in KMIGT’s last transportation rate case settlement, remain just and reasonable.  The FERC made no findings in its order as to what would constitute just and reasonable rates or a reasonable return for KMIGT.  A proceeding under Section 5 of the Natural Gas Act is prospective in nature and any potential change in rates charged customers by KMIGT can only occur after the FERC has issued a final order.  Prior to that, an Administrative Law Judge will preside over an evid entiary hearing and make an initial decision (which the FERC has directed to be issued within 47 weeks).  The final FERC decision will be based on the record developed before the Administrative Law Judge.  We do not believe that this investigation will have a material adverse impact on us.

California Public Utilities Commission Proceedings

SFPP has previously reported ratemaking and complaint proceedings pending with the CPUC.  The ratemaking and complaint cases generally involve challenges to rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the state of California and request prospective rate adjustments and refunds with respect to tariffed and previously untariffed charges for certain pipeline transportation and related services.  These matters have been consolidated and assigned to two administrative law judges. 

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On April 6, 2010, a CPUC administrative law judge issued a proposed decision in several intrastate rate cases involving SFPP and a number of its shippers.  The proposed decision includes determinations on issues, such as SFPP’s entitlement to an income tax allowance and allocation of environmental expenses, that we believe are contrary both to CPUC policy and precedent and to established federal regulatory policies for pipelines.  Moreover, the proposed decision orders refunds relating to these issues where the underlying rates were previously deemed reasonable by the CPUC, which we believe to be contrary to California law.  Based on our review of these CPUC proceedings, we estimate that our maximum exposure is approximately $220 million in reparation and refund payments and if the determinations made in the proposed decision were applied prospectively in two pending cases this could result in approximately $30 million in annual rate reductions.

The proposed decision is advisory in nature and can be rejected, accepted or modified by the CPUC.  SFPP filed comments on May 3, 2010 outlining what it believes to be the errors in law and fact within the proposed decision, and on May 5, 2010, SFPP made oral arguments before the full CPUC.  The matter remains pending before the CPUC, which may act at any time at its scheduled bimonthly meetings.  Further procedural steps, including motions for rehearing and writ of review to California’s Court of Appeals, will be taken if warranted.  We do not expect the final resolution of this matter to have an impact on our expected distributions to our limited partners for 2011.

Carbon Dioxide Litigation

Gerald O. Bailey et al. v. Shell Oil Co. et al., Southern District of Texas Lawsuit

Kinder Morgan CO2, Kinder Morgan Energy Partners, L.P. and Cortez Pipeline Company are among the defendants in a proceeding in the federal courts for the Southern District of Texas, Gerald O. Bailey et al. v. Shell Oil Company et al. (Civil Action Nos. 05-1029 and 05-1829 in the U.S. District Court for the Southern District of Texas—consolidated by Order dated July 18, 2005).  The plaintiffs assert claims for the underpayment of royalties on carbon dioxide produced from the McElmo Dome unit, located in southwestern Colorado.  The plaintiffs assert claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary and agency duties, breach of c ontract and covenants, violation of the Colorado Unfair Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment, and open account.  Plaintiffs Gerald O. Bailey, Harry Ptasynski, and W.L. Gray & Co. also assert claims as private relators under the False Claims Act, claims on behalf of the State of Colorado and Montezuma County, Colorado, and claims for violation of federal and Colorado antitrust laws.  The plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief.  The defendants filed motions for summary judgment on all claims. 

On April 22, 2008, the federal district court granted defendants’ motions for summary judgment and ruled that plaintiffs Bailey and Ptasynski take nothing on their claims, and that the claims of Gray be dismissed with prejudice. The court entered final judgment in favor of the defendants on April 30, 2008.  The plaintiffs appealed to the United States Fifth Circuit Court of Appeals.  On June 16, 2010, the Fifth Circuit Court of Appeals affirmed the trial court’s summary judgment decision.  On October 18, 2010, the U.S. Supreme Court denied Gerald Bailey’s petition for writ of certiorari to the U.S. Supreme Court seeking further appellate review of the Fifth Circuit Court of Appeals’ decision.

CO2 Claims Arbitration

Kinder Morgan CO2 and Cortez Pipeline Company 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 underpa yment of royalties and other payments on carbon dioxide produced from the McElmo Dome unit. 

The settlement imposed certain future obligations on the defendants in the underlying litigation.  The plaintiffs in the arbitration 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 plaintiffs 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.  On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement.  On June 21, 2007, the New Mexico federal district court entered final judgment confirming the August 7, 2 006 arbitration decision.

On October 2, 2007, the plaintiffs initiated a second arbitration (CO2 Committee, Inc. v. Shell CO2 Company, Ltd., aka Kinder Morgan CO2 Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO2 and an ExxonMobil entity.  The second arbitration asserts claims similar to those asserted in the first arbitration.  A second arbitration panel has convened and a final hearing on the parties’ claims and defenses is expected to occur in 2011.

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MMS Notice of Noncompliance and Civil Penalty

On December 20, 2006, Kinder Morgan CO2 received from the MMS 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.”  This Notice, and the MMS’s position that Kinder Morgan CO2 has violated certain reporting obligations, relates to a disagreement between the MMS and Kinder Morgan CO2 concerning the approved transportation allowance to be used in valuing McElmo Dome carbon dioxide for purposes of calculating federal royalties.

The Notice of Noncompliance and Civil Penalty assessed 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 17 alleged violations) for Kinder Morgan CO2’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 stated that civil penalties would continue to accrue at the same rate until the alleged violations are corrected.

On January 3, 2007, Kinder Morgan CO2 appealed the Notice of Noncompliance and Civil Penalty to the Office of Hearings and Appeals of the Department of the Interior.

In July 2008, the parties reached a settlement in principle of the Notice of Noncompliance and Civil Penalty, subject to final approval by the MMS and the Department of the Interior.  On September 8, 2010, the United States Department of the Interior, Bureau of Ocean Energy Management, Regulation, and Enforcement (formerly known as the MMS) approved the settlement, which is now final.

MMS Orders to Report and Pay

On March 20, 2007, Kinder Morgan CO2 received an Order to Report and Pay from the MMS.  The MMS contends that Kinder Morgan CO2 over-reported transportation allowances and underpaid royalties in the amount of approximately $4.6 million for the period from January 1, 2005 through December 31, 2006 as a result of its use of the Cortez Pipeline tariff as the transportation allowance in calculating federal royalties.  The MMS claims that the Cortez Pipeline tariff is not the proper transportation allowance and that Kinder Morgan CO2 must use its “reasonable actual costs” calculated in accorda nce with certain federal product valuation regulations.

Kinder Morgan CO2 submitted a notice of appeal in response to the Order to Report and Pay, challenging the Order and appealing it to the Director of the MMS in accordance with 30 C.F.R. sec. 290.100, et seq.

In addition to the March 2007 Order to Report and Pay, the MMS issued a second Order to Report and Pay in August 2007, in which the MMS claims that Kinder Morgan CO2 over-reported transportation allowances and underpaid royalties (due to the use of the Cortez Pipeline tariff as the transportation allowance for purposes of federal royalties) in the amount of approximately $8.5 million for the period from April 2000 through December 2004.  Kinder Morgan CO2 filed its notice of appeal and statement of reasons in response to the second Order in September 2007, challenging the Order and appealing it to the Director of the MMS.

In July 2008, the parties reached a settlement in principle of the March 2007 and August 2007 Orders to Report and Pay, subject to final approval by the MMS and the Department of the Interior.  On September 8, 2010, the United States Department of the Interior, Bureau of Ocean Energy Management, Regulation, and Enforcement (formerly known as the MMS) approved the settlement, which is now final.

Colorado Severance Tax Assessment

On September 16, 2009, the Colorado Department of Revenue issued three Notices of Deficiency to Kinder Morgan CO2.  The Notices of Deficiency assessed additional state severance tax against Kinder Morgan CO2 with respect to carbon dioxide produced from the McElmo Dome unit for tax years 2005, 2006, and 2007.  The total amount of tax assessed was $5.7 million, plus interest of $1.0 million, plus penalties of $1.7 million.  Kinder Morgan CO2 protested the Notices of Deficiency and paid the tax and interest under protest.  Kinder Morgan CO2 is now awaiting the Colorado Department of Revenue’s response to the protest.

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Montezuma County, Colorado Property Tax Assessment

In November of 2009, the County Treasurer of Montezuma County, Colorado, issued to Kinder Morgan CO2, as operator of the McElmo Dome unit, retroactive tax bills for tax year 2008, in the amount of $2 million.  Of this amount, 37.2% is attributable to Kinder Morgan CO2’s interest.  The retroactive tax bills were based on the assertion that a portion of the actual value of the carbon dioxide produced from the McElmo Dome unit was omitted from the 2008 tax roll due to an alleged over statement of transportation and other expenses used to calculate the net taxable value.Kinder Morgan CO2 paid the retroactive tax bills under protest and will file petitions for refunds of the taxes paid under protest and will vigorously contest Montezuma County’s position.

Other

In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO2’s payments on carbon dioxide produced from the McElmo Dome and Bravo Dome units are currently ongoing.  These audits and inquiries involve federal agencies, the states of Colorado and New Mexico, and county taxing authorities in the state of Colorado.

Commercial Litigation Matters

Union Pacific Railroad Company Easements

SFPP and UPRR are engaged in a 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).  In February 2007, a trial began to determine the amount payable for easements on UPRR rights-of-way.  The trial is ongoing and is expected to conclude by the end of the first quarter of 2011.

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.  In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR.  SFPP appealed this decision, and in December 2008, the appellate court affirmed the decision.  In addition, UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards in determining when relocations are necessary and in completing relocations.  Each party is seeking declaratory relief wit h respect to its positions regarding the application of these standards with respect to relocations.

Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effects of the outcome of these cases on SFPP.  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.

Severstal Sparrows Point Crane Collapse

On June 4, 2008, a bridge crane owned by Severstal Sparrows Point, LLC and located in Sparrows Point, Maryland collapsed while being operated by KMBT.  According to our investigation, the collapse was caused by unexpected, sudden and extreme winds.  On June 24, 2009, Severstal filed suit against KMBT in the United States District Court for the District of Maryland, cause no. WMN 09CV1668.  Severstal alleges that KMBT was contractually obligated to replace the collapsed crane and that its employees were negligent in failing to properly secure the crane prior to the collapse.  Severstal seeks unspecified damages for value of the crane and lost profits.  KMBT denies each of Severstal’s allegations.

JR Nicholls Tug Incident

On February 10, 2010, the JR Nicholls, a tugboat operated by one of our subsidiaries, overturned and sank in the Houston Ship Channel.  Five employees were on board and four were rescued, treated and released from a local hospital.  The fifth employee died in the incident.  The U.S. Coast Guard shut down a section of the ship channel for approximately 60 hours.  Approximately 2,200 gallons of diesel fuel was released from the tugboat.  Emergency response crews deployed booms and contained the product, which is substantially cleaned up.  Salvage operations were commenced and the tugboat has been recovered.  A full investigation of the incident is underway.  Our subsidiary J.R. Nicholls LLC filed a limitations action entitle d In the Matter of the Complaint of J.R. Nicholls LLC as Owner of the M/V J.R. NICHOLLS For Exoneration From or Limitation of Liability, CA No. 4:10-CV-00449, U.S. District Court, S.D. Tex.  To date, three surviving crew members have filed claims in that action for personal injuries and emotional distress.  On September 15, 2010, our subsidiary KM Ship Channel Services LLC, agreed to pay a civil penalty of $7,500 to the United States Coast Guard for the unintentional discharge of diesel fuel which occurred when the vessel sank.

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The Premcor Refining Group, Inc. v. Kinder Morgan Energy Partners, L.P. and Kinder Morgan Petcoke, L.P.; Arbitration in Houston, Texas

On August 12, 2010, Premcor filed a demand for arbitration against us and our subsidiary Kinder Morgan Petcoke, L.P., collectively referred to as Kinder Morgan, asserting claims for breach of contract.  Kinder Morgan performs certain petroleum coke handling operations at the Port Arthur, Texas refinery that is the subject of the claim.  The arbitration is being administered by the American Arbitration Association in Dallas, Texas.  Premcor alleges that Kinder Morgan breached its contract with Premcor by failing to name Premcor as an additional insured and failing to indemnify Premcor for claims brought against Premcor by PACC.  PACC and Premcor are affiliated companies.  PACC brought its claims against Premcor in a previous separate arbitration seeking to recover damages allegedly suffere d by PACC when a pit wall of a coker unit collapsed at a refinery owned by Premcor.  PACC obtained an arbitration award against Premcor in the amount of $50.3 million, plus post-judgment interest.  Premcor is seeking to hold Kinder Morgan liable for the award.  Premcor’s claim against Kinder Morgan is based in part upon Premcor’s allegation that Kinder Morgan is responsible to the extent of Kinder Morgan’s alleged proportionate fault in causing the pit wall collapse.  Kinder Morgan denies and is vigorously defending against all claims asserted by Premcor.  The final arbitration hearing is scheduled to begin on August 29, 2011.

Employee Matters

James Lugliani vs. Kinder Morgan G.P., Inc. et al. in the Superior Court of California, Orange County

James Lugliani, a former Kinder Morgan employee, filed suit in January 2010 against various Kinder Morgan affiliates.  On behalf of himself and other similarly situated current and former employees, Mr. Lugliani claims that the Kinder Morgan defendants have violated the wage and hour provisions of the California Labor Code and Business & Professions Code by failing to provide meal and rest periods; failing to pay meal and rest period premiums; failing to pay all overtime wages due; failing to timely pay wages; failing to pay wages for vacation, holidays and other paid time off; and failing to keep proper payroll records.  We intend to vigorously defend the case.

Pipeline Integrity and Releases

From time to time, despite our best efforts, our pipelines experience leaks and ruptures.  These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death.  In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines.  Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

Pasadena Terminal Fire

On September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena, Texas liquids terminal facility.  On January 8, 2010, a civil lawsuit was filed on behalf of the People of Texas and the TCEQ for alleged violations of the Texas Clean Air Act.  The lawsuit was filed in the 53rd Judicial District Court, Travis County, Texas and is entitled State of Texas v. Kinder Morgan Liquids Terminals, case no. D1GV10000017.  Specifically, the TCEQ alleges that KMLT had an unauthorized emission event relating to the pit 3 fire at the Pasadena terminal in September 2008.  We have reached an agreement wi th the TCEQ to settle this matter for $40,000 plus $4,000 in attorneys’ fees to be paid to the state of Texas.   The settlement was finalized and entered in court on December 20, 2010.

Charlotte, North Carolina

On January 17, 2010, our subsidiary Kinder Morgan Southeast Terminal LLC’s Charlotte #2 Terminal experienced an issue with a pollution control device known as the Vapor Recovery Unit, which led to a fire and release of gasoline from the facility to adjacent property and a small creek.  There were no injuries.  We are cooperating fully with state and federal agencies on the response and remediation.

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Barstow, California

The United States Department of the Navy has alleged that historic releases of methyl tertiary-butyl ether, or MTBE, from Calnev’s Barstow terminal (i) have migrated underneath the Navy’s Marine Corps Logistics Base in Barstow; (ii) have impacted the Navy’s existing groundwater treatment system for unrelated groundwater contamination not alleged to have been caused by Calnev; and (iii) could affect the Barstow, California Marine Corps Logistic Base’s water supply system.  Although Calnev believes that it has meritorious defenses to the Navy’s claims, it is working with the Navy to agree upon an Administrative Settlement Agreement and Order on Consent for federal Comprehensive Environmental Response, Compensation and Liability Act (referred to as CERCLA) Removal Action to reimburse the Navy for $0.5 million in past response actions. 

Westridge Release, Burnaby, British Columbia

On July 24, 2007, a third-party contractor installing a sewer line for the City of Burnaby struck a crude oil pipeline segment included within our Trans Mountain pipeline system near its Westridge terminal in Burnaby, British Columbia, resulting in a release of approximately 1,400 barrels of crude oil.  The release impacted the surrounding neighborhood, several homes and nearby Burrard Inlet.  No injuries were reported.  To address the release, we initiated a comprehensive emergency response in collaboration with, among others, the City of Burnaby, the British Columbia Ministry of Environment, the National Energy Board (Canada), and the National Transportation Safety Board (Canada).  Cleanup and environmental remediation is complete, and we have received a British Columbia Ministry of Environment C ertificate of Compliance confirming complete remediation.

The National Transportation Safety Board released its investigation report on the incident on March 18, 2009.  The report confirmed that an absence of pipeline location marking in advance of excavation and inadequate communication between the contractor and our subsidiary Kinder Morgan Canada Inc., the operator of the line, were the primary causes of the accident.  No directives, penalties or actions of Kinder Morgan Canada Inc. were required as a result of the report.

Kinder Morgan Canada, Inc. commenced a lawsuit against the parties it believes were responsible for the third party strike, and a number of other parties have commenced related actions.  The parties are currently involved in structured mediation.

On July 22, 2009, the British Columbia Ministry of Environment issued regulatory charges against the third-party contractor, the engineering consultant to the sewer line project, Kinder Morgan Canada Inc., and our subsidiary Trans Mountain L.P.  The British Columbia Ministry of Environment claims that the parties charged caused the release of crude oil, and in doing so were in violation of various sections of the Environmental, Fisheries and Migratory Bird Act.  A trial has been scheduled to commence in October 2011.We are of the view that the charges have been improperly laid against us, and we intend to vigorously defend against them.

Rockies Express Pipeline LLC Indiana Construction Incident

In April 2009, Randy Gardner, an employee of Sheehan Pipeline Construction Company (a third-party contractor to Rockies Express and referred to in this note as Sheehan Construction) was fatally injured during construction activities being conducted under the supervision and control of Sheehan Construction.  The cause of the incident was investigated by Indiana OSHA, which issued a citation to Sheehan Construction.  Rockies Express was not cited in connection with the incident.

In August 2010, the estate of Mr. Gardner filed a wrongful death action against Rockies Express and several other parties in the Superior Court of Marion County, Indiana, at case number 49D111008CT036870.  The plaintiff alleges that the defendants were negligent in allegedly failing to provide a safe worksite, and seeks unspecified compensatory damages.  Rockies Express denies that it was in any way negligent or otherwise responsible for this incident, and intends to assert contractual claims for complete indemnification for any and all costs arising from this incident, including any costs related to this lawsuit, against third parties and their insurers.

General

Although no assurance can be given, we believe that we have meritorious defenses to the actions set forth in this note and, 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.

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Additionally, although it is not possible to predict the ultimate outcomes, we also believe, based on our experiences to date and the reserves we have established, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or distributions to limited partners.  As of December 31, 2010 and 2009, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $169.8 million and $220.9 million, respectively.  The reserve is primarily related to various claims from regulatory proceedings arising from our West Coast products pipeline transportation rates, and the contingent amount is based on both the circumstances of probability and reasonability of dollar estimates.   ;The overall change in the reserve from December 31, 2009 includes both a $172.0 million increase in expense in 2010 associated with various rate case liability adjustments that increased our overall rate case liability, and a $206.3 million payment in the second quarter of 2010 that reduced the liability.  We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.

Environmental Matters

The City of Los Angeles v. Kinder Morgan Liquids Terminals, LLC, Shell Oil Company, Equilon Enterprises LLC;  California Superior Court, County of Los Angeles, Case No. NC041463.

KMLT is a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles.  The lawsuit was stayed beginning in 2009 and remained stayed through the end of 2010.  A hearing was held on December 13, 2010 to hear the City’s motion to remove the litigation stay.   At the hearing, the judge denied the motion to lift the stay without prejudice. A full litigation stay is in effect until the next case management conference set for June 13, 2011. During the stay, the parties deemed responsible by the local regulatory agency have worked with that agency concerning the scope of the required cleanup and are now starting a sampling and testing program at the site. The local regulatory agency issued specific cleanup goals in early 2010, and two of those parties, including KMLT, have appealed those cleanup goals to the state agency.

Plaintiff’s Third Amended Complaint alleges that future environmental cleanup costs at the former terminal will exceed $10 million, and that the plaintiff’s past damages exceed $2 million.  No trial date has yet been set.

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

On April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New Jersey, Gloucester County.  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 later owned by Support Terminals and Pacific Atlantic Terminals, LLC.  The terminal is now owned by Plains Products, and it too is a party to the lawsuit.

The complaint seeks any and all damages related to remediating all environmental contamination 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.  The parties engaged in court ordered mediation in 2008 through 2009, which did not result in settlement.  The trial judge has issued a Case Management Order and the parties are actively engaged in discovery.

On June 25, 2007, the New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint against ExxonMobil Corporation and KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro terminal.  The complaint was filed in Gloucester County, New Jersey.  Both ExxonMobil and KMLT filed third party complaints against Support Terminals/Plains seeking to bring Support Terminals/Plains into the case.  Support Terminals/Plains filed motions to dismiss the third party complaints, which were denied.  Support Terminals/Plains is now joined in the case, and it f iled an Answer denying all claims.  The court has consolidated the two cases.  All private parties and the state participated in two mediation conferences in 2010.

In December 2010, KMLT and Plains Products entered into an agreement in principle with the New Jersey Department of Environmental Protection for settlement of the state’s alleged natural resource damages claim. Currently, a Consent Judgment is being finalized subject to public notice and comment and court approval. The tentative natural resource damage settlement includes a monetary award of $1.1 million and a series of remediation and restoration activities at the terminal site.  KMLT and Plains Products have joint responsibility for this settlement.  We anticipate a final Consent Judgment during second quarter 2011. The settlement with the state does not resolve the original complaint brought by Exxon Mobil. There is no trial date set.

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Mission Valley Terminal Lawsuit

In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and MTBE impacted soils and groundwater beneath the City’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility.  The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL.  On September 26, 2007, we removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB.  The City disclosed in discovery that it is seeking approximately $170 million in damages for alleged lost value/lost prof it from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property.  Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased their claim for damages to approximately $365 million.

According to the Court’s most recent Case Management Order of January 6, 2011, the parties must complete all fact discovery by June 24, 2011 and all expert witness discovery by August 29, 2011. A mandatory settlement conference is set for July 6, 2011 and the trial is now set for March 13, 2012. We have been and will continue to aggressively defend this action.   This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. We continue to be in compliance with this agency order as we conduct an extensive remediation effort at the City’s stadium property site.

Kinder Morgan, EPA Section 114 Information Request

On January 8, 2010, Kinder Morgan Inc., on behalf of Natural Gas Pipeline Company of America LLC, Horizon Pipeline Company and Rockies Express Pipeline LLC, received a Clean Air Act Section 114 information request from the U.S. Environmental Protection Agency, Region V.  This information request requires that the three affiliated companies provide the EPA with air permit and various other information related to their natural gas pipeline compressor station operations in Illinois, Indiana, and Ohio.  The affiliated companies have responded to the request and believe the relevant natural gas compressor station operations are in substantial compliance with applicable air quality laws and regulations.

Other Environmental

We are subject to environmental cleanup and enforcement actions from time to time.  In particular, the CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs.  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 ther e 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 under the terms of authority of those laws, 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 alleged violations of environmental and safety regulations.  As we receive notices of non-compliance, we negotiate and settle these matters.  We do not believe that these alleged violations will have a material adverse effect 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.  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 Releases” above for additional information with respect to ruptures and leaks from our pipelines.

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General

Although it is not possible to predict the ultimate outcomes, we believe that the 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, and changing circumstances could cause these matters to have a material adverse impact.  As of December 31, 2010, we have accrued an environmental reserve of $74.7 million, and we believe the establishment of this environmental reserve is adequate such that the resolution of pending environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations.  In addition, as of December 31, 2010, we have recorded a receivable of $8.6 million for expected cost recoveries that have been deemed probable.  As of December 31, 2009, our environmental reserve totaled $81.1 million and our estimated receivable for environmental cost recoveries totaled $4.3 million.  Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.

Other

We are a defendant in various lawsuits arising from the day-to-day operations of our businesses.  Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, 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.

17.  Regulatory Matters

The tariffs we charge for transportation on our interstate common carrier pipelines are subject to rate regulation by 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, 2010 , 2009 and 2008, the application of the indexing methodology did not significantly affect tariff rates on our interstate petroleum products pipelines.

Below is a brief description of our ongoing regulatory matters, including any material developments that occurred during 2010.

Natural Gas Pipeline Expansion Filings

Rockies Express Pipeline LLC  Meeker to Cheyenne Expansion Project

Pursuant to certain rights exercised by EnCana Gas Marketing USA as a result of its foundation shipper status on the former Entrega Gas Pipeline LLC facilities (now part of the Rockies Express Pipeline), Rockies Express Pipeline LLC requested authorization to construct and operate certain facilities that will comprise its Meeker, Colorado to Cheyenne Hub expansion project.  The proposed expansion would add natural gas compression at its Big Hole compressor station located in Moffat County, Colorado, and its Arlington compressor station located in Carbon County, Wyoming.  Furthermore, the additional compression would permit the transportation of an additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) the Wamsutter Hub eastward to the Cheyenne Hub located in Weld County, Colorado.

By FERC order issued July 16, 2009, Rockies Express Pipeline LLC was granted authorization to construct and operate this project, and it commenced construction on August 4, 2009.  The additional compression at the Big Hole compressor station was made available as of December 9, 2009, and the additional compression at the Arlington compressor station was made available as of October 5, 2010.  The expansion is fully contracted.  The total FERC authorized cost for the proposed project was approximately $78 million; however, total costs for the project were approximately $50.5 million.

Kinder Morgan Interstate Gas Transmission Pipeline - Huntsman 2009 Expansion Project

Our subsidiary Kinder Morgan Interstate Gas Transmission LLC (KMIGT) filed an application with the FERC for authorization to construct and operate certain storage facilities necessary to increase the storage capability of the existing Huntsman Storage Facility, located near Sidney, Nebraska.  KMIGT also requested approval of new incremental rates for the project facilities under its currently effective Cheyenne Market Center Service Rate Schedule CMC-2.  By FERC order issued September 30, 2009, KMIGT was granted authorization to construct and operate the project, and construction of the project commenced on October 12, 2009.  KMIGT received FERC approval to commence service on the expanded storage project effective February 1, 2010, and KMIGT placed all remaining facilities into service on August 13, 2010.&# 160; Total costs for the project were approximately $10.1 million, significantly under the original budget.

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Kinder Morgan Interstate Gas Transmission Pipeline – Franklin to Hastings Expansion Project

KMIGT has filed a prior notice request to expand and replace certain mainline pipeline facilities to create up to 10,000 dekatherms per day of firm transportation capacity  to serve an ethanol plant located near Aurora, Nebraska.  The estimated cost of the proposed facilities is $18.6 million.  On September 24, 2010 Seminole Energy Services, LLC filed a protest to the construction of this project, and the protest was subsequently denied by the FERC in an order issued October 15, 2010.  KMIGT is proceeding with the construction of this project which is expected to be completed in early spring 2011.

Fayetteville Express Pipeline LLC – Docket No.CP09-433-000

In January 2011, construction was fully completed on the previously announced Fayetteville Express Pipeline project.  The Fayetteville Express Pipeline is owned by Fayetteville Express Pipeline LLC, a 50/50 joint venture between us and Energy Transfer Partners, L.P.  The Fayetteville Express Pipeline is a 187-mile, 42-inch diameter natural gas pipeline that begins in Conway County, Arkansas, continues eastward through White County, Arkansas, and terminates at an interconnection with Trunkline Gas Company’s pipeline in Panola County, Mississippi.  The pipeline will have an initial capacity of two billion cubic feet per day, and has currently secured binding commitments for approximately ten years totaling 1.85 billion cubic feet per day of capacity.

On December 17, 2009, the FERC approved the pipeline’s certificate application authorizing pipeline construction, and initial construction on the project began in January 2010.  The pipeline began interim transportation service on October 12, 2010, and began firm contract transportation for all shippers on January 1, 2011.  Our current estimate of total construction costs on the project is slightly less than $1.0 billion (versus the original budget of $1.3 billion).

Products Pipelines and Natural Gas Pipelines Regulatory Proceedings

For information on our pipeline regulatory proceedings, see Note 16 “Litigation, Environmental and Other Contingencies—Federal Energy Regulatory Commission Proceedings” and “—California Public Utilities Commission Proceedings.”

18.  Recent Accounting Pronouncements

Accounting Standards Updates

In December 2009, the FASB issued Accounting Standards Update No. 2009-16, “Accounting for Transfers of Financial Assets” and Accounting Standards Update No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities.”  ASU No. 2009-16 amended the Codification’s “Transfers and Servicing” Topic to include the provisions included within the FASB’s previous Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets—an amendment of FASB Statement No. 140,” issued June 12, 2009.  ASU No. 2009-17 amended the Codification’s “Consolidations” Topic to include the provisions included within the FASB’s previous SFAS No. 167, “Amendments to FASB I nterpretation No. 46(R),” also issued June 12, 2009.  These two Updates changed the way entities must account for securitizations and special-purpose entities.  ASU No. 2009-16 requires more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transferred financial assets.  ASU No. 2009-17 changes how a company determines whether an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated.  For us, both Updates were effective January 1, 2010; however, the adoption of these Updates did not have any impact on our consolidated financial statements.

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In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Improving Disclosures about Fair Value Measurements.”  This ASU requires both the gross presentation of activity within the Level 3 fair value measurement roll forward and the details of transfers in and out of Levels 1 and 2 fair value measurements.  It also clarifies certain disclosure requirements on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques.  For us, this ASU was effective January 1, 2010 (except for the Level 3 roll forward which was effective for us January 1, 2011); however, because this ASU pertains to disclosure requirements only, the adoption of this ASU did not have a material impact on our consolidated financial statements.  Furthermore, during each of the years ended December 31, 2010 and 2009, we made no transfers in and out of Level 1, Level 2, or Level 3 of the fair value hierarchy.

In July 2010, the FASB issued Accounting Standards Update No. 2010-20, “Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses.”  ASU No. 2010-20 requires companies that hold financing receivables, which include loans, lease receivables, and the other long-term receivables to provide more information in their disclosures about the credit quality of their financing receivables and the credit reserves held against them.  On December 31, 2010, we adopted all amendments that require disclosures as of the end of a reporting period, and on January 1, 2011, we adopted all amendments that require disclosures about activity that occurs during a reporting period (the remainder of this ASU).  The adoption of this ASU did not have a material impact on our consolidat ed financial statements.

19.  Quarterly Financial Data (Unaudited)

	Operating Revenues		Operating Income		Net Income		Limited Partners’  Net Income (Loss) per Unit
	(In millions, except per unit amounts)
2010
First Quarter(a)	$	2,129.6	$	287.9	$	227.4	$	(0.08	)
Second Quarter		1,961.5		443.6		365.1		0.88
Third Quarter		2,060.0		407.3		322.4		0.17
Fourth Quarter		1,926.6		466.3		412.2		0.42
2009
First Quarter	$	1,786.5	$	340.0	$	266.8	$	0.15
Second Quarter		1,645.3		372.0		328.6		0.33
Third Quarter		1,660.7		406.7		363.7		0.43
Fourth Quarter		1,910.9		396.4		324.7		0.26

____________

(a) First quarter 2010 includes a $158.0 million increase in expense associated with rate case liability adjustments.  

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20.  Supplemental Information on Oil and Gas Producing Activities (Unaudited)

Operating Statistics

Operating statistics from our oil and gas producing activities for each of the years 2010, 2009 and 2008 are shown in the following table:

Results of Operations for Oil and Gas Producing Activities – Unit Prices and Costs

	Year Ended December 31,
	2010		2009		2008
Consolidated Companies(a)
Production costs per barrel of oil equivalent(b)(c)(d)	$	12.58	$	11.44	$	15.70
Crude oil production (MBbl/d)		35.5		37.4		36.2
SACROC crude oil production (MBbl/d)		24.3		25.1		23.3
Yates crude oil production (MBbl/d)		10.7		11.8		12.3
Natural gas liquids production (MBbl/d)(d)		5.8		5.4		4.8
Natural gas liquids production from gas plants(MBbl/d)(e)		4.2		4.0		3.5
Total natural gas liquids production(MBbl/d)		10.0		9.4		8.3
SACROC natural gas liquids production (MBbl/d)(d)		5.5		5.3		4.6
Yates natural gas liquids production (MBbl/d)(d)		0.2		0.1		0.2
Natural gas production (MMcf/d)(d)(f)		1.4		0.9		1.4
Natural gas production from gas plants(MMcf/d)(e)(f)		1.9		0.7		0.2
Total natural gas production(MMcf/d)(f)		3.3		1.6		1.6
Yates natural gas production (MMcf/d)(d)(f)		1.3		0.8		1.3
Average sales prices including hedge gains/losses:
Crude oil price per Bbl(g)	$	59.96	$	49.55	$	49.42
Natural gas liquids price per Bbl(g)	$	50.34	$	37.70	$	63.48
Natural gas price per Mcf(h)	$	4.08	$	3.45	$	7.73
Total natural gas liquids price per Bbl(e)	$	51.03	$	37.96	$	63.00
Total natural gas price per Mcf(e)	$	4.10	$	3.53	$	7.63
Average sales prices excluding hedge gains/losses:
Crude oil price per Bbl(g)	$	76.93	$	59.03	$	97.70
Natural gas liquids price per Bbl(g)	$	50.34	$	37.70	$	63.48
Natural gas price per Mcf(h)	$	4.08	$	3.45	$	7.73

____________

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Computed using production costs, excluding transportation costs, as defined by the SEC.  Natural gas volumes were converted to barrels of oil equivalent using a conversion factor of six mcf of natural gas to one barrel of oil.
(c)	Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, and general and administrative expenses directly related to oil and gas producing activities.
(d)	Includes only production attributable to leasehold ownership.
(e)	Includes production attributable to our ownership in processing plants and third party processing agreements.
(f)	Excludes natural gas production used as fuel.
(g)	Hedge gains/losses for crude oil and natural gas liquids are included with crude oil.
(h)	Natural gas sales were not hedged.

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The following three tables provide supplemental information on oil and gas producing activities, including (i) capitalized costs related to oil and gas producing activities; (ii) costs incurred for the acquisition of oil and gas producing properties and for exploration and development activities; and (iii) the results of operations from oil and gas producing activities.

Our capitalized costs consisted of the following (in millions):

Capitalized Costs Related to Oil and Gas Producing Activities

	As of December 31,
	2010			2009			2008
Consolidated Companies(a)
Wells and equipment, facilities and other	$	2,676.8		$	2,428.6		$	2,106.9
Leasehold		352.3			352.6			348.9
Total proved oil and gas properties		3,029.1			2,781.2			2,455.8
Unproved property(b)		88.3			10.2			-
Accumulated depreciation and depletion		(1,901.0	)		(1,501.1	)		(1,064.3	)
Net capitalized costs	$	1,216.4		$	1,290.3		$	1,391.5

____________

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.  Includes capitalized asset retirement costs and associated accumulated depreciation.
(b)	The unproved amounts consist of capitalized costs related to the Katz Strawn Unit, which is in the initial stages of the carbon dioxide floding operation.

For each of the years 2010, 2009 and 2008, our costs incurred for property acquisition, exploration and development were as follows (in millions):

Costs Incurred in Exploration, Property Acquisitions and Development

	Year Ended December 31,
	2010			2009			2008
Consolidated Companies(a)
Property acquisitions - proved oil and gas properties		$	-		$	5.3		$	-
Development			326.0			330.3			495.2

____________

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.  During 2010, we spent $78.2 million on unproved properties development costs related to the Katz Strawn Unit, which is in the initial stages of the carbon dioxide flooding operation.  No exploration costs were incurred for the periods reported.  

Our results of operations from oil and gas producing activities for each of the years 2010, 2009 and 2008 are shown in the following table (in millions):

Results of Operations for Oil and Gas Producing Activities

	Year Ended December 31,
	2010		2009		2008
Consolidated Companies(a)
Revenues(b)	$	903.2	$	767.0	$	785.5
Expenses:
Production costs(c)		229.5		188.8		308.4
Other operating expenses(d)		62.7		53.3		99.0
Depreciation, depletion and amortization expenses		406.3		441.4		342.2
Total expenses		698.5		683.5		749.6
Results of operations for oil and gas producing activities	$	204.7	$	83.5	$	35.9

____________

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(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Revenues include losses attributable to our hedging contracts of $219.9 million, $129.5 million and $693.3 million for the years ended December 31, 2010, 2009 and 2008, respectively.
(c)	The decrease in operating expenses in 2009 compared to 2008 was primarily due to (i) lower prices charged by the industry’s material and service providers (for items such as outside services, maintenance, and well workover services), which impacted rig costs, other materials and services, and capital and exploratory costs; (ii) lower fuel and utility rates; and (iii) the successful renewal of lower priced service and supply contracts negotiated since the end of 2008.
(d)	Consists primarily of carbon dioxide expense.

Supplemental information is also provided for the following three items (i) estimated quantities of proved oil and gas reserves; (ii) the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and (iii) a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

The technical persons responsible for preparing the reserves estimates presented in this Note meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.  They are independent petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our oil and gas properties; and we do not employ them on a contingent basis.  Our employee who is primarily responsible for overseeing Netherland, Sewell and Associate, Inc.’s preparation of the reserves estimates is a registered Professional Engineer in the states of Texas and Kansas with a Doctorate of Engineering from the University of  Kans as.  He is a member of the Society of Petroleum Engineers and has over 25 years of professional engineering experience.

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.

Furthermore, our management is responsible for establishing and maintaining adequate internal control over financial reporting, which includes the estimation of our oil and gas reserves.  We maintain internal controls and guidance to ensure the reliability of our crude oil, natural gas liquids and natural gas reserves estimations, as follows:

▪ no employee’s compensation is tied to the amount of recorded reserves;

▪ we follow comprehensive SEC compliant internal policies to determine and report proved reserves, and our reserve estimates are made by experienced oil and gas reservoir engineers or under their direct supervision;

▪ we review our reported proved reserves at each year-end, and at each year-end, our CO2 business segment managers and our Vice President (President, CO2) reviews all significant reserves changes and all new proved developed and undeveloped reserves additions; and

▪ our CO2 business segment reports independently of our four remaining reportable business segments.

For more information on our controls and procedures, see Item 9A “Controls and Procedures—Management’s Report on Internal Control Over Financial Reporting” included in our Annual Report on Form 10-K for the year ended December 31, 2010.

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, current prices and costs calculated as of the date the estimate is made.  Beginning in 2009, pricing is applied based upon the twelve month unweighted arithmetic average of the first day of the month price for the year.  For prior years, pricing was based on the price as of year end.  Future development and production costs are determined based upon actual cost at year-end.  Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through exist ing 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.

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As of December 31, 2008, we had 53.4 million barrels of crude oil and 4.3 million barrels of natural gas liquids classified as proved developed reserves.  Also as of year end 2008, we had 25.2 million barrels of crude oil and 2.6 million barrels of natural gas liquids classified as proved undeveloped reserves.

During 2009 production from the fields totaled 13.7 million barrels of oil and 2.0 million barrels of natural gas liquids.  In addition, we incurred $330.3 million in capital costs which resulted in the development of 7.4 million barrels of oil and 0.4 million barrels of natural gas liquids and their transfer from the proved undeveloped category.  These reclassifications reflect the transfer of 29.2% of crude oil and 13.7% of natural gas liquids from the proved undeveloped reserves reported as of December 31, 2008 to the proved developed classification of reserves reported as of December 31, 2009.

Also during 2009, previous estimates of proved undeveloped reserves were revised upwards by 15.9 million barrels of crude oil and 1.1 million barrels of natural gas liquids.  These revisions were due primarily to utilizing a higher prescribed oil price basis for year end 2009 ($57.65 per barrel) than year end 2008 ($41.00 per barrel).  The higher oil price basis resulted in 75 patterns being added to our SACROC carbon dioxide flood project; also, the SACROC carbon dioxide flood project life was extended from 2014 to 2018.  These revisions to our previous estimates, as well as the transfer of proved undeveloped reserves to the proved developed category, as discussed above, resulted in the percentage of proved undeveloped reserves increasing from 32.4% at year end 2008 to 42.6% at year end 2009.

After giving effect to production, revisions to previous estimates and minor purchases of reserves in place, during 2009 total proved reserves of crude oil increased by 2.2 million barrels and total proved reserves of natural gas liquids decreased by 0.9 million barrels.  As of December 31, 2009, we had 47.0 million barrels of crude oil and 2.7 million barrels of natural gas liquids classified as proved developed reserves.  Also as of year end 2009, we had 33.8 million barrels of crude oil and 3.2 million barrels of natural gas liquids classified as proved undeveloped reserves.  Total proved reserves as of December 31, 2009 were 80.8 million barrels of oil and 5.9 million barrels of natural gas liquids.

During 2010, production from the fields totaled 13.0 million barrels of crude oil and 2.1 million barrels of natural gas liquids.  In addition, we incurred $248.0 million in capital costs which resulted in the development of 10.0 million barrels of crude oil and 1.3 million barrels of natural gas liquids and their transfer from the proved undeveloped category to the proved developed category.  These reclassifications reflect the transfer of 29.6% of crude oil and 39.9% of natural gas liquids from the proved undeveloped reserves reported as of December 31, 2009 to the proved developed classification of reserves reported as of December 31, 2010.

Also during 2010, previous estimates of proved developed reserves were revised upwards by 12.3 million barrels of crude oil and 0.4 million barrels of natural gas liquids, and proved undeveloped reserves were revised upward by 4.0 million barrels of crude oil and 0.7 million barrels of natural gas liquids.  Almost 90 percent of the revisions were associated with our third party oil and gas consultants revising the methodology used to estimate reserves for our Yates Field Unit in order to take greater account of the reservoir mechanisms associated with carbon dioxide injection, for which there are now seven years of history.  The revised methodology used to forecast the Yates Field Unit future performance utilizes a volume balance that is based on a correlation of historical production to observed oil saturations and reserv oir volume factors during the life of the Yates Field Unit, with emphasis on the period from 1996 through 2010.  A portion of these revisions were attributed to utilizing a higher prescribed oil price basis to calculate reserves ($75.96 per barrel for year end 2010 versus $57.65 per barrel for year end 2009).

These revisions to our previous estimates, as well as the transfer of proved undeveloped reservers to the proved developed category as discussed above, resulted in the percentage of proved undeveloped reserves decreasing from 42.6% at year end 2009 to 33.9% at year end 2010.  After giving effect to production and revisions to previous estimates during 2010, total proved reserves of crude oil increased by 3.3 million barrels and total proved reserves of natural gas liquids decreased by 1.1 million barrels.

  As of December 31, 2010, we had 56.4 million barrels of crude oil and 2.2 million barrels of natural gas liquids classified as proved developed reserves.  Also, as of year end 2010, we had 27.8 million barrels of crude oil and 2.6 million barrels of natural gas liquids classified as proved undeveloped reserves.  Total proved reserves as of December 31, 2010, were 84.2 million barrels of crude oil and 4.9 million barrels of natural gas liquids.  We currently expect that the proved undeveloped reserves we report as of December 31, 2010 will be developed within the next five years.

During 2010, we filed estimates of our oil and gas reserves for the year 2009 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 and gas reserves reported on Form EIA-23 and those reported in this Note exceeds 5%.

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The following Reserve Quantity Information table discloses estimates, as of December 31, 2010, 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 current prices and costs, as discussed above, and the estimates of reserves and future revenues in this Note conform to the guidelines of the U.S. Securities and Exchange Commission (SEC).

Reserve Quantity Information

	Consolidated Companies(a)
	Crude Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)(b)
Proved developed and undeveloped reserves:
As of December 31, 2007		121,355			11,112			1,078
Revisions of previous estimates(c)		(29,536	)		(2,490	)		695
Production		(13,240	)		(1,762	)		(499	)
As of December 31, 2008		78,579			6,860			1,274
Revisions of previous estimates(d)		15,900			1,018			(293	)
Production		(13,688	)		(1,995	)		(298	)
Purchases of reserves in place		53			37			15
As of December 31, 2009		80,844			5,920			698
Revisions of previous estimates(e)		16,294			1,059			2,923
Production		(12,962	)		(2,116	)		(523	)
As of December 31, 2010		84,176			4,863			3,098

Proved developed reserves:
As of December 31, 2008	53,346	4,308	1,274
As of December 31, 2009	47,058	2,665	698
As of December 31, 2010	56,423	2,221	3,098

Proved undeveloped reserves:
As of December 31, 2008	25,233	2,552	-
As of December 31, 2009	33,786	3,255	-
As of December 31, 2010	27,753	2,642	-

____________

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees fahrenheit.
(c)	Predominantly due to lower product prices used to determine reserve volumes.
(d)	Predominantly due to higher product prices resulting in an expanded economic carbon dioxide project area.
(e)	Predominantly due to higher product prices used to determine reserve volumes and the change in methodology discussed above.

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 the “Extractive Activities—Oil and Gas” Topic of the Codification.  The assumptions that underly the computation of the standardized measure of discounted cash flows, presented in the table below, may be summarized as follows:

▪ the standardized measure includes our estimate of proved crude oil, natural gas liquids and natural gas reserves and projected future production volumes based upon year-end economic conditions;

▪ for 2010 and 2009, pricing is applied based upon the 12 month unweighted arithmetic average of the first day of the month price for the year, and for 2008, was based upon the price as of the end of the year;

▪ future development and production costs are determined based upon actual cost at year-end;

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▪ the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and

▪ a discount factor of 10% per year is applied annually to the future net cash flows.

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

Standardized Measure of Discounted Future Net Cash Flows From

Proved Oil and Gas Reserves

	As of December 31,
	2010			2009			2008
Consolidated Companies(a)
Future cash inflows from production	$	6,665.8		$	4,898.0		$	3,498.0
Future production costs		(2,387.9	)		(1,951.5	)		(1,671.6	)
Future development costs(b)		(1,433.7	)		(1,179.7	)		(910.3	)
Undiscounted future net cash flows		2,844.2			1,766.8			916.1
10% annual discount		(946.6	)		(503.5	)		(257.7	)
Standardized measure of discounted future net cash flows	$	1,897.6		$	1,263.3		$	658.4

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(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Includes abandonment costs.

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

	As of December 31,
	2010			2009			2008
Consolidated Companies(a)
Present value as of January 1	$	1,263.3		$	658.4		$	4,078.4
Changes during the year:
Revenues less production and other costs(b)		(828.2	)		(652.7	)		(1,012.4	)
Net changes in prices, production and other costs(b)		890.0			915.7			(3,076.9	)
Development costs incurred		248.0			330.3			495.2
Net changes in future development costs		(296.6	)		(445.4	)		231.1
Purchases of reserves in place		-			-			-
Revisions of previous quantity estimates(c)		494.2			391.1			(417.1	)
Accretion of discount		126.9			65.9			392.9
Timing differences and other		-			-			(32.8	)
Net change for the year		634.3			604.9			(3,420.0	)
Present value as of December 31	$	1,897.6		$	1,263.3		$	658.4

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(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Excludes the effect of losses attributable to our hedging contracts of $219.9 million, $129.5 million and $639.3 million for the years ended December 31, 2010, 2009 and 2008, respectively.
(c)	2010 revisions were primarily due to higher product prices used to determine reserve volumes and the change in methodology discussed above.  2009 revisions were primarily due to higher product prices resulting in an expanded economic carbon dioxide project area.  2008 revisions were predominately due to lower product prices used to determine reserve volumes.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

KINDER MORGAN ENERGY PARTNERS, L.P.

Registrant (a Delaware Limited Partnership)

By: KINDER MORGAN G.P., INC.,

Its sole General Partner

By: KINDER MORGAN MANAGEMENT, LLC, the Delegate of Kinder Morgan G.P., Inc.

By: /s/ KIMBERLY A. DANG

Kimberly A. Dang,

Vice President and Chief Financial Officer

(principal financial and accounting officer)

Date: February 22, 2011