UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

F O R M 10‑Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June~~September 30, 2012

[ ] 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 incorporation or organization)		(I.R.S. Employer Identification No.)

500 Dallas Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

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

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

Indicate by check mark whether the registrant 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 (§232.405 of this chapter) 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] (Do not check if a smaller reporting company) Smaller reporting company [ ]

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

The Registrant had ~~240,140,446~~246,381,091 common units outstanding as of ~~July 27,~~October 29, 2012.

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES TABLE OF CONTENTS

		Page Number
	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	3
	Consolidated Statements of Income - Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2012 and 2011	3
	Consolidated Statements of Comprehensive Income - Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2012 and 2011	4
	Consolidated Balance Sheets – ~~June~~September 30, 2012 and December 31, 2011	5
	Consolidated Statements of Cash Flows – ~~Six~~Nine Months Ended ~~June~~September 30, 2012 and 2011	6
	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3338
	General and Basis of Presentation	3338
	Critical Accounting Policies and Estimates	3439
	Results of Operations	3439
	Financial Condition	4956
	Recent Accounting Pronouncements	5562
	Information Regarding Forward-Looking Statements	5563

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5563

Item 4.	Controls and Procedures	5563

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	5764

Item 1A.	Risk Factors	5764

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5764

Item 3.	Defaults Upon Senior Securities	5764

Item 4.	Mine Safety Disclosures	5764

Item 5.	Other Information	5864

Item 6.	Exhibits	5865

	Signature	5967

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions Except Per Unit Amounts) (Unaudited)	KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions Except Per Unit Amounts) (Unaudited)												KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions Except Per Unit Amounts) (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Revenues
Natural gas sales	$	497		$	847		$	1,081		$	1,650		$	675		$	925		$	1,756		$	2,575
Services	737			712			1,498			1,453			989			737			2,585			2,190
Product sales and other	618			379			1,121			752			669			449			1,791			1,201
Total Revenues	1,852			1,938			3,700			3,855			2,333			2,111			6,132			5,966

Operating Costs, Expenses and Other
Gas purchases and other costs of sales	624			843			1,204			1,636			828			914			2,036			2,550
Operations and maintenance	336			468			642			764			429			399			1,094			1,163
Depreciation, depletion and amortization	248			223			487			438			292			247			796			685
General and administrative	98			98			205			287			131			100			379			387
Taxes, other than income taxes	51			50			101			96			63			37			169			133
Other expense (income)	(20		)	(14		)	(20		)	(14		)	(8		)	(1		)	(28		)	(15		)
Total Operating Costs, Expenses and Other	1,337			1,668			2,619			3,207			1,735			1,696			4,446			4,903

Operating Income	515			270			1,081			648			598			415			1,686			1,063

Other Income (Expense)
Earnings from equity investments	67			56			132			103			100			52			225			155
Amortization of excess cost of equity investments	(2		)	(2		)	(4		)	(3		)	(1		)	(2		)	(5		)	(5		)
Interest expense	(142		)	(130		)	(282		)	(262		)	(184		)	(134		)	(480		)	(396		)
Interest income	5			6			10			10			8			6			19			16
Loss on remeasurement of previously held equity interest in KinderHawk to fair value (Note 2)													—			(167		)	—			(167		)
Other, net	9			7			10			8			4			3			14			11
Total Other Income (Expense)	(63		)	(63		)	(134		)	(144		)	(73		)	(242		)	(227		)	(386		)

Income from Continuing Operations Before Income Taxes	452			207			947			504			525			173			1,459			677

Income Tax (Expense) Benefit	(14		)	(15		)	(29		)	(21		)	(11		)	(12		)	(40		)	(33		)

Income from Continuing Operations	438			192			918			483			514			161			1,419			644

Discontinued Operations (Note 2)
Income from operations of FTC Natural Gas Pipelines disposal group	48			40			98			90			47			55			145			145
Loss on remeasurement of FTC Natural Gas Pipelines disposal group to fair value	(327		)	—			(649		)	—
Loss from costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value													(178		)	—			(827		)	—
Income (Loss) from Discontinued Operations	(279		)	40			(551		)	90			(131		)	55			(682		)	145

Net Income	159			232			367			573			383			216			737			789

Net Income Attributable to Noncontrolling Interests	(6		)	(2		)	(8		)	(5		)	(4		)	(1		)	(12		)	(6		)

Net Income Attributable to Kinder Morgan Energy Partners, L.P.	$	153		$	230		$	359		$	568		$	379		$	215		$	725		$	783

Calculation of Limited Partners’ Interest in Net Income (Loss)
Calculation of Limited Partners’ Interest in Net Loss
Attributable to Kinder Morgan Energy Partners, L.P.:
Income from Continuing Operations	$	429		$	191		$	904		$	479		$	509		$	161		$	1,400		$	640
Less: General Partner’s Interest	(336		)	(292		)	(657		)	(572		)
Less: Pre-acquisition income from operations of drop-down asset group allocated to General Partner (Note 2)													(36		)	—			(23		)	—
Less: General Partner’s remaining Interest													(367		)	(298		)	(1,024		)	(870		)
Limited Partners’ Interest	93			(101		)	247			(93		)	106			(137		)	353			(230		)
Add: Limited Partners’ Interest in Discontinued Operations	(274		)	39			(540		)	88			(128		)	54			(668		)	142
Limited Partners’ Interest in Net Loss	$	(181	)	$	(62	)	$	(293	)	$	(5	)	$	(22	)	$	(83	)	$	(315	)	$	(88	)

Limited Partners’ Net Income (Loss) per Unit:
Income (Loss) from Continuing Operations	$	0.27		$	(0.31	)	$	0.73		$	(0.29	)	$	0.30		$	(0.41	)	$	1.02		$	(0.71	)
Income (Loss) from Discontinued Operations	(0.80		)	0.12			(1.59		)	0.27			(0.36		)	0.16			(1.93		)	0.44
Net Loss	$	(0.53	)	$	(0.19	)	$	(0.86	)	$	(0.02	)	$	(0.06	)	$	(0.25	)	$	(0.91	)	$	(0.27	)

Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income (Loss) per Unit	342			321			340			319			356			331			345			323

Per Unit Cash Distribution Declared	$	1.23		$	1.15		$	2.43		$	2.29		$	1.26		$	1.16		$	3.69		$	3.45

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

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In Millions) (Unaudited)	KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In Millions) (Unaudited)												KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In Millions) (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Net Income	$	159		$	232		$	367		$	573		$	383		$	216		$	737		$	789

Other Comprehensive Income (Loss):
Change in fair value of derivatives utilized for hedging purposes	303			165			189			(98		)	(90		)	387			99			289
Reclassification of change in fair value of derivatives to net income	(11		)	87			20			140			(10		)	49			10			189
Foreign currency translation adjustments	(40		)	10			(2		)	61			70			(163		)	68			(102		)
Adjustments to pension and other postretirement benefit plan liabilities, net of tax	—			—			(1		)	(13		)	—			—			—			(13		)
Total Other Comprehensive Income	252			262			206			90
Total Other Comprehensive Income (Loss)													(30		)	273			177			363

Comprehensive Income	411			494			573			663			353			489			914			1,152
Comprehensive Income Attributable to Noncontrolling Interests	(9		)	(4		)	(10		)	(5		)	(4		)	(5		)	(14		)	(10		)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.	$	402		$	490		$	563		$	658		$	349		$	484		$	900		$	1,142

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

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions)	KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions)				KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions)

	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
ASSETS	(Unaudited)				(Unaudited)
Current assets
Cash and cash equivalents	$	522	$	409	$	532	$	409
Restricted deposits					6		—
Accounts, notes and interest receivable, net	822		884		956		884
Inventories	186		110		241		110
Gas in underground storage	45		62		56		62
Fair value of derivative contracts	113		72		59		72
Assets held for sale	1,938		—		1,859		—
Other current assets	51		39		59		39
Total Current assets	3,677		1,576		3,768		1,576

Property, plant and equipment, net	15,130		15,596		19,326		15,596
Investments	2,087		3,346		3,070		3,346
Notes receivable	163		165		168		165
Goodwill	1,351		1,436		4,605		1,436
Other intangibles, net	1,112		1,152		1,115		1,152
Fair value of derivative contracts	710		632		705		632
Deferred charges and other assets	184		200		836		200
Total Assets	$	24,414	$	24,103	$	33,593	$	24,103
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	979	$	1,638	$	2,697	$	1,638
Cash book overdrafts	27		21		63		21
Accounts payable	682		706		849		706
Accrued interest	260		259		149		259
Accrued taxes	77		38		140		38
Deferred revenues	96		100		97		100
Fair value of derivative contracts	31		121		41		121
Accrued other current liabilities	329		236		526		236
Total Current liabilities	2,481		3,119		4,562		3,119

Long-term liabilities and deferred credits
Long-term debt
Outstanding	12,154		11,159		15,217		11,183
Debt fair value adjustments	1,136		1,079		1,530		1,055
Total Long-term debt	13,290		12,238		16,747		12,238
Deferred income taxes	256		250		262		250
Fair value of derivative contracts	6		39		15		39
Other long-term liabilities and deferred credits	814		853		950		853
Total Long-term liabilities and deferred credits	14,366		13,380		17,974		13,380

Total Liabilities	16,847		16,499		22,536		16,499
Commitments and contingencies (Notes 3 and 9)
Commitments and contingencies (Notes 4 and 10)
Partners’ Capital
Common units	4,170		4,347		4,360		4,347
Class B units	24		42		18		42
i-units	2,772		2,857		3,492		2,857
General partner	282		259		2,856		259
Accumulated other comprehensive income	207		3		178		3
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital	7,455		7,508		10,904		7,508
Noncontrolling interests	112		96		153		96
Total Partners’ Capital	7,567		7,604		11,057		7,604
Total Liabilities and Partners’ Capital	$	24,414	$	24,103	$	33,593	$	24,103
The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)	KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)						KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)

	Six Months Ended June 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Cash Flows From Operating Activities
Net Income	$	367		$	573		$	737		$	789
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on remeasurement of FTC Natural Gas Pipelines disposal group to fair value (Note 2)	649			—
Depreciation, depletion and amortization	494			451			803			705
Amortization of excess cost of equity investments	4			3			5			5
Noncash compensation expense allocated from parent (Note 8)	—			90
Loss from costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value (Note 2)							827			—
Loss on remeasurement of previously held interest in Kinderhawk to fair value (Note 2)							—			167
Noncash compensation expense allocated from parent (Note 9)							—			90
Earnings from equity investments	(174		)	(141		)	(289		)	(214		)
Distributions from equity investments	159			136			277			201
Proceeds from termination of interest rate swap agreements	53			—			53			73
Changes in components of working capital:
Accounts receivable	55			55			(40		)	28
Inventories	(90		)	12			(98		)	9
Other current assets	(6		)	(71		)	13			(2		)
Accounts payable	(25		)	15			41			(9		)
Cash book overdrafts	6			(13		)	42			9
Accrued interest	1			4			(138		)	(143		)
Accrued taxes	44			19			74			47
Accrued liabilities	66			(10		)	49			(2		)
Rate reparations, refunds and other litigation reserve adjustments	(54		)	102			(42		)	161
Other, net	(45		)	14			—			70
Net Cash Provided by Operating Activities	1,504			1,239			2,314			1,984

Cash Flows From Investing Activities
Payment to KMI for drop-down asset group, net of cash acquired (Note 2)							(3,482		)	—
Acquisitions of assets and investments	(30		)	(110		)	(72		)	(945		)
Repayments from related party	—			1			42			29
Capital expenditures	(777		)	(535		)	(1,273		)	(838		)
Sale or casualty of property, plant and equipment, and other net assets net of removal costs	15			17			36			29
(Investments in) Net proceeds from margin and restricted deposits	(1		)	49			(16		)	56
Contributions to equity investments	(86		)	(60		)	(155		)	(297		)
Distributions from equity investments in excess of cumulative earnings	86			121			120			165
Refined products, natural gas liquids and transmix line-fill	(21		)	—			14			3
Other, net							—			1
Net Cash Used in Investing Activities	(814		)	(517		)	(4,786		)	(1,797		)

Cash Flows From Financing Activities
Issuance of debt	3,438			3,515			8,378			6,356
Payment of debt	(3,093		)	(3,641		)	(5,074		)	(5,538		)
Debt issue costs	(5		)	(8		)	(16		)	(17		)
Proceeds from issuance of i-units							727			—
Proceeds from issuance of common units	277			706			387			813
Contributions from noncontrolling interests	17			13			40			15
Distributions to partners and noncontrolling interests:
Common units	(551		)	(499		)	(847		)	(762		)
Class B units	(13		)	(12		)	(19		)	(18		)
General Partner	(630		)	(562		)	(970		)	(859		)
Noncontrolling interests	(15		)	(13		)	(23		)	(20		)
Net Cash Used in Financing Activities	(575		)	(501		)
Other, net							(1		)	—
Net Cash Provided by (Used in) Financing Activities							2,582			(30		)

Effect of Exchange Rate Changes on Cash and Cash Equivalents	(2		)	3			13			(15		)

Net increase in Cash and Cash Equivalents	113			224			123			142
Cash and Cash Equivalents, beginning of period	409			129			409			129
Cash and Cash Equivalents, end of period	$	522		$	353		$	532		$	271

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

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (In Millions) (Unaudited)	KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (In Millions) (Unaudited)				KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (In Millions) (Unaudited)

	Six Months Ended June 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Noncash Investing and Financing Activities
Net assets acquired by the transfer of the drop-down asset group					$	6,371	$	—
Assets acquired or liabilities settled by the issuance of common units	$	296	$	24	$	686	$	24
Assets acquired by the assumption or incurrence of liabilities	$	—	$	10	$	—	$	180
Contribution of net assets to investments	$	—	$	8	$	—	$	8
Sale of investment ownership interest in exchange for note	$	—	$	4	$	—	$	4

Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	277	$	261	$	586	$	510
Cash paid during the period for income taxes	$	11	$	10	$	16	$	9

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

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

Kinder Morgan Energy Partners, L.P. is a leading pipeline transportation and energy storage company in North America, and 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 an interest in or operate approximately ~~29,000~~53,000 miles of pipelines and 180 terminals, and conduct our business through five reportable business segments (described further in Note 7)8). Our pipelines transport natural gas, refined petroleum products, crude oil, carbon dioxide and other products, and our terminals store petroleum products and chemicals, and handle such products as ethanol, coal, petroleum coke and steel. We are also the leading producer and transporter of carbon dioxide, commonly called CO₂, for enhanced oil recovery projects in North America. Our general partner is owned by Kinder Morgan, Inc., as discussed below.

Kinder Morgan, 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 our general partner, Kinder Morgan G.P., Inc., a Delaware corporation; however, in July 2007, our general partner issued and sold to a third party 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.

On February 29, 2012, Kinder Morgan Kansas, Inc., a Kansas corporation, merged with and into its parent, Kinder Morgan Holdco DE Inc., a Delaware corporation and a wholly-owned subsidiary of KMI. Immediately following this merger, Kinder Morgan Holdco DE Inc. (the surviving legal entity from the merger) then merged with and into its parent KMI. KMI’s common stock trades on the New York Stock Exchange under the symbol “KMI.” As of ~~June~~September 30, 2012, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary Kinder Morgan Management, LLC (discussed following), an approximate ~~12.2%~~13% interest in us.

On ~~October 16, 2011,~~May 25, 2012, KMI ~~and El Paso Corporation (EP) announced a definitive agreement whereby KMI would acquire~~acquired all of the outstanding shares of El Paso Corporation (referred to as EP in this report) in a transaction that ~~would create~~created one of the largest energy companies in the United States. ~~On March 2, 2012,~~ ~~100%~~ ~~of KMI’s shareholders that voted approved the proposed EP acquisition, and on March 9, 2012, more than~~ ~~95%~~ ~~of EP shareholders that voted approved the acquisition. The transaction was effective May 25, 2012.~~

On March 15, 2012, KMI announced that it had reached an agreement with the U.S. Federal Trade Commission (FTC) to divest certain of our assets in order to receive regulatory approval for its proposed EP acquisition. Subject to final FTC approval, KMI agreed to sell our (i) Kinder Morgan Interstate Gas Transmission natural gas pipeline system; (ii) Trailblazer natural gas pipeline system; (iii) Casper and Douglas natural gas processing operations; and (iv) 50% equity investment in the Rockies Express natural gas pipeline system. In this report, we refer to this combined group of assets as our FTC Natural Gas Pipelines disposal group.

Prior to KMI’s announcement, we included ~~each of~~ the assets we are required to sell pursuant to the FTC's order in our Natural Gas Pipelines business segment. Because this combined group of assets, including our equity investment in Rockies Express, has its own operations and cash flows, we now report this FTC Natural Gas Pipelines disposal group as a business held for sale.

We expect to complete the sale of our FTC Natural Gas Pipelines disposal group in the third quarter of 2012. Furthermore, we expect KMI to offer to sell (drop-down) all of the Tennessee Gas Pipeline system and a 50% ownership interest in the El Paso Natural Gas pipeline system to us in order to replace the assets that we will divest, and we expect that these drop-downs will also occur in the third quarter ofNovember 2012. For more information about this planned divestiture, see both “—Basis of Presentation” below and Note 2.2 "Acquisitions and Discontinued Operations—FTC Natural Gas Pipelines Disposal Group - Discontinued Operations."

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Kinder Morgan Management, LLC

Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company. 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

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manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. KMR’s shares representing limited liability company interests trade on the New York Stock Exchange under the symbol “KMR.”

More information about the entities referred to above and the delegation of control agreement is contained in our Annual Report on Form 10-K for the year ended December 31, 2011 and in our Current Report on Form 8-K filed May 1, 2012. In this report, we refer to our Annual Report on Form 10-K for the year ended December 31, 2011 as our 2011 Form 10-K.

Basis of Presentation

We have prepared our accompanying unaudited consolidated financial statements under the rules and regulations of the United States Securities and Exchange Commission. These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America and referred to in this report as the Codification. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with the Codification. We believe, however, that our disclosures are adequate to make the information presented not misleading.

Our accompanying consolidated financial statements reflect normal adjustments, and also recurring adjustments that are, in the opinion of our management, necessary for a fair statement of our financial results for the interim periods, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

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 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 financial statements are consolidated into the consolidated financial statements of KMI; however, except for the related party transactions described in Note 89 “Related Party Transactions—Asset Acquisitions,” 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 determination 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.

Following KMI’s March 15, 2012 announcement of its intention to sell the assets that comprise our FTC Natural Gas Pipelines disposal group (described above in “—Kinder Morgan, Inc. and Kinder Morgan G.P., Inc.”), we accounted for the disposal group as discontinued operations in accordance with the provisions of the “Presentation of Financial Statements—Discontinued Operations” Topic of the Codification. Accordingly, we (i) reclassified and excluded the FTC Natural Gas Pipelines disposal group’s results of operations from our results of continuing operations and reported the disposal group’s results of operations separately as “Income from operations of FTC Natural Gas Pipelines disposal group” within the discontinued operations section of our accompanying consolidated statements of income for all periods presented; (ii) separately reported a “Loss onfrom costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value” within the discontinued operations section of our accompanying consolidated statements of income for the three and ~~six~~nine months ended ~~June~~September 30, 2012; and (iii) reclassified and reported the disposal group’s combined assets ~~separately as~~within “Assets held for sale” in our accompanying consolidated balance sheet as of ~~June~~September 30, 2012.

Because the disposal group’s combined liabilities were not material to our consolidated balance sheet, we included the disposal group’s liabilities

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within “Accrued other current liabilities” in our accompanying consolidated balance sheet as of ~~June~~September 30, 2012. In addition, we did not elect to present separately the operating, investing and financing cash flows related to the disposal group in our accompanying consolidated statements of cash flows. For more information about the discontinued operations of our FTC Natural Gas Pipelines disposal group, see Note 2.2 "Acquisitions and Discontinued

~~We evaluate goodwill for impairment on May 31~~

Table 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)Contents

Operations—FTC Natural Gas ~~Pipelines; (iv) CO~~₂; (v) Terminals; and (vi) Kinder Morgan Canada. There were no impairment charges resulting from our May 31, 2012 impairment testing, and no event indicating an impairment has occurred subsequent to that date.Pipelines Disposal Group - Discontinued Operations."

Limited Partners’ Net Income (Loss) per Unit

We compute Limited Partners’ Net Income (Loss) per Unit by dividing our limited partners’ interest in net income (loss) by the weighted average number of units outstanding during the period. The overall computation, presentation, and disclosure requirements for our Limited Partners’ Net Income (Loss) per Unit are made in accordance with the “Earnings per Share” Topic of the Codification.

2. Acquisitions and Discontinued Operations

~~Acquisitions~~El Paso Midstream Investment Company, LLC

Effective June 1, 2012, we acquired from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates, referred to as KKR) a 50% ownership interest in El Paso Midstream Investment Company, LLC, a joint venture that owns (i) the Altamont natural gas gathering, processing and treating assets located in the Uinta Basin in Utah; and (ii) the Camino Real natural gas and oil gathering system located in the Eagle Ford shale formation in South Texas. We acquired our equity interest for an aggregate consideration of $289 million in common units (we issued 3,792,461 common units and determined each unit's value based on the $76.23 closing market price of the common units on the New York Stock Exchange on the June 4, 2012 issuance date). A subsidiary of KMI owns the remaining 50% interest in the joint venture.

We account for our investment under the equity method of accounting, and 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. As of ~~June~~September 30, 2012, our net equity investment in the joint venture totaled $~~290~~301 million and is included within “Investments” on our accompanying consolidated balance sheet.

August 2012 KMI Asset Drop-Down

Effective August 1, 2012, we acquired the full ownership interest in the Tennessee Gas natural gas pipeline system and a 50% ownership interest in the El Paso Natural Gas pipeline system from KMI for an aggregate consideration of approximately $6.2 billion. In this report, we refer to this acquisition of assets from KMI as the drop-down transaction; the combined group of assets acquired from KMI as the drop-down asset group; the Tennessee Gas natural gas pipeline system or Tennessee Gas Pipeline L.L.C. as TGP, and the El Paso Natural Gas pipeline system or El Paso Natural Gas Pipeline LLC as EPNG.

We purchased the drop-down asset group from KMI in order to replace the cash flows associated with the FTC Natural Gas Pipelines disposal group that we will divest. Our consideration to KMI consisted of (i) $3.5 billion in cash; (ii) 4,667,575 common units (valued at $0.4 billion based on the $81.52 closing market price of the common units on the New York Stock Exchange on the August 13, 2012 issuance date); and (iii) $2.3 billion in assumed debt (consisting of the combined carrying value of 100% of TGP's debt borrowings and 50% of EPNG's debt borrowings as of August 1, 2012, excluding any debt fair value adjustments). The terms of the drop-down transaction were approved on behalf of KMI by the independent members of its board of directors and on our behalf by the audit committees and the boards of directors of both our general partner and KMR, in its capacity as the delegate of our general partner, following the receipt by the independent directors of KMI and the audit committees of our general partner and KMR of separate fairness opinions from different independent financial advisors.

KMI acquired the drop-down asset group as part of its acquisition of EP on May 25, 2012 (discussed above in Note 1). Pursuant to current accounting principles in conformity with the Codification, KMI accounted for its acquisition of the drop-down asset group under the purchase accounting method, and we accounted for the drop-down transaction as a transfer of net assets between entities under common control. Accordingly, we prepared our consolidated financial statements and the related financial information contained in this report to reflect the transfer of net assets from KMI to us as if such transfer had taken place on May 25, 2012. Specifically, we (i) recognized the acquired assets and assumed liabilities at KMI's carrying value as of its acquisition date, May 25, 2012 (including all of KMI's purchase accounting adjustments); (ii) recognized any difference between our purchase price and the carrying value of the net assets we

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acquired as an adjustment to our Partners' Capital (specifically, as an adjustment to our general partner's capital interests); and (iii) retrospectively adjusted our consolidated financial statements, for any date after KMI's May 25, 2012 acquisition of EP, to reflect our results on a consolidated combined basis including the results of the drop-down asset group as of or at the beginning of the respective period.

Additionally, because KMI both controls us and consolidates our financial statements into its consolidated financial statements as a result of its ownership of our general partner, we fully allocated the earnings of the drop-down asset group for the period beginning May 25, 2012 and ending August 1, 2012 to our general partner and we reported this amount separately as “Pre-acquisition income from operations of drop-down asset group allocated to General Partner" within the Calculation of Limited Partners' Interest in Net Loss section of our accompanying consolidated statements of income for the three and nine months ended September 30, 2012. For all periods beginning after our acquisition date of August 1, 2012, we allocated our earnings (including the earnings from the drop-down asset group) to all of our partners according to our partnership agreements. For more information on the changes to our Partners' Capital related to the drop-down transaction, see Note 5 "Partners' Capital—Changes in Partners' Capital."

TGP is a 13,900 mile pipeline system with a transport design capacity of approximately 7.5 billion cubic feet per day of natural gas. It transports natural gas from Louisiana, the Gulf of Mexico and south Texas to the northeastern United States, including the metropolitan areas of New York City and Boston. EPNG is a 10,200 mile pipeline system with a design capacity of approximately 5.6 billion cubic feet per day of natural gas. It transports natural gas from the San Juan, Permian and Anadarko basins to California, other western states, Texas and northern Mexico. Combined, the two pipeline systems have more than 200 billion cubic feet of working natural gas storage capacity.

The drop-down asset group is included in our Natural Gas Pipelines reportable business segment. We account for our 100% ownership interest in TGP under the consolidation method and we account for our 50% investment in EPNG under the equity method of accounting. As of September 30, 2012, our net equity investment in EPNG totaled $870 million and is included within “Investments” on our accompanying consolidated balance sheet.

Pro Forma Information

The following summarized unaudited pro forma consolidated income statement information for the nine months ended September 30, 2012 and 2011, assumes that the drop-down transaction had occurred as of January 1, 2011. We have prepared these unaudited pro forma financial results for comparative purposes only. These unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed the drop-down transaction as of January 1, 2011 or the results that will be attained in the future. Amounts presented below are in millions, except for the per unit amounts:



	Pro Forma Nine Months Ended September 30,
	2012			2011
	(Unaudited)
Revenues	$	6,549		$	6,640
Income from Continuing Operations	$	1,396		$	844
Income (Loss) from Discontinued Operations	$	(682	)	$	145
Net Income	$	714		$	989
Net Income Attributable to Noncontrolling Interests	$	(12	)	$	(8	)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.	$	702		$	981

Limited Partners’ Net Income (Loss) per Unit:
Income (Loss) from Continuing Operations	$	0.82		$	(0.19	)
Income (Loss) from Discontinued Operations	(1.89		)	0.43
Net Income (Loss)	$	(1.07	)	$	0.24

FTC Natural Gas Pipelines Disposal Group – Discontinued Operations

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As described above in Note 1 “General—Basis of Presentation,” in March 2012, we began accounting for our FTC Natural Gas Pipelines disposal group as discontinued operations. We had previously remeasured the disposal group in the first ~~quarter~~half of 2012 to reflect our initial assessment of its fair value as a result of the FTC mandated sale ~~requirement. Based~~requirement, and based on additional information gained in the sale process ~~we have recognized an additional adjustment in~~during the current quarter, ~~for~~we recognized additional loss amounts from fair value remeasurement and sales liability adjustments. For the nine months ended September 30, 2012, we recognized a combined $~~649~~827 million non-cash ~~loss. We~~loss from both remeasurement and estimated costs to sell, and we reported this loss amount separately as “Loss onfrom costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value” within the discontinued operations section of our accompanying consolidated statement of income for the ~~six~~nine months ended ~~June~~September 30, 2012.

We also reclassified the fair value of the disposal group’s assets ~~as “held~~and included this fair value amount within “Assets held for sale” ~~assets~~ in our accompanying consolidated balance sheet as of ~~June~~September 30, 2012 (because the disposal ~~group’s~~group's combined liabilities were not material to our consolidated balance sheet as of ~~June 30, 2012~~,this date, we included the disposal group’s liabilities within “Accrued other current ~~liabilities”~~liabilities.”). Our “Assets held for sale” are primarily comprised of property, plant and equipment, and our investment in the Rockies Express natural gas pipeline system.

Summarized financial information for the disposal group is as follows (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Operating revenues	$	71		$	83		$	204		$	241
Operating expenses	(45		)	(42		)	(116		)	(136		)
Depreciation and amortization	—			(7		)	(7		)	(20		)
Other expense	(1		)	—			(1		)	—
Earnings from equity investments	22			21			64			59
Interest income and Other, net	—			1			1			2
Income tax (expense) benefit	—			(1		)	—			(1		)
Earnings from discontinued operations	$	47		$	55		$	145		$	145

KinderHawk Field Services LLC

Effective July 1, 2011, we acquired from Petrohawk Energy Corporation the remaining 50% equity ownership interest in KinderHawk Field Services LLC (KinderHawk) that we did not already own. Following our acquisition of the remaining ownership interest, we changed our method of accounting from the equity method to full consolidation, and due to us acquiring a controlling financial interest in KinderHawk, we remeasured our previous 50% equity investment in KinderHawk to its fair value. We recognized a $167 million non-cash loss as a result of this remeasurement, and we reported this loss separately within the “Other Income (Expense)” section in our accompanying consolidated statements of income for the three and nine months ended September 30, 2011. For additional information regarding our July 2011 KinderHawk acquisition, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

3. Goodwill

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, but combined with Products Pipelines for presentation in the table below); (iii) Natural Gas Pipelines; (iv) CO₂; (v) Terminals; and (vi) Kinder Morgan Canada. There were no impairment charges resulting from our May 31, 2012 impairment test, and no event indicating an impairment has occurred subsequent to that date.

Changes in the gross amounts of our goodwill and accumulated impairment losses for the nine months ended

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September 30, 2012 are summarized as follows (in millions):

Three Months Ended
June 30, Six Months Ended
June 30,
2012 2011 2012 2011
Operating revenues $ 62
$ 82
$ 133
$ 158
Operating expenses (34 ) (56 ) (71 ) (94 )
Depreciation and amortization —
(6 ) (7 ) (13 )
Earnings from equity investments 20
20
42
38
Interest income and Other, net —
—
1
1
Earnings from discontinued operations $ 48
$ 40
$ 98
$ 90



	Products Pipelines		Natural Gas Pipelines			CO₂		Terminals		Kinder Morgan Canada			Total
Historical Goodwill	$	263	$	557		$	46	$	326	$	621		$	1,813
Accumulated impairment losses(a)	—		—			—		—		(377		)	(377		)
Balance as of December 31, 2011	263		557			46		326		244			1,436
Acquisitions(b)	—		3,246			—		—		—			3,246
Disposals(c)	—		(85		)	—		—		—			(85		)
Currency translation adjustments	—		—			—		—		8			8
Balance as of September 30, 2012	$	263	$	3,718		$	46	$	326	$	252		$	4,605

__________

(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 U.S. 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 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.


(b)	Acquisition amount relates to our August 1, 2012 acquisition of the drop-down asset group from KMI as discussed in Note 2.

(c)

Amount represents reclassification of FTC Natural Gas Pipelines disposal group’s goodwill to “Assets held for sale.” Since our FTC Natural Gas Pipelines disposal group represents a significant portion of our Natural Gas Pipelines business segment, we allocated the goodwill of the segment based on the relative fair value of the portion being disposed of and the portion of the segment remaining.

3.4. Debt

The following table summarizes the net carrying value of our outstanding debt, excluding our debt fair value adjustments, as of ~~June~~September 30, 2012 and December 31, 2011 (in millions):


	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Current portion of debt(a)	$	979	$	1,638	$	2,697	$	1,638
Long-term portion of debt	12,154		11,159		15,217		11,183
Net carrying value of debt(b)	$	13,133	$	12,797	$	17,914	$	12,821

__________


(a)	As of ~~June~~September 30, 2012 and December 31, 2011, includes commercial paper borrowings of $~~446~~2,664 million and $645 million, respectively.

(b)

Excludes debt fair value adjustments. As of ~~June~~September 30, 2012 and December 31, 2011, our "Debt fair value adjustments" increased our debt balances by $1,530 million and $1,055 million, respectively. In addition to normal adjustments associated with valuing our debt obligations equal to the present value of amounts to be paid determined at appropriate current interest rates, our debt fair value adjustments also include (i) the value of our interest rate swap ~~agreements, including~~agreements; and (ii) any unamortized portion of proceeds received from the early termination of interest rate swap ~~agreements, totaled~~ ~~$1,136 million~~ ~~and~~ ~~$1,079 million, respectively.~~agreements.

Changes in our outstanding debt, excluding debt fair value adjustments, during the ~~six~~nine months ended ~~June~~September 30, 2012 are summarized as follows (in millions):

Debt borrowings Interest rate Increase / (decrease) Cash received / (paid)
Issuances and discount amortization
Senior notes due September 1, 2022(a) 3.95 % $ 998
$ 998
Commercial paper variable
2,440
2,440
Credit facility variable
—
—
Discount amortization various
1
—
Total increases in debt $ 3,439
$ 3,438

Repayments and other
Senior notes due March 15, 2012(a) 7.125 % $ (450 ) $ (450 )
Commercial paper variable
(2,638 ) (2,638 )
Credit facility variable
—
—
Kinder Morgan Texas Pipeline, L.P. - senior notes due January 2, 2014 5.23 % (4 ) (4 )
Kinder Morgan Arrow Terminals L.P. - note due April 4, 2014 6.0 % (1 ) (1 )
Kinder Morgan Operating L.P. "A" - BP note due March 31, 2012 5.40 % (5 ) —
Kinder Morgan Canada Company - BP note due March 31, 2012 5.40 % (5 ) —
Total decreases in debt $ (3,103 ) $ (3,093 )

~~__________~~

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Debt borrowings	Interest rate		Increase / (decrease)			Cash received / (paid)
Issuances and Assumptions
Senior notes due September 1, 2022(a)	3.95	%	$	1,000		$	998
Senior notes due February 15, 2023(b)	3.45	%	625			622
Senior notes due August 15, 2042(b)	5.00	%	625			621
Commercial paper	variable		5,561			5,561
Bridge loan credit facility due February 6, 2013(c)	variable		576			576
Tennessee Gas Pipeline L.L.C. - senior notes due February 1, 2016(d)	8.00	%	250			—
Tennessee Gas Pipeline L.L.C. - senior notes due April 4, 2017(d)	7.50	%	300			—
Tennessee Gas Pipeline L.L.C. - senior notes due March 15, 2027(d)	7.00	%	300			—
Tennessee Gas Pipeline L.L.C. - senior notes due October 15, 2028(d)	7.00	%	400			—
Tennessee Gas Pipeline L.L.C. - senior notes due June 15, 2032(d)	8.375	%	240			—
Tennessee Gas Pipeline L.L.C. - senior notes due April 1, 2037(d)	7.625	%	300			—
Total increases in debt			$	10,177		$	8,378

Repayments and other
Senior notes due March 15, 2012(a)	7.125	%	$	(450	)	$	(450	)
Senior notes due September 15, 2012(e)	5.85	%	(500		)	(500		)
Commercial paper	variable		(3,542		)	(3,542		)
Bridge loan credit facility due February 6, 2013(c)	variable		(576		)	(576		)
Kinder Morgan Texas Pipeline, L.P. - senior notes due January 2, 2014	5.23	%	(5		)	(5		)
Kinder Morgan Arrow Terminals L.P. - note due April 4, 2014	6.0	%	(1		)	(1		)
Kinder Morgan Operating L.P. "A" - BP note due March 31, 2012	5.40	%	(5		)	—
Kinder Morgan Canada Company - BP note due March 31, 2012	5.40	%	(5		)	—
Total decreases in debt			$	(5,084	)	$	(5,074	)

__________

(a)

On March 14, 2012, we completed a public offering of $1.0 billion in principal amount of 3.95% senior notes due September 1, 2022. We received proceeds from the issuance of the notes, after deducting the underwriting discount, of $994 million, and we used the proceeds both to repay our $450 million 7.125% senior notes that matured on March 15, 2012 and to reduce the borrowings under our commercial paper program.

(b)

On August 13, 2012, we completed a public offering of $1,250 million in principal amount of senior notes in two separate series, consisting of $625 million of 3.45% notes due February 15, 2023 and $625 million of 5.00% notes due August 15, 2042. We received proceeds from the issuance of the notes, after deducting the underwriting discount, of $1,236 million, and we used the proceeds to pay a portion of the purchase price for the drop-down transaction.

(c)

On August 6, 2012, we entered into a second credit agreement with us as borrower; Wells Fargo Bank, National Association, as administrative agent; Barclays Bank PLC, as syndication agent; and a syndicate of other lenders. This credit agreement provided for borrowings up to $2.0 billion pursuant to a short-term bridge loan credit facility with a term of six months. The covenants of this facility are substantially similar to the covenants of our existing senior unsecured revolving credit facility that is due July 1, 2016, and similar to our existing credit facility, borrowings under this bridge loan credit facility may be used to back our commercial paper issuances and for other general partnership purposes (including to pay a portion of the purchase price for the drop-down transaction). In August 2012, we made borrowings of $576 million under our short-term bridge loan credit facility to pay a portion of the purchase price for the drop-down transaction. We then repaid these credit facility borrowings in August 2012 with incremental borrowings under our commercial paper program, and as of September 30, 2012, our bridge loan credit facility was not drawn on.

The size of our bridge loan credit facility will be reduced by an amount equal to the net cash proceeds of certain debt and equity issuances in excess of $1.65 billion, and as of September 30, 2012, our bridge loan credit facility was reduced to allow for maximum borrowings of $1.685 billion. We are also required to prepay borrowings under this credit facility with net proceeds received from certain debt and equity issuances and from the expected divestiture of our FTC Natural Gas Pipelines disposal group. All such prepayments will automatically reduce the borrowing capacity of the credit facility. In addition, in conjunction with the establishment of this short-term bridge loan credit facility, we increased our commercial paper program to provide for the

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issuance of up to $3.885 billion of commercial paper (up from $2.2 billion).


(d)	Our subsidiary, Tennessee Gas Pipeline L.L.C. is the obligor of six separate series of fixed-rate unsecured senior notes having a combined principal amount of $1,790 million. We assumed these debt borrowings as part of the drop-down transaction.


(e)	On September 15, 2012, we paid $500 million to retire the principal amount of our 5.85% senior notes that matured on that date.

We had, as of ~~June~~September 30, 2012, approximately $~~1.5~~1.0 billion of combined borrowing capacity available under our ~~$2.2 billion~~ ~~senior~~two separate unsecured ~~revolving~~ credit ~~facility.~~facilities. As of this date, the combined ~~June 30, 2012~~$3,885 million~~, the~~ amount available for borrowing under our two credit ~~facility~~facilities was reduced by a combined amount of $~~672~~2,886 million, consisting of $~~446~~2,664 million of commercial paper borrowings and$~~226~~222 million of letters of credit, consisting of (i) a $100 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 $86 million in three letters of credit that support tax-exempt bonds; (iii) a $12 million letter of credit that supports debt securities issued by the Express pipeline system; ~~(iv) an~~ ~~$11 million~~ ~~letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation;~~ and ~~(v)~~(iv) a combined $1724 million in other letters of credit supporting other obligations of us and our subsidiaries.

For additional information regarding our debt facilities and for information on our contingent debt agreements, see Note 8 “Debt” and Note 12 “Commitments and Contingent Liabilities” to our consolidated financial statements included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

4.5. Partners’ Capital

Limited Partner Units

As of ~~June~~September 30, 2012 and December 31, 2011, our ~~partners’ capital~~Partners’ Capital included the following limited partner units:


	June 30, 2012	December 31, 2011	September 30, 2012	December 31, 2011
Common units	239,971,640	232,677,222	246,111,590	232,677,222
Class B units	5,313,400	5,313,400	5,313,400	5,313,400
i-units	101,577,509	98,509,389	113,276,125	98,509,389
Total limited partner units	346,862,549	336,500,011	364,701,115	336,500,011

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 right to receive incentive distributions.

As of ~~both~~ ~~June~~September 30, 2012, (i) KMI and its consolidated affiliates (excluding our general partner) held 19,314,003 common units; (ii) our general partner held 1,724,000 common units; (iii) a wholly-owned subsidiary of KMI held all of our Class B units; and (iv) KMR held all of our i-units. As ofDecember 31, 2011, (i) KMI and its consolidated affiliates (excluding our general partner) held ~~14,646,428~~14,464,428 common units; (ii) our general partner held 1,724,000 common units; (iii) a wholly-owned subsidiary of KMI held all of our Class B units; and (iv) KMR held all of our i-units. Our Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. Our i-units are a separate class of limited partner interests in us and are not publicly traded. 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 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.

Changes in Partners’ Capital

For each of the ~~six~~nine month periods ended ~~June~~September 30, 2012 and 2011, changes in the carrying amounts of our Partners’ Capital attributable to both us and our noncontrolling interests, including our comprehensive income are summarized as follows (in millions):

1215

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	Six Months Ended June 30,																		Nine Months Ended September 30,
	2012									2011									2012									2011
	KMP			Noncontrolling Interests			Total			KMP			Noncontrolling interests			Total			KMP			Noncontrolling Interests			Total			KMP			Noncontrolling interests			Total
Beginning Balance	$	7,508		$	96		$	7,604		$	7,211		$	82		$	7,293		$	7,508		$	96		$	7,604		$	7,211		$	82		$	7,293
Units issued for cash	277			—			277			706			—			706			1,114			—			1,114			813			—			813
Units issued as consideration in the acquisition of assets	296			—			296			24			—			24			686			—			686			24			—			24
Distributions paid in cash	(1,194		)	(15		)	(1,209		)	(1,073		)	(13		)	(1,086		)	(1,836		)	(23		)	(1,859		)	(1,639		)	(20		)	(1,659		)
Noncash compensation expense allocated from KMI(a)	—			—			—			89			1			90
Adjustments to capital due to acquisitions from KMI(a)																			2,483			25			2,508			—			—			—
Contribution from KMI for FTC Natural Gas Pipelines disposal group selling expenses(b)																			45			—			45			—			—			—
Noncash compensation expense allocated from KMI(c)																			—			—			—			89			1			90
Cash contributions	—			17			17			—			13			13			—			40			40			—			15			15
Other adjustments	5			4			9			1			—			1			4			1			5			(3		)	—			(3		)
Comprehensive income	563			10			573			658			5			663			900			14			914			1,142			10			1,152
Ending Balance	$	7,455		$	112		$	7,567		$	7,616		$	88		$	7,704		$	10,904		$	153		$	11,057		$	7,637		$	88		$	7,725

__________

(a)

Amounts relate to the drop-down transaction, described in Note 2. We determined that the drop-down transaction constituted a transfer of net assets between entities under common control, and accordingly, we recognized the assets we acquired and the liabilities we assumed at KMI's carrying value (including all purchase accounting adjustments from KMI's acquisition of the drop-down asset group from EP effective May 25, 2012). We then recognized the difference between our purchase price and the carrying value of the assets acquired and liabilities assumed as an adjustment to our Partners' Capital. As of September 30, 2012, the carrying value of the assets we acquired and the liabilities we assumed totaled $6,371 million. We paid to KMI $3,482 million in cash, issued to KMI 4,667,575 common units valued at $381 million, and recognized a non-cash increase of $2,508 million in our Partners' Capital. The increase to Partners' Capital consisted of a $2,483 million increase in our general partner's 1% general partner capital interest in us, and a $25 million increase in our general partner's 1.0101% general partner capital interest in our subsidiary Kinder Morgan Operating L.P. "A" (a noncontrolling interest to us).


(b)	For further information about this contribution, see Note 9.


(c)	For further information about this expense, see Note 8.9. We do not have any obligation, nor do we expect to pay any amounts related to this expense.

During each of the ~~six~~nine month periods ended ~~June~~September 30, 2012 and 2011, there were no material changes in our ownership interests in subsidiaries in which we retained a controlling financial interest.

Equity Issuances

On February 27, 2012, we entered into a third amended and restated equity distribution agreement with UBS Securities LLC (UBS) which increased the aggregate offering price of our common units to up to $1.9 billion (up from $1.2 billion). During the three and ~~six~~nine months ended ~~June~~September 30, 2012, we issued ~~1,953,723~~1,357,946 and ~~3,414,795~~4,772,741, respectively, of our common units pursuant to our equity distribution agreement with UBS. We received net proceeds of $~~153~~110 million and $~~277~~387 million, respectively, from the issuance of these common units and we used the proceeds to reduce the borrowings under our commercial paper program. For additional information regarding our equity distribution agreement, see Note 10 to our consolidated financial statements included in our 2011 Form 10-K.

OnFor the ~~March 14,~~nine month period ended September 30, 2012, ~~we issued~~ ~~87,162~~in addition to the issuance of common units ~~as part of~~pursuant to our ~~purchase price for the petroleum coke terminal assets we acquired from TGS Development, L.P. We valued the common units at approximately~~ ~~$7 million, determining the units’ value based on the~~ ~~$83.87~~ ~~closing market price~~equity distribution agreement, our significant equity issuances consisted of the ~~common units on the New York Stock Exchange on March 14, 2012.~~following:

Onon June 4, 2012, we issued 3,792,461 common units as our purchase price for the 50% equity ownership interest in El Paso Midstream Investment Company, LLC we acquired from KKR. For more information about this acquisition, see Note 2 ~~“Acquisitions~~"Acquisitions and Discontinued Operations—~~Acquisitions.”~~El Paso Midstream Investment Company, LLC;"

in August 2012, in connection with the drop-down transaction, we issued 4,667,575 of our common units to KMI. We valued the units at $381 million, based on the $81.52 closing market price of the common units on the New

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York Stock Exchange on August 13, 2012. For more information on the drop-down transaction, see Note 2 "Acquisitions and Discontinued Operations—August 2012 KMI Asset Drop-Down;" and

in the third quarter of 2012, KMR issued 10,120,000 of its shares in a public offering at a price of approximately $73.50 per share, less commissions and underwriting expenses. KMR used the net proceeds received from the issuance of these 10,120,000 shares to buy additional i-units from us, and we received net proceeds of $727 million. We used the proceeds to pay a portion of the purchase price for the drop-down transaction.

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 levels, according to the provisions of our partnership agreement.

On ~~May 15,~~August 14, 2012, we paid a cash distribution of $~~1.20~~1.23 per unit to our common unitholders and to our Class B unitholder for the quarterly period ended ~~March 31,~~June 30, 2012. KMR, our sole i-unitholder, received a distribution of ~~1,603,975~~1,578,616 i-units from us on ~~May 15,~~August 14, 2012, based on the $~~1.20~~1.23 per unit distributed to our common unitholders on that

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date. The distributions were declared on ~~April~~July 18, 2012, payable to unitholders of record as of ~~April 30,~~July 31, 2012.

On ~~May 13,~~August 12, 2011, we paid a cash distribution of $~~1.14~~1.15 per unit to our common unitholders and to our Class B unitholder for the quarterly period ended ~~March 31,~~June 30, 2011. KMR, our sole i-unitholder, received a distribution of ~~1,599,149~~1,701,916 i-units from us on ~~May 13,~~August 12, 2011, based on the $~~1.14~~1.15 per unit distributed to our common unitholders on that date. The distributions were declared on ~~April~~July 20, 2011, payable to unitholders of record as of ~~April 29,~~August 1, 2011.

Our general partner’s incentive distribution that we paid in ~~May~~August 2012 and ~~May~~August 2011 (for the quarterly periods ended ~~March 31,~~June 30, 2012 and 2011, respectively) was $~~319~~337 million and $~~280~~293 million, respectively. The increased incentive distribution to our general partner paid for the ~~first~~second quarter of 2012 over the incentive distribution paid for the ~~first~~second quarter of 2011 reflects the increase in the amount distributed per unit as well as an increase in the number of common units and i-units outstanding. ~~These~~Each of these two incentive distributions were reduced from what they would have been, however, by waived incentive amounts equal to $~~6 million~~ ~~and~~ $7 million~~, respectively,~~ related to common units issued to finance our acquisition of KinderHawk ~~Field Services LLC~~ (we acquired an initial 50% ownership interest in KinderHawk in May 2010 and the remaining 50% interest in July 2011). To support our KinderHawk acquisition, our general partner agreed to waive certain incentive distribution amounts beginning with the distribution payments we made for the quarterly period ended June 30, 2010, and ending with the distribution payments we make for the quarterly period ended March 31, 2013.

For additional information about our 2011 partnership distributions, see Notes 10 and 11 to our consolidated financial statements included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

Subsequent Events

In early ~~July~~October 2012, we issued ~~168,806~~269,501 of our common units for the settlement of sales made on or before ~~June~~September 30, 2012 pursuant to our equity distribution agreement. We received net proceeds of $1322 million from the issuance of these ~~168,806~~269,501 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.

On ~~July 18,~~October 17, 2012, we declared a cash distribution of $~~1.23~~1.26 per unit for the quarterly period ended ~~June~~September 30, 2012. The distribution will be paid on ~~August~~November 14, 2012 to unitholders of record as of ~~July~~October 31, 2012. Our common unitholders and our Class B unitholder will receive cash. KMR will receive a distribution of ~~1,578,616~~1,842,210 additional i-units based on the$~~1.23~~1.26 distribution per common unit. For each outstanding i-unit that KMR holds, a fraction of an i-unit (~~0.015541~~0.016263) will be issued. This fraction was determined by dividing:

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▪ $~~1.23~~1.26, the cash amount distributed per common unit


▪	~~$79.145, the average of KMR’s shares’ closing market prices from July 13-26,~~ $77.478, the average of KMR’s shares’ closing market prices from October 15-26, 2012, 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.

5.6. 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

As of ~~June~~September 30, 2012, we had entered into the following outstanding commodity forward contracts to hedge our forecast energy commodity purchases and sales:

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	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil	~~(20.6)~~(20.5) million barrels
Natural gas fixed price	~~(31.4)~~(27.6) billion cubic feet
Natural gas basis	~~(32.0)~~(27.6) billion cubic feet
Derivatives not designated as hedging contracts
Natural gas ~~basis~~fixed price	~~14.4~~(0.6) billion cubic feet

As of ~~June~~September 30, 2012, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with energy commodity price risk is through December ~~2016.~~2016.

Interest Rate Risk Management

As of ~~June~~September 30, 2012, we had a combined notional principal amount of $5,525 million 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~~London InterBank Offered Rate (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 ~~June~~September 30, 2012, 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 throughMarch 15, 2035.

As of December 31, 2011, we had a combined notional principal amount of $5,325 million of fixed-to-variable interest rate swap agreements. In March 2012, (i) we entered into four additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million, effectively converting a portion of the interest expense associated with our 3.95% senior notes due September 1, 2022 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread; and (ii) two separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $200 million and converting a portion of the interest expense associated with our 7.125% senior notes terminated upon the maturity of the associated notes. In addition, (i) in June 2012, we terminated an existing fixed-to-variable interest rate swap agreement having a notional amount of $100 million, and we received proceeds of $53 million from the early termination of this swap ~~agreement.~~agreement; (ii) in August 2012, we entered into an additional fixed-to-variable interest rate swap agreement having a notional principal amount of $100 million, effectively converting a portion of the interest expense associated with our 3.45% senior notes due February 15, 2023 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread; and (iii) in September 2012, a fixed-to-variable interest rate swap agreement having a combined notional principal amount of $100 million and effectively converting a portion of the interest expense

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associated with our 5.85% senior notes terminated upon the maturity of the associated notes.

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” in the respective sections of our accompanying consolidated balance sheets, or, as of ~~June~~September 30, 2012 only, included within “Assets held for sale.” The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of ~~June~~September 30, 2012 and December 31, 2011 (in millions):

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Fair Value of Derivative Contracts
		Asset derivatives				Liability derivatives							Asset derivatives				Liability derivatives
		June 30, 2012		December 31, 2011		June 30, 2012			December 31, 2011				September 30, 2012		December 31, 2011		September 30, 2012			December 31, 2011
	Balance sheet location	Fair value		Fair value		Fair value			Fair value			Balance sheet location	Fair value		Fair value		Fair value			Fair value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Current-Fair value of derivative contracts	$	109	$	66	$	(29	)	$	(116	)	Current-Fair value of derivative contracts	$	58	$	66	$	(39	)	$	(116	)
	Current-Assets held for Sale / Accrued other current liabilities	3		—		—			—			Current-Assets held for Sale / Accrued other current liabilities	1		—		—			—
	Non-current-Fair value of derivative contracts	87		39		(6		)	(39		)	Non-current-Fair value of derivative contracts	52		39		(15		)	(39		)
Subtotal		199		105		(35		)	(155		)		111		105		(54		)	(155		)
Interest rate swap agreements	Current-Fair value of derivative contracts	1		3		—			—			Current-Fair value of derivative contracts	—		3		—			—
	Non-current-Fair value of derivative contracts	623		593		—			—			Non-current-Fair value of derivative contracts	652		593		—			—
Subtotal		624		596		—			—				652		596		—			—
Total		823		701		(35		)	(155		)		763		701		(54		)	(155		)

Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current-Fair value of derivative contracts	3		3		(2		)	(5		)	Current-Fair value of derivative contracts	1		3		(2		)	(5		)
												Non-current-Fair value of derivative contracts	1		—		—			—
Total		3		3		(2		)	(5		)		2		3		(2		)	(5		)
Total derivatives		$	826	$	704	$	(37	)	$	(160	)		$	765	$	704	$	(56	)	$	(160	)

The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Debt fair value adjustments” on our accompanying consolidated balance ~~sheets, which~~sheets. Our “Debt fair value adjustments” also ~~includes~~include all unamortized debt discount/premium amounts and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. As of ~~June~~September 30, 2012, we had a combined unamortized debt premium amount of $378 million, and as of December 31, 2011, we had a combined debt discount amount of $24 million. As of September 30, 2012 and December 31, 2011, ~~this~~the unamortized premium from the termination of interest rate swap agreements totaled $~~512~~500 million and $483 million, respectively, and as of ~~June~~September 30, 2012, the weighted average amortization period for this premium was approximately 18 years.

Effect of Derivative Contracts on the Income Statement

The following two tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 (in millions):

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Derivatives in fair value hedging relationships	Location of gain/(loss) recognized in income on derivatives	Amount of gain/(loss) recognized in income on derivatives and related hedged item(a)												Location of gain/(loss) recognized in income on derivatives	Amount of gain/(loss) recognized in income on derivatives and related hedged item(a)
		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2012			2011			2012			2011				2012			2011			2012			2011
Interest rate swap agreements	Interest expense	$	194		$	128		$	81		$	64		Interest expense	$	28		$	437		$	109		$	501
Total		$	194		$	128		$	81		$	64			$	28		$	437		$	109		$	501

Fixed rate debt	Interest expense	$	(194	)	$	(128	)	$	(81	)	$	(64	)	Interest expense	$	(28	)	$	(437	)	$	(109	)	$	(501	)
Total		$	(194	)	$	(128	)	$	(81	)	$	(64	)		$	(28	)	$	(437	)	$	(109	)	$	(501	)

___________


(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.

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Derivatives in cash flow hedging relationships	Amount of gain/(loss) recognized in OCI on derivative (effective portion)(a)					Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)	Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)						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)						Amount of gain/(loss) recognized in OCI on derivative (effective portion)(a)					Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)	Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)						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)
	Three Months Ended June 30,						Three Months Ended June 30,							Three Months Ended June 30,						Three Months Ended September 30,						Three Months Ended September 30,							Three Months Ended September 30,
	2012		2011				2012			2011				2012			2011			2012			2011			2012			2011				2012			2011
Energy commodity derivative contracts	$	303	$	165		Revenues-Natural gas sales	$	2		$	—		Revenues-Natural gas sales	$	—		$	—		$	(90	)	$	387	Revenues-Natural gas sales	$	2		$	—		Revenues-Natural gas sales	$	—		$	—
						Revenues-Product sales and other	(2		)	(87		)	Revenues-Product sales and other	—			(2		)						Revenues-Product sales and other	—			(51		)	Revenues-Product sales and other	(5		)	8
						Gas purchases and other costs of sales	11			—			Gas purchases and other costs of sales	—			—								Gas purchases and other costs of sales	8			2			Gas purchases and other costs of sales	—			—
Total	$	303	$	165		Total	$	11		$	(87	)	Total	$	—		$	(2	)	$	(90	)	$	387	Total	$	10		$	(49	)	Total	$	(5	)	$	8

	Six Months Ended June 30,						Six Months Ended June 30,							Six Months Ended June 30,						Nine Months Ended September 30,						Nine Months Ended September 30,							Nine Months Ended September 30,
	2012		2011				2012			2011				2012			2011			2012			2011			2012			2011				2012			2011
Energy commodity derivative contracts	$	189	$	(98	)	Revenues-Natural gas sales	$	2		$	1		Revenues-Natural gas sales	$	—		$	—		$	99		$	289	Revenues-Natural gas sales	$	4		$	1		Revenues-Natural gas sales	$	—		$	—
						Revenues-Product sales and other	(31		)	(152		)	Revenues-Product sales and other	(3		)	2								Revenues-Product sales and other	(31		)	(203		)	Revenues-Product sales and other	(8		)	10
						Gas purchases and other costs of sales	9			11			Gas purchases and other costs of sales	—			—								Gas purchases and other costs of sales	17			13			Gas purchases and other costs of sales	—			—
Total	$	189	$	(98	)	Total	$	(20	)	$	(140	)	Total	$	(3	)	$	2		$	99		$	289	Total	$	(10	)	$	(189	)	Total	$	(8	)	$	10

____________

(a)

We expect to reclassify an approximate $8325 million gain associated with energy commodity price risk management activities and included in our Partners’ Capital as of ~~June~~September 30, 2012 into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.

(b)

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, the amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchase actually occurred).

For each of the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, we recognized no material gain or loss in income from derivative contracts not designated as hedging contracts.

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

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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

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the future.

The maximum potential exposure to credit losses on our derivative contracts as of ~~June~~September 30, 2012 was (in millions):


	Asset position			Asset position
Interest rate swap agreements	$	624		$	652
Energy commodity derivative contracts	202			113
Gross exposure	826			765
Netting agreement impact	(28		)	(39		)
Cash collateral held	(9		)	—
Net exposure	$	789		$	726

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 both ~~June~~September 30, 2012 and December 31, 2011, we had no outstanding letters of credit supporting our hedging of energy commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil. As of ~~June~~September 30, 2012, we had cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners totaling $6 million, and we reported this amount as "Restricted deposits" in our accompanying consolidated balance sheet. As of December 31, 2011, our counterparties associated with our energy commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $~~9 million~~ ~~and~~ $10 million, ~~respectively,~~ and we reported ~~these amounts~~this amount within “Accrued other current liabilities” in our accompanying consolidated balance ~~sheets.~~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. As of ~~June~~September 30, 2012, we estimate that if our credit rating was downgraded one notch, we would be required to post no additional collateral to our counterparties. If we were downgraded two notches (that is, below investment grade), we would be required to post$28 million of additional collateral.

6.7. Fair Value

The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. 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;~~

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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).

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 ~~June~~September 30, 2012 and December 31, 2011, based on the three levels established by the ~~Codification (in millions).~~Codification. The fair values of our current and non-current asset and liability derivative contracts each reported separately as “Fair value of derivative contracts” in the respective sections of our accompanying consolidated balance sheets, or, as of September 30, 2012 only, included within “Assets held for sale.” The fair value measurements in the tables below do not include cash margin deposits made by us or our counterparties, which are reported within "Restricted deposits" and “Accrued other current ~~liabilities”~~liabilities,” respectively, in our accompanying

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consolidated balance ~~sheets.~~sheets (in millions).


	Asset fair value measurements using								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)		Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
As of June 30, 2012
As of September 30, 2012
Energy commodity derivative contracts(a)	$	202	$	27	$	153	$	22	$	113	$	16	$	88	$	9
Interest rate swap agreements	$	624	$	—	$	624	$	—	$	652	$	—	$	652	$	—

As of December 31, 2011
Energy commodity derivative contracts(a)	$	108	$	34	$	47	$	27	$	108	$	34	$	47	$	27
Interest rate swap agreements	$	596	$	—	$	596	$	—	$	596	$	—	$	596	$	—

____________


	Liability fair value measurements using												Liability 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)			Total			Quoted prices in active markets for identical assets (Level 1)			Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
As of June 30, 2012
As of September 30, 2012
Energy commodity derivative contracts(a)	$	(37	)	$	(9	)	$	(26	)	$	(2	)	$	(56	)	$	(14	)	$	(39	)	$	(3	)
Interest rate swap agreements	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—

As of December 31, 2011
Energy commodity derivative contracts(a)	$	(160	)	$	(15	)	$	(125	)	$	(20	)	$	(160	)	$	(15	)	$	(125	)	$	(20	)
Interest rate swap agreements	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—

____________


(a)	Level 1 consists primarily of ~~NYMEX~~the New York Mercantile Exchange (NYMEX) natural gas futures. Level 2 consists primarily of ~~OTC~~over-the-counter (OTC) West Texas Intermediate swaps and OTC natural gas swaps that are settled on NYMEX. Level 3 consists primarily of West Texas Intermediate options.

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The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 (in millions):

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Significant unobservable inputs (Level 3)
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Derivatives-net asset (liability)
Beginning of Period	$	(3	)	(3		)	$	7		$	19		$	20		7			$	7		$	19
Transfers out of Level 3	—			—			—			—
Total gains or (losses):
Included in earnings	(2		)	3			—			3			(3		)	3			(3		)	6
Included in other comprehensive income	28			7			6			(16		)	(6		)	37			—			21
Purchases	—			—			3			5			—			—			3			5
Settlements	(3		)	—			4			(4		)	(5		)	(2		)	(1		)	(6		)
End of Period	$	20		7			$	20		$	7		$	6		45			$	6		$	45

The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date	$	(2	)	$	(4	)	$	(1	)	$	1		$	(5	)	$	3		$	(1	)	$	4

As of ~~June~~September 30, 2012, we reported our West Texas Intermediate options at fair value using Level 3 inputs due to such derivatives not having observable market prices. We determined the fair value of our West Texas Intermediate options using the Black Scholes option valuation methodology after giving consideration to a range of factors, including the ~~price~~prices at which the ~~option was~~options were acquired, local market conditions, implied volatility, and trading values on public exchanges.

The significant unobservable input we use to measure the fair value of our Level 3 derivatives is implied volatility of options. We obtain the implied volatility of our West Texas Intermediate options from a third party service provider. As of ~~June~~September 30, 2012, this volatility ranged from ~~29%~~30% – ~~32%~~31% based on both historical market data and future estimates of market fluctuation. Significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.

Fair Value of Financial Instruments

The estimated fair value of our outstanding debt balance as of ~~June~~September 30, 2012 and December 31, 2011 (both short-term and ~~long-term, but excluding our debt fair value adjustments)~~long-term), is disclosed below (in millions):

June 30, 2012 December 31, 2011

Carrying
Value

Estimated
Fair value

Carrying
Value

Estimated
Fair value
Total debt $ 13,133
$ 14,717
$ 12,797
$ 14,238



	September 30, 2012				December 31, 2011
	Carrying Value		Estimated Fair value		Carrying Value		Estimated Fair value
Total debt	$	19,444	$	20,748	$	13,876	$	14,238

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both ~~June~~September 30, 2012 and December 31, 2011.

7.8. Reportable Segments

We divide our operations into five reportable business segments. These segments and their principal ~~source~~sources 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;

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

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▪	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 segment’s 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 structured based on how our chief operating decision maker organizes their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and marketing strategies.

Financial information by segment follows (in millions):


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011		2012		2011			2012			2011
Revenues
Products Pipelines
Revenues from external customers	$	331		$	228	$	554		$	453	$	386	$	242		$	940		$	695
Natural Gas Pipelines
Revenues from external customers	693			963		1,487			1,906		1,113		1,093			2,699			2,999
CO₂
Revenues from external customers	413			350		830			691		420		372			1,250			1,063
Terminals
Revenues from external customers	342			320		683			652		334		327			1,017			979
Intersegment revenues	1			—		1			—		—		1			1			1
Kinder Morgan Canada
Revenues from external customers	73			77		146			153		80		77			226			230
Total segment revenues	1,853			1,938		$	3,701		3,855		2,333		2,112			$	6,133		5,967
Less: Total intersegment revenues	(1		)	—		(1		)	—		—		(1		)	(1		)	(1		)
Total consolidated revenues	$	1,852		$	1,938	$	3,700		$	3,855	$	2,333	$	2,111		$	6,132		$	5,966

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	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(a)
Products Pipelines(b)	$	166		$	21		$	342		$	201		$	150		$	103		$	492		$	304
Natural Gas Pipelines(c)	190			135			412			301			405			18			877			319
CO₂	327			266			661			528			327			295			988			823
Terminals	195			171			382			345			183			180			565			525
Kinder Morgan Canada	52			54			102			102			56			48			158			150
Total segment earnings before DD&A	$	930		647			$	1,899		1,477			1,121			644			3,080			2,121
Total segment depreciation, depletion and amortization	(248		)	(223		)	(487		)	(438		)	(292		)	(247		)	(796		)	(685		)
Total segment amortization of excess cost of investments	(2		)	(2		)	(4		)	(3		)	(1		)	(2		)	(5		)	(5		)
General and administrative expenses~~(c)~~(d)	(98		)	(98		)	(205		)	(287		)	(131		)	(100		)	(379		)	(387		)
Interest expense, net of unallocable interest income	(141		)	(129		)	(280		)	(261		)	(181		)	(132		)	(474		)	(393		)
Unallocable income tax expense	(3		)	(3		)	(5		)	(5		)	(2		)	(2		)	(7		)	(7		)
Income (Loss) from discontinued operations~~(d)~~(e)	(279		)	40			(551		)	90			(131		)	55			(682		)	145
Total consolidated net income	$	159		$	232		$	367		$	573		$	383		$	216		$	737		$	789


	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Assets
Products Pipelines	$	4,717	$	4,479	$	4,775	$	4,479
Natural Gas Pipelines	7,527		9,958		16,479		9,958
CO₂	2,334		2,147		2,297		2,147
Terminals	4,662		4,428		4,869		4,428
Kinder Morgan Canada	1,803		1,827		1,866		1,827
Total segment assets	21,043		22,839		30,286		22,839
Corporate assets~~(e)~~(f)	1,433		1,264		1,448		1,264
Assets held for sale~~(f)~~(g)	1,938		—		1,859		—
Total consolidated assets	$	24,414	$	24,103	$	33,593	$	24,103

____________


(a)	Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).


(b)	Three and ~~six~~nine month 2012 amounts include increases in expense of $9 million associated with rate case liability adjustments. Three and nine month 2011 amounts include aincreases in expense of $~~165~~69 million ~~increase in expense~~and $234 million, respectively, associated with rate case, leased rights-of-way, and other legal liability adjustments.


(c)	~~Six~~Three and nine month 2011 amounts include a $167 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk to fair value (discussed further in Note 2).


(d)	Nine month 2011 amount includes an $87 million increase in expense allocated to us from KMI and associated with a one-time special cash bonus payment that was paid to non-senior management employees in May 2011; however, we do not have any obligation, nor did we pay any amounts related to this expense.


~~(d)~~(e)	Represents amounts attributable to our FTC Natural Gas Pipelines disposal group. Three and ~~six~~nine month 2012 amounts include loss amounts of $~~327~~178 million and $~~649~~827 million, respectively, from both the remeasurement of net assets to fair ~~value.~~value and estimated costs to sell (discussed further in Note 2).


~~(e)~~(f)	Includes cash and cash equivalents; margin and restricted deposits; unallocable interest receivable, prepaid assets and deferred charges; and risk management assets related to debt fair value adjustments.


~~(f)~~(g)	~~Represents~~Primarily represents amounts attributable to our FTC Natural Gas Pipelines disposal group.

8.9. Related Party Transactions

~~Notes Receivable~~

~~Plantation Pipe Line Company~~

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Notes Receivable

Plantation Pipe Line Company

We and ExxonMobil have a term loan agreement covering a note receivable due from Plantation Pipe Line Company. We own a 51.17% equity interest in Plantation and our proportionate share of the outstanding principal amount of the note receivable was $50 million as of both ~~June~~September 30, 2012 and December 31, 2011. The note bears interest at the rate of 4.25% per annum and provides for semiannual payments of principal and interest on December 31 and June 30 each year, with a final principal payment of $45 million (for our portion of the note) due on July 20, 2016. We included $1 million of our note receivable balance within “Accounts, notes and interest receivable, net,” on our accompanying consolidated balance sheets as of both ~~June~~September 30, 2012 and December 31, 2011, and we included the remaining outstanding balance within “Notes receivable.”

Express US Holdings LP

We own a 33 1/3% equity ownership interest in the Express pipeline system. We also hold a long-term investment in a C$114 million debt security issued by Express US Holdings LP (the obligor), the partnership that maintains ownership of the U.S. portion of the Express pipeline system. The debenture (i) is denominated in Canadian dollars; (ii) is due in full on January 9, 2023; (iii) bears interest at the rate of 12.0% per annum; and (iv) provides for quarterly payments of interest in Canadian dollars on March 31, June 30, September 30 and December 31 each year. As of ~~June~~September 30, 2012 and December 31, 2011, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was$~~111~~116 million and $112 million, respectively, and we included these amounts within “Notes receivable” on our accompanying consolidated balance sheets.

KMI and El Paso Corporation

At the time of KMI's acquisition of EP on May 25, 2012 (discussed in Note 1), TGP had a note receivable from EP, and during the second quarter of 2012, TGP received combined principal note repayments of approximately $44 million. Upon our acquisition of TGP from KMI on August 1, 2012 (as part of the drop-down transaction discussed in Note 2), we and KMI agreed that the remaining $466 million amount due on the note receivable would not be repaid. Accordingly, this amount was treated as a decrease in KMI's investment in TGP and us, and as a result, TGP no longer has a related party note receivable with either KMI or EP. However, because we have included the historical results of TGP as though the net assets had been transferred to us May 25, 2012, the $44 million repayment is now included within "Repayments from related party" on our consolidated statement of cash flows for the nine months ended September 30, 2012.

Other Receivables and Payables

As of ~~June~~September 30, 2012 and December 31, 2011, our related party receivables (other than the notes receivable discussed above in “—Notes Receivable”) totaled $3032 million and $26 million, respectively. The ~~June~~September 30, 2012 receivables amount consisted of (i) $2830 million included within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet; and (ii) $2 million of natural gas imbalance receivables included within “Other current assets.” The $2830 million receivable amount consisted primarily of ~~amounts~~a net receivable amount due from KMI (including a $45 million receivable amount discussed below in "—FTC Natural Gas Pipelines Disposal Group Selling Expenses") and the Express pipeline system. The $2 million natural gas imbalance receivable consisted primarily of amounts due from Natural Gas Pipeline Company of America LLC, a 20%-owned equity investee of KMI and referred to in this report as NGPL.

The December 31, 2011 receivables amount consisted of $15 million included within “Accounts, notes and interest receivable, net,” and $11 million of natural gas imbalance receivables included within “Other current assets.” The $15 million receivable amount primarily consisted of amounts due from the Express pipeline system, NGPL, and KMI. The $11 million natural gas imbalance receivable consisted of amounts due from both NGPL and Rockies Express Pipeline LLC.

As of ~~both~~ ~~June~~September 30, 2012 ~~and~~ ~~December 31, 2011~~, our related party payables totaled $13 million, and we included these amounts within “Accounts payable” on our accompanying consolidated balance sheets. This amount consisted primarily of $2 million in payables due to two of our equity method investees. The December 31, 2011 related party payables totaled $1 million. At ~~each~~

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both balance sheet ~~date,~~dates, our related party payables ~~consisted of~~included a $1 million amount we owed to the noncontrolling partner of Globalplex Partners, a Louisiana joint venture owned 50% and controlled by us.

Asset Acquisitions

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~~KMI in November 2004; and (iii) TGP and 50% of EPNG from KMI ~~on November 1, 2004,~~in August 2012, KMI agreed to indemnify us and our general partner with respect to approximately $~~734 million~~3.8 billion of our debt. KMI would be obligated to perform under this indemnity only if we are unable, and/or our assets were insufficient, to satisfy our obligations.

In addition, KMI has indemnified us and our general partner with respect to approximately $558 million for our proportionate 50% share of EPNG's debt. Because we account for our investment in EPNG under the equity method of accounting, we do not include its debt in the debt reported on our accompanying consolidated balance sheets.

Non-Cash Compensation Expenses

In the first ~~six~~nine months of 2011, KMI allocated to us certain non-cash compensation expenses totaling $90 million; however, we do not have any obligation, nor did we pay any amounts related to these compensation expenses. The amount included an $87 million expense associated with a one-time special cash bonus payment that was paid by KMI to non-senior management employees in May 2011, and a $3 million expense related to KMI’s going-private transaction in May 2007. Since we were not responsible for paying these expenses, we recognized the amounts allocated to us as both

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an expense on our income statement and a contribution to “Total Partners’ Capital” on our balance sheet.

~~Derivative Counterparties~~FTC Natural Gas Pipelines Disposal Group Selling Expenses

AsIn the third quarter of 2012, we recognized an estimated $78 million selling expense (and an associated liability) related to the divestiture of our FTC Natural Gas Pipelines disposal group. We expect to pay the liability associated with this expense in the fourth quarter of 2012. Furthermore, KMI agreed to contribute $45 million to us to be used as partial funding for this liability payment, and accordingly, we recognized a ~~result of KMI’s going-private transaction in May 2007, a number of individuals and entities became significant investors in~~$45 million receivable from KMI and ~~by virtue of the size of its ownership~~an associated increase to our Partners' Capital (specifically, an increase to our general partner's capital interest in ~~KMI, one of those investors—Goldman Sachs Capital Partners and certain of its affiliates—remains a “related party” (as defined by U.S. generally accepted accounting principles) to us as of~~ us).~~June 30, 2012. 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 our affiliates.~~

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 ~~June 30, 2012~~ ~~and~~ ~~December 31, 2011~~ ~~(in millions):~~

June 30,
2012 December 31,
2011
Derivatives – asset/(liability)
Current assets $ 17
$ 9
Noncurrent assets $ 28
$ 18
Current liabilities $ (14 ) $ (64 )
Noncurrent liabilities $ (3 ) $ (10 )

~~For more information on our risk management activities see Note 5.~~

Other

Generally, KMR makes all decisions relating to the management and control of our business, and in general, KMR has a 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 indirectly 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 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 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.

For a more complete discussion of our related party transactions, including (i) the accounting for our general and administrative expenses; (ii) KMI’s operation and maintenance of the assets comprising our Natural Gas Pipelines business segment; and (iii) our partnership interests and distributions, see Note 11 to our consolidated financial statements included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

10. Litigation, Environmental and Other Contingencies

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~~9. 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 the ~~six~~nine months ended ~~June~~September 30, 2012. Additional information with respect to these proceedings can be found in Note 16 to our consolidated financial statements that were included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012. This note also contains a description of any material legal proceedings that were initiated against us during the ~~six~~nine months ended ~~June~~September 30, 2012, and a description of any material events occurring subsequent to ~~June~~September 30, 2012, 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; BP West Coast Products, LLC as BP; ConocoPhillips Company (now Phillips 66 Company) as Phillips 66; Tesoro Refining and Marketing Company as Tesoro; Western Refining Company, L.P. as Western Refining; Navajo Refining Company, L.L.C. as Navajo; Holly Refining & Marketing Company LLC (now HollyFrontier Refining & Marketing LLC) as HollyFrontier; ExxonMobil Oil Corporation as ExxonMobil; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; Continental Airlines, Inc., Northwest Airlines, Inc. (now Delta Air Lines, Inc.), Southwest Airlines Co. and US Airways, Inc., collectively, as the Airlines; our subsidiary Tennessee Gas Pipeline L.L.C. as TGP; 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 Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company) as UPRR; the American Railway Engineering and Maintenance-of-Way Association as AREMA; Severstal Sparrows Point, LLC as Severstal; RG Steel Sparrows Point LLC as RG Steel; the Texas Commission of Environmental Quality as the TCEQ; The Premcor Refining Group, Inc. as Premcor; Port Arthur Coker Company as PACC; the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration as the PHMSA; a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order as an NOPV; the federal Comprehensive Environmental Response, Compensation and Liability Act as CERCLA; the United States Environmental Protection Agency as the U.S. EPA; the United States Environmental Protection Agency’s Suspension and Debarment Division as the U.S. EPA SDD; the New Jersey Department of Environmental Protection as the NJDEP; our subsidiary Kinder Morgan Bulk Terminals, Inc. as KMBT; our subsidiary Kinder Morgan Liquids Terminals LLC as KMLT; our subsidiary Kinder Morgan Interstate Gas Transmission LLC as KMIGT; Rockies Express Pipeline LLC as Rockies Express; and Plantation Pipe Line Company as Plantation. “OR” dockets designate complaint proceedings, and “IS” dockets designate protest proceedings.

Federal Energy Regulatory Commission Proceedings

The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the shippers' complaints and protests regarding interstate rates on the pipeline systems listed below. 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 federal courts.

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

SFPP

The following FERC dockets are currently pending:

▪

FERC Docket No. IS08-390 (West Line Rates) (Opinion Nos. 511 and 511-A)~~—Protestants:~~-Protestants: BP, ExxonMobil, Phillips 66, Valero Marketing, Chevron, the ~~Airlines—Status:~~Airlines-Status: FERC order issued on December 16, 2011 (Opinion No. 511-A). While the order made certain findings that were adverse to SFPP, it ruled in favor of SFPP on many significant issues. SFPP made a compliance filing at the end of January 2012, and our rates reflect this filing. SFPP also filed a rehearing request on certain adverse rulings in the FERC order. ~~Certain shippers and SFPP filed petitions at the D.C. Circuit~~Petitions for review of Opinion Nos. 511 and ~~511-A; these petitions~~511-A have been filed at the D.C. Circuit and are held in abeyance pending a ruling on SFPP's request for rehearing. It is not possible to predict the outcome of ~~the~~ FERC review of the rehearing request or

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~~the rehearing request or~~ appellate review;

▪

FERC Docket No. IS09-437 (East Line Rates)~~—Protestants:~~-Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, Western Refining, Navajo, HollyFrontier, and Southwest ~~Airlines—Status:~~Airlines-Status: Opinion and Order on Initial ~~decision~~Decision, Opinion No. 522, issued on ~~February 10, 2011. A~~September 20, 2012. The FERC ~~administrative law judge~~ generally made findings ~~adverse~~favorable to SFPP ~~found that East Line rates should have been lower,~~on significant issues and ~~recommended that SFPP pay refunds for alleged over-collections. SFPP has filed a brief~~consistent 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’sFERC's Opinion Nos. 511 and ~~511-A, it~~511-A. Requests for rehearing, if any, must be filed in October 2012. It is not possible to predict the outcome of FERC review of any request for rehearing or appellate ~~review;~~review of this order;

▪

FERC Docket No. IS11-444 (2011 West Line Index Rate Increases)~~—Protestants:~~-Protestants: BP, ExxonMobil, Phillips 66, Valero Marketing, Chevron, the Airlines, Tesoro, Western Refining, Navajo, and ~~HollyFrontier—Status:~~HollyFrontier-Status: The shippers filed a motion for summary disposition that was granted in the shippers' favor in an initial decision issued on March 16, 2012. SFPP filed a brief with the FERC taking exception to the initial decision. The FERC will review the initial decision, and it is not possible to predict the outcome of FERC or appellate review;

▪

FERC Docket ~~No.~~Nos. IS12-390 (SFPP East Line Index Rates)~~—Protestants:~~/IS12-388 and IS12-501 (SFPP West Line Index Rates)-Protestants: the Airlines, BP, Chevron, HollyFrontier, Phillips 66, ~~Southwest Airlines, US Airways,~~Tesoro, Valero Marketing, and Western ~~Refining—Status: These~~Refining-Status: Collectively, these shippers protested SFPP's index-based rate increases for its East ~~Line.~~Line (IS12-390) and West Line (IS12-388 and IS12-501). FERC rejected the protests against SFPP's East Line rate increases and accepted the protests against SFPP's West Line rate increases (IS12-388). Following FERC acceptance of the West Line protests, SFPP withdrew these rate increases, and FERC terminated the IS12-388 proceeding. SFPP subsequently made a new filing to increase its West Line rates by a smaller index-based percentage (IS12-501), which FERC accepted notwithstanding shipper protests. Shippers ~~may file~~requested rehearing of FERC's acceptance of the East Line and West Line rate increases, and those requests ~~for rehearing, and it~~are pending before FERC. It is not possible to predict the outcome of ~~further~~ FERC ~~review, if any;~~

or appellate review;

▪

FERC Docket ~~No.~~Nos. IS12-388/IS12-500 (SFPP West Line Index Rates)~~—Protestants:~~-Protestants: the Airlines, BP, Chevron, Phillips 66, Tesoro, Valero ~~Marketing—Status:~~Marketing-Status: These shippers protested SFPP's index-based rate increases for its West Line. Following FERC acceptance of the protests, SFPP withdrew these rate increases and subsequently increased its West Line rates by a smaller percentage that FERC found acceptable as to SFPP's East Line in ~~IS12‑390.~~IS12-390. Shippers may protest SFPP's new West Line index filing, and it is not possible to predict the outcome of further FERC review, if any;


▪	FERC Docket No. OR11-13 (SFPP Base Rates)—Complainant: Phillips 66—Status: SFPP to provide further data within 90 days of the issuance of a final order in Docket No. IS08-390. Phillips 66 permitted to amend its complaint based on additional data;


▪	FERC Docket No. OR11-16 (SFPP Base Rates)—Complainant: Chevron—Status: SFPP to provide further data within 90 days of the issuance of a final order in Docket No. IS08-390. Chevron permitted to amend its complaint based on additional data; and


▪	FERC Docket No. OR11-18 (SFPP Base Rates)—Complainant: Tesoro—Status: SFPP to provide further data within 90 days of the issuance of a final order in Docket No. IS08-390. Tesoro permitted to amend its complaint based on additional data.

With respect to all of the SFPP proceedings above, we estimate that the shippers are seeking approximately $20 million in annual rate reductions and approximately $100 million in refunds. However, applying the principles of Opinion Nos. 511, ~~and~~ 511-A, ~~a full FERC decision on our West Line rates,~~522, as applicable, to ~~these~~pending cases would result in substantially lower rate reductions and ~~refunds.~~refunds than those sought by the shippers. We do not expect refunds in these cases to have an impact on our distributions to our limited partners.

Calnev

On March 17, 2011, the FERC issued an order consolidating and setting for hearing the complaints in Docket Nos. OR07-7, OR07-18, OR07-19, OR07-22, OR09-15, and OR09-20 filed by Tesoro, the Airlines, BP, Chevron, Phillips 66 and Valero Marketing. A settlement agreement resolving these proceedings was filed on February 24, 2012 and was

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certified to the FERC on March 1, 2012. On April 3, 2012, the FERC approved the settlement, and in May 2012, after the rates reduced by the settlement became effective, we made settlement payments of $54 million.

California Public Utilities Commission Proceedings

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We have previously reported ratemaking and complaint proceedings against SFPP 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.

On ~~April 6, 2010, a~~May 26, 2011, the CPUC ~~administrative law judge~~ issued a ~~proposed~~ decision ~~(Long case)~~ in several intrastate rate cases involving SFPP and a number of its ~~shippers.~~shippers (the “Long” cases). The ~~proposed~~ decision includes determinations on issues, such as ~~SFPP’s~~SFPP's entitlement to an income tax allowance, ~~and~~ allocation of environmental expenses, and refund liability which we believe are contrary both to CPUC policy and precedent and to established federal regulatory policies for pipelines. ~~Moreover, the 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.~~ On March ~~13,~~8, 2012, the CPUC issued ~~its~~another decision onrelated to the Long ~~case. The~~cases. This decision largely reflected the determinations made on ~~April 6, 2010,~~May 26, 2011, including the denial of an income tax allowance for SFPP. The ~~CPUC’s~~CPUC's order denied ~~SFPP’s~~SFPP's request for rehearing of the ~~CPUC’s~~CPUC's income tax allowance treatment, while granting requested rehearing of various other issues relating to ~~SFPP’s~~SFPP's refund liability and staying the payment of refunds until resolution of the outstanding issues on rehearing. On March 23, 2012, SFPP filed a petition for writ of review in the California Court of Appeals ~~seeking~~including, among other things, a ~~court order vacating~~review of the ~~CPUC’s~~CPUC's determination that SFPP is not entitled to recover an income tax allowance in its intrastate rates. In October 2012, the Court ~~review remains pending.~~agreed to hear an appeal on the merits of the issues appealed.

On April 6, 2012, in proceedings unrelated to the above-referenced CPUC dockets, a CPUC administrative law judge issued a proposed decision ~~(Bemesderfer case)~~ substantially reducing SFPP’s authorized cost of service and ordering SFPP to pay refunds from May 24, 2007 to the present of revenues collected in excess of the authorized cost of service. The proposed decision was subsequently withdrawn, and the presiding administrative law judge is expected to reissue a proposed decision at some indeterminate time in the future. On January 30, 2012, SFPP filed an application reducing its intrastate rates by approximately 7%. This matter remains pending before the CPUC.

Based on our review of these CPUC proceedings and the shipper comments thereon, we estimate that the shippers are requesting approximately $375 million in reparation payments and approximately $30 million in annual rate reductions. The actual amount of reparations will be determined through further proceedings at the CPUC and, potentially, the California Court of Appeals. We believe that the appropriate application of the income tax allowance and corrections of errors in law and fact should result in a considerably lower amount. We do not expect any reparations that we would pay in these matters to have an impact on our distributions to our limited partners.

Carbon Dioxide Tax Assessments

Colorado Severance Tax Assessment

On September 16, 2009, the Colorado Department of Revenue issued three Notices of Deficiency to our subsidiary Kinder Morgan CO₂. The Notices of Deficiency assessed additional state severance tax against Kinder Morgan CO₂with respect to carbon dioxide produced from the McElmo Dome unit for tax years 2005, 2006, and 2007. The total amount of tax assessed was $6 million, plus interest of $1 million and penalties of $2 million. Kinder Morgan CO₂protested the Notices of Deficiency and paid the tax and interest under protest. Kinder Morgan CO₂is now awaiting the Colorado Department of Revenue’s response to the protest.

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 overstatement of transportation and other expenses used to calculate the net taxable value. Kinder Morgan CO₂ paid the retroactive tax bills under protest and filed petitions for a refund of the taxes paid under protest. On February 6,

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2012, the Montezuma County Board of County Commissioners denied the refund petitions, and we appealed to the Colorado Board of Assessment Appeals. A hearing on this matter will be held in the first quarter of 2013.

Other

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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 v. 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 September 2011, the judge determined that the annual rent payable as of January 1, 2004 was $15 million, subject to annual consumer price index increases. SFPP intends to appeal the judge’s determination, but if that determination is upheld, SFPP would owe approximately $75 million in back rent. Accordingly, during 2011, we increased our rights-of-way liability to cover this liability amount. In addition, the judge determined that UPRR is entitled to an estimated $20 million for interest on the outstanding back rent liability. We believe the award of interest is without merit and we are pursuing our appellate rights.

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 AREMA standards in determining when relocations are necessary and in completing relocations. Each party is seeking declaratory relief with respect to its positions regarding the application of these standards with respect to relocations. A trial occurred in the fourth quarter of 2011, with a verdict having been reached that SFPP was obligated to comply with AREMA standards in connection with a railroad project in Beaumont Hills, California. SFPP is evaluating its post-trial and appellate options.

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, our results of operations, our cash flows, and our distributions to our limited partners. 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 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, Case No. 09CV1668-WMN. Severstal and its successor in interest, RG Steel, allege 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. RG Steel seeks to recover in excess of $30 million for the alleged value of the crane and lost profits. KMBT denies each of RG Steel’s allegations. On or about June 1, 2012, RG Steel filed for bankruptcy in Case No. 12-11669 in the United States Bankruptcy Court for the District of Delaware; consequently, the trial date has been postponed indefinitely.

Pipeline Integrity and Releases

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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,

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state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

Perth Amboy, New Jersey Tank Release

In May 2011, the PHMSA issued ~~a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order, or~~an NOPV to KMLT. The notice alleges violations of PHMSA’s regulations related to an October 28, 2009 tank release from our Perth Amboy, New Jersey liquids terminal. No product left the company’s property, and additionally, there were no injuries, no impact to the adjacent community or public, and no fire as a result of the release. The notice proposes a penalty of less than $1 million. KMLT is pursuing an administrative appeal of the NOPV.

Central Florida Pipeline Release, Tampa, Florida

On July 22, 2011, our subsidiary Central Florida Pipeline LLC reported a refined petroleum products release on a section of its 10-inch diameter pipeline near Tampa, Florida. The pipeline carries jet fuel and diesel to Orlando and was carrying jet fuel at the time of the incident. There was no fire and were no injuries associated with the incident. We immediately began clean up operations in coordination with federal, state and local agencies. The cause of the incident is outside force damage. The incident is under investigation by the PHMSA, U.S. EPA and the Florida Department of Environmental Protection.

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 reasonably 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.

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 ~~June~~September 30, 2012 and December 31, 2011, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $~~280~~309 million and $332 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. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.

Environmental Matters

New Jersey Department of Environmental Protection v. Occidental Chemical Corporation, et al. (Defendants), Maxus Energy Corp. and Tierra Solutions, Inc. (Third Party Plaintiffs) v. 3M Company et al., Superior Court of New Jersey, Law Division – Essex County, Docket No. L-9868-05

The NJDEP sued Occidental Chemical and others under the New Jersey Spill Act for contamination in the Newark Bay Complex including numerous waterways and rivers. Occidental et al. then brought in approximately 300 third party defendants for contribution. NJDEP claimed damages related to forty years of discharges of TCDD (a form of dioxin), DDT and “other hazardous substances.” GATX Terminals Corporation (n/k/a/ KMLT) was brought in as a third party defendant because of the noted hazardous substances language and because the Carteret, New Jersey facility (a former GATX Terminals facility) is located on the Arthur Kill River, one of the waterways included in the litigation. This case was filed against third party defendants in 2009. The judge issued his trial plan for this case during the first quarter of 2011. According to the trial plan, hethe judge allowed the State to file summary judgment motions against Occidental, Maxus and Tierra on liability issues immediately. Numerous third party defendants, as part of a joint defense group of which KMLT is a member, filed motions to dismiss, which were denied, and now have filed interim appeals from those motions. The appeals court panel heard oral arguments on these motions to dismiss in March 2012 and issued a ruling

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denying these motions in June 2012. The appellants ~~are now considering filing~~have filed appeals to the New Jersey Supreme ~~Court.~~Court regarding this lower court ruling. Maxus/Tierra’s claims against the third party defendants are set to be tried in April 2013 with damages to be tried in September 2013.

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Portland Harbor Superfund Site, Willamette River, Portland, Oregon

In December 2000, the U.S. EPA sent out General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. The major potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the Remedial Investigation and Feasibility Study leading to the proposed remedy for cleanup of the Portland Harbor site. Once the U.S. EPA determines the cleanup remedy from the remedial investigations and feasibility studies conducted during the last decade at the site, it will issue a Record of Decision. Currently, KMLT and 90 other parties are involved in an allocation process to determine each party’s respective share of the cleanup costs. This is a non-judicial allocation process. We are participating in the allocation process on behalf of both KMLT and KMBT. Each entity has two facilities located in Portland Harbor. We expect the allocation to conclude in 2013 or 2014, depending upon when the U.S. EPA issues its Record of Decision.

Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona

This is a CERCLA case brought against a number of defendants by a water purveyor whose wells have allegedly been contaminated due to the presence of a number of contaminants. The Roosevelt Irrigation District is seeking up to $175 million from approximately 70 defendants. The plume of contaminants has traveled under Kinder Morgan’s Phoenix Terminal. The plaintiffs have advanced a novel theory that the releases of petroleum from the Phoenix Terminal (which are exempt under the petroleum exclusion under CERCLA) have facilitated the natural degradation of certain hazardous substances and thereby have resulted in a release of hazardous substances regulated under CERCLA. We are part of a joint defense group consisting of other terminal operators at the Phoenix Terminal including Chevron, BP, Salt River Project, Shell and a number of others, collectively referred to as the terminal defendants. Together, we filed a motion to dismiss all claims based on the petroleum exclusion under CERCLA. This case was assigned to a new judge, who has deemed all previous motions withdrawn and will grant leave to re-file such motions at a later date. We plan to re-file the motion to dismiss as well as numerous summary judgment motions as the judge allows.

Casper and Douglas, U.S. EPA Notice of Violation

In March 2011, the U.S. EPA conducted inspections of several environmental programs at the Douglas and Casper Gas Plants in Wyoming. In June 2011, we received two letters from the U.S. EPA alleging violations at both gas plants of the Risk Management Program requirements under the Clean Air Act. ~~Kinder Morgan has executed a~~In September 2012, we entered into Combined Complaint and Consent Agreements ~~including~~and paid a monetary ~~penalties~~penalty of $158,000 for each plant to resolve these ~~issues, and is awaiting final, executed settlement documents from the U.S. EPA.~~issues.

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 remains stayed through the next case management conference in ~~October 2012.~~March 2013. During the stay, the parties deemed responsible by the local regulatory agency (including the City of Los Angeles) have worked with that agency concerning the scope of the required cleanup and have now completed a sampling and testing program at the site. We anticipate that cleanup activities at the site will begin in the Spring of 2013. 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 water board. The state water board has not yet taken any action with regard to our appeal petitions.

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. We have begun settlement negotiations with the Port of Los Angeles.

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

On April 23, 2003, ExxonMobil filed a complaint in the Superior Court of New Jersey, Gloucester County. The

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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.

On June 25, 2007, the NJDEP, 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 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 filed 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 mid 2011, KMLT and Plains Products entered into an agreement in principle with the NJDEP for settlement of the state’s alleged natural resource damages claim. The parties then entered into a Consent Judgment which was subject to public notice and comment and court approval. The natural resource damage settlement includes a monetary award of $1 million and a series of remediation and restoration activities at the terminal site. KMLT and Plains Products have joint responsibility for this settlement. Simultaneously, KMLT and Plains Products entered into a settlement agreement that settled each parties’ relative share of responsibility (50/50) to the NJDEP under the Consent Judgment noted above. The Consent Judgment is now entered with the Court and the settlement is final. Now Plains will begin conducting remediation activities at the site and KMLT will provide oversight and 50% of the costs. The settlement with the state does not resolve the original complaint brought by ExxonMobil. KMLT and Plains received a settlement demand from ExxonMobil in the amount of $1.38 million for past costs related to the remediation at the Paulsboro facility. Plains and weKMLT are in ~~settlement~~ discussions ~~with~~regarding the ExxonMobil ~~and Plains.~~offer. There is no trial date set.

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~~methyl tertiary butyl ether (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 profit 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.

The Court issued a Case Management Order on January 6, 2011, setting dates for completion of discovery and setting a trial date. In April 2011, the parties filed a joint stipulation to extend the discovery schedule by approximately three months. In December 2011, the parties again entered into a joint stipulation to extend the various schedules in the Court’s Case Management Order. According to the schedule, the parties completed fact discovery in March 2012 and expert discovery in May 2012. Both parties filed their respective summary adjudication motions and motions to exclude experts on June 29, 2012. Oral arguments related to these motions are set for ~~August and September~~November 30, 2012. The trial is now set for ~~February 12,~~April 9, 2013. 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 conduct an extensive remediation effort at the City's stadium property site.

Kinder Morgan, U.S. EPA Section 114 Information Request

On January 8, 2010, ~~Kinder Morgan Inc.,~~KMI, on behalf of Natural Gas Pipeline Company of America LLC, Horizon Pipeline Company and Rockies Express, received a Clean Air Act Section 114 information request from the U.S. EPA, Region V. This

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information request requires that the three affiliated companies provide the U.S. EPA with air permit and various other information related to their natural gas pipeline compressor station operations located 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.

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Administrative Agreement with the U.S. EPA

In April 2011, we received Notices of Proposed Debarment from the U.S. EPA SDD. The Notices proposed the debarment of us (along with four of our subsidiaries), ~~Kinder Morgan, Inc.,~~KMI, Kinder Morgan G.P., Inc., and Kinder Morgan Management, LLC, from participation in future federal contracting and assistance activities. The Notices alleged that certain of the respondents’ past environmental violations indicated a lack of present responsibility warranting debarment.

In May 2012, we reached an administrative agreement with the U.S. EPA which resolved this matter without the debarment of any Kinder Morgan entities. The agreement requires independent monitoring of our Environmental Compliance and Ethics Programs, independent auditing of our facilities, enhanced training and notification requirements, and certain enhancements to our operational and compliance policies and procedures. We take environmental compliance very seriously and expect to comply with all aspects of this agreement.

TGP, PHMSA Notice of Violation

On April 25, 2012, the PHMSA issued an NOPV against TGP proposing $118,500 in penalties for alleged violations discovered during an inspection prior to Kinder Morgan's ownership of TGP. We responded to the NOPV and paid the penalty to resolve this matter.

Other Environmental

We are subject to environmental cleanup and enforcement actions from time to time. In particular, 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 there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies 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, financial position, results of operations or cash flows.

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.

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental

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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 ~~June~~September 30, 2012, we have accrued an environmental reserve of $71110 million (including $1 million of environmental related liabilities belonging to our FTC Natural Gas Pipelines disposal group). In addition, as of ~~June~~September 30, 2012, we have recorded a receivable of $5 million for expected cost recoveries that have been deemed probable. As of December 31, 2011, our environmental reserve totaled $75 million and our estimated receivable for environmental cost recoveries totaled $5 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

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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.

~~10.~~11. Regulatory Matters

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 ~~June~~September 30, 2012 and December 31, 2011 are not material to our consolidated balance sheets.

For information on our pipeline regulatory proceedings, see Note 910 “Litigation, Environmental and Other Contingencies—Federal Energy Regulatory Commission Proceedings” and “California Public Utilities Commission Proceedings.”

TGP's Proposed Sale of Production Area Facilities

On July 26, 2012, TGP filed an application with the FERC seeking authority to abandon by sale certain offshore and

onshore supply facilities as well as a related offer of settlement that addresses the proposed rate and accounting treatment

associated with the sale. The offer of settlement provides for a rate adjustment to TGP’s maximum tariff rates upon the transfer of the assets and the establishment of a regulatory asset for a portion of the unrecovered net book value of the facilities to be sold. The sale is conditioned on approval by the FERC of both the requested abandonment authorization and offer of settlement. As of September 30, 2012, these assets totaled$32 million and are included within "Assets held for sale" in our accompanying consolidated balance sheet. Additionally, we have recorded an approximately $115 million regulated asset, which is included within "Deferred charges and other assets" in our accompanying consolidated balance sheet as of September 30, 2012, for the portion of the loss that we expect to recover through TGP's jurisdictional transportation rates as outlined in the FERC filing.

TGP Northeast Supply Diversification Project (Docket No. CP11-30-000)

On September 10, 2011, the FERC issued an order authorizing the expansion of TGP's pipeline facilities in northern Pennsylvania and western New York along with an associated lease of transportation capacity from Dominion Transmission, Inc. in order to provide incremental firm transportation service to shippers of 250,000 dekatherms per day of natural gas produced in the Marcellus Shale supply area to northeast markets. The estimated capital cost of the project is $56 million and the capacity is fully subscribed under long-term contracts. The project is planned to be placed in service on November 1, 2012.

TGP Northeast Upgrade Project (Docket No. CP11-161-000)

On May 29, 2012, the FERC issued an order authorizing the expansion of TGP's pipeline facilities in Pennsylvania and New Jersey that will provide needed infrastructure to support continued development of Marcellus shale natural gas production and increase TGP's delivery capacity in the region by 636,000 dekatherms per day. The estimated capital cost of the project is approximately $376 million and the capacity is fully subscribed under long term contracts. The project is anticipated to be placed in service on November 1, 2013.

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TGP MPP Project (Docket No. CP12-28-000)

On August 9, 2012, the FERC issued an order authorizing the expansion of TGP's pipeline facilities in northwestern Pennsylvania that will provide needed infrastructure to support continued development of Marcellus shale natural gas production and increase TGP's delivery capacity in the region by 240,000 dekatherms per day. The estimated capital cost of the project is approximately $89 million, and the capacity is fully subscribed under long term contracts. The project is anticipated to be placed in service on November 1, 2013.

TGP Rose Lake Expansion Project (Docket No. CP13-03-000)

On October 10, 2012, TGP filed an application with the FERC requesting authority to expand its pipeline capacity in northern Pennsylvania through the installation and modification of new and existing compression facilities that will result in increased capacity of 230,000 dekatherms per day and will improve the efficiency and reduce emissions by replacing certain older existing compression facilities. The project will further support continued development of Marcellus shale natural gas production in the region. The estimated capital cost of the project is approximately $92 million and the capacity is fully subscribed under long term contracts. The project is anticipated to be placed in service on November 1, 2014.

EPNG Regulatory Matters

Docket No. RP08-426

In April 2010, the FERC approved an offer of settlement which increased EPNG's base tariff rates, effective January 1, 2009. The settlement resolved all but four issues in the proceeding. In January 2011, the presiding administrative law judge issued a decision that for the most part found against EPNG on those four issues. In May 2012, the FERC upheld the initial decision of the presiding administrative law judge in Opinion No. 517 on three of the issues and found in favor of EPNG on one of the issues. EPNG, along with other parties, has sought rehearing of those decisions to the FERC and may also seek review of any of the FERC's decisions to the U.S. Court of Appeals. However, in compliance with Opinion No. 517, EPNG filed with the FERC to implement certain aspects of the May 2012 order as they relate to rates under Docket No. RP08-426. Although the final outcome of all issues related to this open docket is not currently determinable, EPNG believes the accruals established for this matter are adequate.

Docket No. RP10-1398

In September 2010, EPNG filed a new rate case with the FERC proposing an increase in base tariff rates which would increase revenues by approximately $100 million annually over previously effective tariff rates. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. Hearings were conducted during the fourth quarter of 2011 and in June 2012, the presiding administrative law judge issued an initial decision which was overall favorable for EPNG. The initial decision is currently being reviewed by the FERC. Participants may appeal this decision to the FERC and ultimately seek review of the FERC's decision to the U.S. Court of Appeals. Additionally, certain customers have requested that the FERC require EPNG to decrease its currently effective recourse rates based on an order issued in May 2012 for matters in Docket No. RP08-426. The FERC issued an order requiring the implementation of its decisions in Docket No. RP08-426, which included interim reductions to the currently effective rates. Although EPNG requested rehearing on the interim rate decrease, EPNG filed proforma tariff records to comply with the FERC's order and requested adequate surcharge authority in the event the final rates are above the interim rates. That rehearing request and filing currently are pending before the FERC. EPNG is pursuing settlement with its customers of all issues in both open rate cases. It is uncertain whether the expected increase in revenues will be achieved in the context of any such settlement or following the final determination of the FERC or the courts on the rate matters. Although the final outcome is not currently determinable, EPNG believes the accruals established for this matter are adequate.

Docket No. CP12-6-000

On October 7, 2011, EPNG submitted an application, pursuant to Section 7(c) of the Natural Gas Act (NGA), requesting a certificate of public convenience and necessity authorizing the construction and operation of the Willcox Lateral 2013 Expansion Project located in Cochise County, Arizona. Concurrent with that application, EPNG also filed an application, pursuant to Section 3 of the NGA, for amended presidential permits to increase the export capacity of

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certain border crossings connected to the Willcox Lateral. At a cost of approximately $23 million, the project consists of modifications to the existing EPNG Willcox Compressor Station, increasing the maximum allowable operating pressure of the Willcox Lateral, replacing various pipeline road crossings, and upgrading existing meter stations. The new project facilities would create 185,000 dekatherms per day of incremental capacity on the Willcox Lateral. A FERC order approving this project was issued on October 12, 2012, with construction activities beginning shortly thereafter to permit a project in-service date by the second quarter 2013.

~~11.~~12. Recent Accounting Pronouncements

Accounting Standards Updates

None of the Accounting Standards Updates (ASU) that we adopted and that became effective January 1, 2012 (including ASU No. 2011-8, “Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment”) had a material impact on our consolidated financial statements.

ASU No. 2011-11

On December 16, 2011, the Financial Accounting Standards Board issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This ASU requires disclosures to provide information to help reconcile differences in the offsetting requirements under U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards. The disclosure requirements of this ASU mandate that entities disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an enforceable master netting arrangement or similar agreement. ASU No. 2011-11 also requires disclosure of collateral received and posted in connection with master netting arrangements or similar arrangements. The scope of this ASU includes derivative contracts, repurchase agreements, and securities borrowing and lending arrangements. Entities are required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. All disclosures provided by those amendments are required to be provided retrospectively for all comparative periods presented. We are currently reviewing the ~~effect~~effects of ASU No. 2011-11.

ASU No. 2012-02

On July 27, 2012, the Financial Accounting Standards Board issued ASU No. 2012-02, “Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment.” This ASU allows an entity the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not (that is, a likelihood of more than 50%) that an indefinite-lived intangible asset other than goodwill is impaired. If, after this assessment, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test prescribed by current accounting principles. Moreover, an entity can bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to the quantitative impairment test, and then resume performing the qualitative assessment in any subsequent period. ASU No. 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012 (January 1, 2013 for us), and early adoption is permitted. We are currently reviewing the effects of ASU No. 2012-02.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

General and Basis of Presentation

The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes (included elsewhere in this report); (ii) our consolidated financial statements and related notes included in our 2011 Form 10-K; and (iii) our management’s discussion and analysis of financial condition and results of operations included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

We prepared our consolidated financial statements in accordance with U.S. generally accepted accounting ~~principles~~principles. In addition, as discussed in Notes 1, 2, and ~~these~~3 to our consolidated financial statements ~~include~~ included elsewhere in this report,

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our financial statements reflect:

the reclassifications necessary to reflect the results of our FTC Natural Gas Pipelines disposal group as discontinued operations. Accordingly, we have excluded the disposal group’s financial results from our Natural Gas Pipelines business segment disclosures for all periods presented in this ~~report. For more~~report; and

our August 1, 2012 acquisition of net assets from KMI as if such acquisition had taken place on May 25, 2012, the effective date that KMI acquired the same net assets from El Paso Corporation. We refer to this transfer of net assets from KMI to us as the drop-down transaction, and we refer to the transferred assets as our drop-down asset group. We accounted for the drop-down transaction as a transfer of net assets between entities under common control, and accordingly, the financial information ~~about our discontinued operations, see Notes 1 and 2 to our consolidated financial statements included elsewhere~~contained in this ~~report.~~Management's Discussion and Analysis of Financial Condition and Results of Operations include the financial results of the drop-down asset group for all periods subsequent to May 25, 2012.

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Critical Accounting Policies and Estimates

Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of U.S. generally accepted accounting principles involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Furthermore, with regard to goodwill impairment testing, we review our goodwill for impairment annually, and we evaluated our goodwill for impairment on May 31, 2012. Our goodwill impairment analysis performed on that date did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units (including its inherent goodwill) is less than the carrying value of its net assets.

Further information about us and information regarding our accounting policies and estimates that we consider to be “critical” can be found in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2011 Form 10-K and our Current Report on Form 8-K filed May 1, 2012.

Results of Operations

In our discussions of the operating results of individual businesses that follow, we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods.

Consolidated

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	Three Months Ended June 30,											Three Months Ended September 30,
	2012			2011			Earnings increase/(decrease)					2012			2011			Earnings increase/(decrease)
	(In millions, except percentages)											(In millions, except percentages)
Segment earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Products Pipelines(b)	$	166		$	21		$	145		690	%	$	150		$	103		$	47		46	%
Natural Gas Pipelines(c)	190			135			55			41	%	405			18			387			2,150	%
CO₂~~(c)~~(d)	327			266			61			23	%	327			295			32			11	%
Terminals~~(d)~~(e)	195			171			24			14	%	183			180			3			2	%
Kinder Morgan Canada~~(e)~~	52			54			(2		)	(4	)%	56			48			8			17	%
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	930			647			283			44	%	1,121			644			477			74	%
Depreciation, depletion and amortization expense(f)	(248		)	(223		)	(25		)	(11	)%	(292		)	(247		)	(45		)	(18	)%
Amortization of excess cost of equity investments	(2		)	(2		)	—			—	%	(1		)	(2		)	1			50	%
General and administrative expense~~(f)~~(g)	(98		)	(98		)	—			—	%	(131		)	(100		)	(31		)	(31	)%
Interest expense, net of unallocable interest income(h)	(141		)	(129		)	(12		)	(9	)%	(181		)	(132		)	(49		)	(37	)%
Unallocable income tax expense	(3		)	(3		)	—			—	%	(2		)	(2		)	—			—	%
Income from continuing operations	438			192			246			128	%	514			161			353			219	%
Income (Loss) from discontinued operations~~(g)~~(i)	(279		)	40			(319		)	(798	)%	(131		)	55			(186		)	(338	)%
Net Income	159			232			(73		)	(31	)%	383			216			167			77	%
Net (Income) Loss attributable to noncontrolling interests(h)	(6		)	(2		)	(4		)	(200	)%
Net Income (Loss) attributable to Kinder Morgan Energy Partners, L.P.	153			$	230		(77		)	(33	)%
Net Income attributable to noncontrolling interests(j)												(4		)	(1		)	(3		)	(300	)%
Net Income attributable to Kinder Morgan Energy Partners, L.P.												$	379		$	215		$	164		76	%

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	Six Months Ended June 30,											Nine Months Ended September 30,
	2012			2011			Earnings increase / (decrease)					2012			2011			Earnings increase / (decrease)
	(In millions, except percentages)											(In millions, except percentages)
Segment earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Products Pipelines~~(b)~~(k)	$	342		$	201		$	141		70	%	$	492		$	304		$	188		62	%
Natural Gas Pipelines(l)	412			301			111			37	%	877			319			558			175	%
CO₂~~(i)~~(m)	661			528			133			25	%	988			823			165			20	%
Terminals~~(j)~~(n)	382			345			37			11	%	565			525			40			8	%
Kinder Morgan Canada~~(e)~~(o)	102			102			—			—	%	158			150			8			5	%
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	1,899			1,477			422			29	%	3,080			2,121			959			45	%
Depreciation, depletion and amortization expense(p)	(487		)	(438		)	(49		)	(11	)%	(796		)	(685		)	(111		)	(16	)%
Amortization of excess cost of equity investments	(4		)	(3		)	(1		)	(33	)%	(5		)	(5		)	—			—	%
General and administrative expense~~(k)~~(q)	(205		)	(287		)	82			29	%	(379		)	(387		)	8			2	%
Interest expense, net of unallocable interest income(r)	(280		)	(261		)	(19		)	(7	)%	(474		)	(393		)	(81		)	(21	)%
Unallocable income tax expense	(5		)	(5		)	—			—	%	(7		)	(7		)	—			—	%
Income from continuing operations	918			483			435			90	%	1,419			644			775			120	%
Income (Loss) from discontinued operations~~(l)~~(s)	(551		)	90			(641		)	(712	)%	(682		)	145			(827		)	(570	)%
Net Income	367			573			(206		)	(36	)%	737			789			(52		)	(7	)%
Net (Income) Loss attributable to noncontrolling interests(m)	(8		)	(5		)	(3		)	(60	)%
Net Income attributable to noncontrolling interests(t)												(12		)	(6		)	(6		)	(100	)%
Net Income (Loss) attributable to Kinder Morgan Energy Partners, L.P.	$	359		$	568		$	(209	)	(37	)%	$	725		$	783		$	(58	)	(7	)%

____________


(a)	Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other expense (income). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

(b)

~~2011~~2012 amount includes a ~~$165~~$34 million increase in expense associated with environmental liability adjustments, a $9 million increase in expense associated with rate case liability adjustments, and an ~~$11~~$8 million ~~increase in income~~gain from the disposal of property related to the sale of a portion of our former Gaffey Street terminal land, located in San Pedro, California. 2011 amount includes a $69 million increase in expense associated with rate case, leased rights-of-way and other legal liability adjustments, and a $6 million increase in expense associated with environmental liability adjustments.

(c)

2012 amount includes (i) earnings of $71 million attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012; (ii) a $7$1 million ~~gain~~increase in expense related to hurricane clean-up and repair activities; and (iii) a $1 million decrease in income from ~~the sale of our ownership interest in the Claytonville oil field unit.~~incremental severance expenses. 2011 amount includes a $2$167 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value.


(d)	2012 and 2011 amounts include a $5 million decrease in income and an $8 million increase in income, respectively, from unrealized gains and losses on derivative contracts used to hedge forecast crude oil sales.

~~(d)~~(e)

2012 amount includes a ~~$12~~$1 million ~~casualty indemnification gain~~increase in expense related to ~~a 2010 casualty at our Port Sulphur, Louisiana, International Marine Terminal facility.~~hurricane clean-up and repair activities. 2011 amount includes (i) a $4 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal; (ii) a $2 million increase in income associated with the sale of a 51% ownership interest in two of our subsidiaries: River Consulting LLC and Devco USA L.L.C.; and (iii) a $1 million increase in expense associated with ~~environmental liability adjustments.~~

~~(e)~~

~~2011 amount includes~~storm damage and repair activities at our Carteret, New Jersey liquids terminal; (ii) a $2$1 million ~~decrease~~loss from property write-offs associated with the on-going dissolution of our partnership interest in ~~expense (reflecting tax savings) related to non-cash compensation expense allocated to us~~Globalplex Handling; and (iii) a $1 million gain from ~~KMI (however, we do not have any obligation, nor did we pay any amounts related to this compensation expense).~~the sale of our ownership interest in Arrow Terminals B.V.


(f)	~~2011~~2012 amount includes a $14 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012.

(g)

2012 amount includes (i) a $13 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012; (ii) a $3 million increase in unallocated severance expenses; and (iii) a $2 million increase in expense for certain asset and business acquisition costs. 2011 amount includes (i) a $1 million decrease in unallocated payroll tax expense (related to an $87 million special bonus expense to non-senior management employees allocated to us from KMI in the first quarter of 2011); however, we do not have any obligation, nor did we pay any amounts related to this compensation ~~expense.~~expense; and (ii) a $1 million increase in expense for certain asset and business acquisition costs.


~~(g)~~(h)	2012 amount includes an $8 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012, and a $1 million increase in expense attributable to incremental fees related to our short-term

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bridge loan credit facility.

(i)

Represents amounts attributable to our FTC Natural Gas Pipelines disposal group. 2012 amount consists of a ~~$279~~$131 million loss before depreciation, depletion and amortization expense and amortization of excess cost of equity investments (including a ~~$327~~combined $178 million ~~non-cash~~ loss from ~~remeasurements~~both costs to sell and the remeasurement of net assets to fair value). 2011 amount consists of ~~(i) $46~~$62 million of earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments, ~~(including a $10 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011);~~ and ~~(ii) $6~~$7 million of depreciation and amortization expense.


~~(h)~~(j)	2012 and 2011 amounts include ~~increases~~decreases of $1 million and ~~decreases of~~ $3 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the three month 2012 and 2011 items previously disclosed in these footnotes.

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~~in these footnotes.~~

(k)

2012 amount includes a $34 million increase in expense associated with environmental liability adjustments, a $9 million increase in expense associated with rate case liability adjustments, and an $8 million gain from the disposal of property related to the sale of a portion of our former Gaffey Street terminal land. 2011 amount includes (i) a $234 million increase in expense associated with rate case, leased rights-of-way, and other legal liability adjustments; (ii) a $6 million increase in expense associated with environmental liability adjustments; and (iii) an $11 million gain from the disposal of property related to the sale of a portion of our former Gaffey Street terminal land.

(l)

2012 amount includes (i) earnings of $131 million attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012; (ii) a $1 million increase in expense related to hurricane clean-up and repair activities; and (iii) a $1 million decrease in income from incremental severance expenses. 2011 amount includes a $167 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value.


(m)	2012 and 2011 amounts include ~~a $3~~an $8 million decrease in income and a $2$10 million increase in income, respectively, from unrealized gains and losses on derivative contracts used to hedge forecast crude oil sales. 2012 amount also includes a $7 million gain from the sale of our ownership interest in the Claytonville oil field unit.

~~(j)~~(n)

2012 amount includes a $12 million casualty indemnification gain related to a 2010 casualty at our Port Sulphur, Louisiana, International Marine Terminal ~~facility.~~facility, and a $1 million increase in expense related to hurricane clean-up and repair activities. 2011 amount includes (i) a $5 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (however, we do not have any obligation, nor did we pay any amounts related to this compensation expense); (ii) a $4 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal; (iii) a combined $2 million increase in income from adjustments associated with the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009; (iv) a combined $2 million increase in income associated with the sale of a 51% ownership interest in two of our subsidiaries: River Consulting LLC and Devco USA L.L.C.; (v) a $2$1 million ~~decrease~~gain from the sale of our ownership interest in ~~income from casualty insurance deductibles and the write-off of assets related to casualty losses;~~Arrow Terminals B.V.; (vi) a $1$4 million increase in expense at our Carteret terminal, associated with storm and fire damage and repair activities, environmental liability adjustments, and the settlement of a certain litigation ~~matter at our Carteret, New Jersey liquids terminal; and~~matter; (vii) a $1 million ~~increase in expense~~loss from property write-offs associated with ~~environmental liability adjustments.~~the on-going dissolution of our partnership interest in Globalplex Handling; and (viii) a $1 million loss from property write-offs associated with the 2010 casualty at our International Marine Terminal facility.


~~(k)~~(o)	2011 amount includes a $2 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (however, we do not have any obligation, nor did we pay any amounts related to this compensation expense).


(p)	2012 amount includes a $1$31 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012.

(q)

2012 amount includes (i) a $56 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012; (ii) a $4 million increase in unallocated severance expenses; and (iii) a $2 million increase in expense ~~associated with~~for certain ~~Terminal operations.~~asset and business acquisition costs. 2011 amount includes (i) a combined $90 million increase in non-cash compensation expense (including $87 million related to a special bonus expense to non-senior management employees) allocated to us from KMI in the first quarter of 2011; however, we do not have any obligation, nor did we pay any amounts related to this compensation expense; (ii) a $2 million increase in expense for certain asset and business acquisition costs; and (iii) a $1 million increase in unallocated payroll tax expense (related to an $87 million special bonus expense to non-senior management employees allocated to us from KMI in the first quarter of 2011); however, we do not have any obligation, nor did we pay any amounts related to this compensation ~~expense;~~expense.


(r)	2012 amount includes a $21 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012, and ~~(iii)~~ a $1 million increase in expense ~~for certain asset and business acquisition costs.~~attributable to incremental fees related to our short-term bridge loan credit facility.

~~(l)~~(s)

Represents amounts attributable to our FTC Natural Gas Pipelines disposal group. 2012 amount consists of (i) a ~~$544~~$675 million loss before depreciation, depletion and amortization expense and amortization of excess cost of equity investments (including a ~~$649~~combined $827 million ~~non-cash~~ loss from ~~remeasurements~~both costs to sell and the remeasurement of net assets to fair value); and (ii) $7 million of depreciation and amortization expense. 2011 amount consists of (i) ~~$103~~$165 million of earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments (including a $10 million increase in expense from the ~~write-off of a receivable for fuel under-collected prior to 2011); and (ii) $13 million of depreciation and amortization expense.~~

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write-off of a receivable for fuel under-collected prior to 2011); and (ii) $20 million of depreciation and amortization expense.


~~(m)~~(t)	2012 and 2011 amounts include decreases of $2$4 million and $4$7 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the ~~six~~nine month 2012 and 2011 items previously disclosed in these footnotes.

~~Because~~As more fully described in our 2011 Form 10-K and our Current Report on Form 8-K filed May 1, 2012, we own and manage a diversified portfolio of energy transportation and storage assets, and primarily, our business model is designed to generate stable, fee-based income that provides overall long-term value to our unitholders. Our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash as defined in our partnership agreement generally consists of all our cash receipts, less cash disbursements and changes in reserves),. Distributable cash flow, sometimes referred to as DCF, is an overall performance metric we use as a measure of available cash, and the calculation of our DCF, for each of the three and nine month periods ended September 30, 2012 and 2011 is as follows (calculated before the combined effect from all of the three and nine month certain items disclosed in the footnotes to the tables above):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(In millions)
Net Income	$	383		$	216		$	737		$	789
Add-back: Certain items - combined expense(a)	191			235			838			479
Net Income before certain items	574			451			1,575			1,268
Less: Net Income before certain items attributable to noncontrolling interests	(5		)	(4		)	(16		)	(13		)
Net Income before certain items attributable to Kinder Morgan Energy Partners, L.P.	569			447			1,559			1,255
Less: General Partner's interest in Net Income before certain items(b)	(367		)	(301		)	(1,025		)	(876		)
Limited Partners' interest in Net Income before certain items	202			146			534			379
Depreciation, depletion and amortization(c)	331			292			913			834
Book (cash) taxes paid, net	—			9			7			19
Incremental contributions from equity investments in the Express Pipeline and Endeavor Gathering LLC	—			2			3			8
Sustaining capital expenditures(d)	(78		)	(55		)	(174		)	(140		)
Distributable cash flow (DCF) before certain items	$	455		$	394		$	1,283		$	1,100

____________


(a)	Equal to the combined effect from all of the three and nine month 2012 and 2011 items previously disclosed in the footnotes to the tables included above.


(b)	Three and nine month 2012 amounts include decreases in income of $6 million and$19 million, respectively, and three and nine month 2011 amounts include decreases in income of $7 million and $21 million, respectively, for waived incentive amounts related to common units issued to finance a portion of our May 2010 KinderHawk Field Services LLC acquisition.

(c)

Three and nine month 2012 amounts include increases in expense of $52 million and $136 million, respectively, and three and nine month 2011 amounts include increases in expense of $36 million and $124 million, respectively, for our proportionate share of the depreciation expenses of (i) Rockies Express Pipeline LLC; (ii) Midcontinent Express Pipeline LLC; (iii) Fayetteville Express Pipeline LLC; (iv) Cypress Interstate Pipeline LLC; (v) EagleHawk Field Services LLC; (vi) Red Cedar Gathering LLC; (vii) for 2012 amounts only, Eagle Ford Gathering LLC, El Paso Midstream Investment Company LLC, El Paso Natural Gas Pipeline LLC and Bear Creek Storage LLC; and (viii) for 2011 amounts only, KinderHawk Field Services LLC.

(d)

Three and nine month 2012 amounts include increases in expenditures of $8 million and $13 million, respectively, and nine month 2011 amount includes an increase in expenditures of $3 million, all for our proportionate share of the sustaining capital expenditures of (i) Rockies Express Pipeline LLC; (ii) Midcontinent Express Pipeline LLC; (iii) Fayetteville Express Pipeline LLC; (iv) Cypress Interstate Pipeline LLC; (v) EagleHawk Field Services LLC; (vi) Eagle Ford Gathering LLC; (vii) Red Cedar Gathering LLC; (viii) El Paso Natural Gas Pipeline LLC; (ix) Bear Creek Storage LLC; and (x) El Paso Midstream Investment Company, LLC.

Table of Contents

With regard to our reportable business segments, we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. We also use segment earnings before depreciation, depletion and amortization expenses (defined in the table above and sometimes referred to in this report as EBDA) internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our five reportable business segments.

For the comparable ~~second~~third quarter periods of 2012 and 2011, our total segment earnings before depreciation, depletion and amortization expenses increased ~~$283~~$477 million ~~(44%~~(74%) in 2012; however, this overall increase in earnings:

▪

included a ~~$168~~$263 million increase in earnings before depreciation, depletion and amortization expenses from the effect of the certain items described in footnotes (b), (c), (d), and (e) to the table above (which combined to increase total segment EBDA by ~~$19~~$28 million in the ~~second~~third quarter of 2012 and decrease segment EBDA by ~~$149~~$235 million in the ~~second~~third quarter of 2011); and


▪	excluded ~~an $8~~a $15 million decrease in earnings before depreciation, depletion and amortization expenses from discontinued operations (as described in footnote ~~(g)~~(i) to the table above and excluding ~~both~~ the ~~$327~~combined $178 million ~~non-cash~~ loss from both costs to sell and the remeasurement of net assets to fair value in the ~~second~~third quarter of 2012).

After adjusting for these two items, the remaining $199 million (21%) increase in quarterly segment earnings before depreciation, depletion and amortization resulted primarily from better performance in the third quarter of 2012 from all five of our business segments.

For the comparable nine month periods, total segment earnings before depreciation, depletion and amortization expenses increased $959 million (45%) in 2012; however, this overall increase:


▪	included a $480 million increase in earnings before depreciation, depletion and amortization expenses from the effect of the certain items described in footnotes (k), (l), (m), (n) and (o) to the table above (which combined to increase total segment EBDA by $104 million in the first nine months of 2012 and decrease segment EBDA by $376 million in the first nine months of 2011); and

▪

excluded a $23 million decrease in earnings before depreciation, depletion and amortization expenses from discontinued operations (as described in footnote (s) to the table above and excluding both the combined $827 million loss from costs to sell and the remeasurement of net assets to fair value in the first nine months of 2012 and the $10 million increase in expense in the ~~second~~third quarter of 2011 from the write-off of a receivable for fuel under-collected prior to 2011).

After adjusting for these two items, the remaining ~~$107~~$456 million ~~(13%) increase in quarterly segment earnings before depreciation, depletion and amortization resulted from better performance in the second quarter of 2012 from our CO~~_2,~~Natural Gas Pipelines, and Terminals business segments, partially offset by lower earnings from our Products Pipelines~~

~~Table of Contents~~

~~business segment.~~

~~For the comparable six month periods, total segment earnings before depreciation, depletion and amortization expenses increased $422 million (29%) in 2012; however, this overall increase:~~


▪	included a $157 million increase in earnings before depreciation, depletion and amortization from the effect of the certain items described in footnotes (b), (e), (i), and (j) to the table above (which combined to increase total segment EBDA by $16 million in the first six months of 2012 and decrease segment EBDA by $141 million in the first six months of 2011); and

▪

excluded an $8 million decrease in earnings before depreciation, depletion and amortization expenses from discontinued operations (as described in footnote (l) to the table above and excluding both the $649 million non-cash loss from the remeasurement of net assets to fair value in the first six months of 2012 and the $10 million increase in expense in the second quarter of 2011 from the write-off of a receivable for fuel under-collected prior to 2011).

~~After adjusting for these two items, the remaining $257 million (15%~~(17%) increase in segment earnings before depreciation, depletion and amortization in the first ~~half~~nine months of 2012 versus the first ~~half~~nine months of 2011 resulted from higher earnings from our Natural Gas Pipelines, CO₂, ~~Natural Gas Pipelines,~~and Terminals, and Kinder Morgan Canada business segments, partially offset by lower earnings from our Products Pipelines business segment.

Products Pipelines

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	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
	(In millions, except operating statistics)												(In millions, except operating statistics)
Revenues	$	331		$	228		$	554		$	453		$	386		$	242		$	940		$	695
Operating expenses(a)	(184		)	(228		)	(241		)	(280		)	(256		)	(146		)	(497		)	(426		)
Other income(b)	—			11			—			11
Other income (expense)(b)													7			(1		)	7			10
Earnings from equity investments	15			12			29			23			14			12			43			35
Interest income and Other, net	8			2			10			3			1			1			11			4
Income tax (expense) benefit	(4		)	(4		)	(10		)	(9		)	(2		)	(5		)	(12		)	(14		)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	166		$	21		$	342		$	201		$	150		$	103		$	492		$	304

Gasoline (MMBbl)(c)	99.7			99.6			194.8			195.5			98.1			101.7			292.9			297.2
Diesel fuel (MMBbl)	35.8			36.9			69.4			73.5			36.3			37.2			105.7			110.7
Jet fuel (MMBbl)	28.8			29.2			55.7			54.8			28.3			28.1			84.0			82.9
Total refined product volumes (MMBbl)	164.3			165.7			319.9			323.8			162.7			167.0			482.6			490.8
Natural gas liquids (MMBbl)	7.2			5.6			14.6			12.2			8.5			7.6			23.1			19.8
Total delivery volumes (MMBbl)(d)	171.5			171.3			334.5			336.0			171.2			174.6			505.7			510.6
Ethanol (MMBbl)(e)	7.8			7.7			15.1			15.0			8.9			8.0			24.1			23.0

____________

(a)

Three and ~~six~~nine month ~~2011~~2012 amounts include a ~~$165~~$34 million increase in expense associated with environmental liability adjustments, and a $9 million increase in expense associated with rate case liability adjustments. Three and nine month 2011 amounts include increases in expense of $69 million and $234 million, respectively, associated with rate case, leased rights-of-way and other legal liability adjustments, and a $6 million increase in expense associated with environmental liability adjustments.


(b)	Three and ~~six~~nine month 2012 amounts include a gain of $8 million, and nine month 2011 ~~amounts represent an~~amount includes a gain of $11 million, ~~increase in income~~all from the disposal of property related to the sale of a portion of our former Gaffey Street terminal ~~land, located in San Pedro, California.~~land.


(c)	Volumes include ethanol pipeline volumes.


(d)	Includes Pacific, Plantation, Calnev, Central Florida, Cochin and Cypress pipeline volumes.


(e)	Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.

~~Table of Contents~~

~~The~~Combined, the certain items described in footnotes (a) and (b) to the table above ~~increased our Product Pipelines’~~accounted for increases in segment earnings before depreciation, depletion and amortization expenses ~~by $154~~of $40 million in ~~both~~ the ~~second~~third quarter of 2012, and $194 million in the the first ~~six~~nine months of 2012, when compared to the same two periods of 2011. Following is information, for each of the comparable three and ~~six~~nine month periods of 2012 and 2011, related to the segment’s (i) remaining ~~$9 million (5%) and $13~~$7 million (4%) ~~decreases~~increase and $6 million (1%) decrease in earnings before depreciation, depletion and amortization; and (ii) ~~$103~~$144 million ~~(45%~~increase (60%) and ~~$101~~$245 million ~~(22%~~(35%) ~~increases~~increase in operating revenues:

Three months ended June 30, 2012 versus Three months ended June 30, 2011
Three months ended September 30, 2012 versus Three months ended September 30, 2011											Three months ended September 30, 2012 versus Three months ended September 30, 2011

	EBDA increase/(decrease)					Revenues increase/(decrease)					EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Transmix operations	$	(13	)	(151	)%	$	108		842	%	$	3		34	%	$	152		1,344	%
Cochin Pipeline											2			15	%	(5		)	(18	)%
Southeast Terminals											2			11	%	—			—	%
Calnev Pipeline											(2		)	(15	)%	(2		)	(10	)%
Pacific operations	(8		)	(10	)%	(7		)	(6	)%	(1		)	(2	)%	(5		)	(4	)%
Cochin Pipeline	10			137	%	2			19	%
Plantation Pipeline	2			16	%	—			—	%
All others (including eliminations)	—			—	%	—			—	%	3			7	%	4			9	%
Total Products Pipelines	$	(9	)	(5	)%	$	103		45	%	$	7		4	%	$	144		60	%

____________

Table of Contents

Six months ended June 30, 2012 versus Six months ended June 30, 2011
Nine months ended September 30, 2012 versus Nine months ended September 30, 2011											Nine months ended September 30, 2012 versus Nine months ended September 30, 2011

	EBDA increase/(decrease)					Revenues increase/(decrease)					EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Pacific operations	$	(16	)	(10	)%	$	(10	)	(5	)%	$	(17	)	(7	)%	$	(15	)	(5	)%
Transmix operations	(14		)	(80	)%	107			427	%	(11		)	(44	)%	259			713	%
Calnev Pipeline											(6		)	(14	)%	(4		)	(7	)%
Cochin Pipeline	10			41	%	2			7	%	12			30	%	(3		)	(5	)%
Plantation Pipeline	4			14	%	1			6	%	3			8	%	1			6	%
All others (including eliminations)	3			3	%	1			1	%	13			8	%	7			4	%
Total Products Pipelines	$	(13	)	(4	)%	$	101		22	%	$	(6	)	(1	)%	$	245		35	%

The primary increases and decreases in our Products Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in the comparable three and ~~six~~nine month periods of 2012 and 2011 included the following:

▪

~~decreases~~an increase of ~~$13~~$3 million ~~(151%~~(34%) and ~~$14~~a decrease of $11 million ~~(80%~~(44%), respectively, from our transmix processing ~~operations—due primarily to lower earnings in the second quarter of 2012.~~operations. The quarter-to-quarter ~~decrease~~increase in earnings was driven by ~~both an $8 million~~favorable pricing. The drop in ~~gross margin (due mainly~~earnings across the comparable nine month periods was primarily due to ~~an 18%~~a decrease in processing ~~volumes)~~volumes and ~~a $4 million decrease due to~~ unfavorable net carrying value adjustments to product inventory. The period-to-period increases in revenues were due mainly to the expiration of certain transmix fee-based processing agreements in March 2012. ~~The expiring contracts provided for transmix processing at certain of our facilities to be performed by us for third parties under a "for fee" basis.~~ Due to the expiration of these contracts, ~~and our assumption of additional marketing rights,~~ we now directly purchase incremental volumes of transmix and sell incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;

▪

increases of $2 million (15%) and $12 million (30%), respectively, from our Cochin Pipeline—the increase in earnings in the comparable quarterly periods was primarily due to a favorable income tax adjustment. The increase in earnings across the comparable year-to-date periods was largely due to a 25% increase in pipeline throughput volumes (due in part to completed expansion projects since the end of the third quarter of 2012), and to the favorable settlement of a pipeline access dispute;


▪	decreases of $8$2 million ~~(10%~~(15%) and ~~$16~~$6 million ~~(10%~~(14%), respectively, from our Calnev Pipeline—chiefly due to lower period-to-period delivery volumes that were due in part to incremental services offered by a competing pipeline;


▪	for the comparable three month periods, a $2 million (11%) increase from our Southeast terminal operations—due mainly to increased throughput volumes of refined products and biofuels;

▪

decreases of $1 million (2%) and $17 million (7%), respectively, from our Pacific ~~operations—driven~~operations. Earnings were essentially flat across both quarterly periods, but decreased in the comparable nine month periods due primarily byto lower ~~mainline~~operating revenues. Mainline transportation revenues ~~resulting from~~dropped in the first nine months of 2012, due largely to lower average FERC tariffs as a result of rate case rulings settlements made since the end of the ~~second~~third quarter of 2011; and ~~for the comparable six month periods, by higher operating expenses related to certain rights-of-way obligations and legal matters;~~


▪	~~increases~~ for the comparable nine month periods, an increase of ~~$10~~$3 million ~~(137%~~(8%) and $10 million (41%), respectively, from our Cochin Pipeline—chiefly due to higher revenues, due to an 87% increase in pipeline throughput volumes, and to higher non-operating other income from the favorable settlement of a pipeline access dispute; and

~~Table of Contents~~


▪	~~increases of $2 million (16%) and $4 million (14%), respectively,~~ from our approximate 51% interest in the Plantation pipeline system—due ~~primarily~~largely to higher transportation revenues driven by higher average tariff rates since the end of the ~~second~~third quarter of 2011.

Natural Gas Pipelines

Table of Contents


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
	(In millions, except operating statistics)												(In millions, except operating statistics)
Revenues(a)	$	693		$	963		$	1,487		$	1,906		$	1,113		$	1,093		$	2,699		$	2,999
Operating expenses(b)	(543		)	(864		)	(1,151		)	(1,669		)	(783		)	(939		)	(1,966		)	(2,608		)
Earnings from equity investments	39			37			77			66
Interest income and Other, net	1			1			1			1
Other expense													(1		)	—			(1		)	—
Earnings from equity investments(c)													75			29			145			95
Interest income and Other, net(d)													2			(165		)	3			(164		)
Income tax (expense) benefit	—			(2		)	(2		)	(3		)	(1		)	—			(3		)	(3		)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments from continuing operations	190			135			412			301			405			18			877			319
Discontinued operations(a)	(279		)	46			(544		)	103
Discontinued operations(e)													(131		)	62			(675		)	165
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments including discontinued operations	$	(89	)	$	181		$	(132	)	$	404		$	274		$	80		$	202		$	484

Natural gas transport volumes (Bcf)(b)	795.3			749.9			1,531.3			1,457.6
Natural gas sales volumes (Bcf)(c)	215.6			192.4			428.4			383.6
Natural gas transport volumes (Bcf)(f)													1,772.1			1,598.1			5,175.8			4,708.9
Natural gas sales volumes (Bcf)(f)													228.7			215.1			657.2			598.7

____________


(a)	Three and nine month 2012 amounts include increases of $82 million and $181 million, respectively, attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012.


(b)	Three and nine month 2012 amounts include (i) increases of $19 million and $51 million, respectively, attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012; and (ii) a $1 million increase in expense related to hurricane clean-up and repair activities.


(c)	Three and nine month 2012 amounts include a $1 million decrease in earnings from incremental severance expenses. Three month 2012 amount also includes an increase of $7 million attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012.


(d)	Three and nine month 2012 amounts include an increase of $1 million attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012. Three and nine month 2011 amounts include a $167 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value.

(e)

Represents earnings (losses) before depreciation, depletion and amortization expense attributable to our FTC Natural Gas Pipelines disposal group. Three and ~~six~~nine month 2012 amounts include ~~non-cash~~ losses of ~~$327~~$178 million and ~~$649~~$827 million, respectively, from ~~remeasurements~~both incremental selling expenses and the remeasurement of ~~the FTC Natural Gas Pipelines disposal group~~net assets to fair value. ~~Three and six~~Nine month 2011 ~~amounts include~~amount includes a $10 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011. Three and ~~six~~nine month 2012 amounts also include revenues of ~~$62~~$71 million and ~~$133~~$204 million, respectively, and three and ~~six~~nine month 2011 amounts also include revenues of ~~$82~~$83 million and ~~$158~~$241 million, respectively.

~~(b)~~(f)

Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC, Fayetteville Express Pipeline LLC, Rockies Express Pipeline LLC, Tennessee Gas Pipeline L.L.C., El Paso Natural Gas Pipeline LLC and Texas intrastate natural gas pipeline group pipeline volumes.


~~(c)~~	~~Represents Texas intrastate natural gas pipeline group volumes.~~ Volumes for acquired pipelines are included for all periods.

~~When compared to the same two periods of 2011,~~Combined, the certain items described in ~~footnote~~footnotes (a) through (e) to the table above ~~decreased~~increased our Natural Gas Pipelines business segment’s earnings before depreciation, depletion and amortization (including discontinued operations) by ~~$317~~$58 million in the third quarter of 2012, and decreased earnings before depreciation, depletion and amortization by $521 million in the first nine months of 2012, when compared to the same prior year periods. The certain items also accounted for increases of $82 million and ~~$639~~$181 million, respectively, in ~~the second quarter~~segment revenues for both comparable three and ~~first six months of 2012.~~nine month periods. Following is information, for each of the comparable three and ~~six~~nine month periods of 2012 and 2011 and including discontinued operations, related to the increases and decreases in the segment’s (i) remaining ~~$47~~$136 million ~~(25%~~(55%) and ~~$103~~$239 million ~~(25%~~(36%) increases in earnings before depreciation, depletion and amortization; and (ii) ~~$290~~remaining $74 million ~~(28%~~(6%) and ~~$444~~$518 million ~~(22%~~(16%) decreases in operating revenues:

4047

Table of Contents

Three months ended June 30, 2012 versus Three months ended June 30, 2011
Three months ended September 30, 2012 versus Three months ended September 30, 2011											Three months ended September 30, 2012 versus Three months ended September 30, 2011

	EBDA increase/(decrease)					Revenues increase/(decrease)					EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Tennessee Gas Pipeline											$	124		n/a		$	166		n/a
El Paso Natural Gas Pipeline(b)											15			n/a		n/a			n/a
Kinder Morgan Treating operations											13			119	%	30			191	%
Eagle Ford Gathering(b)											9			529	%	n/a			n/a
Fayetteville Express Pipeline(b)											7			118	%	n/a			n/a
Texas Intrastate Natural Gas Pipeline Group											(12		)	(17	)%	(252		)	(25	)%
KinderHawk Field Services(a)	$	31		246	%	$	50		n/a		(3		)	(7	)%	(1		)	(2	)%
Kinder Morgan Treating operations	11			99	%	27			170	%
Fayetteville Express Pipeline(b)	9			171	%	n/a			n/a
Eagle Ford Gathering(b)	4			n/a		n/a			n/a
EagleHawk Field Services(b)	2			n/a		n/a			n/a
Texas Intrastate Natural Gas Pipeline Group	(2		)	(4	)%	(347		)	(38	)%
All others (including eliminations)	—			—	%	—			—	%	(2		)	(4	)%	(5		)	(15	)%
Total Natural Gas Pipelines-continuing operations	$	55		41	%	$	(270	)	(28	)%	151			82	%	(62		)	(6	)%
Discontinued operations(c)	(8		)	(14	)%	(20		)	(25	)%	(15		)	(24	)%	(12		)	(14	)%
Total Natural Gas Pipelines-including discontinued operations	$	47		25	%	$	(290	)	(28	)%	$	136		55	%	$	(74	)	(6	)%

____________

Six months ended June 30, 2012 versus Six months ended June 30, 2011
Nine months ended September 30, 2012 versus Nine months ended September 30, 2011											Nine months ended September 30, 2012 versus Nine months ended September 30, 2011

	EBDA increase/(decrease)					Revenues increase/(decrease)					EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Tennessee Gas Pipeline											$	124		n/a		$	166		n/a
KinderHawk Field Services(a)	$	66		296	%	$	101		n/a		63			93	%	100			203	%
Kinder Morgan Treating operations											31			95	%	74			155	%
Fayetteville Express Pipeline(b)	21			371	%	n/a			n/a		28			239	%	n/a			n/a
Kinder Morgan Treating operations	18			84	%	44			137	%
Eagle Ford Gathering(b)	6			n/a		n/a			n/a		15			919	%	n/a			n/a
EagleHawk Field Services(b)	5			n/a		n/a			n/a
El Paso Natural Gas Pipeline(b)											15			n/a		n/a			n/a
Texas Intrastate Natural Gas Pipeline Group	(7		)	(4	)%	(564		)	(31	)%	(19		)	(8	)%	(816		)	(29	)%
All others (including eliminations)	2			2	%	—			—	%	5			4	%	(5		)	(5	)%
Total Natural Gas Pipelines-continuing operations	$	111		37	%	$	(419	)	(22	)%	262			54	%	(481		)	(16	)%
Discontinued operations(c)	(8		)	(7	)%	(25		)	(16	)%	(23		)	(13	)%	(37		)	(15	)%
Total Natural Gas Pipelines-including discontinued operations	$	103		25	%	$	(444	)	(22	)%	$	239		36	%	$	(518	)	(16	)%

____________

n/a – not applicable


(a)	Equity investment until July 1, 2011. See Note (b).


(b)	Equity investment. We record earnings under the equity method of accounting, but we receive distributions in amounts essentially equal to equity earnings plus depreciation and amortization expenses less sustaining capital expenditures.


(c)	Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.

The ~~primary~~overall increases ~~and decreases~~ in our Natural Gas Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in the comparable three and ~~six~~nine month periods of 2012 and 2011 were driven by incremental contributions from (i) our Tennessee Gas Pipeline and our 50%-owned El Paso Natural Gas Pipeline, which we acquired from KMI effective August 1, 2012; and (ii) the inclusion of a full nine months of operations in 2012 from our Kinder Morgan Treating operations, which we acquired from SouthTex Treaters, Inc. effective November 30, 2011.

Other significant increases and decreases in our Natural Gas Pipelines business segment’s earnings before depreciation, depletion and amortization in the comparable three and nine month periods of 2012 and 2011 included the following:

▪

~~increases~~incremental equity earnings of ~~$31~~$9 million ~~(246%)~~ and ~~$66~~$15 million, ~~(296%),~~ respectively, ~~attributable to incremental earnings~~ from our ~~now wholly-owned KinderHawk Field Services LLC. Effective July 1, 2011, we acquired the remaining~~ 50% ~~ownership interest in KinderHawk that we did not already own, and subsequently, began accounting for our investment under the full consolidation method;~~-owned Eagle Ford

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Gathering LLC, which initiated flow on its natural gas gathering system on August 1, 2011;


▪	increases of ~~$11~~$7 million ~~(99%~~(118%) and ~~$18~~$28 million (84%), respectively, from our Kinder Morgan Treating operations—due mainly to incremental earnings from the natural gas treating operations we acquired from SouthTex Treaters, Inc. effective November 30, 2011;

~~Table of Contents~~

▪

~~increases of $9 million (171%) and $21 million (371%~~(239%), respectively, attributable to incremental equity earnings from our 50%-owned Fayetteville Express pipeline system—~~due to both higher~~driven by a ramp-up in firm contract transportation ~~revenues~~volumes, and to lower ~~period-to-period~~ interest expense. ~~The higher~~Period-to-period transportation revenues ~~were driven by~~increased due to increases in natural gas transmission volumes of 8% and ~~19%~~15%, respectively, ~~(while full transportation service began January 1, 2011, contracts were still ramping up during the first half of 2011),~~ and the decreases in interest expense related to Fayetteville's refinancing of its prior bank credit facility in July 2011;

▪

~~incremental equity earnings~~decreases of $6$12 million (17%) and ~~$11~~$19 million (8%), respectively, from ~~the combined operations of~~ our ~~50%-owned Eagle Ford Gathering LLC and our 25%-owned EagleHawk Field Services LLC, both of which provide~~Texas intrastate natural gas ~~gathering, transportation~~pipeline group. The decreases were driven by higher operating and ~~processing services in the Eagle Ford shale gas formation in South Texas. Eagle Ford Gathering initiated flow~~maintenance expenses, lower margins on ~~its~~ natural gas ~~gathering system~~processing activities, and for the comparable nine month periods, by lower margins on ~~August 1, 2011. We acquired our ownership interest~~natural gas sales. The increases in ~~EagleHawk effective July 1, 2011;~~expenses were driven by both higher pipeline integrity maintenance and unexpected well repairs. The decreases in processing margins were mostly due to lower natural gas liquids prices, and the period-to-period decrease in sales margin was primarily due to lower average natural gas sales prices;

▪

~~earnings~~a decrease of $3 million (7%) and an increase of $63 million (93%), respectively, from our ~~Texas intrastate natural gas pipeline group were essentially flat across both quarterly periods.~~now wholly-owned KinderHawk Field Services LLC. The ~~$7 million (4%)~~quarter-to-quarter decrease in earnings ~~in the first half of 2012 versus the first half of 2011 was due~~related primarily to lower margins on both natural gas sales and processing activities (attributable to lower average sales prices and higher severance/royalties expenses, respectively), higher gas losses, and the timing of higher operating expenses. The overall decrease was partially offset, however, by higher transportation and storage margins (attributable to a 22% increase in transportgathering volumes and ~~higher storage spreads, respectively).~~lower cashout settlement revenues. The increase across the comparable nine month periods was mainly due to incremental earnings resulting from the inclusion of a full nine months of operations in 2012. Effective July 1, 2011, we acquired the remaining 50% ownership interest in KinderHawk that we did not already own.

The period-to-period decreases in earnings before depreciation, depletion and amortization from discontinued operations were largely due to lower operating revenues from both our Kinder Morgan Interstate Gas Transmission and Trailblazer pipeline systems. The decreases generally related to lower net fuel recoveries, lower margins on operational natural gas sales, and excess natural gas transportation capacity existing out of the Rocky Mountain region.

The overall changes in both segment revenues and segment operating expenses (which include natural gas costs of sales) in the comparable three and ~~six~~nine month periods of 2012 and 2011 primarily relate to the natural gas purchase and sale activities of our Texas intrastate natural gas pipeline group, with the variances from period-to-period in both revenues and operating expenses mainly due to corresponding changes in the intrastate group’s average prices and volumes for natural gas purchased and sold. Our intrastate group both purchases and sells significant volumes of natural gas, which is often stored and/or transported on its pipelines, and because the group generally sells natural gas in the same price environment in which it is purchased, the increases and decreases in its gas sales revenues are largely offset by corresponding increases and decreases in its gas purchase costs. For the comparable ~~second~~third quarter periods of 2012 and 2011, our Texas intrastate natural gas pipeline group accounted for ~~75%~~68% and ~~88%~~85%, respectively, of the segment’s revenues, and ~~88%~~85% and 94%, respectively, of the segment’s operating expenses. For the comparable ~~six~~nine month periods of both years, the intrastate group accounted for ~~77%~~73% and ~~88%~~87%, respectively, of total segment revenues, and ~~89%~~87% and 94%, respectively, of total segment operating expenses.

CO₂

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	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
	(In millions, except operating statistics)												(In millions, except operating statistics)
Revenues(a)	$	413		$	350		$	830		$	691		$	420		$	372		$	1,250		$	1,063
Operating expenses	(98		)	(89		)	(185		)	(173		)	(97		)	(83		)	(282		)	(256		)
Other income(b)	7			—			7			—			—			—			7			—
Earnings from equity investments	7			5			13			11			5			7			18			18
Interest income and Other, net	(1		)	1			(1		)	1			1			1			—			2
Income tax (expense) benefit	(1		)	(1		)	(3		)	(2		)	(2		)	(2		)	(5		)	(4		)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	327		$	266		$	661		$	528		$	327		$	295		$	988		$	823

Southwest Colorado carbon dioxide production (gross) (Bcf/d)(c)	1.2			1.3			1.2			1.3			1.2			1.2			1.2			1.2
Southwest Colorado carbon dioxide production (net) (Bcf/d)(c)	0.5			0.5			0.5			0.5			0.5			0.5			0.5			0.5
SACROC oil production (gross)(MBbl/d)(d)	28.4			28.4			27.6			28.6			30.0			29.4			28.4			28.9
SACROC oil production (net)(MBbl/d)(e)	23.6			23.7			23.0			23.9			25.0			24.5			23.7			24.1
Yates oil production (gross)(MBbl/d)(d)	20.8			21.8			21.0			21.8			20.6			21.5			20.9			21.7
Yates oil production (net)(MBbl/d)(e)	9.2			9.7			9.3			9.7			9.3			9.5			9.3			9.6
Katz oil production (gross)(MBbl/d)(d)	1.8			0.3			1.6			0.2			1.8			0.5			1.7			0.3
Katz oil production (net)(MBbl/d)(e)	1.5			0.2			1.4			0.2			1.5			0.4			1.4			0.3
Natural gas liquids sales volumes (net)(MBbl/d)(e)	9.5			8.4			9.3			8.3			9.3			8.4			9.3			8.4
Realized weighted average oil price per Bbl(f)	85.96			69.37			$	88.25		$	69.07		$	88.64		$	70.43		$	88.39		$	69.54
Realized weighted average natural gas liquids price per Bbl(g)	49.44			66.67			$	55.22		$	63.83		$	44.27		$	68.86		$	51.53		$	65.53

____________


(a)	~~Six~~Three and nine month 2012 ~~amount includes~~amounts include unrealized losses of $3$5 million and $8 million, respectively, and three and ~~six~~nine month 2011 amounts include unrealized ~~losses~~gains of $2$8 million and ~~unrealized gains of $2~~$10 million, respectively, all relating to derivative contracts used to hedge forecast crude oil sales.


(b)	~~Three and six~~Nine month 2012 ~~amounts represent~~amount represents the gain from the sale of our ownership interest in the Claytonville oil field unit.


(c)	Includes McElmo Dome and Doe Canyon sales volumes.


(d)	Represents 100% of the production from the field. We own an approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, and an approximately 99% working interest in the Katz Strawn unit.


(e)	Net to us, after royalties and outside working interests.


(f)	Includes all of our crude oil production properties.


(g)	Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.

Our CO₂ segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO₂) and crude oil, and the production and marketing of natural gas and natural gas liquids. We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and its Sales and Transportation Activities.

For the three and ~~six~~nine months ended ~~June~~September 30, 2012, the certain items described in footnotes (a) and (b) to the table above (i) ~~increased~~decreased earnings before depreciation, depletion and amortization by $9$13 million and $2$11 million, respectively; and (ii) ~~increased revenues by $2 million and~~ decreased revenues by $5$13 million and $18 million, respectively, when compared to the same two periods of 2011. For each of the segment’s two primary businesses, following is information related to the increases and decreases, in the comparable three and ~~six~~nine month periods of 2012 and 2011, in the segment’s remaining (i) $5245 million ~~(19%~~(16%) and ~~$131~~$176 million ~~(25%~~(22%) increases in earnings before depreciation, depletion and amortization; and (ii) $61 million (17%) and ~~$144~~$205 million ~~(21%~~(19%) increases in operating revenues:

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Three months ended June 30, 2012 versus Three months ended June 30, 2011
Three months ended September 30, 2012 versus Three months ended September 30, 2011									Three months ended September 30, 2012 versus Three months ended September 30, 2011

	EBDA increase/(decrease)				Revenues increase/(decrease)				EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)								(In millions, except percentages)
Oil and Gas Producing Activities	$	38	20	%	$	49	18	%	$	32	15	%	$	51	18	%
Sales and Transportation Activities	14		17	%	11		13	%	13		19	%	8		9	%
Intrasegment eliminations	—		—	%	1		6	%	—		—	%	2		9	%
Total CO₂	$	52	19	%	$	61	17	%	$	45	16	%	$	61	17	%

____________

Six months ended June 30, 2012 versus Six months ended June 30, 2011
Nine months ended September 30, 2012 versus Nine months ended September 30, 2011									Nine months ended September 30, 2012 versus Nine months ended September 30, 2011

	EBDA increase/(decrease)				Revenues increase/(decrease)				EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)								(In millions, except percentages)
Oil and Gas Producing Activities	$	105	28	%	$	118	22	%	$	137	23	%	$	169	20	%
Sales and Transportation Activities	26		17	%	22		13	%	39		17	%	30		11	%
Intrasegment eliminations	—		—	%	4		13	%	—		—	%	6		11	%
Total CO₂	$	131	25	%	$	144	21	%	$	176	22	%	$	205	19	%

The ~~period-to-period~~ increases in earnings for the comparable three and nine month periods of 2012 and 2011 from the segment’s oil and gas producing activities were driven by increases of ~~$57~~$68 million ~~(27%~~(30%) and ~~$120~~$188 million ~~(28%~~(29%), respectively, in crude oil sales revenues. The increases were due to both higher average realizations for U.S. crude oil, ~~and~~ increased oil production at the Katz field unit, and for the comparable nine month periods, to increased oil production at the SACROC field unit. When compared to the same periods a year ago, our realized weighted average price per barrel of crude oil increased ~~24%~~26% in the ~~second~~third quarter of 2012 (from $70.43 per barrel in third quarter 2011 to $88.64 per barrel in third quarter 2012) and ~~28%~~27% in the first ~~six~~nine months of ~~2012.~~2012 (from $69.54 per barrel in the first nine months of 2011 to $88.39 per barrel in the first nine months of 2012) . Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged ~~$87.45~~$89.07 and ~~$93.92~~$92.23 per barrel in the ~~second~~third quarter and first ~~six~~nine months of 2012, respectively, and ~~$99.83~~$87.73 and ~~$95.29~~$92.71 per barrel in the ~~second~~third quarter and first ~~six~~nine months of 2011, respectively. Partially offsetting the increases in crude oil sales revenues were decreases in plant product sales revenues of $8$15 million ~~(16%~~(29%) and $3$19 million ~~(3%~~(12%), respectively, due to period-to-period decreases in the realized weighted average price per barrel of natural gas liquids of ~~26%~~36% and ~~13%~~21%, respectively.

The increases in earnings before depreciation, depletion and amortization expenses from the segment’s sales and transportation activities were ~~primarily related to~~driven by higher non-consent revenues, higher reimbursable project revenues, and for the comparable nine month periods, higher carbon dioxide sales ~~revenues and higher~~revenues. The increases in non-consent revenues ~~relative~~related to sharing arrangements pertaining to certain expansion projects completed at the McElmo Dome unit in Colorado since the end of the third quarter of 2011. ~~When compared~~The increase in reimbursable revenues related to the ~~same 2011~~completion of prior expansion projects on the Central Basin pipeline system. Although essentially flat across both comparable quarterly periods, the revenues we realized from carbon dioxide sales ~~revenues~~ increased ~~by $9 million (14%) in the second quarter of 2012 and~~ by $15 million ~~(12%~~(8%) in the first ~~six~~nine months of 2012, when compared to the first nine months of last year. The increase was driven by ~~increases of 23% and 21%, respectively,~~a 17% increase in ~~the average price received for all carbon dioxide sales. The higher~~ average sales prices, ~~were~~ due primarily to two ~~factors~~factors: (i) a change in the mix of contracts resulting in more carbon dioxide being delivered under higher price contracts; and (ii) heavier weighting of new carbon dioxide contract prices to the price of crude oil. The increases in non-consent revenues during 2012 related to sharing arrangements pertaining to certain expansion projects completed at the McElmo Dome unit in Colorado since the end of the second quarter of 2011.

Terminals

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	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
	(In millions, except operating statistics)												(In millions, except operating statistics)
Revenues	$	343		320			$	684		$	652		$	334		$	328		$	1,018		$	980
Operating expenses(a)	(164		)	(156		)	(324		)	(324		)	(156		)	(156		)	(480		)	(480		)
Other income(b)	13			3			13			3			2			2			15			5
Earnings from equity investments	5			3			11			5			5			3			16			8
Interest income and Other, net(c)	1			4			1			5			—			—			1			5
Income tax (expense) benefit(d)	(3		)	(3		)	(3		)	4			(2		)	3			(5		)	7
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	195		$	171		$	382		$	345		$	183		$	180		$	565		$	525

Bulk transload tonnage (MMtons)(e)	25.9			24.8			50.2			48.1			23.7			26.7			74.2			74.8
Ethanol (MMBbl)	16.3			13.6			34.2			29.3			15.7			15.5			49.9			44.9
Liquids leaseable capacity (MMBbl)	60.2			58.8			60.2			58.8			60.2			59.5			60.2			59.5
Liquids utilization %	93.0		%	92.6		%	93.0		%	92.6		%	92.9		%	93.2		%	92.9		%	93.2		%

__________

(a)

Three and ~~six~~nine month 2012 amounts include increases in expense of $1 million related to hurricane clean-up and repair activities. Three and nine month 2011 amounts include aincreases in expense of $1 million ~~increase in expense~~and $4 million, respectively, at our Carteret, New Jersey liquids terminal, associated with ~~environmental liability adjustments. Six month 2011 amount also includes (i) a combined $2 million increase in expense at our Carteret terminal, associated with~~storm and fire damage and repair activities, environmental liability adjustments, and the settlement of a certain litigation ~~matter; and (ii)~~matter. Nine month 2011 amount also includes a $1 million increase in expense associated with the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009.

(b)

~~Three and six~~Nine month 2012 ~~amounts include~~amount includes a $12 million casualty indemnification gain related to a 2010 casualty at our Port Sulphur, Louisiana, International Marine Terminal facility. Three and ~~six~~nine month 2011 amounts include a $1 million loss from property write-offs associated with the on-going dissolution of our partnership interest in Globalplex Handling, and a $1 million gain from the sale of our ownership interest in Arrow Terminals B.V. Nine month 2011 amount also includes (i) a $4 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids ~~terminal.~~terminal; (ii) a $1 million gain associated with the sale of our ownership interest in the boat fleeting business described in footnote (a); and (iii) a $1 million loss from property write-offs associated with the 2010 casualty at our International Marine Terminal facility.


(c)	~~Three and six~~Nine month 2011 ~~amounts include~~amount includes a $4 million ~~increase in income~~gain associated with the sale of a 51% ownership interest in two of our subsidiaries: River Consulting LLC and Devco USA L.L.C.

(d)

Three and six month 2011 amounts include a $2 million increase in expense associated with the increase in income from the sale of a 51% ownership interest in two of our subsidiaries described in footnote (c). SixNine month 2011 amount ~~also~~ includes (i) a $5 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (however, we do not have any obligation, nor did we pay any amounts related to this compensation expense)~~, and~~; (ii) a $2 million decrease in expense (reflecting tax savings) related to the net decrease in income from the sale of our ownership interest in the boat fleeting business described in footnote (a); and (iii) a $2 million increase in expense associated with the increase in income from the sale of a 51% ownership interest in two of our subsidiaries described in footnote (c).


(e)	Volumes for acquired terminals are included for all periods and include our proportionate share of joint venture tonnage.

Our Terminals business segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities. For the ~~three and six~~nine months ended ~~June~~September 30, 2012, the certain items related to our Terminals business segment and described in the footnotes to the table above increased ~~segment~~ earnings before depreciation, depletion and amortization ~~expenses~~ by ~~$7 million and~~ $3 million, ~~respectively,~~ when compared to the ~~same two periods~~first nine months of 2011.

Following is information related to the increases and decreases, in the comparable three and ~~six~~nine month periods of 2012 and 2011, in the segment’s ~~remaining~~ (i) ~~$17~~$3 million ~~(10%~~(2%) and ~~$34~~remaining $37 million ~~(10%~~(7%) increases in earnings before depreciation, depletion and amortization; and (ii) ~~$23~~$6 million ~~(7%~~(2%) and ~~$32~~$38 million ~~(5%~~(4%) increases in operating revenues:

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Three months ended June 30, 2012 versus Three months ended June 30, 2011
Three months ended September 30, 2012 versus Three months ended September 30, 2011											Three months ended September 30, 2012 versus Three months ended September 30, 2011

	EBDA increase/(decrease)					Revenues increase/(decrease)					EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Gulf Liquids	$	6		14	%	$	5		8	%	$	5		12	%	$	4		7	%
Mid-Atlantic	4			26	%	8			27	%	4			32	%	5			14	%
Acquired assets and businesses											2			n/a		—			n/a
Northeast											1			7	%	4			14	%
Gulf Bulk	4			28	%	3			9	%	(3		)	(15	)%	—			—	%
Northeast	3			17	%	4			12	%
Acquired assets and businesses	2			n/a		2			n/a
Rivers	(2		)	(11	)%	(2		)	(6	)%	(1		)	(9	)%	(6		)	(13	)%
All others (including intrasegment eliminations and unallocated income tax expenses)	—			—	%	3			2	%	(5		)	(6	)%	(1		)	(1	)%
Total Terminals	$	17		10	%	$	23		7	%	$	3		2	%	$	6		2	%

__________

Six months ended June 30, 2012 versus Six months ended June 30, 2011
Nine months ended September 30, 2012 versus Nine months ended September 30, 2011											Nine months ended September 30, 2012 versus Nine months ended September 30, 2011

	EBDA increase/(decrease)					Revenues increase/(decrease)					EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Mid-Atlantic	$	13		42	%	$	16		28	%	$	17		39	%	$	21		23	%
Gulf Liquids	10			11	%	10			8	%	15			12	%	14			8	%
Northeast											8			14	%	14			14	%
Acquired assets and businesses	6			n/a		4			n/a		8			n/a		4			n/a
Northeast	7			18	%	10			14	%
Gulf Bulk	6			24	%	3			4	%	3			6	%	3			2	%
Rivers	(6		)	(16	)%	(5		)	(7	)%	(7		)	(14	)%	(11		)	(9	)%
All others (including intrasegment eliminations and unallocated income tax expenses)	(2		)	(2	)%	(6		)	(2	)%	(7		)	(3	)%	(7		)	(2	)%
Total Terminals	$	34		10	%	$	32		5	%	$	37		7	%	$	38		4	%

The overall increases in earnings before depreciation, depletion and amortization from our Terminals segment were driven by higher contributions from both our Gulf Liquids and Mid-Atlantic regions. The increases from our Gulf Liquids facilities were ~~due to~~driven by higher ~~gasoline throughputs,~~warehousing revenues (as a result of new and renewed customer agreements at higher rates), higher ethanol volumes through our Deer Park, Texas rail terminal, and tofor the comparable nine month periods, by higher ~~warehousing revenues as a result of new and renewed customer agreements at higher rates.~~overall gasoline throughput volumes. For all liquids facilities combined, we increased our liquids leasable capacity by ~~1.4~~0.7 million barrels ~~(2.4%~~(1.2%) since the end of the ~~second~~third quarter of last year, primarily via completed terminal expansion ~~projects.~~projects, and, at the same time, our overall liquids utilization capacity rate remained essentially flat across both comparable three and nine month periods.

The period-to-period earnings increases ~~in earnings~~ from our Mid-Atlantic region ~~were driven by increases of $4 million~~across both comparable three and ~~$11 million, respectively,~~nine month periods resulted primarily from higher export coal shipments from our Pier IX terminal, located in Newport News, ~~Virginia. Pier IX’s earnings increases were primarily due to~~Virginia, and higher ~~export coal shipments, driven by~~import steel and iron ore imports from our Fairless Hills, Pennsylvania bulk terminal. Economic expansion in developing countries has generated a growth cycle in the coal export ~~market. Including~~market, and for all terminals combined, our total export coal ~~transload tonnage~~volumes increased by ~~1.1~~1.2 million tons ~~(12%~~(32%) in the ~~second~~third quarter of 2012 and by ~~1.6~~4.9 million tons ~~(9%~~(45%) in the first ~~half~~nine months of 2012, when compared to the same prior year periods.

We also benefitted from higher period-to-period earnings from (i) our Gulf Bulk terminals—due mainly to higher coal and petroleum coke handling and loading operations at our Deepwater terminal located on the Houston Ship Channel, and to higher coal and petroleum coke volumes at our Port of Houston and Port Arthur, Texas facilities, respectively; and (ii) our Carteret, New Jersey liquids terminal (Northeast region)—due primarily to higher transfer and storage rates and to tank expansion projects completed since the end of the second quarter of 2011.

The incremental earnings and revenues from acquired assets and businesses primarily represent contributions from our additional equity investment in the short-line railroad operations of Watco Companies, LLC (acquired in December 2011) and our bulk terminal that handles petroleum coke for the Total refinery in Port Arthur, Texas (acquired in June 2011). The

~~Table of Contents~~

incremental amounts represent earnings and revenues from acquired terminals’ operations during the additional ~~month~~months of ownership in the first ~~six~~nine months of 2012, and do not include increases or decreases during the same months we owned the assets in 2011.

~~The combined earnings~~

Table of Contents

Earnings before depreciation, depletion and amortization from our Gulf Bulk terminals decreased in the third quarter of 2012 compared to the third quarter of 2011, due mainly to favorable cost of sales expense adjustments and to the favorable settlement of a petroleum coke rate escalation issue, both recognized in the third quarter of 2011. Earnings increased across the comparable nine month periods, due primarily to higher coal and petroleum coke handling and loading operations at our Deepwater and Port of Houston terminal facilities located on the Houston Ship Channel.

Combined earnings from all of the terminal operations included in our Rivers region was essentially unchanged across both three month periods, but decreased $6$7 million ~~(16%~~(14%) in the ~~first half of 2012, versus the first half of 2011.~~comparable year-to-date periods. The decrease was driven by lower coal transload volumes in the first ~~half~~nine months of 2012, ~~as a~~largely the result of a drop in domestic ~~demand, due mainly to lower natural gas prices, and the impact of unfavorable weather relative to the first half of 2011.~~

The quarter-to-quarter decrease in our Terminals segment’s revenues—reported in the “All others” line in the table above—relates largely to terminal assets we sold (or contributed to joint ventures) and no longer consolidate since the end of the first quarter of 2011.demand.

Kinder Morgan Canada


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
	(In millions, except operating statistics)												(In millions, except operating statistics)
Revenues	$	73		$	77		$	146		$	153		$	80		$	77		$	226		$	230
Operating expenses	(23		)	(24		)	(47		)	(50		)	(28		)	(27		)	(75		)	(77		)
Earnings (losses) from equity investments	1			(1		)	2			(2		)
Earnings (loss) from equity investments													1			1			3			(1		)
Interest income and Other, net	4			4			7			7			5			3			12			10
Income tax (expense) benefit(a)	(3		)	(2		)	(6		)	(6		)	(2		)	(6		)	(8		)	(12		)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	52		$	54		$	102		$	102		$	56		$	48		$	158		$	150

Transport volumes (MMBbl)(b)	26.9			22.9			51.8			49.6			28.1			25.6			79.9			75.2

__________


(a)	~~Three and six~~Nine month 2011 ~~amounts include~~amount includes a $2 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (however, we do not have any obligation, nor did we pay any amounts related to this compensation expense).


(b)	Represents Trans Mountain pipeline system volumes.

Our Kinder Morgan Canada business segment includes the operations of our Trans Mountain and Jet Fuel pipeline systems, and our one-third ownership interest in the Express crude oil pipeline system. ~~For the comparable three and six month periods, the~~The certain item relating to income tax savings described in footnote (a) to the table above decreased segment earnings before depreciation, depletion and amortization by $2 million in ~~both~~ the ~~second quarter and~~ first ~~six~~nine months of 2012, when compared to the same ~~two periods~~period last year. For each of the segment’s three primary businesses, following is information for each of the comparable three and nine month periods of 2012 and 2011, related to the segment's (i) ~~the~~$8 million (17%) and remaining $2$10 million ~~(2%~~(7%) ~~increase~~increases in earnings before depreciation, depletion and ~~amortization in the first six months of 2012 versus the first six months of 2011;~~amortization; and (ii) ~~the~~$3 million (4%) increase and and $4 million ~~(5%~~(2%) ~~and $7 million (5%) decreases~~decrease in operating ~~revenues, respectively, for each of the comparable three and six month periods of 2012 and 2011:~~revenues:

Three months ended June 30, 2012 versus Three months ended June 30, 2011
Three months ended September 30, 2012 versus Three months ended September 30, 2011											Three months ended September 30, 2012 versus Three months ended September 30, 2011

	EBDA increase/(decrease)					Revenues increase/(decrease)					EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Trans Mountain Pipeline											$	6	13	%	$	3	4	%
Express Pipeline(a)	$	2		72	%	n/a			n/a		2		53	%	n/a		n/a
Trans Mountain Pipeline	(2		)	(3	)%	$	(4	)	(5	)%
Jet Fuel Pipeline	—			—	%	—			—	%	—		—	%	—		—	%
Total Kinder Morgan Canada	$	—		—	%	$	(4	)	(5	)%	$	8	17	%	$	3	4	%

____________

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~~____________~~

Six months ended June 30, 2012 versus Six months ended June 30, 2011
Nine months ended September 30, 2012 versus Nine months ended September 30, 2011											Nine months ended September 30, 2012 versus Nine months ended September 30, 2011

	EBDA increase/(decrease)					Revenues increase/(decrease)					EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Trans Mountain Pipeline											$	5	4	%	$	(4	)	(2	)%
Express Pipeline(a)	$	3		60	%	n/a			n/a		5		58	%	n/a			n/a
Trans Mountain Pipeline	(1		)	(1	)%	$	(7	)	(4	)%
Jet Fuel Pipeline	—			—	%	—			—	%	—		—	%	—			—	%
Total Kinder Morgan Canada	$	2		2	%	$	(7	)	(5	)%	$	10	7	%	$	(4	)	(2	)%


(a)	Equity investment. We record earnings under the equity method of accounting.

~~Our Kinder Morgan Canada segment’s~~The period-to-period increases in Trans Mountain’s earnings before depreciation, depletion and amortization expenses were ~~essentially flat across both comparable three~~mainly due to lower income tax expenses, and ~~six month periods.~~partly due to higher non-operating income related to incremental management incentive fees earned from its operation of the Express pipeline system. The ~~slight~~drop in income tax expenses related primarily to favorable tax adjustments taken in the third quarter of 2012 related to lower taxable income. The period-to-period increases in earnings from our equity investment in the Express pipeline system were mainly due to volumes moving at higher transportation rates on the Express portion of the system, and higher domestic volumes on ~~Express’~~the Platte ~~Pipeline segment. The slight decreases in Trans Mountain’s earnings were due mainly to the impacts of unfavorable currency translation, due to the weakening, in 2012,~~portion of the ~~Canadian dollar relative to the U.S. dollar in both comparable three and six month periods.~~segment.

Other


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011		2012		2011		2012		2011
	(In millions)								(In millions)
General and administrative expenses(a)	$	98	$	98	$	205	$	287	$	131	$	100	$	379	$	387

Interest expense, net of unallocable interest income(b)	$	141	$	129	$	280	$	261	$	181	$	132	$	474	$	393

Unallocable income tax expense	$	3	$	3	$	5	$	5	$	2	$	2	$	7	$	7

Net income attributable to noncontrolling interests~~(b)~~(c)	$	6	$	2	$	8	$	5	$	4	$	1	$	12	$	6

__________

(a)

~~Six~~Three and nine month 2012 ~~amount includes a $1~~amounts include (i) increases in expense of $13 million ~~increase~~and $56 million, respectively, attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012; (ii) increases in unallocated severance expenses of $3 million and $4 million, respectively; and (iii) increases in expense ~~associated with~~of $2 million for certain ~~Terminal operations.~~asset and business acquisition costs. Three and ~~six~~nine month 2011 amounts include (i) a $2$1 million decrease in unallocated payroll tax expense and a $1 million increase in unallocated payroll tax expense, ~~(related~~respectively (all related to an $87 million special bonus expense to non-senior management employees allocated to us from KMI in the first quarter of 2011); however, we do not have any obligation, nor did we pay any amounts related to this compensation ~~expense. Six~~expense; and (ii) increases in expense of $1 million and $2 million, respectively, for certain asset and business acquisition costs. Nine month 2011 amount also includes ~~(i)~~ a combined $90 million increase in non-cash compensation expense (including $87 million related to athe special bonus expense to non-senior management employees) allocated to us from KMI in the first quarter of ~~2011;~~2011); however, we do not have any obligation, nor did we pay any amounts related to this ~~expense; and (ii) a $1 million increase in expense for certain asset and business acquisition costs.~~expense.


(b)	Three and ~~six~~nine month 2012 amounts include (i) increases in expense of $8 million and $21 million, respectively, attributable to our drop-down asset group for periods prior to our acquisition date of August 1, 2012; and (ii) increases in expense of $1 million attributable to incremental fees related to our short-term bridge loan credit facility.

(c)

Three and nine month 2012 amounts include decreases of $1 million and ~~decreases of $2~~$4 million, respectively, in net income attributable to our noncontrolling interests, and the three and ~~six~~nine month 2011 amounts include decreases of $3 million and $4$7 million, respectively, in net income attributable to our noncontrolling interests, all related to the combined effect of the three and ~~six~~nine month 2012 and 2011 items previously disclosed in the footnotes to the tables included above in “—Results of Operations.”

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Items not attributable to any segment include general and administrative expenses, unallocable interest income and income tax expense, interest expense, and net income attributable to noncontrolling interests. Our general and administrative expenses include such items as unallocated salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services—including

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accounting, information technology, human resources and legal services.

~~Compared with~~ These expenses are generally not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. For this reason and because we manage our business based on our reportable business segments and not on the ~~same quarter~~basis of ~~2011,~~our ownership structure, we do not specifically allocate our general and administrative expenses ~~were essentially flat in the second quarter~~to our business segments. As discussed previously, we use segment earnings before depreciation, depletion and amortization (EBDA) internally as a measure of ~~2012.~~ profit and loss used for evaluating segment performance, and each of our segment's EBDA includes all costs directly incurred by that segment.

For the ~~comparable six month periods,~~three and nine months ended September 30, 2012, the certain items described in footnote (a) to the table above accounted for an $18 million increase and a ~~$92~~$31 million decrease, respectively, in ~~expense in 2012 versus 2011.~~our general and administrative expenses, when compared to the same periods a year ago. The remaining ~~$10~~$13 million ~~(5%~~(13%) and $23 million (8%) period-to-period ~~increase~~increases in ~~expense included increases~~expenses were driven by the acquisition of additional business, associated primarily with the Tennessee Gas and ~~decreases in various operational expenses, but consisted primarily of~~El Paso Natural Gas (50% interest) pipeline systems we acquired from KMI effective August 1, 2012. We also realized higher benefit and payroll tax expenses, and higher employee labor ~~expenses. These increases~~expenses, which were ~~driven~~impacted by cost inflation increases on work-based health and insurance benefits, higher wage rates and a larger year-over-year labor force.

~~In the table above, we~~We report our interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our interest expense to arrive at one interest ~~amount. Our~~amount, and after taking into effect the certain items described in footnote (b) to the table above, our net interest expense increased ~~$12~~$40 million ~~(9%~~(30%) in the ~~second~~third quarter of 2012 and ~~$19~~$59 million ~~(7%~~(15%) in the first ~~six~~nine months of 2012, when compared with the same prior year periods. The increases in interest expense were primarily due to higher average debt balances in ~~2012 (average~~2012. Average borrowings for ~~both comparable~~the three and ~~six~~nine month periods ended September 30, 2012 increased ~~13% in 2012~~30% and 28%, respectively, when compared to ~~2011),~~the same periods a year ago, largely due to the capital expenditures, business acquisitions (including debt assumed from the drop-down transaction), and joint venture contributions we have made since the end of the ~~second~~third quarter of 2011. ~~The increases in net interest expense were slightly offset, however, by lower weighted average interest rates.~~ The weighted average interest rate on all of our borrowings—including both short-term and long-term amounts—~~was essentially flat across both three month~~increased 4% in the comparable quarterly periods (from ~~4.29%~~4.12% for the ~~second~~third quarter of 2011 to ~~4.27%~~4.28% for the ~~second~~third quarter of 2012), ~~and dropped 3% in the first half of 2012 versus the first half of 2011~~but was essentially unchanged across both nine month periods (from ~~4.36%~~4.28% for the first ~~half~~nine months of 2011 to ~~4.25%~~4.26% for the first ~~half~~nine months of 2012).

We use interest rate swap agreements to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of ~~June~~September 30, 2012 and December 31, 2011, approximately46% and 47%, respectively, of our consolidated debt balances (excluding our debt fair value adjustments) was subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 56 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements included elsewhere in this report.

Financial Condition

General

As of ~~June~~September 30, 2012, we had ~~$522~~$532 million of “Cash and cash equivalents” on our consolidated balance sheet (included elsewhere in this report), an increase of ~~$113~~$123 million ~~(28%~~(30%) from December 31, 2011. We also had, as of ~~June~~September 30, 2012, approximately ~~$1.5~~$1.0 billion of borrowing capacity available under our ~~$2.2 billion senior~~two unsecured ~~revolving~~ credit ~~facility~~facilities (discussed below in “—Short-term Liquidity”). We believe our cash position and our remaining borrowing capacity allow us to manage our day-to-day cash requirements and any anticipated obligations, and currently, we believe our liquidity to be adequate.

Our primary cash requirements, in addition to normal operating expenses, are for debt service, sustaining capital expenditures (defined as capital expenditures which do not increase the capacity of an asset), expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholder and general partner.

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In general, we expect to fund:


▪	cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities;

▪

expansion capital expenditures and working capital deficits with retained cash (which may result from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), additional borrowings (including commercial paper issuances), and the issuance of additional common units or the proceeds from purchases of additional i-units by KMR;


▪	interest payments with cash flows from operating activities; and


▪	debt principal payments, as such debt principal payments become due, with additional borrowings or by the issuance of additional common units or the proceeds from purchases of additional i-units by KMR.

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~~issuance of additional common units or the proceeds from purchases of additional i-units by KMR.~~

In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.”

Credit Ratings and Capital Market Liquidity

Currently, our long-term corporate debt credit rating is BBB (stable), Baa2 (stable) and BBB (stable), at Standard & Poor’s Ratings Services, Moody’s Investors Service, Inc. and Fitch, Inc., respectively. ~~On July 17, 2012, Moody's changed its outlook for us from negative to stable.~~ Our short-term corporate debt credit rating is A-2 (susceptible to adverse economic conditions, however, capacity to meet financial commitments is satisfactory), Prime-2 (strong ability to repay short-term debt obligations) and F2 (good quality grade with satisfactory capacity to meet financial commitments), at Standard & Poor’s Ratings Services, Moody’s Investors Service, Inc. and Fitch, Inc., respectively. Our credit ratings affect our ability to access the commercial paper market and the public and private debt markets, as well as the terms and pricing of our debt (see Part II, Item 1A "Risk Factors"). Based on these credit ratings, we expect that our short-term liquidity needs will be met primarily through borrowings under our commercial paper program. Nevertheless, our ability to satisfy our financing requirements or fund our planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the energy pipeline and terminals industries and other financial and business factors, some of which are beyond our control.

Short-term Liquidity

As of ~~June~~September 30, 2012, our principal sources of short-term liquidity were (i) our $2.2 billion senior unsecured revolving credit facility with a diverse syndicate of banks that matures July 1, 2016; (ii) our ~~$2.2~~$2.0 billion short-term bridge loan credit facility that matures February 6, 2013, and which, as of September 30, 2012, allowed for maximum borrowings of $1.7 billion; (iii) our $3.9 billion short-term commercial paper program (which is supported by our ~~revolving~~two credit ~~facility,~~facilities, with the amount available for borrowing under our credit ~~facility~~facilities being reduced by our outstanding commercial paper borrowings and letters of credit); and ~~(iii)~~(iv) cash from operations (discussed below in “—Operating Activities”). The loan commitments under our ~~revolving~~two credit ~~facility~~facilities can be used to fund borrowings for general partnership purposes and as a backup for our commercial paper ~~program. The~~program, and our $2.2 billion long-term senior unsecured revolving credit facility can be amended to allow for borrowings of up to $2.5 billion. As of ~~June~~September 30, 2012, we had no outstanding borrowings under either credit facility. For more information about our $2.0 billion short-term credit ~~facility was not drawn on.~~agreement, which we entered into effective August 6, 2012, see Note 4 "Debt” to our consolidated financial statements included elsewhere in this report.

Our outstanding short-term debt as of ~~June~~September 30, 2012 was ~~$979~~$2,697 million, primarily consisting of ~~$500 million in principal amount of 5.85% senior notes that mature September 15, 2012, and $446~~$2,664 million of outstanding commercial paper borrowings. We intend to refinance our current short-term debt through the proceeds we expect to receive from the sale of our FTC Natural Gas Pipelines disposal group, and a combination of long-term debt, equity, and/or the issuance of additional commercial paper or credit facility borrowings to replace maturing commercial paper and current maturities of long-term debt. As of December 31, 2011, our short-term debt totaled $1,638 million.

We had a working capital ~~surplus~~deficit of ~~$1,196~~$794 million as of ~~June~~September 30, 2012, and a working capital deficit of $1,543 million as of December 31, 2011. The overall ~~$2,739~~$749 million ~~(178%~~(49%) favorable change from year-end 2011 was primarily due to (i) ~~our reclassification of~~an increase in working capital due to reclassifying the ~~June~~September 30, 2012 net assets of our FTC Natural Gas

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Pipelines disposal group as current assets and liabilities held for sale (we expect to sell the disposal group's net assets in the ~~third~~fourth quarter of 2012 and because the disposal group’s combined liabilities were not material to our consolidated balance sheet, we included the disposal group’s liabilities within “Accrued other current liabilities” in our accompanying consolidated balance sheet as of ~~June~~September 30, ~~2012)~~2012, included elsewhere in this report); and (ii) ~~an increase~~a decrease in working capital due to ~~a decrease~~an increase in short-term debt. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in cash and cash equivalent balances as a result of debt or equity issuances (discussed below in “—Long-term Financing”).

Long-term Financing

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

Our equity offerings consist of the issuance of additional common units or the issuance of additional i-units to KMR (which KMR purchases with the proceeds from the sale of additional KMR shares). As a publicly traded limited

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partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations, and we are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors. For more information about our equity issuances in the first ~~half~~nine months of 2012, see Note 45 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report.

From time to time we issue long-term debt securities, often referred to as our senior notes. Our senior notes issued to date, other than those issued by our subsidiaries and operating partnerships, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our outstanding senior notes are unsecured obligations that rank equally with all of our other senior debt obligations; however, a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries. Our fixed rate 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.

In addition, from time to time our subsidiary Tennessee Gas Pipeline L.L.C. has issued long-term debt securities, often referred to as its senior notes. As of ~~June~~September 30, 2012, Tennessee Gas Pipeline L.L.C. is the obligor of six separate series of fixed-rate unsecured senior notes having a combined principal amount of $1,790 million. The interest rates on these notes range from 7% per annum through 8.375% per annum, and the maturity dates range from February 2016 through April 2037. We assumed these senior notes as part of the drop-down transaction.

As of September 30, 2012 and December 31, 2011, the ~~net carrying value~~aggregate principal amount of the various series of our senior notes was ~~$12,575~~$13,350 million and ~~$12,026~~$12,050 million, respectively, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries (including Tennessee Gas Pipeline L.L.C.'s senior notes discussed above) was ~~$112~~$1,900 million and $126 million, respectively. To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt related transactions in the first ~~six~~nine months of 2012, see Note 34 “Debt” to our consolidated financial statements included elsewhere in this report. For additional information regarding our debt securities, see Note 8 “Debt” to our consolidated financial statements included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives. We are subject, however, to conditions in the equity and debt markets for our limited partner units and long-term senior notes, and there can be no assurance we will be able or willing to access the public or private markets for our limited partner units and/or long-term senior notes in the future. If we were unable or unwilling to issue additional limited partner units, we would be required to either restrict expansion capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. Furthermore, our ability to access the public and private debt markets is affected by our credit ratings. See “—Credit Ratings and Capital Market Liquidity” above for a discussion of our credit ratings.

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Capital Expenditures

We define sustaining capital expenditures as capital expenditures which do not increase the capacity of an asset. For the first ~~six~~nine month periods of 2012 and 2011, our sustaining capital expenditures totaled ~~$96~~$174 million and ~~$85~~$140 million, respectively. These amounts included $5$13 million and $3 million, respectively, for our proportionate share of the sustaining capital expenditures of (i) Rockies Express Pipeline LLC; (ii) Midcontinent Express Pipeline LLC; (iii) Fayetteville Express Pipeline LLC; (iv) Cypress Interstate Pipeline LLC; (v) EagleHawk Field Services LLC; (vi) Eagle Ford Gathering LLC; (vii) Red Cedar Gathering Company; (viii) for the periods after our acquisition date of August 1, 2012 only, El Paso Natural Gas Pipeline LLC, Bear Creek Storage Company, L.L.C., and ~~(viii)~~El Paso Midstream Investment Company, LLC; and (ix) for the first six months of 2011 only, KinderHawk Field Services LLC (effective July 1, 2011, we acquired the remaining 50% ownership interest in KinderHawk that we did not already own and we subsequently included its sustaining capital expenditures in our consolidated totals).

In addition, we have forecasted ~~$304~~$306 million for sustaining capital expenditures for the full year 2012. This amount (i) includes expenditures associated with the ~~assets~~drop-down asset group we ~~expect to acquire~~acquired from KMI ~~in the third quarter of~~since May 25, 2012 ~~for the months of our ownership~~ (discussed ~~below~~above in “—~~Additional Capital Requirements”~~General and Basis of Presentation”); and (ii) excludes expenditures associated with the assets in our FTC Natural Gas Pipelines disposal group for the months after the expected disposal.

Generally, we fund our sustaining capital expenditures with existing cash or from cash flows from operations. In addition to utilizing cash generated from their own operations, Rockies Express, Midcontinent Express and Fayetteville Express can each fund their own cash requirements for expansion capital expenditures through borrowings under their own credit facilities, with proceeds from issuing their own long-term notes, or with proceeds from contributions received from their member owners. We have no contingent debt obligations with respect to Rockies Express, Midcontinent Express, or Fayetteville Express.

~~All of our capital expenditures, with~~In addition to the ~~exception of~~ sustaining capital expenditures ~~are classified as discretionary.~~

~~Table~~described above (excluding the proportionate share of ~~Contents~~

~~Our discretionary~~the sustaining capital expenditures ~~totaled $686 million in~~of our unconsolidated joint ventures), our consolidated statements of cash flows for the ~~first half of~~nine months ended September 30, 2012 and ~~$453~~2011 include capital expenditures of $1,112 million and $701 million, respectively. We report our combined capital expenditures separately as "Capital expenditures" within the "Cash Flows from Investing Activities" section on our accompanying cash flow statements (included elsewhere in this report), and the ~~first half of 2011. The~~ period-to-period increase in ~~discretionary~~our capital expenditures was primarily due to higher investment undertaken in the first ~~half~~nine months of 2012 to expand and improve our Terminals and ~~Products~~Natural Gas Pipelines business segments. Generally, we initially fund our ~~discretionary~~ capital expenditures through borrowings under our commercial paper program or our revolving credit ~~facility~~facilities until the amount borrowed is of a sufficient size to cost effectively offer either debt, equity, or both.

Capital Requirements for Recent Drop-Down Transaction

In the first nine months of 2012, our cash outlays for the drop-down transaction totaled $3,482 million (net of an acquired cash balance of $3 million) and we reported this amount separately as "Payment to KMI for drop-down asset group" on our accompanying consolidated statement of cash flows included elsewhere in this report. With the exception of our partial payment of the combined purchase price to KMI by the issuance of addition common units (valued at $381 million), we funded this acquisition with proceeds received from (i) our August 2012 issuance of long-term senior notes; (ii) our third quarter 2012 issuances of additional i-units to KMR; (iii) borrowings under our short-term bridge loan credit facility; and (iv) borrowings under our commercial paper program. We subsequently repaid the borrowings made under our short-term bridge loan credit facility with incremental borrowings under our commercial paper program, and as of September 30, 2012, we had no borrowings under the credit facility.

Additional Capital Requirements

In April 2012, we announced that we will proceed with our proposal to expand our existing Trans Mountain pipeline system. When completed, the proposed expansion will increase capacity on Trans Mountain from its current 300,000 barrels per day of crude oil and refined petroleum products to approximately 750,000 barrels per day. ~~In the second quarter of 2012, we confirmed binding commercial support for this~~This expansion project ~~which includes~~entails the following: (i) twinning the existing pipeline within the existing right-of-way, where possible; (ii) adding new pump stations along the route; (iii) increasing the number of storage tanks at existing facilities; and (iv) expanding the Westridge Marine terminal, located within Port Metro Vancouver in Vancouver, British Columbia. ~~Pending~~We confirmed binding commercial support for this project, and pending the filing and approval of tolling and facilities

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applications with Canada’s National Energy Board, we expect to begin construction in 2015 or 2016, with the proposed project operating in late 2017. Our current estimate of total construction costs on the project is approximately $4.1 billion.

In addition, we regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and are currently contemplating potential acquisitions. Such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations. Currently, we expect KMI to offer to sell (drop-down) all of the Tennessee Gas Pipeline system and a 50% ownership interest in the El Paso Natural Gas pipeline system to us in order to replace the assets that we will divest (our FTC Natural Gas Pipelines disposal group). We expect that these asset drop-downs and the divestitures (discussed in Note 1 “General—Kinder Morgan, Inc. and Kinder Morgan G.P., Inc.” to our consolidated financial statements included elsewhere in this report) will close in the third quarter of 2012. Excluding amounts for the ~~assets~~drop-down asset group we ~~expect to acquire~~acquired from KMI and the expansion projects associated with those assets, we now expect to invest approximately ~~$2.2~~$2.2 billion for our 2012 capital expansion program, including small acquisitions and investment contributions.

Our ability to make accretive acquisitions (i) is a function of the availability of suitable acquisition candidates at the right cost; (ii) is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions; and (iii) includes factors over which we have limited or no control. Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates. Our ability to expand our assets is also impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such expansions.

As a master limited partnership, we distribute all of our available cash and we access capital markets to fund acquisitions and asset expansions. Historically, we have succeeded in raising necessary capital in order to fund our acquisitions and expansions, and although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that our stable cash flows, our investment grade credit rating, and our historical record of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, distribution and acquisition strategies, as well as refinance maturing debt when required.

Operating Activities

Net cash provided by operating activities was ~~$1,504~~$2,314 million for the ~~six~~nine months ended ~~June~~September 30, 2012, versus ~~$1,239~~$1,984 million infor the same comparable period of 2011. The period-to-period increase of ~~$265~~$330 million ~~(21%~~(17%) in cash flow from operations was primarily ~~consisted of~~due to a $311 million increase in cash from overall higher partnership income—after adjusting our period-to-period $52 million decrease in net income for the ~~following:~~following six non-cash items:

▪

a ~~$199 million increase in cash from overall higher partnership income—after adjusting our period-to-period $206 million decrease in net income for the following five non-cash items: (i) a $649~~$582 million increase from ~~the~~ non-cash ~~loss on~~losses from the remeasurement of ~~our FTC Natural Gas Pipelines disposal group~~net assets to fair value (discussed further in Note 2 to our consolidated financial statements included elsewhere in this report); ~~(ii)~~


▪	a ~~$44~~$98 million increase due to higher non-cash depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments); ~~(iii)~~

▪

a ~~$165~~$78 million increase from a non-cash expense recognized in the third quarter of 2012 related to the divestiture of our FTC Natural Gas Pipelines disposal group. We expect to pay the liability associated with this expense in the fourth quarter of 2012 (as discussed in Note 9 “Related Party Transactions—FTC Natural Gas Pipelines Disposal Group Selling Expenses” to our consolidated financial statements included elsewhere in this report, KMI has agreed to contribute $45 million to us as partial funding for this payment);


▪	a $230 million decrease related to higher non-cash expenses in the first nine months of 2011 as a result of adjustments to our rate case, ~~reserve adjustments that increased expense~~leased rights-of-ways and other legal liabilities;

▪

a $90 million decrease due to certain higher non-cash compensation expenses allocated to us from KMI in ~~June~~the first nine months of 2011 (as discussed in Note 9 “Related Party Transactions—Non-Cash Compensation Expenses” to our consolidated financial statements included elsewhere in this report, we do not have any obligation, nor did we pay any amounts related to these allocated expenses); and


▪	a $75 million decrease due to higher earnings from equity investees in the first nine months of 2012.

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2011; (iv) a $90 million decrease due to certain higher non-cash compensation expenses allocated to us from KMI in the first half of 2011 (as discussed in Note 8 “Related Party Transactions—Non-Cash Compensation Expenses” to our consolidated financial statements included elsewhere in this report, we do not have any obligation, nor did we pay any amounts related to these allocated expenses); and (v) a $33 million decrease due to higher earnings from equity investees in the first half of 2012. The period-to-period change in partnership income in 2012 versus 2011 is discussed above in “—Results of Operations” (including all of the certain items disclosed in the associated table footnotes);.


▪	~~a $72 million increase in cash due to lower volumes and costs of natural gas put into storage on our Kinder Morgan Texas Pipeline system;~~


▪	a $53 million increase in cash from an interest rate swap termination payment received in June 2012, when we terminated a fixed-to-variable interest rate swap agreement having a notional principal amount of $100 million; and


▪	~~an $89 million decrease in cash due to higher products inventory, primarily due to incremental expenditures for short-term liquids transmix inventories.~~

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Investing Activities

Net cash used in investing activities was ~~$814~~$4,786 million for the ~~six~~nine month period ended ~~June~~September 30, 2012, compared to ~~$517~~$1,797 million used in the comparable 2011 period (our issuance of an aggregate consideration of $289 million in common units for the acquisition of a 50% ownership interest in El Paso Midstream Investment Company, LLC in June 2012 ~~for~~and our issuance of an aggregate consideration of ~~$289~~$381 million in common units as partial payment for the drop-down asset group in August 2012 is included within "Noncash Investing and Financing Activities—Assets acquired or liabilities settled by the issuance of common units" on our accompanying consolidated statement of cash ~~flows).~~flows included elsewhere in this report. The overall ~~$297~~$2,989 million ~~(57%~~(166%) decrease in cash from investing activities primarily consisted of the following:


▪	our $3,482 million cash outlay (net of an acquired cash balance of $3 million) as partial payment for the drop-down asset group in August 2012, as described above in “—Capital Requirements for Recent Drop-Down Transaction;”


▪	a ~~$242~~$435 million decrease in cash due to higher capital expenditures, as described above in “—Capital Expenditures;”


▪	a $50 million decrease in cash related to net changes in margin and restricted deposits, due to the January 2011 release of $50 million in cash previously restricted for our investment in Watco (described below);

▪

a $35 million decrease in cash due to lower capital distributions (distributions in excess of cumulative earnings) received from equity investments in the first half of 2012—chiefly due to decreases in capital distributions received from both Rockies Express Pipeline LLC and KinderHawk Field Services LLC. However, (i) the decrease in distributions of capital from Rockies Express was partially offset by higher distributions of earnings, which are included within the Operating Activities section of our consolidated statement of cash flows; and (ii) the decrease in distributions of capital received from KinderHawk was due to the fact that we held only a 50% ownership interest in KinderHawk during the first half of 2011 and we accounted for our investment under the equity method of accounting; and

▪

an ~~$80~~$873 million increase in cash due to lower expenditures for the acquisitions of assets and ~~investments.~~investments from unrelated parties. In the first ~~six~~nine months of 2012, we paid a combined $72 million for asset acquistions, including (i) $30 million to Enhanced Oil Resources to acquire a carbon dioxide source field and related assets located in Apache County, Arizona, and Catron County, New ~~Mexico.~~Mexico; and (ii) $28 million to Lincoln Oil Co. Inc. to acquire an ethanol and biodiesel terminaling facility located in Belton, South Carolina. In the first ~~half~~nine months of 2011, we spent a ~~combined $110~~aggregate amount of $945 million for asset and investment acquisitions, including (i) $835 million for both our remaining 50% ownership interest in KinderHawk Field Services LLC and our 25% equity interest in EagleHawk Field Services LLC; (ii) $50 million for an initial preferred equity interest in Watco Companies, ~~LLC,~~LLC; and (iii) $43 million for a newly constructed petroleum coke terminal located in Port Arthur, Texas.

Financing Activities

Net cash ~~used in~~provided by financing activities amounted to ~~$575~~$2,582 million for the first ~~half~~nine months of ~~2012, and $501~~2012. In the comparable prior year period, we used $30 million ~~for the first half of 2011.~~in cash from financing activities. The ~~$74~~$2,612 million ~~(15%~~(871%) overall ~~decrease~~increase in cash from the comparable 2011 period was mainly due to ~~higher cash expended for financing activities consisted of~~ the following:

▪

a ~~$429~~$2,487 million ~~decrease~~increase in cash from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs. This increase in cash was primarily due to (i) a $2,188 million increase due to higher short-term net borrowings under our commercial paper program (largely related to the portion of the drop-down transaction we funded in cash); (ii) a $154 million increase due to the immediate repayment of all of the outstanding borrowings under KinderHawk Field Services LLC's bank credit facility that we assumed on our July 1, 2011 acquisition date; and (iii) a combined $144 million increase due to higher net issuances of our senior notes (in the first nine months of 2012 and 2011, we generated net proceeds of $1,280 million and $1,136 million, respectively, from both issuing and repaying senior notes);

▪

a $301 million increase in cash due to ~~lower~~higher partnership equity issuances. ~~The decrease~~This increase reflects the ~~$277~~$1,114 million we received, after commissions and underwriting expenses, from the sales of additional common units and i-units in the first ~~six~~nine months of 2012 (discussed in Note 45 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report), versus the $813 million we received from the sales of additional common units in the first nine months a year ago; and

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statements included elsewhere in this report), versus the $706 million we received from the sales of additional common units in the first six months a year ago. In both six month periods, we used the proceeds from our equity issuances to reduce the borrowings under our commercial paper program;

▪

a ~~$123~~$200 million decrease in cash due to higher partnership distributions. Distributions to all partners, consisting of our common and Class B unitholders, our general partner and our noncontrolling interests, totaled ~~$1,209~~$1,859 million in the first ~~six~~nine months of 2012. In the same comparable period ~~of 2011,~~last year, we distributed ~~$1,086~~$1,659 million to our partners. Further information regarding our distributions is discussed following in “—Partnership ~~Distributions;~~Distributions.” ~~and~~

▪

a $474 million increase in cash from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs. The increase in cash consisted of (i) a $323 million increase due to lower net repayments of short-term borrowings under our commercial paper program; and (ii) a combined $151 million increase due to higher net issuances of our senior notes (in the first six months of 2012 and 2011, we generated net proceeds of $544 million and $393 million, respectively, from both issuing and repaying senior notes).

Partnership Distributions

Our partnership agreement requires that we distribute 100% of “Available Cash,” as defined in our partnership

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agreement, to our partners within 45 days following the end of each calendar quarter. Our 2011 Form 10-K and our Current Report on Form 8-K filed May 1, 2012 contain additional information concerning our partnership distributions, including the definition of “Available Cash,” the manner in which our total distributions are divided between our general partner and our limited partners, and the form of distributions to all of our partners, including our noncontrolling interests.

For further information about the partnership distributions we paid in the ~~second~~third quarters of 2012 and 2011 (for the ~~first~~second quarterly periods of 2012 and 2011, respectively), see Note 45 “Partners’ Capital—Income Allocation and Declared Distributions” to our consolidated financial statements included elsewhere in this report.

Furthermore, on ~~July 18,~~October 17, 2012, we declared a cash distribution of ~~$1.23~~$1.26 per unit for the ~~second~~third quarter of 2012 (an annualized rate of ~~$4.92~~$5.04 per unit). This distribution is 7%9% higher than the ~~$1.15~~$1.16 per unit distribution we made for the ~~second~~third quarter of 2011. Our declared distribution for the ~~second~~third quarter of 2012 of ~~$1.23~~$1.26 per unit will result in an incentive distribution to our general partner of ~~$337~~$364 million (including the effect of a waived incentive distribution amount of $7$6 million related to our KinderHawk acquisition). Comparatively, our distribution of ~~$1.15~~$1.16 per unit paid on ~~August 12,~~November 14, 2011 for the ~~second~~third quarter of 2011 resulted in an incentive distribution payment to our general partner in the amount of ~~$293~~$299 million (and included the effect of a waived incentive distribution amount of $7 million related to our KinderHawk acquisition). The increased incentive distribution to our general partner for the ~~second~~third quarter of 2012 over the incentive distribution for the ~~second~~third quarter of 2011 reflects the increase in the distribution per unit as well as the issuance of additional units. For additional information about our ~~second~~third quarter 2012 cash distribution, see Note 45 “Partners’ Capital—Subsequent Events” to our consolidated financial statements included elsewhere in this report. For additional information about our 2011 partnership distributions, see Notes 10 and 11 to our consolidated financial statements included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

Currently, we expect to declare cash distributions of $4.98 per unit for 2012, an 8% increase over our cash distributions of $4.61 per unit for 2011. We also expect that the combination of the asset divestitures and ~~drop-downs from~~the drop-down transaction with KMI (discussed in Note 1 ~~“General—Kinder Morgan, Inc.~~ and ~~Kinder Morgan G.P., Inc.”~~Note 2 to our consolidated financial statements included elsewhere in this report) will be slightly accretive to our distribution per unit in 2012 and nicely accretive thereafter.

Although the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices, our CO₂ business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids, and while we hedge the majority of our crude oil production, we do have exposure on our unhedged volumes, the majority of which are natural gas liquids volumes. Our 2012 budget assumes an average West Texas Intermediate (WTI) crude oil price of approximately $93.75 per barrel (with some minor adjustments for timing, quality and location differences) in 2012, and based on the actual prices we have received through the date of this report and the forward price curve for WTI (adjusted for the same factors used in our 2012 budget), we currently expect the average price of WTI crude oil will be approximately ~~$93.05~~$95.25 per barrel in 2012.

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~~Furthermore, for~~ For 2012, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO₂ segment’s cash flows by approximately $6 million (or slightly over 0.1% of our combined business segments’ anticipated earnings before depreciation, depletion and amortization expenses). This sensitivity to the average WTI price is very similar to what we experienced in 2011. ~~We also~~

Furthermore, we currently expect to be unfavorably impacted in 2012 by lower natural gas liquids prices, which we now project to be approximately ~~23%~~21% lower for the full year 2012 than was assumed when we developed our 2012 ~~budget.~~budget, which equates to a negative impact of over $50 million. Due to the deteriorating natural gas ~~liquids~~liquid prices, we now expect to generate 2012 distributable cash flow ~~in 2012 essentially equivalent to~~slightly above our distributions, ~~for 2012.~~but below our budgeted amount.

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2011 in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

Recent Accounting Pronouncements

Please refer to Note 1112 “Recent Accounting Pronouncements” to our consolidated financial statements included elsewhere in this report for information concerning recent accounting pronouncements.

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Information Regarding Forward-Looking Statements

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

See Part I, Item 1A “Risk Factors” and Part II, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations—Information Regarding Forward-Looking Statements" of our 2011 Form 10-K and Part II, Item 1A “Risk Factors” in this report for a more detailed description of factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in our 2011 Form 10-K and in this report. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to update any forward-looking statements to reflect future events or developments after the date of this report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2011, in Item 7A of our 2011 Form 10-K and our Current Report on Form 8-K filed May 1, 2012. For more information on our risk management activities, see Note 56 “Risk Management” to our consolidated financial statements included elsewhere in this report.

Item 4. Controls and Procedures.

As of ~~June~~September 30, 2012, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control

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over financial reporting during the quarter ended ~~June~~September 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Part I, Item 1, Note 910 to our consolidated financial statements entitled “Litigation, Environmental and Other Contingencies,” which is incorporated in this item by reference.

Item 1A. Risk Factors.

Except as set forth below, there have been no material changes in or additions to the risk factors disclosed in Part I, Item 1A “Risk Factors” in our 2011 Form 10-K.

~~The terms upon which we will sell the assets comprising our FTC Natural Gas Pipelines disposal group are uncertain.~~

As a condition to receiving antitrust approval from the FTC of KMI’s acquisition of El Paso, KMI has agreed to divest the assets comprising our FTC Natural Gas Pipelines disposal group within six months following its acquisition of El Paso. As a result, the price at which we ultimately agree to sell these assets may be less than the price at which we would otherwise expect to sell them.

Further, as a result of this agreement with the FTC, in the first six months of 2012, we reduced the disposal group’s net asset carrying value to its estimated fair value and recognized a $649 million loss on the remeasurement to fair value. However, the terms upon which we will sell these assets are subject to negotiation and agreement with an as-yet undetermined third party. As a result, our estimate of the fair value of the disposal group’s net assets may not reflect the price at which we ultimately agree to sell them.

Our business, financial condition and operating results may be affected adversely by increased costs of capital or a reduction in the availability of credit.

Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings could cause our cost of doing business to increase by limiting our access to capital, limiting our ability to pursue acquisition opportunities and reducing our cash flows. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions. Also, continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect our business, financial condition and results of operations.

In addition, due to our relationship with KMI, our credit ratings, and thus our ability to access the capital markets and the terms and pricing we receive therein, may be adversely affected by any impairments to KMI's financial condition or adverse changes in its credit ratings. Similarly, any reduction in our credit ratings could negatively impact the credit ratings of our subsidiaries, which could increase their cost of capital and negatively affect their business and operating results. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our debt instruments, as well as the market value of our common units.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

On ~~June 4,~~August 13, 2012,, we paid to KMI $3,482 million in cash, issued ~~3,792,461~~4,667,575 common units, and assumed $2.3 billion in debt for the acquisition of certain natural gas pipeline assets. We valued the common units at $381 million, determining the units’ value based on the $81.52 closing market price of the common units on the New York Stock Exchange on the August 13, 2012 issuance date. The units were issued to KMI pursuant to Section 4(2) of the Securities Act of 1933.

On August 6, 2012, we issued 114,429 common units as ~~the~~part of our purchase price for a ~~50%~~ ~~equity ownership interest in El Paso Midstream Investment Company, LLC that~~certain refined petroleum products terminal assets we acquired from ~~an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P.~~Lincoln Oil Company. The ~~acquisition~~total purchase price for the acquired assets was ~~made effective~~ ~~June 1,~~$37 million, consisting of $28 million in cash, and $9 million in common units. We valued the common units at $9 million, determining the units’ value based on the $80.43 closing market price of the common units on the New York Stock Exchange on the August 6, 2012. issuance date. The units were issued to a single accredited investor in a transaction not involving a public offering and were therefore exempt from registration pursuant to Section 4(2) of the Securities Act of 1933.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures

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The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in exhibit 95 to this quarterly report.

Item 5. Other Information.

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None.

Item 6. Exhibits.



	*2.1 —	Purchase and Sale Agreement, dated as of August 17, 2012, between Kinder Morgan Operating L.P. "A" and Tallgrass Energy Partners, LP (filed as exhibit 2.1 to Kinder Morgan Energy Partners, L.P.'s Current Report on Form 8-K filed August 23, 2012 and incorporated herein by reference).
	*2.2 —	Purchase and Sale Agreement, dated as of August 17, 2012, between Kinder Morgan Operating L.P. "A" and Tallgrass Energy Partners, LP (filed as exhibit 2.2 to Kinder Morgan Energy Partners, L.P.'s Current Report on Form 8-K filed August 23, 2012 and incorporated herein by reference).
	*2.3 —	Contribution Agreement, dated as of August 6, 2012, among Kinder Morgan, Inc., El Paso TGPC Investments, L.L.C., El Paso EPNG Investments, L.L.C. and Kinder Morgan Energy Partners, L.P. (filed as exhibit 2.1 to Kinder Morgan Energy Partners, L.P.'s Current Report on Form 8-K filed August 6, 2012 and incorporated herein by reference).
	4.1 —	Certificate of the Vice President and Chief Financial Officer and the Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.45% Senior Notes due February 15, 2023, and the 5.00% Senior Notes due August 15, 2042.
	4.2 —	Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K (17 CFR 229.601). Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
	*10.1 —	Credit Agreement dated as of August 6, 2012 among Kinder Morgan Energy Partners, L.P.; Wells Fargo Bank, National Association, as Administrative Agent; Barclays Bank PLC, as Syndication Agent; and the lenders party thereto (filed as exhibit 10.1 to Kinder Morgan Energy Partners, L.P.'s Current Report on Form 8-K filed August 10, 2012 and incorporated herein by reference).
	11 —	Statement re: computation of per share earnings.
	12 —	Statement re: computation of ratio of earnings to fixed charges.
	31.1 —	Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2 —	Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1 —	Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2 —	Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	95 —	Mine Safety Disclosures.
	101 —	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011; (ii) our Consolidated Statements of Comprehensive Income for the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011; (iii) our Consolidated Balance Sheets as of ~~June~~September 30, 2012 and December 31, 2011; (iv) our Consolidated Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011; and (v) the notes to our Consolidated Financial Statements.

___________

* Asterisk indicates exhibit incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	KINDER MORGAN ENERGY PARTNERS, L.P.
			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.

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	June 30, 2012				December 31, 2011
	Carrying Value		Estimated Fair value		Carrying Value		Estimated Fair value
Total debt	$	13,133	$	14,717	$	12,797	$	14,238



	June 30, 2012			December 31, 2011
Derivatives – asset/(liability)
Current assets	$	17		$	9
Noncurrent assets	$	28		$	18
Current liabilities	$	(14	)	$	(64	)
Noncurrent liabilities	$	(3	)	$	(10	)

Date: ~~July 27,~~October 29, 2012

/s/ Kimberly A. Dang

Kimberly A. Dang
Vice President and Chief Financial Officer
(principal financial and accounting officer)