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 30, 2013

or

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 1‑11234

KINDER MORGAN ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

1001 Louisiana 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 307,743,507 common units outstanding as of July 26, 2013.

1

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES TABLE OF CONTENTS
		Page Number
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2013 and 2012	4
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2013 and 2012	5
	Consolidated Balance Sheets – June 30, 2013 and December 31, 2012	6
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2013 and 2012	7
	Consolidated Statements of Partners’ Capital – Six Months Ended June 30, 2013 and 2012	9
	Notes to Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation	52
	Critical Accounting Policies and Estimates	52
	Results of Operations	53
	Financial Condition	69
	Recent Accounting Pronouncements	76
	Information Regarding Forward-Looking Statements	76
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	76
Item 4.	Controls and Procedures	76
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	77
Item 1A.	Risk Factors	77
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	77
Item 3.	Defaults Upon Senior Securities	77
Item 4.	Mine Safety Disclosures	77
Item 5.	Other Information	77
Item 6.	Exhibits	78
	Signature	79

2

KINDER MORGAN ENERGY PARTNERS, L.P.
Company Abbreviations
BOSTCO	=	Battleground Oil Specialty Terminal Company LLC	KMP	=	Kinder Morgan Energy Partners, L.P., our majority-owned and controlled subsidiaries
Calnev	=	Calnev Pipe Line LLC	KinderHawk	=	KinderHawk Field Services LLC
Copano	=	Copano Energy, L.L.C.	KMI	=	Kinder Morgan, Inc.
Credit Suisse	=	Credit Suisse Securities (USA) LLC	KMR	=	Kinder Morgan Management, LLC
Eagle Ford	=	Eagle Ford Gathering LLC	Plantation	=	Plantation Pipe Line Company
EP	=	El Paso Corporation and its majority-owned and controlled subsidiaries	SFPP	=	SFPP, L.P.
EPB	=	El Paso Pipeline Partners, L.P.	Tallgrass	=	Tallgrass Development, LP (f/k/a Tallgrass Energy Partners, LP)
EPNG	=	El Paso Natural Gas Company, L.L.C.	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
KMEP	=	Kinder Morgan Energy Partners, L.P.	UBS	=	UBS Securities LLC
Unless the context otherwise requires, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P., our majority-owned and controlled subsidiaries, and our operating limited partnerships and their majority-owned and controlled subsidiaries.
Common Industry and Other Terms
AFUDC	=	allowance for funds used during construction	LIBOR	=	London Interbank Offered Rate
Bcf/d	=	billion cubic feet per day	LLC	=	Limited Liability Company
CERCLA	=	Comprehensive Environmental Response, Compensation and Liability Act	LNG	=	liquefied natural gas
CO2	=	Carbon Dioxide	MLP	=	master limited partnership
EBDA	=	Earnings before depreciation, depletion and amortization	MMcf/d	=	million cubic feet per day
DD&A	=	depreciation, depletion and amortization	Moody’s	=	Moody’s Investor Services
DCF	=	distributable cash flow	NYMEX	=	New York Mercantile Exchange
EPA	=	Environmental Protection Agency	NYSE	=	New York Stock Exchange
FERC	=	Federal Energy Regulatory Commission	PRP	=	Potentially Responsible Party
FASB	=	Financial Accounting Standards Board	S&P	=	Standard & Poor’s Rating Services
Fitch	=	Fitch Ratings	SEC	=	Securities and Exchange Commission
FTC	=	Federal Trade Commission	WTI	=	West Texas Intermediate
GAAP	=	Generally Accepted Accounting Principles in the United States of America	OTC	=	over-the-counter
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

3

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)
	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012(a)			2013			2012(a)
Revenues
Natural gas sales	$	942		$	500		$	1,677		$	1,084
Services	1,170			890			2,358			1,651
Product sales and other	905			620			1,643			1,123
Total Revenues	3,017			2,010			5,678			3,858
Operating Costs, Expenses and Other
Costs of sales	1,248			633			2,205			1,213
Operations and maintenance	597			374			981			680
Depreciation, depletion and amortization	357			276			685			515
General and administrative	163			171			297			278
Taxes, other than income taxes	75			59			149			109
Other expense (income)	(24		)	(20		)	(24		)	(20		)
Total Operating Costs, Expenses and Other	2,416			1,493			4,293			2,775
Operating Income	601			517			1,385			1,083
Other Income (Expense)
Earnings from equity investments	74			68			157			133
Amortization of excess cost of equity investments	(2		)	(2		)	(4		)	(4		)
Interest expense, net	(214		)	(156		)	(413		)	(291		)
Gain on remeasurement of previously held equity interest in Eagle Ford Gathering to fair value (Note 2)	558			—			558			—
Gain on sale of investments in Express pipeline system (Note 2)	—			—			225			—
Other, net	19			9			23			10
Total Other Income (Expense)	435			(81		)	546			(152		)
Income from Continuing Operations Before Income Taxes	1,036			436			1,931			931
Income Tax Expense	(26		)	(19		)	(127		)	(34		)
Income from Continuing Operations	1,010			417			1,804			897
Discontinued Operations (Notes 1 and 2)
Income from operations of FTC Natural Gas Pipelines disposal group	—			48			—			98
Loss on sale and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value	—			(327		)	(2		)	(649		)
Loss from Discontinued Operations	—			(279		)	(2		)	(551		)
Net Income	1,010			138			1,802			346
Net Income Attributable to Noncontrolling Interests	(10		)	(6		)	(19		)	(8		)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.	$	1,000		$	132		$	1,783		$	338
Calculation of Limited Partners’ Interest in Net Income (Loss)
Attributable to Kinder Morgan Energy Partners, L.P.:
Income from Continuing Operations	$	1,000		$	408		$	1,785		$	883
Less: Pre-acquisition income from operations of drop-down asset groups allocated to General Partner	—			21			(19		)	21
Add: Drop-Down asset groups’ severance expense allocated to General Partner	4			—			6			—
Less: General Partner’s remaining interest	(422		)	(336		)	(824		)	(657		)
Limited Partners’ Interest	582			93			948			247
Add: Limited Partners’ Interest in discontinued operations	—			(274		)	(2		)	(540		)
Limited Partners’ Interest in Net Income (Loss)	$	582		$	(181	)	$	946		$	(293	)
Limited Partners’ Net Income (Loss) per Unit - Basic and Diluted:
Income from Continuing Operations	$	1.41		$	0.27		$	2.40		$	0.73
Loss from Discontinued Operations	—			(0.80		)	(0.01		)	(1.59		)
Net Income (Loss) - Basic and Diluted	$	1.41		$	(0.53	)	$	2.39		$	(0.86	)
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income per Unit	413			342			395			340
Per Unit Cash Distribution Declared for the Period	$	1.32		$	1.23		$	2.62		$	2.43
The accompanying notes are an integral part of these consolidated financial statements.

____________

(a) Retrospectively adjusted as discussed in Note 1.

4

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,
	2013			2012(a)			2013			2012(a)
Net Income	$	1,010		$	138		$	1,802		$	346
Other Comprehensive Income (Loss):
Change in fair value of derivatives utilized for hedging purposes	70			303			29			189
Reclassification of change in fair value of derivatives to net income	(3		)	(11		)	(10		)	20
Foreign currency translation adjustments	(71		)	(40		)	(114		)	(2		)
Adjustments to pension and other postretirement benefit plan liabilities, net of tax	—			2			1			1
Total Other Comprehensive Income (Loss)	(4		)	254			(94		)	208
Comprehensive Income	1,006			392			1,708			554
Comprehensive Income Attributable to Noncontrolling Interests	(10		)	(9		)	(18		)	(10		)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.	$	996		$	383		$	1,690		$	544
The accompanying notes are an integral part of these consolidated financial statements.

____________

(a) Retrospectively adjusted as discussed in Note 1.

5

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions) (Unaudited)
	June 30, 2013		December 31, 2012(a)
ASSETS
Current assets
Cash and cash equivalents	$	656	$	529
Accounts receivable	1,300		1,114
Inventories	313		338
Fair value of derivative contracts	59		55
Assets held for sale	32		211
Other current assets	235		130
Total Current assets	2,595		2,377
Property, plant and equipment, net	26,023		22,330
Investments	2,213		1,864
Goodwill	6,532		5,417
Other intangibles, net	2,459		1,142
Fair value of derivative contracts	340		634
Deferred charges and other assets	1,247		1,212
Total Assets	$	41,409	$	34,976
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	1,899	$	1,155
Accounts payable	1,200		1,091
Accrued interest	351		327
Fair value of derivative contracts	28		21
Accrued other current liabilities	1,138		653
Total Current liabilities	4,616		3,247
Long-term liabilities and deferred credits
Long-term debt
Outstanding	17,338		15,907
Debt fair value adjustments	1,417		1,698
Total Long-term debt	18,755		17,605
Deferred income taxes	259		249
Fair value of derivative contracts	60		13
Other long-term liabilities and deferred credits	911		1,100
Total Long-term liabilities and deferred credits	19,985		18,967
Total Liabilities	24,601		22,214
Commitments and contingencies (Notes 3 and 9)
Partners’ Capital
Common units	9,395		4,723
Class B units	13		14
i-units	3,911		3,564
General partner	3,059		4,026
Accumulated other comprehensive income	75		168
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital	16,453		12,495
Noncontrolling interests	355		267
Total Partners’ Capital	16,808		12,762
Total Liabilities and Partners’ Capital	$	41,409	$	34,976
The accompanying notes are an integral part of these consolidated financial statements.

____________

(a) Retrospectively adjusted as discussed in Note 1.

6

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)
	Six Months Ended June 30,
	2013			2012(a)
Cash Flows From Operating Activities
Net Income	$	1,802		$	346
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	685			522
Amortization of excess cost of equity investments	4			4
(Gain) loss from the remeasurement of net assets to fair value (Note 2)	(558		)	649
Gain from the sale of investments in Express pipeline system (Note 2)	(225		)	—
Earnings from equity investments	(157		)	(174		)
Distributions from equity investments	152			159
Proceeds from termination of interest rate swap agreements	96			53
Changes in components of working capital net of the effects of acquisitions:
Accounts receivable	(26		)	(23		)
Inventories	(50		)	(81		)
Other current assets	(35		)	(20		)
Accounts payable	(151		)	(92		)
Accrued interest	12			1
Accrued other current liabilities	(7		)	190
Rate reparations, refunds and other litigation reserve adjustments	177			(54		)
Other, net	6			(51		)
Net Cash Provided by Operating Activities	1,725			1,429
Cash Flows From Investing Activities
Payment to KMI for drop-down asset groups, net of cash acquired (Note 2)	(994		)	20
Acquisitions of assets and investments, net of cash acquired	(286		)	(30		)
Repayments from related party	—			64
Capital expenditures	(1,268		)	(801		)
Proceeds from sale of investments in Express pipeline system	403			—
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs	23			30
Contributions to equity investments	(93		)	(86		)
Distributions from equity investments in excess of cumulative earnings	36			86
Other, net	22			(21		)
Net Cash Used in Investing Activities	(2,157		)	(738		)
Cash Flows From Financing Activities
Issuance of debt	4,858			3,438
Payment of debt	(3,860		)	(3,093		)
Debt issue costs	(11		)	(5		)
Proceeds from issuance of common units	834			277
Proceeds from issuance of i-units	73			—
Contributions from noncontrolling interests	99			17
Contributions from General Partner	38			—
Pre-acquisition contributions and distributions from KMI to drop-down asset group	35			—
Distributions to partners and noncontrolling interests:
Common units	(662		)	(551		)
Class B units	(14		)	(13		)
General Partner	(792		)	(630		)
Noncontrolling interests	(19		)	(15		)
Net Cash Provided by (Used in) Financing Activities	579			(575		)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	(20		)	(2		)
Net increase in Cash and Cash Equivalents	127			114
Cash and Cash Equivalents, beginning of period	529			409
Cash and Cash Equivalents, end of period	$	656		$	523
The accompanying notes are an integral part of these consolidated financial statements.

7

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (In Millions) (Unaudited)
	Six Months Ended June 30,
	2013		2012(a)
Noncash Investing and Financing Activities
Net assets acquired by the transfer of the drop-down asset groups	$	—	$	7,716
Assets acquired or liabilities settled by the issuance of common units	$	3,841	$	296
Increase in accrual for capital expenditures	$	141	$	23
Assets acquired by the assumption or incurrence of liabilities	$	1,490	$	—
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	411	$	300
Cash paid during the period for income taxes	$	14	$	11
The accompanying notes are an integral part of these consolidated financial statements.

____________

(a) Retrospectively adjusted as discussed in Note 1.

8

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (In Millions, Except Units)
	Six Months Ended June 30,
	2013				2012
	Units	Amount			Units	Amount
Common units:
Beginning Balance	252,756,425	$	4,723		232,677,222	$	4,347
Net income (loss)		659				(202		)
Units issued as consideration in the acquisition of assets	44,620,662	3,841			3,879,623	296
Units issued for cash	9,863,329	834			3,414,795	277
Distributions		(662		)		(551		)
Other adjustments		—				3
Ending Balance	307,240,416	9,395			239,971,640	4,170
Class B units:
Beginning Balance	5,313,400	14			5,313,400	42
Net income (loss)		13				(5		)
Distributions		(14		)		(13		)
Ending Balance	5,313,400	13			5,313,400	24
i-Units:
Beginning Balance	115,118,338	3,564			98,509,392	2,857
Net income (loss)		274				(86		)
Units issued for cash	860,600	73				—
Distributions	3,531,548	—			3,068,120	—
Other adjustments		—				1
Ending Balance	119,510,486	3,911			101,577,512	2,772
General partner:
Beginning Balance		4,026				259
Net income		837				631
Distributions		(792		)		(630		)
Drop-Down acquisitions (Note 1)		(1,057		)		7,658
Noncash compensation and severance expense allocated from KMI		5				—
Contributions		38				—
Other adjustments		2				1
Ending Balance		3,059				7,919
Accumulated other comprehensive income (loss):
Beginning Balance		168				3
Change in fair value of derivatives utilized for hedging purposes		29				187
Reclassification of change in fair value of derivatives to net income		(10		)		20
Foreign currency translation adjustments		(113		)		(2		)
Adjustments to pension and other postretirement benefit plan liabilities		1				1
Ending Balance		75				209
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital	432,064,302	16,453			346,862,552	15,094
Noncontrolling interests:
Beginning Balance		267				96
Net income		19				8
Contributions		99				17
Distributions		(19		)		(15		)
Drop-Down acquisitions (Note 3)		(10		)		78
Change in fair value of derivatives utilized for hedging purposes		—				2
Foreign currency translation adjustments		(1		)		—
Other adjustments		—				4
Ending Balance		355				190
Total Partners’ Capital	432,064,302	$	16,808		346,862,552	$	15,284

9

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., our operating limited partnerships and their majority-owned and controlled subsidiaries. We own an interest in or operate more than 53,000 miles of pipelines and 180 terminals, and conduct our business through five reportable business segments (described further in Note 7). We trade on the NYSE under the symbol “KMP.”

Our pipelines transport natural gas, refined petroleum products, crude oil, CO₂ 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 CO₂ for enhanced oil recovery projects in North America.

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

KMI, a Delaware corporation, indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation. 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 and Calnev.

KMI’s common stock trades on the NYSE under the symbol “KMI.” As of June 30, 2013, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by KMR (discussed below), an approximate 11.8% interest in us.

Effective May 25, 2012, KMI acquired all of the outstanding shares of EP. KMI’s acquisition of EP created one of the largest energy companies in the United States. As a result, KMI now owns a 41% limited partner interest and the 2% general partner interest in EPB.

Kinder Morgan Management, LLC

KMR 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 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 NYSE under the symbol “KMR.” As of June 30, 2013, KMR, through its sole ownership of our i-units, owned approximately27.7% of all of our outstanding limited partner units (all of our i-units are issued only to 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, 2012. In this report, we refer to our Annual Report on Form 10-K for the year ended December 31, 2012 as our 2012 Form 10-K.

10

Basis of Presentation

General

We have prepared our accompanying unaudited consolidated financial statements under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards 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 unaudited 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 2012 Form 10-K.

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 8 “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.

KMI Asset Drop-Downs

Effective August 1, 2012, we acquired a 100% interest in TGP and a 50% ownership interest in EPNG from KMI for an aggregate consideration of approximately $6.2 billion (including our proportional share of assumed debt borrowings as of August 1, 2012). In this report, we refer to this acquisition of assets from KMI as the August 2012 drop-down transaction; the combined group of assets acquired from KMI effective August 1, 2012 as the August 2012 drop-down asset group.

Effective March 1, 2013, we acquired from KMI both the remaining 50% ownership interest in EPNG and the remaining 50% ownership interest we did not already own in the EP midstream assets for an aggregate consideration of approximately $1.7 billion (including our proportional share of assumed debt borrowings as of March 1, 2013). In this report, we refer to this acquisition of assets from KMI as the March 2013 drop-down transaction; the combined group of assets acquired from KMI effective March 1, 2013 as the March 2013 drop-down asset group; the EP midstream assets or Kinder Morgan Altamont LLC (formerly, El Paso Midstream Investment Company, L.L.C.) as the midstream assets; and the combined August 2012 drop-down asset group (described above) and the March 2013 drop-down asset group as the drop-down asset groups. We acquired our initial 50% ownership interest in the midstream assets from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates, referred to as KKR) effective June 1, 2012. Prior to the March 2013 drop-down transaction, we accounted for the March 1, 2013 drop-down asset group under the equity method of accounting.

11

KMI acquired all of the assets included in the drop-down asset groups as part of its acquisition of EP on May 25, 2012 (discussed above), and KMI accounted for its EP acquisition under the acquisition method of accounting. We, however, accounted for the drop-down transactions as combinations of entities under common control. Accordingly, we prepared our consolidated financial statements to reflect the transfer of TGP, EPNG and the remaining 50% ownership interest in the midstream assets from KMI to us as if such transfers had taken place on the date when TGP, EPNG and the midstream assets met the accounting requirements for entities under common control—May 25, 2012 for both TGP and EPNG, and June 1, 2012 for the midstream assets. Specifically, we (i) consolidated our now 100% investments in the drop-down asset groups as of the effective dates of common control, recognizing the acquired assets and assumed liabilities at KMI’s carrying value (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 acquired as an adjustment to our Partners’ Capital (specifically, as an adjustment to our general partner’s and our noncontrolling interests’ capital interests); and (iii) retrospectively adjusted our consolidated financial statements, for any date after the effective dates of common control.

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 to our general partner:

▪ the earnings of the drop-down asset groups for the periods beginning on the effective dates of common control (described above) and ending August 1, 2012 for the August 2012 drop-down asset group and March 1, 2013 for the March 2013 drop-down asset group, respectively (we refer to these earnings as “pre-acquisition” earnings and we reported these earnings separately as “Pre-acquisition income from operations of drop-down asset groups allocated to General Partner” within the Calculation of Limited Partners’ Interest in Net Income (Loss) section of our accompanying consolidated statements of income for the three and six months ended June 30, 2013 and 2012); and

▪ incremental severance expense related to KMI’s acquisition of EP and allocated to us from KMI (and we reported this expense separately as “Drop-down asset groups’ severance expense allocated to General Partner” within the Calculation of Limited Partners’ Interest in Net Income (Loss) section of our accompanying consolidated statements of income for the three and six months ended June 30, 2013). The severance expense allocated to us was associated with the drop-down asset groups; however, we do not have any obligation, nor did we pay any amounts related to this expense.

For all periods beginning after our acquisition dates of August 1, 2012 and March 1, 2013, respectively, we allocated our earnings (including the earnings from the drop-down asset groups) to all of our partners according to our partnership agreement. For further information about the drop-down transactions, see Note 2 “Acquisitions and Divestitures—Acquisitions.”

FTC Natural Gas Pipelines Disposal Group – Discontinued Operations

Effective November 1, 2012, we sold 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 to Tallgrass for approximately $1.8 billion in cash (before selling costs), or $3.3 billion including our share of joint venture debt. In this report, we refer to this combined group of assets as our FTC Natural Gas Pipelines disposal group. The sale of our FTC Natural Gas Pipelines disposal group satisfied the terms of a March 15, 2012 agreement between KMI and the FTC to divest certain of our assets in order to receive regulatory approval for KMI’s EP acquisition. For more information about the presentation of our FTC Natural Gas Pipelines disposal group as discontinued operations, see Note 2 “Summary of Significant Accounting Policies—Basis of Presentation—FTC Natural Gas Pipelines Disposal Group - Discontinued Operations” to our consolidated financial statements included in our 2012 Form 10-K.

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Goodwill

We evaluate goodwill for impairment on May 31 of each year.  For this purpose, we have seven reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO₂; (vi) Terminals; and (vii) Kinder Morgan Canada.  During the quarter ended June 30, 2013, the Natural Gas Pipelines Non-Regulated reporting unit was created to include the non-regulated businesses acquired from Copano on May 1, 2013 as well as other non-regulated businesses that were historically part of the former Natural Gas Pipelines reporting unit (now the Natural Gas Pipelines Regulated reporting unit). Goodwill was allocated between these two reporting units based on the relative fair values of the reporting units. There were no impairment charges resulting from our May 31, 2013 impairment testing, and no event indicating an impairment has occurred subsequent to that date.

The fair value of each reporting unit was determined based on a market approach utilizing an average dividend/distribution yield of comparable companies. The value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price estimated to be received in a sale of the unit as a whole in an orderly transaction between market participants at the measurement date.

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.

2. Acquisitions and Divestitures    

Acquisitions

March 2013 KMI Asset Drop-Down

As discussed above in Note 1 “General—Basis of Presentation—KMI Asset Drop-Downs,” we acquired the March 2013 drop-down asset group from KMI effective March 1, 2013. Our consideration to KMI consisted of (i) $994 million in cash (including $6 million paid to KMI in the second quarter of 2013 to settle the final working capital adjustment); (ii) 1,249,452 common units (valued at $108 million based on the $86.72 closing market price of a common unit on the NYSE on the March 1, 2013 issuance date); and (iii) $557 million in assumed debt (consisting of 50% of the outstanding principal amount of EPNG’s debt borrowings as of March 1, 2013, 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. We included the March 2013 drop-down asset group in our Natural Gas Pipelines segment.

August 2012 KMI Asset Drop-Down

As discussed above in Note 1 “General—Basis of Presentation—KMI Asset Drop-Downs,” we acquired the August 2012 drop-down asset group from KMI effective August 1, 2012. For additional information about this acquisition, see Note 2 “Summary of Significant Accounting Policies—Basis of Presentation—August 2012 KMI Asset Drop-Down” and Note 3 “Acquisitions and Divestitures—August 2012 KMI Asset Drop-Down” to our consolidated financial statements included in our 2012 Form 10-K.

Copano Energy, L.L.C.

Effective May 1, 2013, we closed our previously announced acquisition of Copano. We acquired all of Copano’s outstanding units for a total purchase price of approximately $5.2 billion (including assumed debt and all other assumed liabilities). The transaction was a 100% unit for unit transaction with an exchange ratio of 0.4563 of our common units for each Copano common unit. We issued 43,371,210 of our common units valued at $3,733 million as consideration for the Copano acquisition (based on the $86.08 closing market price of a common unit on the NYSE on the May 1, 2013 issuance date).

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We accounted for our acquisition of Copano under the acquisition method of accounting, and accordingly, we measured the consideration paid to Copano unitholders, the acquired identifiable tangible and intangible assets, and the assumed liabilities at their acquisition-date fair values. Also, due to the fact that our acquisition included the remaining 50% interest in Eagle Ford that we did not already own, we remeasured our existing 50% equity investment in Eagle Ford to its fair value as of the acquisition date, resulting in the recognition of a $558 million pre-tax non-cash gain reported separately within “Other Income (Expense)”.

The preliminary purchase price allocation related to the Copano acquisition is as follows (in millions). Our evaluation of the assigned fair values is ongoing and subject to adjustment:

Preliminary Purchase Price Allocation:
Current assets (including cash acquired of $29)	$	217
Property, plant and equipment	2,753
Investments	448
Goodwill	1,123
Other intangibles, net	1,350
Other assets	12
Total assets	5,903
Less: Fair value of previously held 50% interest in Eagle Ford Gathering, LLC	(704		)
Total assets acquired	5,199
Current liabilities	(207		)
Other liabilities	(7		)
Long-term debt	(1,252		)
Common unit consideration	$	3,733

The “Goodwill” intangible asset amount represents the future economic benefits expected to be derived from this acquisition that are not assignable to other individually identifiable, separately recognizable assets acquired. We believe the primary items that generated the goodwill are the value of the synergies created by expanding our natural gas gathering and refined product transportation operations. This goodwill is not deductible for tax purposes, and is subject to an impairment test at least annually. The “Other intangibles, net” asset amount represents the fair value of acquired customer contracts and agreements. We are currently amortizing these intangible assets over an estimated remaining useful life of 25 years.

Copano provides comprehensive services to natural gas producers, including natural gas gathering, processing, treating and natural gas liquids fractionation. Copano owns an interest in or operates approximately 6,900 miles of pipelines with 2.7 Bcf/d of natural gas transportation capacity, and also owns nine natural gas processing plants with more than 1 Bcf/d of natural gas processing capacity and 315 MMcf/d of natural gas treating capacity. Its operations are located primarily in Texas, Oklahoma and Wyoming. Most of the acquired assets will be included in our Natural Gas Pipelines business segment.

Goldsmith Landreth Unit

On June 1, 2013, we acquired certain oil and gas properties, rights, and related assets in the Permian Basin of West Texas from Legado Resources LLC for approximately $285 million (before working capital adjustments). We also assumed $18 million of liabilities. The acquisition of the Goldsmith Landreth San Andres oil field unit includes more than 6,000 acres located in Ector County, Texas, and based on our measurement of fair values for all of the identifiable tangible and intangible assets acquired and liabilities assumed, we assigned the $285 million amount to “Property, plant and equipment, net.” The acquired oil field is in the early stages of CO₂ flood development and includes a residual oil zone along with a classic San Andres waterflood. The field currently produces approximately 1,250 barrels of oil per day, and as part of the transaction, we obtained a long-term supply contract for up to 150 MMcf/d of CO₂. The acquisition complements our existing oil and gas producing assets in the Permian Basin, and we included the acquired assets as part of our CO₂ business segment.

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Pro Forma Information

The following summarized unaudited pro forma consolidated income statement information for the three and six months ended June 30, 2013 and 2012, assumes that our acquisitions of the drop-down asset groups, Copano and the Goldsmith Landreth Unit had occurred as of January 1, 2012. We prepared the following unaudited pro forma financial results for comparative purposes only. The unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed our acquisitions of the drop-down asset groups and Copano as of January 1, 2012 or the results that will be attained in the future. Amounts presented below are in millions, except for the per unit amounts:

	Pro Forma
	Three Months Ended June 30, 2013			Three Months Ended June 30, 2012			Six Months Ended June 30, 2013			Six Months Ended June 30, 2012
	(Unaudited)
Revenues	$	3,204		$	2,660		$	6,383		$	5,366
Income from Continuing Operations	$	984		$	288		$	1,766		$	695
Loss from Discontinued Operations	$	—		$	(279	)	$	(2	)	$	(551	)
Net Income	$	984		$	9		$	1,764		$	144
Net Income Attributable to Noncontrolling Interests	$	(10	)	$	(7	)	$	(19	)	$	(8	)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.	$	974		$	2		$	1,745		$	136
Limited Partners’ Net Income (Loss) per Unit:
Income from Continuing Operations	$	1.30		$	(0.04	)	$	2.21		$	0.19
Loss from Discontinued Operations	—			(0.70		)	(0.01		)	(1.39		)
Net Loss	$	1.30		$	(0.74	)	$	2.20		$	(1.20	)

Divestitures

FTC Natural Gas Pipelines Disposal Group – Discontinued Operations

As described above in Note 1 “General—Basis of Presentation,” we began accounting for our FTC Natural Gas Pipelines disposal group as discontinued operations in the first quarter of 2012 (prior to KMI’s sale announcement, we included the disposal group in our Natural Gas Pipelines business segment). During that quarter, we also remeasured the disposal group’s net assets to reflect our initial assessment of its fair value as a result of the FTC mandated sale requirement, and based on additional information gained in the sale process during the second quarter of 2012, we recognized an additional loss amount from fair value remeasurement. For the six months ended June 30, 2012, we recognized a combined $649 million non-cash loss from remeasurement, and we reported this loss amount separately as “Loss on sale 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. As a result of our remeasurement of net assets to fair value and the sale of net assets, we recognized a combined $829 million loss for the year ended December 31, 2012.

We and Tallgrass trued up the final consideration for the sale of our FTC Natural Gas Pipelines disposal group in the first quarter of 2013, and based on this true up, we recognized an additional $2 million loss. We reported this loss amount separately as “Loss on sale 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 months ended June 30, 2013, and except for this loss amount, we recorded no other financial results from the operations of our FTC Natural Gas Pipelines disposal group in the first six months of 2013.

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Summarized financial information for the FTC Natural Gas Pipelines Disposal Group is as follows (in millions):

	Three Months Ended June 30, 2012			Six Months Ended June 30, 2012
Operating revenues	$	62		$	133
Operating expenses	(34		)	(71		)
Depreciation and amortization	—			(7		)
Earnings from equity investments	20			42
Interest income and Other, net	—			1
Income from operations of FTC Natural Gas Pipelines disposal group	$	48		$	98

Express Pipeline System

Effective March 14, 2013, we sold both our one-third equity ownership interest in the Express pipeline system and our subordinated debenture investment in Express to Spectra Energy Corp. for $403 million in cash. We recorded a pre-tax gain of $225 million with respect to this transaction in the first quarter of 2013, and we reported this gain amount separately within the “Other Income (Expense)” section of our accompanying consolidated statements of income for the six months ended June 30, 2013. We also recorded an income tax expense of $84 million related to this gain amount, and we included this expense within “Income Tax Expense” in our accompanying consolidated statement of income for the six months ended June 30, 2013. As of the date of sale, our equity investment in Express totaled $67 million and our note receivable due from Express totaled $110 million.

Prior to the sale, we (i) accounted for our equity investment under the equity method of accounting; (ii) accounted for our debt investment under the historical amortized cost method of accounting; and (iii) included the financial results of the Express pipeline system within our Kinder Morgan Canada business segment. As of December 31, 2012, our equity and debt investments in Express totaled $65 million and $114 million, respectively, and we included the combined $179 million amount within “Assets held for sale” on our accompanying consolidated balance sheet as of that date.

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3. Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income. The following provides detail on the principal amount of our outstanding debt, which excludes debt fair value adjustments (which includes discounts and premiums), as of June 30, 2013 and December 31, 2012 (in millions):

	June 30, 2013			December 31, 2012
Kinder Morgan Energy Partners, L.P. borrowings:
Senior notes, 3.45% through 9.00%, due 2013 through 2043(a)	$	14,350		$	13,350
Commercial paper borrowings(b)	1,369			621
Credit facility due May 1, 2018(c)	—			—
Subsidiary borrowings (as obligor):
Tennessee Gas Pipeline Company, L.L.C. - Notes, 7.00% through 8.375%, due 2016 through 2037(d)	1,790			1,790
El Paso Natural Gas Company, L.L.C. - Notes, 5.95% through 8.625%, due 2017 through 2032(e)	1,115			1,115
Copano Energy, L.L.C. - Notes, 7.125%, due April 1, 2021(f)	510			—
Other miscellaneous subsidiary debt	103			186
Total long-term debt	19,237			17,062
Less: Current portion of debt(g)	(1,899		)	(1,155		)
Total long-term debt, less current portion of debt(h)	$	17,338		$	15,907

__________

(a) All of our fixed rate senior notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. On February 28, 2013, we completed a public offering of $1 billion in principal amount of senior notes in two separate series, consisting of $600 million of 3.50% notes due September 1, 2023 and $400 million of 5.00% notes due March 1, 2043. We received net proceeds of $991 million, and used the proceeds to pay a portion of the purchase price for our March 2013 drop-down transaction and to reduce the borrowings under our commercial paper program.

(b) In May 2013, in association with the increase in capacity negotiated for our senior unsecured revolving bank credit facility (discussed below), we increased our commercial paper program by $500 million to provide for the issuance of up to $2.7 billion.  Our senior unsecured revolving credit facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. As of June 30, 2013 and December 31, 2012, the average interest rates on our outstanding commercial paper borrowings were 0.33% and 0.45%, respectively. The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during the first half of 2013 and during 2012, and in the near term, we expect that our short-term liquidity and financing needs will be met primarily through borrowings made under our commercial paper program.

(c) See “—Credit Facility” below.

(d) Consists of six separate series of fixed-rate unsecured senior notes that we assumed as part of the August 2012 drop-down transaction.

(e) Consists of four separate series of fixed-rate unsecured senior notes that we assumed as part of the August 2012 and March 2013 drop-down transactions.

(f) Consists of a single series of fixed-rate unsecured senior notes that we guaranteed as part of our May 1, 2013 Copano acquisition. The notes consist of an aggregate principal amount of $510 million with a fixed annual stated interest rate of 7.125%. The notes mature in full on April 1, 2021, and interest is payable semiannually on April 1 and October 1 of each year. As part of our purchase price, we valued the debt equal to $589 million as of May 1, 2013, representing the present value of amounts to be paid determined using an approximate interest rate of 4.79%.

(g) As of June 30, 2013 and December 31, 2012, includes commercial paper borrowings of $1,369 million and $621 million, respectively.

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(h) Excludes debt fair value adjustments. As of June 30, 2013 and December 31, 2012, our “Debt fair value adjustments” increased our debt balances by $1,417 million and $1,698 million, respectively. In addition to all unamortized debt discount/premium amounts and purchase accounting on our debt balances, our debt fair value adjustments also include (i) amounts associated with the offsetting entry for hedged debt; and (ii) any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see Note 5 “Risk Management—Fair Value of Derivative Contracts.”

Credit Facility

On May 1, 2013, we replaced our previous $2.2 billionthree-year, senior unsecured revolving bank credit facility that was due July 1, 2016, with a new $2.7 billionfive-year, senior unsecured revolving credit facility expiring May 1, 2018. Borrowings under the credit facility can be used for general partnership purposes and as a backup for our commercial paper program. We had no borrowings under the credit facility as of June 30, 2013. The credit facility’s financial covenants are substantially similar to those in our previous facility, and as of June 30, 2013, we were in compliance with all required financial covenants. The new facility provides that the margin we will pay with respect to borrowings and the facility fee we will pay on the total commitment will vary based on our senior debt credit rating. Interest on the credit facility accrues at our option at a floating rate equal to either:

▪ the administrative agent’s base rate, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt (the administrative agent’s base rate is a rate equal to the greatest of (i) the Federal Funds Rate, plus 0.5%; (ii) the Prime Rate; or (iii) LIBOR for a one-month eurodollar loan, plus 1%); or

▪ LIBOR for a one-month eurodollar loan, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.

In addition, we had, as of June 30, 2013, $1,127 million of borrowing capacity available under our credit facility. The amount available for borrowing under our credit facility was reduced bya combined amount of $1,573 million, consisting of $1,369 million of commercial paper borrowings and$204 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 $85 million in three letters of credit that support tax-exempt bonds; and (iii) a combined $19 million in other letters of credit supporting other obligations of us and our subsidiaries.

2013 Debt Retirements

In February 2013, prior to the close of the March 2013 drop down transaction, we and KMI each contributed $45 million to Kinder Morgan Altamont LLC to allow it to repay the outstanding $90 million borrowings under its revolving bank credit facility and following this repayment, Kinder Morgan Altamont LLC had no outstanding debt. In May 2013, we terminated the credit facility.

In addition to the senior notes we guaranteed as part of our May 1, 2013 Copano acquisition, the following Copano debt amounts were also outstanding upon acquisition: (i) $404 million of outstanding borrowings under Copano’s revolving bank credit facility due June 10, 2016; and (ii) $249 million aggregate principal amount of Copano’s 7.75% unsecured senior notes due June 1, 2018. On May 1, 2013, immediately following our acquisition, we repaid the outstanding $404 million of borrowings under Copano’s revolving bank credit facility, and we terminated the credit facility at the time of such repayment. On June 1, 2013, we paid $259 million (based on a price of 103.875% of the principal amount) to fully redeem and retire the 7.75% series of senior notes in accordance with the terms and conditions of the indenture governing the notes. As part of our May 1, 2013 purchase price, we valued the 7.75% senior notes equal to the $259 million redemption value. We utilized borrowings under our commercial paper program for both of these debt retirements.

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4. Partners’ Capital

Limited Partner Units

As of June 30, 2013 and December 31, 2012, our Partners’ Capital included the following limited partner units:

	June 30, 2013	December 31, 2012
Common units:
Held by third parties	284,952,961	231,718,422
Held by KMI and affiliates (excluding our general partner)	20,563,455	19,314,003
Held by our general partner	1,724,000	1,724,000
Total Common units	307,240,416	252,756,425
Class B units(a)	5,313,400	5,313,400
i-units(b)	119,510,486	115,118,338
Total limited partner units	432,064,302	373,188,163

_________

(a) As of both June 30, 2013 and December 31, 2012, all of our Class B units were held by a wholly-owned subsidiary of KMI.  The Class B units are similar to our common units except that they are not eligible for trading on the NYSE.

(b) As of both June 30, 2013 and December 31, 2012, all of our i-units were held by KMR.  Our i-units are a separate class of limited partner interests in us and are not publicly traded.  In accordance with KMR’s limited liability company agreement, KMR’s activities are restricted to being a limited partner in us, and to controlling and managing our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries.  Through the combined effect of the provisions in our partnership agreement and the provisions of KMR’s limited liability company agreement, the number of outstanding KMR shares and the number of our i-units will at all times be equal. 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.

The total limited partner units represent our limited partners’ interest and an effective 98% interest in us, exclusive of our general partner’s right to receive incentive distributions. Our general partner has an effective 2% interest in us, excluding its right to receive incentive distributions.

Equity Issuances

For the six month period ended June 30, 2013, our significant equity issuances consisted of the following:

• on February 26, 2013, we issued, in a public offering, 4,600,000 of our common units at a price of $86.35 per unit, less commissions and underwriting expenses. We received net proceeds, of $385 million for the issuance of these 4,600,000 common units, and used the proceeds to pay a portion of the purchase price for the March 2013 drop-down transaction;

• on March 1, 2013, in connection with the March 2013 drop-down transaction, we issued 1,249,452 of our common units to KMI. We valued the units at $108 million, based on the $86.72 closing market price of a common unit on the NYSE on March 1, 2013;

• on May 1, 2013, we issued 43,371,210 common units to Copano unitholders as our purchase price for Copano;

• in the second quarter of 2013, we issued 5,263,329 of our common units pursuant to our third amended and restated equity distribution agreement with UBS. We received net proceeds from the issuance of these common units of$449 million. We used the proceeds to reduce the borrowings under our commercial paper program; and

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• in the second quarter of 2013, we issued 860,600 i-units to KMR. We received net proceeds of $73 million for the issuance of these 860,600 i-units, and we used the proceeds to reduce the borrowings under our commercial paper program. KMR realized net proceeds of $73 million from the issuance of 860,600 of its shares pursuant to its equity distribution agreement with Credit Suisse, and KMR used the net proceeds received from the issuance of these shares to buy the additional i-units from us. KMR entered into its equity distribution agreement with Credit Suisse on May 4, 2012. The terms of this agreement are substantially similar to the terms of our equity distribution agreement with UBS, and allows KMR to sell from time to time through Credit Suisse, as KMR’s sales agent, KMR’s shares representing limited liability company interests having an aggregate offering price of up to $500 million.

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.

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The following table provides information about our distributions for the three and six month periods ended June 30, 2013 and 2012 (in millions except per unit and i-unit distributions amounts):

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Per unit cash distribution declared for the period	$	1.32	$	1.23	$	2.62	$	2.43
Per unit cash distribution paid in the period	$	1.30	$	1.20	$	2.59	$	2.36
Cash distributions paid in the period to all partners(a)(b)	$	757	$	619	$	1,487	$	1,209
i-unit distributions made in the period to KMR(c)	1,726,952		1,603,975		3,531,548		3,068,120
General Partner’s incentive distribution(d):
Declared for the period(e)	$	416	$	337	$	814	$	656
Paid in the period(c)	$	398	$	319	$	782	$	621

__________

(a) Consisting of our common and Class B unitholders, our general partner and noncontrolling interests.

(b) The period-to-period increases in distributions paid reflect the increases in amounts distributed per unit as well as the issuance of additional units. In addition, as agreed upon with our general partner, distributions paid to all partners include the following decreases in the incentive distribution we paid to our general partner (i) $4 million and $6 million in the second quarters of 2013 and 2012, respectively; and (ii) $11 million and $14 million in the first six months of 2013 and 2012, respectively, all representing waived incentive amounts related to common units issued to finance a portion of our July 2011 KinderHawk acquisition.  Beginning with our distribution payments for the quarterly period ended June 30, 2010, and ending with our distribution payments for the quarterly period ended March 31, 2013, our general partner agreed not to take certain incentive distributions related to our acquisition of KinderHawk.  For more information about our KinderHawk acquisition, see Note 3 “Acquisitions and Divestitures—Business Combinations and Acquisitions of Investments—(3) KinderHawk Field Services LLC (1 of 2)” and “—(6) KinderHawk Field Services LLC and EagleHawk Field Services LLC (2 of 2)” to our consolidated financial statements included in our 2012Form 10-K.

(c) Under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units.  The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR.  The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units.  If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. Based on the preceding, the i-units we distributed were based on the $1.30 and $1.20 per unit paid to our common unitholders during the second quarters of 2013 and 2012, respectively, and the $2.59 and $2.36 per unit paid to our common unitholders during the first six months of 2013 and 2012, respectively.

(d) Incentive distribution does not include the general partner’s initial 2% distribution of available cash.

(e) Three and six month 2013 amounts include reductions of $25 million for waived general partner incentive amounts related to common units issued to finance our May 1, 2013 Copano acquisition.

For additional information about our 2012 partnership distributions, see Note 16 “Litigation, Environmental and Other Contingencies” and Note 17 “Regulatory Matters” to our consolidated financial statements included in our 2012 Form 10-K.

Subsequent Events

Units issued subsequent to period end were comprised of (i) 503,091 of our common units; and (ii) 215,200 of our i-units, both of which were issued in early July 2013, for the settlement of sales made on or before June 30, 2013 pursuant to our equity distribution agreement and KMR’s equity distribution agreement, respectively. We received net proceeds of $43 million and $18 million from the issuances of these additional common units and i-units, respectively, and used the proceeds to reduce the borrowings under our commercial paper program.

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On July 17, 2013, we declared a cash distribution of $1.32 per unit for the quarterly period ended June 30, 2013. The distribution will be paid on August 14, 2013 to unitholders of record as of July 31, 2013. Our common unitholders and our Class B unitholder will receive cash. KMR will receive a distribution of1,880,172 additional i-units based on the$1.32 distribution per common unit. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.015704) will be issued. This fraction was determined by dividing:

• $1.32, the cash amount distributed per common unit

by

• $84.057, the average of KMR’s shares’ closing market prices from July 15-26, 2013, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the NYSE.

5. 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.

As part of the Copano acquisition, we acquired derivative contracts related to natural gas, natural gas liquids and crude oil. None of these derivatives are designated as accounting hedges.

Energy Commodity Price Risk Management

As of June 30, 2013, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:

	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price	(22.0)	million barrels
Natural gas fixed price	(32.8)	billion cubic feet
Natural gas basis	(32.8)	billion cubic feet
Derivatives not designated as hedging contracts
Crude oil fixed price	0.7	million barrels
Crude oil basis	(2.4)	million barrels
Natural gas fixed price	(0.5)	billion cubic feet
Natural gas basis	0.6	billion cubic feet
Natural gas liquids fixed price	0.5	million barrels

As of June 30, 2013, 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 2017.

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Interest Rate Risk Management

As of June 30, 2013, we had a combined notional principal amount of $4,550 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 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 30, 2013, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.

As of December 31, 2012, we had a combined notional principal amount of $5,525 million of fixed-to-variable interest rate swap agreements. In June 2013, we terminated, three fixed-to-variable swap agreements having a combined notional principal amount of $975 million. We received combined proceeds of $96 million from the early termination of these swap agreements.

Fair Value of Derivative Contracts

The fair values of our current and non-current asset and liability derivative contracts are each reported separately as “Fair value of derivative contracts” in the respective sections of our accompanying consolidated balance sheets. The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of June 30, 2013 and December 31, 2012 (in millions):

Fair Value of Derivative Contracts
		Asset derivatives				Liability derivatives
		June 30, 2013		December 31, 2012		June 30, 2013			December 31, 2012
	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	$	37	$	42	$	(21	)	$	(18	)
	Non-current-Fair value  of derivative contracts	77		40		(16		)	(11		)
Subtotal		114		82		(37		)	(29		)
Interest rate swap agreements	Current-Fair value of  derivative contracts	2		9		(6		)	—
	Non-current-Fair value  of derivative contracts	259		594		(43		)	(1		)
Subtotal		261		603		(49		)	(1		)
Total		375		685		(86		)	(30		)
Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current-Fair value of  derivative contracts	20		4		(1		)	(3		)
	Non-current-Fair value  of derivative contracts	4		—		(1		)	(1		)
Total		24		4		(2		)	(4		)
Total derivatives		$	399	$	689	$	(88	)	$	(34	)

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Certain of our derivative contracts are subject to master netting agreements. As of June 30, 2013 and December 31, 2012, we presented the fair value of our derivative contracts on a gross basis on our accompanying consolidated balance sheets.  The following tables present our derivative contracts subject to such netting agreements as of the dates indicated (in millions):

Offsetting of Financial Assets and Derivative Assets
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet		Amounts of Assets Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet						Net Amount
							Financial Instruments			Cash Collateral Held(a)
As of June 30, 2013:
Energy commodity derivative contracts	$	138	$	—	$	138	$	(26	)	$	(1	)	$	111
Interest rate swap agreements	$	261	$	—	$	261	$	(10	)	$	—		$	251
As of December 31, 2012:
Energy commodity derivative contracts	$	86	$	—	$	86	$	(17	)	$	—		$	69
Interest rate swap agreements	$	603	$	—	$	603	$	—		$	—		$	603

Offsetting of Financial Liabilities and Derivative Liabilities
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet		Amounts of Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet				Net Amount
									Financial Instruments		Cash Collateral Posted(b)
As of June 30, 2013:
Energy commodity derivative contracts	$	(39	)	$	—	$	(39	)	$	26	$	—	$	(13	)
Interest rate swap agreements	$	(49	)	$	—	$	(49	)	$	10	$	—	$	(39	)
As of December 31, 2012:
Energy commodity derivative contracts	$	(33	)	$	—	$	(33	)	$	17	$	5	$	(11	)
Interest rate swap agreements	$	(1	)	$	—	$	(1	)	$	—	$	—	$	(1	)

___________

(a) Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Accrued other current liabilities” in our accompanying consolidated balance sheets.

(b) Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current assets” in our accompanying consolidated balance sheets.

Debt Fair Value Adjustments

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. Our “Debt fair value adjustments” also include all unamortized debt discount/premium amounts, purchase accounting on our debt balances, and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. These fair value adjustments to our debt balances included (i) $687 million and $638 million at June 30, 2013 and December 31, 2012, respectively, associated with fair value adjustments to our debt previously recorded in purchase accounting; (ii) $212 million and $602 million at June 30, 2013 and December 31, 2012, respectively, associated with the offsetting entry for hedged debt; (iii) $550 million and $488 million at June 30, 2013 and December 31, 2012, respectively, associated with unamortized premium from the termination of interest rate swap agreements; and offset by (iv) $32 million and $30 million at June 30, 2013 and December 31, 2012, respectively, associated with unamortized debt discount amounts. As of June 30, 2013, the weighted-average amortization period of the unamortized premium from the termination of the interest rate swaps was approximately 16 years.

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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 months ended June 30, 2013 and 2012 (in millions):

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)
		Three Months Ended June 30,						Six Months Ended June 30,
		2013			2012			2013			2012
Interest rate swap agreements	Interest expense	$	(211	)	$	194		$	(294	)	$	81
Total		$	(211	)	$	194		$	(294	)	$	81
Fixed rate debt	Interest expense	$	211		$	(194	)	$	294		$	(81	)
Total		$	211		$	(194	)	$	294		$	(81	)

___________

(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.

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)
	Three Months Ended June 30,					Three Months Ended June 30,							Three Months Ended June 30,
	2013		2012			2013			2012				2013		2012
Energy commodity derivative contracts	$	70	$	303	Revenues-Natural gas sales	$	—		$	2		Revenues-Natural gas sales	$	—	$	—
					Revenues-Product sales and other	8			(2		)	Revenues-Product sales and other	9		—
					Gas purchases and other costs of sales	(5		)	11			Gas purchases and other costs of sales	—		—
Total	$	70	$	303	Total	$	3		$	11		Total	$	9	$	—
	Six Months Ended June 30,					Six Months Ended June 30,							Six Months Ended June 30,
	2013		2012			2013			2012				2013		2012
Energy commodity derivative contracts	$	29	$	189	Revenues-Natural gas sales	$	—		$	2		Revenues-Natural gas sales	$	—	$	—
					Revenues-Product sales and other	15			(31		)	Revenues-Product sales and other	6		(3		)
					Gas purchases and other costs of sales	(5		)	9			Gas purchases and other costs of sales	—		—
Total	$	29	$	189	Total	$	10		$	(20	)	Total	$	6	$	(3	)

____________

(a) We expect to reclassify an approximate $24 milliongain associated with energy commodity price risk management activities and included in our Partners’ Capital as of June 30, 2013 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).

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For each of the three and six months ended June 30, 2013 and 2012, we did not recognize a material gain or loss in income from derivative contracts not designated as accounting hedges.

Credit Risks

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

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

Our OTC 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 with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.

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 ofboth June 30, 2013 and December 31, 2012, 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.

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 30, 2013, 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 $5 million of additional collateral.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

Changes in the components of our “Accumulated other comprehensive income” for the six months ended June 30, 2013 are summarized as follows (in millions):

	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjs.			Total Accumulated other comprehensive income/(loss)
Balance as of December 31, 2012	$	66		$	132		$	(30	)	$	168
Other comprehensive income before reclassifications	30			(114		)	1			(83		)
Amounts reclassified from accumulated other comprehensive income	(10		)	—			—			(10		)
Net current-period other comprehensive income	20			(114		)	1			(93		)
Balance as of June 30, 2013	$	86		$	18		$	(29	)	$	75

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6. 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;

▪ 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 30, 2013 and December 31, 2012, based on the three levels established by the Codification. 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. The fair value measurements in the tables below do not include cash margin deposits made by us, which are reported within “Other current assets” in our accompanying consolidated balance sheets (in millions).

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	Asset fair value measurements using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
As of June 30, 2013
Energy commodity derivative contracts(a)	$	138	$	14	$	89	$	35
Interest rate swap agreements	$	261	$	—	$	261	$	—
As of December 31, 2012
Energy commodity derivative contracts(a)	$	86	$	3	$	76	$	7
Interest rate swap agreements	$	603	$	—	$	603	$	—

	Liability fair value measurements using
	Total			Quoted prices in active markets for identical liabilities (Level 1)			Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
As of June 30, 2013
Energy commodity derivative contracts(a)	$	(39	)	$	(4	)	$	(18	)	$	(17	)
Interest rate swap agreements	$	(49	)	$	—		$	(49	)	$	—
As of December 31, 2012
Energy commodity derivative contracts(a)	$	(33	)	$	(3	)	$	(26	)	$	(4	)
Interest rate swap agreements	$	(1	)	$	—		$	(1	)	$	—

____________

(a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and OTC natural gas swaps that are settled on NYMEX. Level 3 consists primarily of WTI options, WTI basis swaps and natural gas liquids options.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the three and six months ended June 30, 2013 and 2012 (in millions):

Significant unobservable inputs (Level 3)
	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Derivatives-net asset (liability)
Beginning of Period	$	3		$	(3	)	$	3		$	7
Total gains or (losses):
Included in earnings	—			(2		)	6			—
Included in other comprehensive income	1			28			—			6
Purchases(a)	18			—			18			3
Settlements	(4		)	(3		)	(9		)	4
End of Period	$	18		$	20		$	18		$	20
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	$	1		$	(2	)	$	5		$	(1	)

____________

(a) 2013 purchases include a net asset of $18 million of Level 3 energy commodity derivative contracts associated with the Copano acquisition.

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As of June 30, 2013, our Level 3 derivative assets and liabilities consisted primarily of WTI options, WTI basis swaps and natural gas liquids options, where a significant portion of fair value is calculated from underlying market data that is not readily observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in our management’s best estimate of fair value.

Fair Value of Financial Instruments

The estimated fair value of our outstanding debt balance as of June 30, 2013 and December 31, 2012 (both short-term and long-term and including debt fair value adjustments), is disclosed below (in millions):

	June 30, 2013				December 31, 2012
	Carrying Value		Estimated Fair value		Carrying Value		Estimated Fair value
Total debt	$	20,654	$	21,240	$	18,760	$	20,439

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both June 30, 2013 and December 31, 2012.

7. Reportable Segments

We operate in five reportable business segments. These segments and their principal sources of revenues are as follows:

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

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

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

▪ 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 and the State of Washington. As further described in Note 2, Kinder Morgan Canada divested its interest in the Express pipeline system effective March 14, 2013.

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 makers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and marketing strategies.

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Financial information by segment follows (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenues
Natural Gas Pipelines(a)	$	1,696		$	851		$	3,065		$	1,645
CO2	460			413			889			830
Products Pipelines	443			331			897			554
Terminals
Revenues from external customers	343			342			680			683
Intersegment revenues	1			1			1			1
Kinder Morgan Canada	75			73			147			146
Total segment revenues	3,018			2,011			5,679			3,859
Less: Total intersegment revenues	(1		)	(1		)	(1		)	(1		)
Total consolidated revenues	$	3,017		$	2,010		$	5,678		$	3,858

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Segment earnings before depreciation, depletion, amortization     and amortization of excess cost of equity investments(b)
Natural Gas Pipelines(a)	$	1,123		$	289		$	1,680		$	511
CO2	358			327			700			661
Products Pipelines(c)	12			166			197			342
Terminals	207			195			393			382
Kinder Morgan Canada(d)	50			52			243			102
Total segment earnings before DD&A	1,750			1,029			3,213			1,998
Total segment depreciation, depletion and amortization	(357		)	(276		)	(685		)	(515		)
Total segment amortization of excess cost of investments	(2		)	(2		)	(4		)	(4		)
General and administrative expenses	(163		)	(171		)	(297		)	(278		)
Interest expense, net of unallocable interest income	(215		)	(160		)	(417		)	(299		)
Unallocable income tax expense	(3		)	(3		)	(6		)	(5		)
Loss from discontinued operations	—			(279		)	(2		)	(551		)
Total consolidated net income	$	1,010		$	138		$	1,802		$	346

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	June 30, 2013		December 31, 2012
Assets
Natural Gas Pipelines	$	25,112	$	19,403
CO2	2,805		2,337
Products Pipelines	5,192		4,921
Terminals	5,590		5,123
Kinder Morgan Canada	1,628		1,903
Total segment assets	40,327		33,687
Corporate assets(e)	1,082		1,289
Total consolidated assets	$	41,409	$	34,976

____________

(a) Increases in the three and six month 2013 amounts versus the three and six month 2012 amounts reflect our (i) acquisition of the drop-down asset groups from KMI; (ii) acquisition of Copano; and (iii) recognition of a $558 million non-cash gain in the second quarter of 2013 from the remeasurement of net assets to fair value (all discussed further in Note 2 “Acquisitions and Divestitures—Acquisitions”).

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

(c) Three and six month 2013 amounts include increases in expense of $162 million and $177 million, respectively, associated with adjustments to legal liabilities related to both transportation rate case and environmental matters.

(d) Six month 2013 amount includes a $141 million increase in earnings from the after-tax gain on the sale of our investments in the Express pipeline system.

(e) 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.

8. Related Party Transactions

Notes Receivable

Plantation Pipe Line Company

We and ExxonMobil have a term loan agreement covering a note receivable due from Plantation. We own a 51.17% equity interest in Plantation and our proportionate share of the outstanding principal amount of the note receivable was $49 million as of both June 30, 2013 and December 31, 2012. 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 “Other current assets,” on our accompanying consolidated balance sheets as of both June 30, 2013 and December 31, 2012, and we included the remaining outstanding balance within “Deferred charges and other assets.”

Asset Acquisitions

From time to time in the ordinary course of business, we buy and sell assets and related services from KMI and its subsidiaries.  Such transactions are conducted in accordance with all applicable laws and regulations and on an arms’ length basis consistent with our policies governing such transactions.  In conjunction with our acquisition of (i) certain Natural Gas Pipelines assets and partnership interests from KMI in December 1999 and December 2000; (ii) TransColorado Gas Transmission Company LLC from KMI in November 2004; (iii) TGP and 50% of EPNG from KMI in August 2012; and (iv) the remaining 50% ownership interest in EPNG from KMI in March 2013, KMI has agreed to indemnify us and our general partner with respect to approximately $5.9 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.

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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 our general partner’s conflicts and audit committee (consisting of its independent directors) 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 conflicts and audit committee of our general partner’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 “Related Party Transactions” to our consolidated financial statements included in our 2012 Form 10-K.

9. Litigation, Environmental and Other Contingencies

We are party to various legal, regulatory and other matters arising from the day-to-day operations of our businesses that may result in claims against the Partnership. 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 distributions to limited partners. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Partnership. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.

Federal Energy Regulatory Commission Proceedings

The tariffs and rates charged by SFPP and EPNG are subject to a number of ongoing proceedings at the FERC. A substantial portion of our legal reserves relate to these FERC cases and the California Public Utilities Commission (CPUC) cases described below them. 

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SFPP

The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers.  In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA).  If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach back 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, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance we may include in our rates.  With respect to all of the SFPP proceedings at the FERC, 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 several recent FERC decisions in SFPP cases, as applicable, to other pending cases would result in substantially lower rate reductions and 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.

EPNG

The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”).  With respect to the 2008 rate case, the FERC issued its decision (“Opinion 517”) in May 2012 and EPNG implemented certain aspects of that decision. The FERC subsequently issued an order requiring EPNG to decrease its rates related to the 2010 rate case in accordance with Opinion 517.  EPNG has sought rehearing on that order as well as Opinion 517.  With respect to the 2010 rate case, the presiding administrative law judge issued an initial decision in June 2012.  This initial decision is currently being reviewed by the FERC.  EPNG is pursuing settlement with its shippers in both open rate cases and believes the accruals established for these matters are adequate.

California Public Utilities Commission Proceedings

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 generally been consolidated and assigned to two administrative law judges. 

On May 26, 2011, the CPUC issued a decision in several intrastate rate cases involving SFPP and a number of its shippers (the “Long” cases).  The decision includes determinations on issues, such as SFPP’s entitlement to an income tax allowance, 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. On March 8, 2012, the CPUC issued another decision related to the Long cases. This decision largely reflected the determinations made on May 26, 2011, including the denial of an income tax allowance for SFPP. The CPUC’s order denied SFPP’s request for rehearing of the CPUC’s income tax allowance treatment, while granting requested rehearing of various, other issues relating to 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 a court order vacating the CPUC’s determination that SFPP is not entitled to recover an income tax allowance in its intrastate rates. The Court has recently denied SFPP’s petition. SFPP is currently assessing the precise impact of the ruling and its options, including an appeal to the California Supreme Court.

On April 6, 2011, 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. The matter has been submitted, subject to the filing of briefs due August 9, 2013, with a decision expected in the fourth quarter of 2013.

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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. As of June 30, 2013, we believe our legal reserve, including an adjustment of the reserve made in the second quarter of 2013 related in part to this matter, is adequate such that the resolution of pending CPUC matters will not have a material adverse impact on our business, financial position or results of operations. We do not expect any reparations that we would pay in this matter to impact the $5.33 per unit cash distributions we expect to pay to our limited partners for 2013.

Copano Shareholders’ Litigation

Threeputative class action lawsuits were filed in connection with our merger with Copano: (i) Schultes v. Copano Energy, L.L.C., et al. (Case No. 06966), in the District Court of Harris County, Texas, which is referred to as the Texas State Action; (ii) Bruen v. Copano Energy, L.L.C., et al. (Case No. 4:13-CV-00540) in the United States District Court for the Southern District of Texas, which is referred to as the Texas Federal Action; and (iii) In re Copano Energy, L.L.C. Shareholder Litigation, Case No. 8284-VCN in the Court of Chancery of the State of Delaware, which is referred to as the Delaware Action, which reflects the consolidation of three actions originally filed in the Court of Chancery. The Texas State Action, the Texas Federal Action and the Delaware Action are collectively referred to as the “Actions.”

The Actions name Copano, R. Bruce Northcutt, William L. Thacker, James G. Crump, Ernie L. Danner, T. William Porter, Scott A. Griffiths, Michael L. Johnson, Michael G. MacDougall, Kinder Morgan GP, Kinder Morgan Energy Partners and Merger Sub as defendants. The Actions are purportedly brought on behalf of a putative class seeking to enjoin the merger and allege, among other things, that the members of Copano’s board of directors breached their fiduciary duties by agreeing to sell Copano for inadequate and unfair consideration and pursuant to an inadequate and unfair process, and that Copano, Kinder Morgan Energy Partners, Kinder Morgan GP and Merger Sub aided and abetted such alleged breaches. In addition, the plaintiffs in each of the Texas State Action and the Delaware Action allege that the Copano directors breached their duty of candor to unitholders by failing to provide the unitholders with all material information regarding the merger and/or made misstatements in the preliminary proxy statement. The plaintiffs in the Texas Federal Action also assert a claim under the federal securities laws alleging that the preliminary proxy statement omits and/or misrepresents material information in connection with the merger.

On April 21, 2013, the parties in all the Actions executed a Memorandum of Understanding pursuant to which Copano agreed to make certain additional disclosures concerning the merger in a Form 8-K, which Copano filed on April 22, 2013, and the plaintiffs agreed to enter into a stipulation of settlement providing for full settlement and dismissal with prejudice of each of the Actions. The parties then prepared and filed a Stipulation of Settlement with the Delaware Chancery Court, and on June 28, 2013, Copano announced that we had reached an agreement with the plaintiffs to settle all claims asserted against all defendants. The settlement does not require the defendants to pay any monetary consideration to the proposed settlement class, and is subject to, among other conditions, approval of the Delaware Chancery Court. A settlement hearing has been scheduled for September 9, 2013.

Other Commercial Matters

Union Pacific Railroad Company Easements

SFPP and Union Pacific Railroad Company (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.

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SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP appealed this decision, and in December 2008, the appellate court affirmed the decision. In addition, UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way Association (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 Kinder Morgan Bulk Terminals, Inc. (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. Trial is scheduled to begin on November 12, 2013.

Pipeline Integrity and Releases

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

General

As of June 30, 2013 and December 31, 2012, our total reserve for legal fees, transportation rate cases and other potential litigation liabilities was $594 million and $404 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising from our products pipeline and natural gas pipeline transportation rates. The overall change in the reserve from December 31, 2012 includes a $177 million increase in expense in the first half of 2013 associated with interstate and California intrastate transportation rate case liability adjustments.

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Environmental Matters

We are subject to environmental cleanup and enforcement actions from time to time. In particular, the Comprehensive Environmental Response, Compensation and Liability Act, also know as 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 CO₂ 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 attempt to negotiate and settle such matters where appropriate. Specifically, we are involved in matters including incidents at terminal facilities in New Jersey and Texas involving the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Texas Commission on Environmental Quality, respectively, which may result in fines and penalties for alleged violations. We do not believe that these alleged violations will have a material adverse effect on our business, financial position, results of operations or distributions to limited partners.

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 CO₂.

Colorado Oil and Gas Conservation Commission Inspections

In Fall 2012, the Colorado Oil and Gas Conservation Commission (COGCC) performed inspections at multiple well sites in Southwestern Colorado owned by Kinder Morgan CO₂ Company, L.P. and some of these inspections resulted in alleged violations of COGCC’s rules. Kinder Morgan took immediate steps to correct the alleged deficiencies and has engaged COGCC and other agencies in its efforts to maintain compliance. In June 2013, the parties settled the matter through an Administrative Order on Consent under which Kinder Morgan agreed to pay $220,000 of which up to $80,000 may be paid toward a public project. Other than completion of the agreed public project, this matter is resolved and no further actions are anticipated.

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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 New Jersey Department of Environmental Protection (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/ Kinder Morgan Liquids Terminals LLC) (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. Recently, KMLT, as part of a joint defense group, entered a settlement agreement (Consent Judgment) with the NJDEP whereby the settling parties for a prescribed payment, get a contribution bar against first party defendants Occidental, Maxus and Tierra in addition to a release. This third-party Consent Judgment was published in the New Jersey Register for a 60-day comment period and no significant comments were received. Additionally, the NJDEP has reached an agreement for a settlement with Maxus and Tierra. Occidental is not part of the settlement. As part of this settlement, these defendants agreed to dismiss all direct claims against third-party defendants and to not oppose the third-party settlement. This settlement agreement has been published in the New Jersey Register and is in the middle of a 60-day comment period. All discovery and trial proceedings are stayed during settlement negotiations.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

In December 2000, the 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. A group of 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 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 2014 and the EPA to issue its Record of Decision in 2015. It is anticipated that the cleanup activities would begin within one year of the issuance of the 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. The parties are currently finalizing a stipulated case management order.

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

KMLT is a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles. The lawsuit was stayed beginning in 2009 and remained stayed following the last case management conference in 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. We anticipate that cleanup activities by the Port at the site will begin in the summer of 2013. On April 9, 2013, KMLT and the Port of Los Angeles entered into a Settlement and Release Agreement the terms of which provide for the dismissal of the litigation by the Port upon the payment by KMLT of 60% of the Port’s costs to remediate the former terminal site; the amount of payment not to exceed $15 million. The Court approved the parties’ Good Faith Settlement motion in the Superior Court and dismissed the case. Further, according to terms of the Settlement and Release, we received a 5-year lease extension that allows KMLT to continue fuel loading and offloading operations at another KMLT Port of Los Angeles terminal property.

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 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 and successfully brought Support Terminals/Plains into the case. The court consolidated the two cases.

In mid 2011, KMLT and Plains Products entered into a settlement agreement with the NJDEP for settlement of the state’s alleged natural resource damages claim. The parties then entered into a Consent Judgment concerning the claim. 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 party’s 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. According to the agreement, Plains will conduct remediation activities at the site and KMLT will provide oversight and 50% of the costs.

The settlement with the state did not resolve the original complaint brought by ExxonMobil. On or around, April 10, 2013, KMLT, Plains and ExxonMobil settled the original Exxon complaint for past remediation costs for $750,000 to be split 50/50 between KMLT and Plains. All parties have now executed the agreement and the litigation is settled and dismissed.

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 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.

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On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ summary adjudication motions.  The Court tentatively granted our partial motions for summary judgment on the City’s claims for water and real estate damages and the State’s claims for violations of California Business and Professions Code § 17200, tentatively denied the City’s motion for summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary judgment on such claims.  On January 25, 2013, the Court issued its final order reaffirming in all respects its tentative rulings and rendered judgment in favor of all defendants on all claims asserted by the City. 

On February 20, 2013, the City of San Diego filed a notice of appeal of this case to the United States Court of Appeals for the Ninth Circuit. The City filed its Opening Brief in the appeal on June 28, 2013. We were granted a 30-day extension and will file our response by August 28, 2013.

This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board.  SFPP continues to conduct an extensive remediation effort at the City’s stadium property site.

On May 7, 2013, the City of San Diego filed a writ of mandamus to the California Superior Court seeking an order from the Court setting aside the California Regional Water Quality Control Board’s (RWQCB) approval of our permit request to increase the discharge of water from our groundwater treatment system to the City of San Diego’s municipal storm sewer system. This will include Kinder Morgan Energy Partners, L.P. as a real party in interest. Following the completion of the administrative record by the RWQCB, we have 30 days to respond to the writ.

Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., an historical subsidiary of EPNG, operated approximately twenty uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation.  The mining activities were in response to numerous incentives provided to industry by the United States to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program.  In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a potentially responsible party within the meaning of CERCLA.  In February 2013, the EPA delivered a proposed Administrative Order on Consent and proposed Scope of Work regarding the government’s proposed next steps to investigate the mines.  We are negotiating the terms and conditions of both the Administrative Order on Consent and the Scope of Work.  We are also seeking contribution from the United States toward the cost of environmental activities associated with the mines, given its pervasive control over all aspects of the nuclear weapons program.

PHMSA Inspection of Carteret Terminal, Carteret, NJ

On April 4, 2013, the PHMSA, Office of Pipeline Safety issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV) associated with an inspection at the KMLT, Carteret, NJ location on March 15, 2011. The PHMSA inspection followed a release and fire that occurred during a maintenance activity on March 14, 2011. PHMSA is proposing a $500,000 penalty associated with procedural and infrastructure issues that may have contributed to the March 14, 2011 incident. KMLT has been working on addressing the proposed corrective actions since before the NOPV was issued and is currently negotiating the proposed penalty.

Southeast Louisiana Flood Protection Litigation

On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (“Flood Protection Authority”) filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP and approximately one hundred energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The Flood Protection Authority asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization.

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General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows. As of June 30, 2013 and December 31, 2012, we have accrued a total reserve for environmental liabilities in the amount of $167 million and $166 million, respectively.

10. Regulatory Matters and Accounting for Regulatory Activities

Regulatory Assets and Liabilities

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.  We included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Accrued other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets. The recovery period for these regulatory assets is approximately one year to twenty-four years.

The following table summarizes our regulatory asset and liability balances (in millions):

	June 30, 2013		December 31, 2012
Current regulatory assets	$	34	$	18
Non-current regulatory assets	255		204
Total Regulatory Assets	$	289	$	222
Current regulatory liabilities	$	117	$	4
Non-current regulatory liabilities	328		65
Total Regulatory Liabilities(a)	$	445	$	69

(a) During the three months ended June 30, 2013, we began applying regulatory accounting to another one of our pipeline systems due to a newly negotiated long-term tolling agreement approved by the system’s regulator that went into effect in April 2013. The primary impact of applying regulatory accounting, was the reclassification of approximately $362 million of current and long-term deferred credits to regulatory liabilities, of which $115 million remains classified as current. We expect this regulatory liability to be refunded to rate-payers over approximately the next four years.

More information about our regulatory matters can be found in Note 17 “Regulatory Matters” to our consolidated financial statements included in our 2012 Form 10-K.

11. Recent Accounting Pronouncements

Accounting Standards Updates

None of the Accounting Standards Updates (ASU) that we adopted and that became effective January 1, 2013 (including (i) ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities;” (ii) ASU No. 2012-02, “Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment;” (iii) ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities;” and (iv) ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”) had a material impact on our consolidated financial statements. More information about the four ASUs listed above can be found in Note 18 “Recent Accounting Pronouncements” to our consolidated financial statements that were included in our 2012 Form 10-K.

40

On March 5, 2013, the FASB issued ASU No. 2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity (a consensus of the FASB Emerging Issues Task Force).” This ASU amends the FASB’s Accounting Standards Codification (ASC) 830, “Foreign Currency Matters,” and ASC 810, “Consolidation,” to address diversity in practice related to the release of cumulative translation adjustments (CTA) into earnings upon the occurrence of certain derecognition events. ASU No. 2013-05 precludes the release of CTA for derecognition events that occur within a foreign entity, unless such events represent a complete or substantially complete liquidation of the foreign entity; however, derecognition events related to investments in a foreign entity result in the release of all CTA related to the derecognized foreign entity, even when a noncontrolling financial interest is retained. ASU No. 2013-05 also amends ASC 805, “Business Combinations,” for transactions that result in a company obtaining control of a business in a step acquisition by increasing an investment in a foreign entity from one accounted for under the equity method to one accounted for as a consolidated investment. ASU No. 2013-05 is effective for fiscal years beginning after December 15, 2013 (January 1, 2014 for us). It should be applied prospectively, and prior periods should not be adjusted. Early adoption is permitted as of the beginning of the entity’s fiscal year. We are currently reviewing the effects of ASU No. 2013-05.

12. Guarantee of Securities of Subsidiaries

Kinder Morgan Energy Partners, L.P. has guaranteed the payment of Copano’s outstanding series of senior notes that mature on April 1, 2021 (referred to in this report as the “Guaranteed Notes”). Copano Energy Finance Corporation (Copano Finance Corp), a direct subsidiary of Copano, is the co-issuer of the Guaranteed Notes. As of June 30, 2013, Copano had $510 million in aggregate principal amount of Guaranteed Notes outstanding. Copano Finance Corp’s obligations as a co-issuer and primary obligor are the same as and joint and several with the obligations of Copano as issuer, however, it has no subsidiaries and no independent assets or operations. Subject to the limitations set forth in the applicable supplemental indentures, KMEP’s guarantee is full and unconditional and guarantees the Guaranteed Notes through their maturity date. A significant amount of KMEP’s income and cash flow is generated by its respective subsidiaries. As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries. Included among the non-guarantor subsidiaries are KMEP’s five operating limited partnerships and the majority-owned and controlled subsidiaries, along with Copano’s remaining majority-owned and controlled subsidiaries. In the following unaudited condensed consolidating financial information, Kinder Morgan Energy Partners, L.P. is “Parent Guarantor,” and Copano and Copano Finance Corp are the “Subsidiary Issuers.” The Subsidiary Issuers are 100% owned by Kinder Morgan Energy Partners, L.P.

41

Condensed Consolidating Balance Sheet (In Millions) (Unaudited)
June 30, 2013
	Parent Guarantor		Subsidiary Issuers		Non-guarantor Subsidiaries		Eliminations			Consolidated KMP
ASSETS
Cash and cash equivalents	$	—	$	1	$	655	$	—		$	656
All other current assets	2,538		157		1,897		(2,653		)	1,939
Property, plant and equipment, net	—		—		26,023		—			26,023
Investments	—		—		2,213		—			2,213
Investments in subsidiaries	13,998		4,206		—		(18,204		)	—
Goodwill	—		795		5,737		—			6,532
Notes receivable from affiliates	16,474		—		—		(16,474		)	—
Deferred charges and all other assets	346		—		3,700		—			4,046
Total Assets	$	33,356	$	5,159	$	40,225	$	(37,331	)	$	41,409
LIABILITIES AND PARTNERS’ CAPITAL
Liabilities
Current portion of debt	$	1,899	$	—	$	—	$	—		$	1,899
All other current liabilities	359		50		4,961		(2,653		)	2,717
Long-term debt	14,548		588		3,619		—			18,755
Notes payable to affiliates	—		775		15,699		(16,474		)	—
Deferred income taxes	—		2		257		—			259
All other long-term liabilities	97		4		870		—			971
Total Liabilities	16,903		1,419		25,406		(19,127		)	24,601
Partners’ Capital
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital	16,453		3,740		14,464		(18,204		)	16,453
Noncontrolling interests	—		—		355		—			355
Total Partners’ Capital	16,453		3,740		14,819		(18,204		)	16,808
Total Liabilities and Partners’ Capital	$	33,356	$	5,159	$	40,225	$	(37,331	)	$	41,409

42

Condensed Consolidating Balance Sheet (In Millions) (Unaudited)
December 31, 2012
	Parent Guarantor		Subsidiary Issuers		Non-guarantor Subsidiaries		Eliminations			Consolidated KMP(a)
ASSETS
Cash and cash equivalents	$	95	$	—	$	434	$	—		$	529
All other current assets	2,235		—		1,752		(2,139		)	1,848
Property, plant and equipment, net	—		—		22,330		—			22,330
Investments	—		—		1,864		—			1,864
Investments in subsidiaries	10,124		—		—		(10,124		)	—
Goodwill	—		—		5,417		—			5,417
Notes receivable from affiliates	14,787		—		—		(14,787		)	—
Deferred charges and all other assets	674		—		2,314		—			2,988
Total Assets	$	27,915	$	—	$	34,111	$	(27,050	)	$	34,976
LIABILITIES AND PARTNERS’ CAPITAL
Liabilities
Current portion of debt	$	1,155	$	—	$	—	$	—		$	1,155
All other current liabilities	341		—		3,890		(2,139		)	2,092
Long-term debt	13,876		—		3,729		—			17,605
Notes payable to affiliates	—		—		14,787		(14,787		)	—
Deferred income taxes	—		—		249		—			249
All other long-term liabilities	48		—		1,065		—			1,113
Total Liabilities	15,420		—		23,720		(16,926		)	22,214
Partners’ Capital
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital	12,495		—		10,124		(10,124		)	12,495
Noncontrolling interests	—		—		267		—			267
Total Partners’ Capital	12,495		—		10,391		(10,124		)	12,762
Total Liabilities and Partners’ Capital	$	27,915	$	—	$	34,111	$	(27,050	)	$	34,976

_______

(a) Retrospectively adjusted as discussed in Note 1.

43

Condensed Consolidating Statement of Income (In Millions) (Unaudited)
Three Months Ended June 30, 2013
	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Revenues	$	—		$	—		$	3,017		$	—		$	3,017
Operating Costs, Expenses and Other
Costs of sales	—			—			1,248			—			1,248
Depreciation, depletion and amortization	—			—			357			—			357
Other operating expenses	—			22			789			—			811
Total Operating Costs, Expenses and Other	—			22			2,394			—			2,416
Operating Income (Loss)	—			(22		)	623			—			601
Other Income (Expense), Net	1,004			29			436			(1,034		)	435
Income from Continuing Operations Before Income Taxes	1,004			7			1,059			(1,034		)	1,036
Income Tax Benefit (Expense)	(4		)	—			(22		)	—			(26		)
Income from Continuing Operations	1,000			7			1,037			(1,034		)	1,010
Loss from Discontinued Operations	—			—			—			—			—
Net Income	1,000			7			1,037			(1,034		)	1,010
Net Income Attributable to Noncontrolling Interests	—			—			(10		)	—			(10		)
Net Income Attributable to Kinder Morgan Energy Partners, L.P	$	1,000		$	7		$	1,027		$	(1,034	)	$	1,000

44

Condensed Consolidating Statement of Income (In Millions) (Unaudited)
Three Months Ended June 30, 2012
	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Revenues	$	—		$	—	$	2,010		$	—		$	2,010
Operating Costs, Expenses and Other
Costs of sales	—			—		633			—			633
Depreciation, depletion and amortization	—			—		276			—			276
Other operating expenses	—			—		584			—			584
Total Operating Costs, Expenses and Other	—			—		1,493			—			1,493
Operating Income (Loss)	—			—		517			—			517
Other Income (Expense), Net	134			—		(90		)	(125		)	(81		)
Income (Loss) from Continuing Operations Before Income Taxes	134			—		427			(125		)	436
Income Tax Benefit (Expense)	(2		)	—		(17		)	—			(19		)
Income from Continuing Operations	132			—		410			(125		)	417
Loss from Discontinued Operations	—			—		(279		)	—			(279		)
Net Income (Loss)	132			—		131			(125		)	138
Net Income Attributable to Noncontrolling Interests	—			—		(6		)	—			(6		)
Net Income Attributable to Kinder Morgan Energy Partners, L.P	$	132		$	—	$	125		$	(125	)	$	132

45

Condensed Consolidating Statement of Income (In Millions) (Unaudited)
Six Months Ended June 30, 2013
	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Revenues	$	—		$	—		$	5,678		$	—		$	5,678
Operating Costs, Expenses and Other
Costs of sales	—			—			2,205			—			2,205
Depreciation, depletion and amortization	—			—			685			—			685
Other operating expenses	—			22			1,381			—			1,403
Total Operating Costs, Expenses and Other	—			22			4,271			—			4,293
Operating Income (Loss)	—			(22		)	1,407			—			1,385
Other Income (Expense), Net	1,789			29			538			(1,810		)	546
Income from Continuing Operations Before Income Taxes	1,789			7			1,945			(1,810		)	1,931
Income Tax Benefit (Expense)	(6		)	—			(121		)	—			(127		)
Income from Continuing Operations	1,783			7			1,824			(1,810		)	1,804
Loss from Discontinued Operations	—			—			(2		)	—			(2		)
Net Income	1,783			7			1,822			(1,810		)	1,802
Net Income Attributable to Noncontrolling Interests	—			—			(19		)	—			(19		)
Net Income Attributable to Kinder Morgan Energy Partners, L.P	$	1,783		$	7		$	1,803		$	(1,810	)	$	1,783

46

Condensed Consolidating Statement of Income (In Millions) (Unaudited)
Six Months Ended June 30, 2012
	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Revenues	$	—		$	—	$	3,858		$	—		$	3,858
Operating Costs, Expenses and Other
Costs of sales	—			—		1,213			—			1,213
Depreciation, depletion and amortization	—			—		515			—			515
Other operating expenses	—			—		1,047			—			1,047
Total Operating Costs, Expenses and Other	—			—		2,775			—			2,775
Operating Income (Loss)	—			—		1,083			—			1,083
Other Income (Expense), Net	343			—		(173		)	(322		)	(152		)
Income (Loss) from Continuing Operations Before Income Taxes	343			—		910			(322		)	931
Income Tax Benefit (Expense)	(5		)	—		(29		)	—			(34		)
Income from Continuing Operations	338			—		881			(322		)	897
Loss from Discontinued Operations	—			—		(551		)	—			(551		)
Net Income (Loss)	338			—		330			(322		)	346
Net Income Attributable to Noncontrolling Interests	—			—		(8		)	—			(8		)
Net Income Attributable to Kinder Morgan Energy Partners, L.P	$	338		$	—	$	322		$	(322	)	$	338

47

Condensed Consolidating Statement of Comprehensive Income (In Millions) (Unaudited)
Three Months Ended June 30, 2013
	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Income (Loss)	$	1,000		$	7	$	1,037		$	(1,034	)	$	1,010
Other Comprehensive Income (Loss)
Change in fair value of derivatives utilized for hedging purposes	70			—		70			(70		)	70
Reclassification of change in fair value of derivatives to net income	(3		)	—		(3		)	3			(3		)
Foreign currency translation adjustments	(71		)	—		(71		)	71			(71		)
Adjustments to pension and other postretirement benefit plan liabilities, net of tax	—			—		—			—			—
Total Other Comprehensive Income (Loss)	(4		)	—		(4		)	4			(4		)
Comprehensive Income	996			7		1,033			(1,030		)	1,006
Comprehensive Income Attributable to Noncontrolling Interests	—			—		(10		)	—			(10		)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.	$	996		$	7	$	1,023		$	(1,030	)	$	996

Condensed Consolidating Statement of Comprehensive Income (In Millions) (Unaudited)
Three Months Ended June 30, 2012
	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Income (Loss)	$	132		$	—	$	131		$	(125	)	$	138
Other Comprehensive Income (Loss)
Change in fair value of derivatives utilized for hedging purposes	300			—		303			(300		)	303
Reclassification of change in fair value of derivatives to net income	(11		)	—		(11		)	11			(11		)
Foreign currency translation adjustments	(40		)	—		(40		)	40			(40		)
Adjustments to pension and other postretirement benefit plan liabilities, net of tax	2			—		2			(2		)	2
Total Other Comprehensive Income (Loss)	251			—		254			(251		)	254
Comprehensive Income (Loss)	383			—		385			(376		)	392
Comprehensive Income Attributable to Noncontrolling Interests	—			—		(9		)	—			(9		)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.	$	383		$	—	$	376		$	(376	)	$	383

48

Condensed Consolidating Statement of Comprehensive Income (In Millions) (Unaudited)
Six Months Ended June 30, 2013
	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Income (Loss)	$	1,783		$	7	$	1,822		$	(1,810	)	$	1,802
Other Comprehensive Income (Loss)
Change in fair value of derivatives utilized for hedging purposes	29			—		29			(29		)	29
Reclassification of change in fair value of derivatives to net income	(10		)	—		(10		)	10			(10		)
Foreign currency translation adjustments	(113		)	—		(114		)	113			(114		)
Adjustments to pension and other postretirement benefit plan liabilities, net of tax	1			—		1			(1		)	1
Total Other Comprehensive Income (Loss)	(93		)	—		(94		)	93			(94		)
Comprehensive Income (Loss)	1,690			7		1,728			(1,717		)	1,708
Comprehensive Income Attributable to Noncontrolling Interests	—			—		(18		)	—			(18		)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.	$	1,690		$	7	$	1,710		$	(1,717	)	$	1,690

Condensed Consolidating Statement of Comprehensive Income (In Millions) (Unaudited)
Six Months Ended June 30, 2012
	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Income (Loss)	$	338		$	—	$	330		$	(322	)	$	346
Other Comprehensive Income (Loss)
Change in fair value of derivatives utilized for hedging purposes	187			—		189			(187		)	189
Reclassification of change in fair value of derivatives to net income	20			—		20			(20		)	20
Foreign currency translation adjustments	(2		)	—		(2		)	2			(2		)
Adjustments to pension and other postretirement benefit plan liabilities, net of tax	1			—		1			(1		)	1
Total Other Comprehensive Income (Loss)	206			—		208			(206		)	208
Comprehensive Income (Loss)	544			—		538			(528		)	554
Comprehensive Income Attributable to Noncontrolling Interests	—			—		(10		)	—			(10		)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.	$	544		$	—	$	528		$	(528	)	$	544

49

Condensed Consolidating Statement of Cash Flow (In Millions) (Unaudited)
Six Months Ended June 30, 2013
	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Cash Provided by Operating Activities	$	1,548		$	6		$	1,939		$	(1,768	)	$	1,725
Cash Flows from Investing Activities
Payment to KMI for drop-down asset groups, net of cash acquired (Note 2)	—			—			(994		)	—			(994		)
Acquisitions of assets and investments, net of cash acquired	—			5			(291		)	—			(286		)
Repayments from related party	—			—			—			—			—
Capital expenditures	—			—			(1,268		)	—			(1,268		)
Proceeds from sale of investments in Express pipeline system	—			—			403			—			403
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs	—			—			23			—			23
Contributions to investments	—			—			(93		)	—			(93		)
Distributions from equity investments in excess of cumulative earnings	—			—			36			—			36
Funding from (to) affiliates	(3,690		)	(501		)	(1,178		)	5,369			—
Other, net	5			—			17			—			22
Net Cash Provided by (Used in) Investing Activities	(3,685		)	(496		)	(3,345		)	5,369			(2,157		)
Cash Flows From Financing Activities
Issuance of debt	4,844			—			14			—			4,858
Payment of debt	(3,100		)	(663		)	(97		)	—			(3,860		)
Debt issue costs	(11		)	—			—			—			(11		)
Funding from (to) affiliates	832			1,154			3,383			(5,369		)	—
Proceeds from issuance of common units	834			—			—			—			834
Proceeds from issuance of i-units	73			—			—			—			73
Contributions from noncontrolling interest	—			—			99			—			99
Contributions from General Partner	38			—			—			—			38
Pre-acquisition contributions and distributions from KMI to drop-down asset group	—			—			35			—			35
Cash distributions	(1,468		)	—			(1,768		)	1,768			(1,468		)
Distributions to noncontrolling interests	—			—			(19		)	—			(19		)
Net Cash Provided by (Used in) Financing Activities	2,042			491			1,647			(3,601		)	579
Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—			(20		)	—			(20		)
Net increase (decrease) in Cash and Cash Equivalents	(95		)	1			221			—			127
Cash and Cash Equivalents, beginning of period	95			—			434			—			529
Cash and Cash Equivalents, end of period	$	—		$	1		$	655		$	—		$	656

50

Condensed Consolidating Statement of Cash Flow (In Millions) (Unaudited)
Six Months Ended June 30, 2012
	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Cash Provided by Operating Activities	$	1,195		$	—	$	1,662		$	(1,428	)	$	1,429
Cash Flows from Investing Activities
Payment to KMI for drop-down asset groups, net of cash acquired (Note 2)	—			—		20			—			20
Acquisitions of assets and investments, net of cash acquired	—			—		(30		)	—			(30		)
Repayments from related party	—			—		64			—			64
Capital expenditures	—			—		(801		)	—			(801		)
Proceeds from sale of investments in Express pipeline	—			—		—			—			—
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs	—			—		30			—			30
Contributions to investments	—			—		(86		)	—			(86		)
Distributions from equity investments in excess of cumulative earnings	—			—		86			—			86
Funding from (to) affiliates	(1,203		)	—		(601		)	1,804			—
Other, net	(1		)	—		(20		)	—			(21		)
Net Cash Provided by (Used in) Investing Activities	(1,204		)	—		(1,338		)	1,804			(738		)
Cash Flows From Financing Activities
Issuance of debt	3,438			—		—			—			3,438
Payment of debt	(3,088		)	—		(5		)	—			(3,093		)
Debt issue costs	(5		)	—		—			—			(5		)
Funding from (to) affiliates	601			—		1,203			(1,804		)	—
Proceeds from issuance of common units	277			—		—			—			277
Contributions from noncontrolling interests	—			—		17			—			17
Contributions from parent	—			—		—			—			—
Cash distributions	(1,194		)	—		(1,428		)	1,428			(1,194		)
Distributions to noncontrolling interests	—			—		(15		)	—			(15		)
Net Cash Provided by (Used in) Financing Activities	29			—		(228		)	(376		)	(575		)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—		(2		)	—			(2		)
Net increase (decrease) in Cash and Cash Equivalents	20			—		94			—			114
Cash and Cash Equivalents, beginning of period	1			—		408			—			409
Cash and Cash Equivalents, end of period	$	21		$	—	$	502		$	—		$	523

51

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 2012 Form 10-K; and (iii) our management’s discussion and analysis of financial condition and results of operations included in our 2012 Form 10-K.

We prepared our consolidated financial statements in accordance with GAAP. In addition, as discussed in Note 1 “General” and Note 2 “Acquisitions and Divestitures” to our consolidated financial statements included elsewhere in this report, our financial statements reflect:

• our August 2012 and March 2013 acquisitions of net assets from KMI as if such acquisitions had taken place on the effective dates of common control. We refer to these two separate transfers of net assets from KMI to us as the drop-down transactions, and we refer to the transferred assets as our drop-down asset groups. We accounted for the drop-down transactions as a combination of entities under common control, and accordingly, the financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations include the financial results of the drop-down asset groups for all periods subsequent to the effective dates of common control; and

• the reclassifications necessary to reflect the results of our FTC Natural Gas Pipelines disposal group as discontinued operations. We sold our FTC Natural Gas Pipelines disposal group to Tallgrass effective November 1, 2012 for approximately $1.8 billion in cash (before selling costs), or $3.3 billion including our share of joint venture debt. In the first quarter of 2013, following the final working capital adjustment, we recorded an incremental loss of $2 million related to our sale of the disposal group, and except for this loss amount, we recorded no other financial results from the operations of the disposal group during the first half of 2013. Furthermore, we have excluded the disposal group’s financial results from our Natural Gas Pipelines business segment disclosures for the six months ended June 30, 2012.

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 GAAP 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, 2013. 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” in our 2012 Form 10-K.

52

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

Results of Operations
	Three Months Ended June 30,
	2013			2012			Earnings increase/(decrease)
	(In millions, except percentages)
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Natural Gas Pipelines	$	1,123		$	289		$	834		289	%
CO2	358			327			31			9	%
Products Pipelines	12			166			(154		)	(93	)%
Terminals	207			195			12			6	%
Kinder Morgan Canada	50			52			(2		)	(4	)%
Segment EBDA(b)	1,750			1,029			721			70	%
Depreciation, depletion and amortization expense(c)	(357		)	(276		)	(81		)	(29	)%
Amortization of excess cost of equity investments	(2		)	(2		)	—			—	%
General and administrative expense(d)	(163		)	(171		)	8			5	%
Interest expense, net of unallocable interest income(e)	(215		)	(160		)	(55		)	(34	)%
Unallocable income tax expense	(3		)	(3		)	—			—	%
Income from continuing operations	1,010			417			593			142	%
Loss from discontinued operations(f)	—			(279		)	279			100	%
Net Income	1,010			138			872			632	%
Net Income attributable to noncontrolling interests(g)	(10		)	(6		)	(4		)	(67	)%
Net Income attributable to Kinder Morgan Energy Partners, L.P.	$	1,000		$	132		$	868		658	%

____________

53

Results of Operations
	Six Months Ended June 30,
	2013			2012			Earnings increase/(decrease)
	(In millions, except percentages)
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Natural Gas Pipelines	$	1,680		$	511		$	1,169		229	%
CO2	700			661			39			6	%
Products Pipelines	197			342			(145		)	(42	)%
Terminals	393			382			11			3	%
Kinder Morgan Canada	243			102			141			138	%
Segment EBDA(h)	3,213			1,998			1,215			61	%
Depreciation, depletion and amortization expense(i)	(685		)	(515		)	(170		)	(33	)%
Amortization of excess cost of equity investments	(4		)	(4		)	—			—	%
General and administrative expense(j)	(297		)	(278		)	(19		)	(7	)%
Interest expense, net of unallocable interest income(k)	(417		)	(299		)	(118		)	(39	)%
Unallocable income tax expense	(6		)	(5		)	(1		)	(20	)%
Income from continuing operations	1,804			897			907			101	%
Loss from discontinued operations(l)	(2		)	(551		)	549			100	%
Net Income	1,802			346			1,456			421	%
Net Income attributable to noncontrolling interests(m)	(19		)	(8		)	(11		)	(138	)%
Net Income attributable to Kinder Morgan Energy Partners, L.P.	$	1,783		$	338		$	1,445		428	%

____________

(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) 2013 and 2012 amounts include increases in earnings of $413 million and $118 million, respectively, related to the combined effect from all of the three month 2013 and 2012 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results.

(c) 2012 amount includes a $28 million increase in expense attributable to our drop-down asset groups for periods prior to our acquisition dates.

(d) 2013 and 2012 amounts include increases in expense of$32 million and $73 million, respectively, related to the combined effect from all of the three month 2013 and 2012 certain items related to general and administrative expenses disclosed below in “—Other.”

(e) 2013amount includes a $2 million decrease in expense associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition. 2012 amount includes a $19 million increase in expense attributable to our drop-down asset groups for periods prior to our acquisition dates.

(f) Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.2012 amount includes a $327 million loss from a remeasurement of net assets to fair value.

(g) 2013 and 2012 amounts includeincreases of $3 million and $1 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the three month 2013 and 2012 certain items disclosed below in both our management discussion and analysis of segment results and “—Other.”

(h) 2013 and 2012 amounts include increases in earnings of $600 million and $115 million, respectively, related to the combined effect from all of the six month 2013 and 2012 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results.

(i) 2013 and 2012 amounts include increases in expense of $19 million and $28 million, respectively, attributable to our drop-down asset groups for periods prior to our acquisition dates. Six month 2012 amount also excludes a $7 million expense amount attributable to our FTC Natural Gas Pipelines disposal group.

54

(j) 2013 and 2012 amounts include increases in expense of $46 million and $74 million, respectively, related to the combined effect from all of the six month 2013 and 2012 certain items related to general and administrative expenses disclosed below in “—Other.”

(k) 2013 and 2012 amounts include increases in expense of $15 million and $19 million, respectively, attributable to our drop-down asset groups for periods prior to our acquisition dates. 2013amount also includes a $2 million decrease in expense associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition.

(l) Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.2013 amount represents an incremental loss related to the sale of our disposal group effective November 1, 2012. 2012 amount includes a $649 million loss from a remeasurement of net assets to fair value.

(m) 2013 and 2012 amounts includean increase of $5 million and a decrease of $3 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the six month 2013 and 2012 certain items disclosed below in both our management discussion and analysis of segment results and “—Other.”

Distributable Cash Flow

As more fully described in our 2012 Form 10-K, 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). 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 six month periods ended June 30, 2013 and 2012 is as follows (calculated before the combined effect from all of the certain items disclosed in the footnotes to the tables above):

Distributable Cash Flow
	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Net Income	$	1,010		$	138		$	1,802		$	346
(Less)/Add-back: Certain items - combined (income)/expense(a)	(383		)	329			(520		)	655
Net Income before certain items	627			467			1,282			1,001
Less: Net Income before certain items attributable to noncontrolling interests	(7		)	(5		)	(14		)	(11		)
Net Income before certain items attributable to Kinder Morgan Energy Partners, L.P.	620			462			1,268			990
Less: General Partner’s interest in Net Income before certain items(b)	(418		)	(337		)	(819		)	(658		)
Limited Partners’ interest in Net Income before certain items	202			125			449			332
Depreciation, depletion and amortization(c)(e)	379			292			717			582
Book (cash) taxes paid, net	—			(2		)	12			7
Incremental contributions from equity investments in the Express Pipeline and Endeavor Gathering LLC	(6		)	3			(5		)	3
Sustaining capital expenditures(d)(e)	(70		)	(52		)	(118		)	(96		)
Distributable cash flow (DCF) before certain items	$	505		$	366		$	1,055		$	828

____________

(a) Equal to the combined effect from all of the three and six months 2013 and 2012 certain items disclosed in the footnotes to the “—Results of Operations” tables included above (and described in more detail below in both our management discussion and analysis of segment results and “—Other.”

(b) Three and six month 2013 amounts include reductions of $25 million for waived general partner incentive amounts related to common units issued to finance our May 2013 Copano acquisition. The six month 2013 amount and the three and six month 2012 amounts include reductions of $4 million, $7 million and $13 million, respectively, for waived general partner incentive amounts related to common units issued to finance a portion of our July 2011 KinderHawk acquisition.

55

(c) Three and six month 2013 amounts include expense amounts of$20 million and $47 million, respectively, and three and six month 2012 amounts include expense amounts of$42 million and $84 million, respectively, for our proportionate share of the depreciation, depletion and amortization expenses of our unconsolidated joint ventures. The six month 2013 amount and the three and six month 2012 amounts also exclude expense amounts of $19 million, $28 million and $28 million, respectively, attributable to our drop-down asset groups for periods prior to our acquisition dates. Six month 2012 amount alsoincludes a $7 million expense attributable to our FTC Natural Gas Pipelines disposal group.

(d) Three and six month 2013 amounts and three and six month 2012 amounts include expenditures of $1 million, $1 million, $3 million and $5 million, respectively, for our proportionate share of the sustaining capital expenditures of our unconsolidated joint ventures.

(e) DCF includes our proportionate share of the depreciation, depletion and amortization expenses of our unconsolidated joint ventures, less our proportionate share of the sustaining expenditures of our unconsolidated joint ventures, to more closely track the cash distributions we receive from these joint ventures.

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 (defined in the “—Results of Operations” tables above and sometimes referred to in this report as EBDA) to be an important measure of our success in maximizing returns to our partners.We also use segment 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 quarter periods of 2013 and 2012, total segment EBDA increased $721 million (70%) in 2013; however, this overall increase:

▪ includeda $295 million increase in EBDA from the effect of the certain items referenced in footnote (b) to the “—Results of Operations” tables above (which combined to increase total segment EBDA from continuing operations by $413 million in the second quarter of 2013 and increase segment EBDA from continuing operations by $118 million in the second quarter of 2012); and

▪ excluded a $48 million decrease in quarter-to-quarter EBDA from discontinued operations.

After adjusting for these two items, the remaining $378 million (39%) increase in quarterly segment EBDA resulted from better performance in the second quarter of 2013 from our Natural Gas Pipelines, CO₂, Products Pipelines and Terminals business segments. The quarterly increase in total segment EBDA was partially offset by a slight decrease in EBDA from our Kinder Morgan Canada business segment.

For the comparable six month periods of 2013 and 2012, total segment EBDA increased $1,215 million (61%) in 2013; however, this overall increase:

▪ includeda $485 million increase in EBDA from the effect of the certain items referenced in footnote (h) to the “—Results of Operations” table above (which combined to increase total segment EBDA from continuing operations by $600 million in the first half of 2013 and increase segment EBDA from continuing operations by $115 million in the first half of 2012); and

▪ excluded a $105 million decrease in period-to-period EBDA from discontinued operations.

After adjusting for these two items, the remaining $625 million (31%) increase in segment EBDA resulted from better performance in the first half of 2013 from our Natural Gas Pipelines, Products Pipelines, CO₂ and Terminals business segments. EBDA from our Kinder Morgan Canada business segment was unchanged across the comparable six-month periods.

56

Natural Gas Pipelines

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions, except operating statistics)
Revenues(a)	$	1,696		$	851		$	3,065		$	1,645
Operating expenses(b)	(1,179		)	(598		)	(2,039		)	(1,206		)
Other expense	—			—			—			—
Earnings from equity investments(c)	45			40			93			78
Interest income and Other, net(d)	564			1			565			1
Income tax expense(e)	(3		)	(5		)	(4		)	(7		)
EBDA from continuing operations	1,123			289			1,680			511
Discontinued operations(f)	—			(279		)	(2		)	(544		)
EBDA including discontinued operations	$	1,123		$	10		$	1,678		$	(33	)
Natural gas transport volumes (Bcf)(g)	1,372.5			1,449.5			2,911.9			2,888.2
Natural gas sales volumes (Bcf)(h)	220.0			215.6			432.1			428.4

____________

(a) Six month 2013 amount includes an increase in revenue of $111 million, and three and six month 2012 amounts include an increase in revenue of $158 million, all attributable to our drop-down asset groups for periods prior to our acquisition dates. Three and six month 2013 amounts also include a combined $1 million decrease in revenue related to derivative contracts used to hedge forecasted natural gas, natural gas liquids and crude oil sales.

(b) Six month 2013 amount includes an increase in expense of $30 million, and three and six month 2012 amounts include an increase in expense of $55 million, all attributable to our drop-down asset groups for periods prior to our acquisition dates. Six month 2013 amount also includes a $1 million increase in expense related to hurricane clean-up and repair activities.

(c) Six month 2013 amount includes a decrease in earnings of $19 million, and three and six month 2012 amounts include an increase in earnings of $1 million, all attributable to our drop-down asset groups for periods prior to our acquisition dates. Six month 2013 amount also includes a $1 million decrease in earnings from incremental severance expenses.

(d) Three and six month 2013 amounts include a $558 million gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value.

(e) Three and six month 2012 amounts include an increase in expense of $5 million attributable to our drop-down asset groups for periods prior to our acquisition dates.

(f) Represents EBDA attributable to our FTC Natural Gas Pipelines disposal group. Six month 2013 amount represents a $2 million loss from the sale of net assets. Three and six month 2012 amounts include loss amounts of $327 million and $649 million, respectively, from the remeasurement of net assets to fair value, and also include revenues of $62 million and $133 million, respectively.

(g) Includes pipeline volumes for TransColorado Gas Transmission Company LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC, Fayetteville Express Pipeline LLC, TGP, EPNG, Copano South Texas and the Texas intrastate natural gas pipeline group. Volumes for acquired pipelines are included for all periods.

(h) Represents Texas intrastate natural gas pipeline group volumes.

57

For the three and six months ended June 30, 2013, the certain items described in the footnotes to the table above (i) increased our Natural Gas Pipelines business segment’s EBDA (including discontinued operations) by $785 million and $1,165 million, respectively; and (ii) decreased segment revenues (including discontinued operations) by$159 million and $48 million, respectively, when compared to the same year earlier periods. Following is information related to the increases and decreases, in the comparable three and six month periods of 2013 and 2012 and including discontinued operations, in the segment’s remaining (i) $328 million (138%) and$546 million (106%) increases in EBDA; and (ii) $942 million (125%) and $1,335 million (82%) increases in operating revenues:

Three months ended June 30, 2013 versus Three months ended June 30, 2012
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
TGP	$	185		n/a		$	250		n/a
EPNG	93			n/a		128			n/a
Copano operations	58			n/a		196			n/a
Eagle Ford(a)	22			534	%	70			n/a
El Paso Midstream asset operations	19			n/a		39			n/a
Texas Intrastate Natural Gas Pipeline Group	5			7	%	422			75	%
Kinder Morgan Treating operations	(6		)	(28	)%	(14		)	(33	)%
All others (including eliminations)	—			—	%	(87		)	(108	)%
Total Natural Gas Pipelines-continuing operations	376			197	%	1,004			145	%
Discontinued operations(b)	(48		)	(100	)%	(62		)	(100	)%
Total Natural Gas Pipelines-including discontinued operations	$	328		138	%	$	942		125	%

____________

n/a – not applicable

Six months ended June 30, 2013 versus Six months ended June 30, 2012
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
TGP	$	406		n/a		$	516		n/a
EPNG	139			n/a		173			n/a
Copano operations	58			n/a		196			n/a
Eagle Ford(a)	30			521	%	70			n/a
El Paso Midstream asset operations	30			n/a		53			n/a
Texas Intrastate Natural Gas Pipeline Group	1			—	%	566			46	%
Kinder Morgan Treating operations	(11		)	(28	)%	(16		)	(21	)%
All others (including eliminations)	(2		)	(1	)%	(90		)	(55	)%
Total Natural Gas Pipelines-continuing operations	651			158	%	1,468			99	%
Discontinued operations(b)	(105		)	(100	)%	(133		)	(100	)%
Total Natural Gas Pipelines-including discontinued operations	$	546		106	%	$	1,335		82	%

____________

n/a – not applicable

(a) Equity investment until May 1, 2013. On that date, as part of our Copano acquisition, we acquired the remaining 50% ownership interest that we did not already own. Prior to that date, we recorded earnings under the equity method of accounting, but we received distributions in amounts essentially equal to equity earnings plus depreciation and amortization expenses less sustaining capital expenditures.

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

58

The primary increases and decreases in our Natural Gas Pipelines business segment’s EBDA from continuing operations in the comparable three and six month periods of 2013 and 2012 were attributable to the following:

▪ incremental earnings of $185 million and $406 million, respectively, from our Tennessee Gas Pipeline, which we acquired from KMI effective August 1, 2012;

▪ incremental earnings of $93 million and $139 million, respectively, from our El Paso Natural Gas Pipeline, which we acquired 50% from KMI effective August 1, 2012, and 50% from KMI effective March 1, 2013;

▪ incremental earnings of $58 million and $58 million, respectively, from the operations of Copano, which we acquired effective May 1, 2013 (but excluding Copano’s 50% ownership interest in Eagle Ford; which is included below with the 50% ownership interest we already owned);

▪ incremental earnings of $22 million (534%) and $30 million (521%), respectively, from our total (100%) Eagle Ford natural gas gathering operations, due mainly to the incremental 50% ownership interest we acquired as part of our acquisition of Copano effective May 1, 2013;

▪ incremental earnings of $19 million and $30 million, respectively, from the El Paso midstream assets we acquired 50% from Kohlberg Kravis Roberts & Co. L.P. effective June 1, 2012, and 50% from KMI effective March 1, 2013;

▪ increases of $5 million (7%) and $1 million, respectively, from our Texas intrastate natural gas pipeline group. The increases were driven by higher transport margins (primarily related to Eagle Ford) and lower operating expenses (due mainly to the timing of pipeline integrity expenses), but partially offset by lower natural gas processing margins (due mainly to lower natural gas liquids prices), and for the comparable six month periods, by lower storage margins (due mainly to timing differences on storage settlements). The growth in revenues across both comparable three and six month periods reflect higher natural gas sales revenues, driven by higher natural gas sales prices in the second quarter of 2013, relative to the second quarter of 2012. However, because our intrastate group both purchases and sells significant volumes of natural gas, and because the group generally sells natural gas in the same price environment in which it is purchased, the increases in its natural gas sales revenues were largely offset by corresponding increases in its natural gas purchase costs; and

▪ decreases of $6 million (28%) and $11 million (28%), respectively, from our natural gas treating operations, primarily due to lower margins from treating equipment manufacturing.

The period-to-period decreases in earnings before depreciation, depletion and amortization expenses from discontinued operations was due to the sale of our FTC Natural Gas Pipelines disposal group to Tallgrass effective November 1, 2012. For further information about this sale, see Note 1 “General—Basis of Presentation—FTC Natural Gas Pipelines Disposal Group – Discontinued Operations” to our consolidated financial statements included elsewhere in this report.

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CO₂ 

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions, except operating statistics)
Revenues(a)	$	460		$	413		$	889		$	830
Operating expenses	(107		)	(98		)	(199		)	(185		)
Other income(b)	—			7			—			7
Earnings from equity investments	7			7			13			13
Interest income and Other, net	—			(1		)	—			(1		)
Income tax expense	(2		)	(1		)	(3		)	(3		)
EBDA	$	358		$	327		$	700		$	661
Southwest Colorado CO2 production (gross) (Bcf/d)(c)	1.2			1.2			1.2			1.2
Southwest Colorado CO2 production (net) (Bcf/d)(c)	0.5			0.5			0.5			0.5
SACROC oil production (gross)(MBbl/d)(d)	30.0			28.4			30.4			27.6
SACROC oil production (net)(MBbl/d)(e)	25.0			23.6			25.3			23.00
Yates oil production (gross)(MBbl/d)(d)	20.7			20.8			20.6			21.00
Yates oil production (net)(MBbl/d)(e)	9.2			9.2			9.1			9.3
Katz oil production (gross)(MBbl/d)(d)	2.5			1.8			2.3			1.6
Katz oil production (net)(MBbl/d)(e)	2.1			1.5			1.9			1.4
Natural gas liquids sales volumes (net)(MBbl/d)(e)	9.6			9.5			9.9			9.3
Realized weighted average oil price per Bbl(f)	$	94.20		$	85.96		$	90.55		$	88.25
Realized weighted average natural gas liquids price per Bbl(g)	$	44.17		$	49.44		$	45.36		$	55.22

____________

(a) Three and six month 2013 amounts include unrealized gains of $7 million and $9 million, respectively, and six month 2012 amount includes unrealized losses of $3 million, all relating to derivative contracts used to hedge forecasted crude oil sales.

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

(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 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.

60

The certain items described in footnotes (a) and (b) to the table above (i) increased segment EBDA by $5 million in the first half of 2013, and (ii) increased segment revenues by $7 million and $12 million, respectively, in the second quarter and first half of 2013, when compared to the same periods of 2012. For each of the segment’s two primary businesses, following is information related to the increases and decreases, in the comparable three and six month periods of 2013 and 2012, in the segment’s (i)$31 million (10%) and remaining $34 million (5%) increases in EBDA; and (ii) remaining $40 million (10%) and $47 million (6%) increases in operating revenues:

Three months ended June 30, 2013 versus Three months ended June 30, 2012
	EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing Activities	$	29	13	%	$	40		12	%
Sales and Transportation Activities	2		2	%	2			1	%
Intrasegment eliminations	—		—	%	(2		)	(11	)%
Total CO2	$	31	10	%	$	40		10	%

____________

Six months ended June 30, 2013 versus Six months ended June 30, 2012
	EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing Activities	$	27	6	%	$	45		7	%
Sales and Transportation Activities	7		4	%	6			3	%
Intrasegment eliminations	—		—	%	(4		)	(13	)%
Total CO2	$	34	5	%	$	47		6	%

The growth in earnings across both comparable three and six month periods from our CO₂ business segment was driven by strong second quarter 2013 results from our oil and gas producing activities, largely due to higher crude oil sales revenues. In the comparable three and six month periods of 2013 and 2012, sales revenues from U.S. crude oil increased $45 million (16%) and $56 million (10%), respectively, due to both higher average oil price realizations and higher sales volumes. When compared to the same periods of 2012, our realized weighted average price per barrel of crude oil increased by almost 10% in the second quarter of 2013, and by 3% in the first six months of 2013 (had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $93.51 and $89.32 per barrel in the second quarter and first six months of 2013, respectively, and $87.45 and $93.92 per barrel in the second quarter and first six months of 2012, respectively). The period-to-period increases in oil sales revenues were also favorably impacted by increases in oil sales volumes of 6% and 7%, respectively, due primarily to a general year-over-year increase in production at both the SACROC and Katz field units, and partly to the inclusion of one month of production from the Goldsmith Landreth unit, acquired effective June 1, 2013. Additionally, the overall increases in segment results for the comparable three and six month periods were partially offset by decreases of $4 million (10%) and $11 million (12%), respectively, in plant product sales revenues, due to decreases of 11% and 18%, respectively, in our realized weighted average price per barrel of natural gas liquids.

Earnings before depreciation, depletion and amortization expenses from the segment’s sales and transportation activities were relatively flat across both comparable second quarter periods, but increased by $7 million (4%) in the first half of 2013 versus the first half of 2012. The increase was driven by (i) higher reimbursable project revenues, largely related to the completion of prior expansion projects on the Central Basin pipeline system; (ii) higher CO₂ sales revenues, due to an almost 3% increase in average sales prices; and (iii) higher third party storage revenues at the Yates field unit.

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Products Pipelines

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions, except operating statistics)
Revenues	$	443		$	331		$	897		$	554
Operating expenses(a)	(439		)	(184		)	(720		)	(241		)
Other expense(b)	(5		)	—			(5		)	—
Earnings from equity investments	17			15			35			29
Interest income and Other, net	2			8			2			10
Income tax expense	(6		)	(4		)	(12		)	(10		)
EBDA	$	12		$	166		$	197		$	342
Gasoline (MMBbl)(c)	105.6			99.7			203.4			194.8
Diesel fuel (MMBbl)	36.8			35.8			69.6			69.4
Jet fuel (MMBbl)	27.7			28.8			54.9			55.7
Total refined product volumes (MMBbl)(d)	170.1			164.3			327.9			319.9
Natural gas liquids (MMBbl)(e)	8.0			7.2			17.8			14.6
Condensate (MMBbl)(f)	2.6			—			4.6			—
Total delivery volumes (MMBbl)	180.7			171.5			350.3			334.5
Ethanol (MMBbl)(g)	9.7			7.8			18.4			15.1

____________

(a) Three and six month 2013 amounts include a $162 million increase in expense associated with rate case liability adjustments. Six month 2013 amount also includes a $15 million increase in expense associated with a legal liability adjustment related to a certain West Coast terminal environmental matter.

(b) Three and six month 2013 amounts represent the loss from the write-off of assets at our Los Angeles Harbor West Coast terminal.

(c) Volumes include ethanol pipeline volumes.

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

(e) Includes Cochin and Cypress pipeline volumes.

(f) Includes Crude Oil & Condensate pipeline volumes.

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

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When compared to the same periods of 2012, the certain items described in footnotes (a) and (b) to the table above decreased our Products Pipelines business segment’s EBDA by $167 million and $182 million, respectively, in the second quarter and first six months of 2013. Following is information related to the increases and decreases, in the comparable three and six month periods of both years, in the segment’s (i) remaining $13 million (8%) and $37 million (11%) increases in EBDA; and (ii) $112 million (34%) and $343 million (62%) increases in operating revenues:

Three months ended June 30, 2013 versus Three months ended June 30, 2012
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Transmix operations	$	9		216	%	$	96		80	%
Southeast terminal operations	3			20	%	5			21	%
Crude & Condensate Pipeline	1			82	%	5			n/a
Plantation Pipeline	1			9	%	—			n/a
Cochin Pipeline	(1		)	(6	)%	7			47	%
Pacific operations	(6		)	(9	)%	(4		)	(4	)%
All others (including eliminations)	6			12	%	3			5	%
Total Products Pipelines	$	13		8	%	$	112		34	%

____________

Six months ended June 30, 2013 versus Six months ended June 30, 2012
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Transmix operations	$	15		431	%	$	308		234	%
Cochin Pipeline	13			39	%	20			59	%
Crude & Condensate Pipeline	4			149	%	10			n/a
Plantation Pipeline	3			12	%	—			n/a
Southeast terminal operations	3			9	%	6			12	%
Pacific operations	(7		)	(5	)%	(5		)	(2	)%
All others (including eliminations)	6			6	%	4			3	%
Total Products Pipelines	$	37		11	%	$	343		62	%

The primary increases and decreases in our Products Pipelines business segment’s EBDA in the comparable three and six month periods of 2013 and 2012 included the following:

▪ increases of $9 million (216%) and $15 million (431%), respectively, from our transmix processing operations. The increases were driven by (i) higher margins on processing volumes, due mainly to favorable pricing; (ii) incremental earnings from third-party sales of excess renewable identification numbers (RINS), generated through our ethanol blending operations; and (iii) incremental income due to the recognition of unfavorable net carrying value adjustments to product inventory in the first half of 2012. The period-to-period increases in revenues were due mainly to the expiration of certain transmix fee-based processing agreements since the second quarter of 2012. Due to the expiration of these contracts, we now directly purchase incremental transmix volumes and sell incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;

▪ increases of $3 million (20%) and $3 million (9%), respectively, from our Southeast terminal operations, driven by higher margins from ethanol blending operations, and higher revenues from both butane blending and refined products and bio-fuels throughput volumes;

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▪ incremental earnings of $1 million (82%) and $4 million (149%), respectively, from our Kinder Morgan Crude Oil & Condensate Pipeline, which began transporting crude oil and condensate volumes from the Eagle Ford shale gas formation in South Texas to multiple terminaling facilities along the Texas Gulf Coast in October 2012;

▪ increases of $1 million (9%) and $3 million (12%), respectively, from our approximate 51% interest in the Plantation pipeline system—due largely to higher transportation revenues driven by increases in system delivery volumes of 9% and 10%, respectively, and by higher average tariff rates since the end of the second quarter of 2012;

▪ a decrease of $1 million (6%) and an increase of $13 million (39%), respectively, from our Cochin Pipeline. The quarter-to-quarter decrease was due mainly to lower non-operating income, resulting from the favorable settlement of a pipeline access dispute in the second quarter of 2012. However, earnings increased across both the comparable three and six month periods due to increases in operating revenues, driven by increases in pipeline throughput volumes of 10% and 55%, respectively, which includes incremental ethane/propane volumes as a result of pipeline modification projects completed in June 2012; and

▪ decreases of $6 million (9%) and $7 million (5%), respectively, from our Pacific operations, primarily attributable to a reduction in mainline transportation revenues recorded in the the second quarter of 2013. The reduction in transport revenues related to rate reductions associated with various interstate and California intrastate rate case decisions.

Terminals

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions, except operating statistics)
Revenues	$	344		$	343		$	681		$	684
Operating expenses(a)	(169		)	(164		)	(326		)	(324		)
Other income(b)	29			13			29			13
Earnings from equity investments	5			5			12			11
Interest income and Other, net(c)	1			1			2			1
Income tax expense	(3		)	(3		)	(5		)	(3		)
EBDA	$	207		$	195		$	393		$	382
Bulk transload tonnage (MMtons)(d)	22.0			25.7			44.0			49.8
Ethanol (MMBbl)	15.6			16.3			30.8			34.2
Liquids leaseable capacity (MMBbl)	62.1			60.4			62.1			60.4
Liquids utilization %(e)	94.2		%	92.2		%	94.2		%	92.2		%

__________

(a) Three and six month 2013 amounts include increases in expense of $13 million and $14 million, respectively, related to hurricane clean-up and repair activities at our New York Harbor and Mid-Atlantic terminals.

(b) Three and six month 2013 amounts include a $28 million casualty indemnification gain related to 2012 hurricane activity at our New York Harbor and Mid-Atlantic terminals. Three and six month 2012 amounts include a $12 million casualty indemnification gain related to a 2010 casualty at our Myrtle Grove, Louisiana, International Marine Terminal Facility.

(c) Three and six month 2013 amounts include a $1 million casualty indemnification gain related to 2012 hurricane activity at our New York Harbor and Mid-Atlantic terminals.

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

(e) The ratio of our actual leased capacity to our estimated potential capacity.

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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 months ended June 30, 2013, the certain items described in footnotes (a), (b) and (c) to the table above increased segment EBDA by $4 million and $3 million, respectively, when compared to the same two periods of 2012. Following is information related to the increases and decreases, in the comparable three and six month periods of both years, in the segment’s (i) remaining $8 million (4%) and $8 million (2%) increases in EBDA; and (ii) $1 million (0%) increase and $3 million (0%) decrease, respectively, in operating revenues:

Three months ended June 30, 2013 versus Three months ended June 30, 2012
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Gulf Liquids	$	7		13	%	$	9		16	%
Northeast	2			12	%	1			2	%
Gulf Bulk	2			13	%	1			3	%
Mid-Atlantic	(5		)	(23	)%	(8		)	(19	)%
All others (including intrasegment eliminations and unallocated income tax expenses)	2			2	%	(2		)	(1	)%
Total Terminals	$	8		4	%	$	1		—	%

____________

Six months ended June 30, 2013 versus Six months ended June 30, 2012
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Gulf Liquids	$	8		8	%	$	13		11	%
Northeast	4			10	%	1			1	%
West	3			10	%	4			8	%
Mid-Atlantic	(5		)	(11	)%	(7		)	(10	)%
Gulf Bulk	(1		)	(2	)%	(5		)	(7	)%
All others (including intrasegment eliminations and unallocated income tax expenses)	(1		)	(1	)%	(9		)	(3	)%
Total Terminals	$	8		2	%	$	(3	)	—	%

For both comparable three and six month periods, the overall increases in earnings before depreciation, depletion and amortization from our Terminals segment were driven by incremental contributions from our Gulf Liquids terminals, which primarily store and transfer refined petroleum products and petrochemicals along the U.S. Gulf Coast. The increases in earnings were largely related to higher liquids warehousing revenues from our Pasadena, Texas liquids facility, mainly due to high gasoline export demand and to new and incremental customer agreements at higher rates. For all terminals included in our Terminals business segment, total liquids leaseable capacity increased to 62.1 million barrels at the end of the second quarter of 2013, up 3% from a capacity of 60.4 million barrels at the end of the second quarter of 2012. The increase was mainly due to the acquisition of our Norfolk and Chesapeake, Virginia facilities from Allied Terminals in June 2013. At the same time, our overall liquids utilization capacity rate increased 2% since the end of the second quarter of 2012.

The period-to-period increases in earnings from our Northeast terminal operations were driven by incremental contributions from our Carteret and Perth Amboy New Jersey liquids facilities. Carteret benefited primarily from higher non-operating income in the second quarter of 2013, due to insurance indemnifications received for 2012 terminal business interruptions caused by Hurricane Sandy. Our Perth Amboy terminal benefited from higher revenues, due mainly to additional and restructured customer contracts at higher rates.

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Earnings from our Gulf Bulk terminals increased in the second quarter of 2013, but decreased slightly in the first half of the year, when compared to the same year-earlier periods. The quarter-to-quarter increase was chiefly due to higher revenues from our Port of Houston facility, driven by a 59% increase in coal transfer volumes due primarily to additional customer business. The year-over-year decrease in earnings was driven by lower volumes from petroleum coke handling operations, due in large part to refinery and coker shutdowns as a result of turnarounds taken in the first half of 2013.

Earnings from our West region terminals were flat across the comparable three month periods, but increased across the comparable six month periods mainly due to higher revenues from our North 40 Edmonton, Canada crude oil tank farm. The increase related primarily to incremental ancillary terminal services.

The overall increases in segment earnings before depreciation, depletion and amortization in both comparable three and six month periods were partially offset by lower earnings in the second quarter of 2013 from our Mid-Atlantic terminal facilities, due primarily to lower coal transfer volumes. For all terminals combined, overall coal volumes decreased by 21% in the second quarter of 2013 and by 12% in the first half of 2012, when compared to the same year-earlier periods. The decreases were due largely to some weakening in the coal export market, relative to prior periods, and partly to scheduled maintenance at our Newport News, Virginia Pier IX facility in the second quarter of 2013.

Kinder Morgan Canada

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions, except operating statistics)
Revenues	$	75		$	73		$	147		$	146
Operating expenses	(27		)	(23		)	(52		)	(47		)
Earnings from equity investments	—			1			4			2
Interest income and Other, net(a)	11			4			241			7
Income tax expense(b)	(9		)	(3		)	(97		)	(6		)
EBDA	$	50		$	52		$	243		$	102
Transport volumes (MMBbl)(c)	26.8			26.9			53.6			51.8

__________

(a) Six month 2013amount includes a $225 million gain from the sale of our equity and debt investments in the Express pipeline system.

(b) Six month 2013 amount includes an $84 million increase in expense related to the gain associated with the sale of our equity and debt investments in the Express pipeline system described in footnote (a).

(c) Represents Trans Mountain pipeline system volumes.

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Our Kinder Morgan Canada business segment includes the operations of our Trans Mountain and Jet Fuel pipeline systems, and until March 14, 2013, the effective date of sale, our one-third ownership interest in the Express crude oil pipeline system. The certain items relating to our sale of Express (described in the footnotes (a) and (b) to the table above) increased segment EBDA by $141 million in the first half of 2013, when compared to the first half of 2012. For each of the segment’s three primary businesses, following is information related to both the remaining changes in EBDA and the increases in revenues in the comparable three and six month periods of 2013 and 2012:

Three months ended June 30, 2013 versus Three months ended June 30, 2012
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Express Pipeline(a)	$	1		22	%	n/a		n/a
Trans Mountain Pipeline	(3		)	(5	)%	$	2	3	%
Jet Fuel Pipeline	—			—	%	—		—	%
Total Kinder Morgan Canada	$	(2	)	(4	)%	$	2	3	%

__________

Six months ended June 30, 2013 versus Six months ended June 30, 2012
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Express Pipeline(a)	$	2		27	%	n/a		n/a
Trans Mountain Pipeline	(2		)	(2	)%	$	1	1	%
Jet Fuel Pipeline	—			—	%	—		—	%
Total Kinder Morgan Canada	$	—		—	%	$	1	1	%

__________

(a) Equity investment; accordingly, we record earnings under the equity method of accounting. However, we sold our debt and equity investments in Express effective March 14, 2013.

Earnings before depreciation, depletion and amortization expenses from our Kinder Morgan Canada business segment were essentially unchanged across both comparable three and six month periods of 2013 and 2012. The period-to-period decreases in Trans Mountain’s earnings before depreciation, depletion and amortization expenses were mainly due to higher income tax expenses in the second quarter of 2013, largely related to general increases in British Columbia’s income tax rates since the end of the second quarter of 2012. The higher tax expenses more than offset incremental non-operating income from both allowances for funds used during construction (representing an estimate of the cost of capital funded by equity contributions) and higher management incentive fees earned from the operation of the Express pipeline system prior to its sale.

Earnings from our equity investment in the Express pipeline system were essentially flat across the comparable second quarter periods, as higher foreign currency gains offset lower equity earnings and lower interest income (due to the sale of our equity and debt investments in Express). The increase in earnings across the comparable six month periods was primarily due to higher currency gains (on both higher U.S. denominated cash balances and Express’ outstanding, short-term, intercompany borrowings payable in U.S. dollars), and partly due to higher equity earnings as a result of both Canadian and U.S. delivery volumes on the Express portion of the system moving at higher transportation rates in the first quarter of 2013, relative to the first quarter of 2012.

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Other

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In millions)
General and administrative expenses(a)	$	163	$	171	$	297	$	278
Interest expense, net of unallocable interest income(b)	$	215	$	160	$	417	$	299
Unallocable income tax expense	$	3	$	3	$	6	$	5
Net income attributable to noncontrolling interests(c)	$	10	$	6	$	19	$	8

__________

(a) Three and six month 2013 amounts include (i) increases in expense of $28 million and $32 million, respectively, associated with unallocated legal expenses and certain asset and business acquisition costs; and (ii) increases in severance expense of $4 million and $5 million, respectively, associated with the asset drop-down groups and allocated to us from KMI (however, we do not have any obligation, nor did we pay any amounts related to this expense). Six month 2013 amount also includes a $9 million increase in expense attributable to our drop-down asset groups for periods prior to our acquisition dates. Three and six month 2012 amounts include an increase in expense of $73 million attributable to our drop-down asset groups for periods prior to our acquisition dates. Six month 2012 amount also includes a $1 million increase in unallocated severance expense associated with certain Terminal operations.

(b) Three and six month 2013 amounts include a $2 million decrease in interest expense associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition. Six month 2013 amount also includes a $15 million increase in interest expense, and three and six month 2012 amounts include a $19 million increase in interest expense, all attributable to our drop-down asset groups for periods prior to our acquisition dates.

(c) Three and six month 2013 amounts include increases of $3 million and $5 million, respectively, in net income attributable to our noncontrolling interests, and the three and six month 2012 amounts include an increase of $1 million and a decrease of $3 million, respectively, in net income attributable to our noncontrolling interests, all related to the combined effect from all of the three and six month 2013 and 2012 certain items previously disclosed in the footnotes to the tables included above in “—Results of Operations.”

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, employee benefits, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services—including accounting, information technology, human resources and legal services.

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 basis of our ownership structure, we do not specifically allocate our general and administrative expenses to our business segments. As discussed previously, we use segment EBDA internally as a measure of 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 three and six months ended June 30, 2013, the certain items described in footnote (a) to the table above accounted for decreases of $41 million and $28 million, respectively, in our general and administrative expenses, when compared to the same two periods a year ago. The remaining $33 million (34%) and $47 million (23%) period-to-period increases in expense were driven by the acquisition of additional businesses, primarily associated with the acquisition of both our drop-down asset groups from KMI, effective August 1, 2012 and March 1, 2013, and our acquisition of Copano, effective May 1, 2013.

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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, and after taking into effect the certain items described in footnote (b) to the table above, our net interest expense increased $76 million (54%) and $124 million (44%), respectively, in the second quarter and first six months of 2013, when compared to the same year-earlier periods. The increases were due to both higher average debt levels and higher effective interest rates.

For the three and six months ended June 30, 2013, our average debt balance increased by 25% and 23%, respectively, when compared to the same prior year periods. The increases were largely due to the capital expenditures, business acquisitions (including debt assumed from the drop-down transactions), and joint venture contributions we have made since the end of the second quarter of 2012. We also realized increases of 9% and 8%, respectively, in the weighted average interest rate on all of our borrowings in the second quarter and first half of 2013, when compared to the same 2012 periods (including both short-term and long-term borrowing amounts, our average interest rate increased from 4.27% for the second quarter of 2012to4.64% for the second quarter of 2013, and increased from 4.25% for the first half of 2012to4.61% for the first half of 2013). The increases were driven by higher interest rates on the debt obligations we assumed as part of the drop-down transactions.

We swap a portion of 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 30, 2013 and December 31, 2012, approximately31% and 37%, respectively, of our consolidated debt balances (excluding our debt fair value adjustments) were 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 swap agreements. For more information about our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements included elsewhere in this report.

Financial Condition

General

As of June 30, 2013, we had $656 million of “Cash and cash equivalents” on our consolidated balance sheet (included elsewhere in this report), an increase of $127 million (24%) from December 31, 2012. We also had, as of June 30, 2013, approximately$1.1 billion of borrowing capacity available under our $2.7 billion senior unsecured revolving credit facility (discussed below in “—Short-term Liquidity”). We believe our cash position and our remaining borrowing capacity is adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

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.

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.

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

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Credit Ratings and Capital Market Liquidity

Currently, our long-term corporate debt credit rating is BBB (stable), Baa2 (stable) and BBB (stable), at S&P, Moody’s and Fitch, respectively. 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 S&P, Moody’s and Fitch, 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. 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 30, 2013, our principal sources of short-term liquidity were (i) our $2.7 billion senior unsecured revolving credit facility with a diverse syndicate of banks that matures May 1, 2018 (which replaced our previous $2.2 billion senior unsecured revolving bank credit facility that was due July 1, 2016); (ii) our $2.7 billion short-term commercial paper program (which is supported by our credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings and letters of credit); and (iii) cash from operations (discussed below in “—Operating Activities”). The loan commitments under our revolving credit facility can be used to fund borrowings for general partnership purposes and as a backup for our commercial paper program. As of both June 30, 2013 and December 31, 2012, we had no outstanding credit facility borrowings.

Our outstanding short-term debt as of June 30, 2013 was $1,899 million, primarily consisting of (i) $1,369 million of outstanding commercial paper borrowings; and (ii) $500 million in principal amount of 5.00% senior notes that mature December 15, 2013. We intend to refinance our current short-term debt through 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, 2012, our short-term debt totaled $1,155 million.

We had a working capital deficit of$2,021 million as of June 30, 2013, and a working capital deficit of $870 million as of December 31, 2012.  The overall$1,151 million (132%) unfavorable change from year-end 2012 was primarily due to (i) a $744 million increase in short-term debt, due primarily to higher net commercial paper borrowings; and (ii) a $485 million increase in “Accrued other current liabilities,” due largely to certain transportation rate case liabilities being reclassified from long-term liabilities to short-term liabilities. 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 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 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 of 2013, see Note 4 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report.

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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. As of June 30, 2013 and December 31, 2012, the aggregate principal amount of the various series of our senior notes was $14,350 million and $13,350 million, respectively.

In addition, from time to time our subsidiaries TGP, EPNG and Copano have issued long-term debt securities, often referred to as their senior notes. As of June 30, 2013 and December 31, 2012, the total liability balance due on the various borrowings of our operating partnerships and subsidiaries (including senior notes issued by TGP, EPNG and Copano) was $3,518 million and$3,091 million, respectively.

As of June 30, 2013, the outstanding borrowings of Copano consist of a single series of unsecured senior notes with an aggregate principal amount of $510 million. The notes mature on April 1, 2021. The notes have a fixed annual stated interest rate of 7.125%, and interest is payable semiannually on April 1 and October 1 of each year. As part of our Copano purchase price, we valued the debt equal to $589 million as of May 1, 2013, representing the present value of amounts to be paid determined using an approximate interest rate of 4.79%. Additionally, the indenture governing the notes contains several options that allow Copano to redeem all or part of the notes prior to the stated maturity. One such option provides that at any time prior to April 1, 2014, Copano may redeem up to 35% of the aggregate principal amount of the notes at a redemption price of 107.125% of the principal amount, plus accrued and unpaid interest, with proceeds Copano receives from equity offerings. Copano expects to exercise this option sometime in the third quarter of 2013, and following its exercise, to redeem 35% of the aggregate principal amount of the notes ($179 million). Currently, we expect that Copano will fund this redemption with net cash proceeds it receives from the sale of additional membership interests to us. Other indenture provisions allow Copano to redeem all or part of the notes, together with accrued and unpaid interest, (i) at any time prior to April 1, 2016 at a stated make-whole redemption price; or (ii) on or after April 1, 2016 at stated redemption prices. Furthermore, if Copano sells certain of its assets or experiences specific kinds of changes of control, Copano must offer to repurchase the notes.

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 half of 2013 and our consolidated debt obligations as of June 30, 2013 and December 31, 2012, see Note 3 “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 2012 Form 10-K.

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.

Capital Expenditures

We define sustaining capital expenditures as capital expenditures which do not increase the capacity of an asset and generally, we fund our sustaining capital expenditures with existing cash or from cash flows from operations. For the first six months of 2013 and 2012, our sustaining capital expenditures totaled $118 million and$96 million, respectively (these 2013 and 2012 amounts included $1 million and $5 million, respectively, for our proportionate share of the sustaining capital expenditures of our unconsolidated joint ventures). As of June 30, 2013, we have forecasted$348 million for sustaining capital expenditures for the full year 2013. This forecasted amount includes expenditures associated with the assets we acquired from KMI effective March 1, 2013 (the March 2013 drop-down asset group), and also includes$4 million for our proportionate share of our unconsolidated joint ventures’ sustaining capital expenditures.

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In addition to the sustaining capital expenditures described above (excluding our proportionate share of the 2013 and 2012 sustaining capital expenditures of our unconsolidated joint ventures), our consolidated statements of cash flows for the six months ended June 30, 2013 and 2012 included capital expenditures of$1,151 million and$710 million, respectively. We report our total consolidated 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 overall$467 million (58%) period-to-period increase in our consolidated capital expenditures in 2013 versus 2012 was primarily due to higher investment undertaken to expand and improve our Terminals, Natural Gas Pipelines and CO₂business segments. Generally, we initially fund our capital expenditures through borrowings under our commercial paper program or our revolving credit facility until the amount borrowed is of a sufficient size to cost effectively offer either debt, equity, or both.

Capital Requirements for Recent Transactions

In the first half of 2013, our cash outlays for the March 2013 drop-down transaction totaled $994 million and we reported this amount separately as “Cash Flows From Investing Activities—Payment to KMI for drop-down asset groups, net of cash acquired” on our accompanying consolidated statement of cash flows included elsewhere in this report. We funded the $994 million cash portion of this drop-down transaction with proceeds received from (i) our February 2013 issuance of long-term senior notes; (ii) our February 2013 public offering of additional common units; and (iii) borrowings under our commercial paper program. In the first half of 2012, we realized a combined $20 million increase in cash resulting from the drop-down groups’ cash balances we acquired on the effective dates of common control.

In the first half of 2013, we issued an aggregate consideration of(i) $108 million in common units to KMI as partial payment for the March 2013 drop-down asset group; and (ii) $3,733 million in common units as payment for all of Copano’s outstanding units. We reported this combined $3,841 million amount separately as “Noncash Investing and Financing Activities—Assets acquired or liabilities settled by the issuance of common units” on our accompanying consolidated statement of cash flows included elsewhere in this report.

Our cash outlays for the acquisition of assets and investments from unrelated parties during the first half of 2013 totaled$286 million, and we reported this amount separately as “Cash Flows From Investing Activities—Acquisitions of assets and investments, net of cash acquired” on our accompanying consolidated statement of cash flows included elsewhere in this report. This amount primarily consisted of the $280 million we paid on June 1, 2013 to acquire the Goldsmith-Landreth oil field unit in the Permian Basin area of West Texas. In the first half of 2012, our acquisitions of assets totaled $30 million, representing the amount we paid to a subsidiary of Enhanced Oil Resources to acquire a CO₂ source field and related assets located in Apache County, Arizona, and Catron County, New Mexico. We utilized our commercial paper program to fund our 2013 and 2012 strategic acquisitions.

For more information about our asset acquisitions during the first six months of 2013, including our acquisitions from KMI, see Note 2 “Acquisitions and Divestitures—Acquisitions” to our consolidated financial statements included elsewhere in this report.

Additional Capital Requirements

In April 2012, we announced that we were proceeding 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 890,000 barrels per day. In 2012, we confirmed binding commercial support for this project, and in May 2013, Canada’s National Energy Board (NEB) approved the commercial terms of the expansion project. We expect to file a Facilities Application with the NEB in late 2013, for authorization to build and operate the necessary facilities for the proposed expansion project. Failure to secure NEB approval of this project at a reasonable toll rate could require us to either delay or cancel this project; however, if approvals are received as planned, we expect to begin construction in 2015 or 2016, with the proposed project beginning operations in late 2017. Our current estimate of total construction costs on the project is approximately$5.4 billion.

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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. For the year 2013, we expect to invest approximately $4 billion for our capital expansion program, which includes small acquisitions and contributions to joint ventures, but excludes the March 2013 drop-down from KMI and the acquisition of Copano.

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 MLP, we distribute all of our available cash (except to the extent that we retain cash from the payment of distributions on i-units in additional i-units) 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$1,725 million for the six months ended June 30, 2013, versus$1,429 million for the same comparable period of 2012. The period-to-period increase of$296 million (21%) in cash flow from operations was primarily due to the following:

▪ a $364 million increase in cash from overall higher partnership income—after adjusting our period-to-period $1,456 million increase in net income for the following four non-cash items: (i) a combined $1,207 million decrease from higher net gains from the remeasurement of net assets to fair value; (ii) a $225 million decrease from the 2013 gain on the sale of our investments in Express (we reported the proceeds received from this sale within the operating activities section of our statement of cash flows); (iii) a $177 million increase from incremental expenses recorded in the first half of 2013 associated with adjustments to both our West Coast Products Pipelines’ interstate and California intrastate transportation rate case liabilities and our West Coast terminals’ legal liabilities; and (iv) a $163 million increase due to higher depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments).

The period-to-period change in partnership income in 2013 versus 2012 is discussed above in “—Results of Operations” (including all of the certain items disclosed in the associated table footnotes). Our net asset remeasurements and the sale of our investments in Express are all discussed further in Note 2 “Acquisitions and Divestitures” to our consolidated financial statements included elsewhere in this report;

▪ a $54 million increase in cash attributable to a payment made in May 2012 to various shippers on our Calnev Pipeline. The payment settled various transportation rate challenges filed by the shippers with the FERC;

▪ a $43 million increase in cash from interest rate swap termination payments. In the first six months of 2013 and 2012, we received proceeds of $96 million and $53 million, respectively, for the early termination of various fixed-to-variable interest rate swap agreements;

▪ a combined $115 million decrease in cash due to unfavorable changes in (i) the collection and payment of trade and related party receivables and payables; (ii) the collection and payment on natural gas transportation and exchange imbalance receivables and payables; and (iii) net changes in cash book overdrafts (resulting from timing differences on checks issued but not yet presented for payment). The combined decrease in cash was due primarily to the timing of invoices received from customers and paid to vendors and suppliers; and

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▪ a $36 million decrease in cash due to lower net dock premiums and toll collections received from our Trans Mountain pipeline system customers—due to lower shipper bids for dock space, driven by market price conditions.

Investing Activities

Net cash used in investing activities was$2,157 million for the six month period ended June 30, 2013, compared to $738 million in the comparable 2012 period. The overall$1,419 million (192%) decrease in cash from investing activities primarily consisted of the following:

▪ a $1,014 million decrease from our net cash outlays as partial payment for the drop-down asset groups (net of cash acquired), as described above in “—Capital Requirements for Recent Transactions;”

▪ a $467 million decrease in cash due to higher capital expenditures, as described above in “—Capital Expenditures;”

▪ a $256 million decrease in cash due to higher expenditures for the acquisition of assets and investments from unrelated parties, as described above in “—Capital Requirements for Recent Transactions;” and

▪ a $403 million increase in cash from the proceeds we received in March 2013 from the sale of our investments in the Express pipeline system.

Financing Activities

Net cash provided by financing activities amounted to $579 million for the six months ended June 30, 2013. In the comparable prior year period, we used $575 million in cash from financing activities. The $1,154 million (201%) overall increase in cash from the comparable 2012 period was mainly due to the following:

▪ a $647 million 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 $947 million increase due to higher short-term net borrowings made under our commercial paper program; (ii) a combined $447 million increase due to higher net issuances of our senior notes (in the first half of 2013, we generated proceeds of $991 million from the issuance of senior notes, and in the first half of 2012, we generated net cash proceeds of $544 million from both issuing and repaying senior notes); (iii) a $404 million decrease due to the immediate repayment of all of the outstanding borrowings under Copano’s bank credit facility that we assumed on the May 1, 2013 acquisition date; (iv) a $259 million decrease from the June 1, 2013 redemption and retirement of the principal amount of Copano’s 7.75% senior notes; and (v) a $78 million decrease related to the net repayment of all of the outstanding borrowings under the midstream assets’ bank credit facility that we assumed on the March 1, 2013 acquisition date;

▪ a $630 million increase in cash due to higher partnership equity issuances. This increase reflects the $907 million we received, after commissions and underwriting expenses, from the sales of additional common units and i-units in the first half of 2013 (discussed in Note 4 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report), versus the$277 million we received from the sales of additional common units in the first half of 2012;

▪ an $82 million increase in cash due to higher net contributions from noncontrolling interests, chiefly due to the $73 million of contributions we received from our BOSTCO partners in the first half of 2013 for their proportionate share of the joint venture’s oil terminal construction costs; and

▪ a $278 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 $1,487 million in the first half of 2013, compared to $1,209 million in the first six months of 2012. The increase in distributions was due to increases in the per unit cash distributions paid, the number of outstanding units, and the resulting increase in our general partner incentive distributions. Further information regarding our distributions is discussed following in “—Partnership Distributions.”

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Partnership Distributions

Our partnership agreement requires that we distribute 100% of “Available Cash,” as defined in our partnership agreement, to our partners within 45 days following the end of each calendar quarter. Our 2012 Form 10-K contains 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 quarters of 2013 and 2012 (for the first quarterly periods of 2013 and 2012, respectively), see Note 4 “Partners’ Capital—Income Allocation and Declared Distributions” to our consolidated financial statements included elsewhere in this report.

Furthermore, on July 17, 2013, we declared a cash distribution of $1.32 per unit for the second quarter of 2013 (an annualized rate of $5.28 per unit). This distribution is 7% higher than the $1.23 per unit distribution we made for the second quarter of 2012. Based on our declared distribution, the number of units outstanding and our general partner’s agreement to forgo $25 million of its cash distribution in conjunction with our Copano acquisition, our declared distribution for the second quarter of 2013 of $1.32 per unit will result in an incentive distribution to our general partner of $416 million.

Comparatively, our distribution of $1.23 per unit paid on August 14, 2012 for the second quarter of 2012 resulted in an incentive distribution payment to our general partner in the amount of $337 million (and included the effect of a waived incentive distribution amount of$7 million related to our July 2011 KinderHawk acquisition). The increased incentive distribution to our general partner for the second quarter of 2013 over the incentive distribution for the second quarter of 2012 reflects the increase in the distribution per unit as well as the issuance of additional units. For additional information about our second quarter 2013 cash distribution, see Note 4 “Partners’ Capital—Subsequent Events” to our consolidated financial statements included elsewhere in this report. For additional information about our 2012 partnership distributions, see Note 16 “Litigation, Environmental and Other Contingencies” and Note 17 “Regulatory Matters” to our consolidated financial statements included in our 2012 Form 10-K.

On May 13, 2013, we announced an increase in the amount of cash distributions we expect to declare for the year 2013. Currently, we expect to declare cash distributions of $5.33 per unit for 2013, up from our 2013 published annual budget amount of $5.28 per unit. The increase was primarily based on projected contributions from our Copano acquisition, which closed on May 1, 2013. We expect the Copano acquisition to be modestly accretive to us in 2013, given the partial year, and due to additional cost savings, we now estimate the incremental impact from Copano to be slightly higher than our initial projections at the time we announced the acquisition. Our current expected distributions of $5.33 per unit represent a 7% increase over our cash distributions of $4.98 per unit for 2012. We expect the Copano acquisition to be approximately $0.10 per unit accretive to us for at least the next five years beginning in 2014. Please read “Information Regarding Forward-Looking Statements” below.

Additionally, as a result of our Copano acquisition, our general partner has agreed to forego $75 million of its incremental incentive distributions in 2013 (foregoing equal amounts of $25 million from each of its second, third and fourth quarter incentive distribution amounts), and intends to forgo incentive distribution amounts of $120 million in 2014, $120 million in 2015, $110 million in 2016, and annual amounts thereafter decreasing by $5 million per year from the 2016 level.

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 2013 budget assumes an average WTI crude oil price of approximately $91.68 per barrel (with some minor adjustments for timing, quality and location differences) in 2013, 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 2013 budget), we currently expect the average price of WTI crude oil will be approximately$96.36 per barrel in 2013. For 2013, 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 on a full year basis (or approximately 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 2012.

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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, 2012 in our 2012 Form 10-K.

Recent Accounting Pronouncements

Please refer to Note 11 “Recent Accounting Pronouncements” to our consolidated financial statements included elsewhere in this report for information concerning recent accounting pronouncements.

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” in our 2012 Form 10-K 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 2012 Form 10-K. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Because of these risks and uncertainties, you should not place undue reliance on any forward-looking statement. We plan to provide updates to projections included in this report when we believe previously disclosed projections no longer have a reasonable basis.

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, 2012, in Item 7A in our 2012 Form 10-K. For more information on our risk management activities, see Note 5 “Risk Management” to our consolidated financial statements included elsewhere in this report.

Item 4. Controls and Procedures.

As of June 30, 2013, 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 over financial reporting during the quarter ended June 30, 2013 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 9 to our consolidated financial statements entitled “Litigation, Environmental and Other Contingencies,” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in or additions to the risk factors disclosed in Part I, Item 1A “Risk Factors” in our 2012 Form 10-K.

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

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures

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.

None.

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Item 6. Exhibits.

4.1 —	Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K (17 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.
*10.2 —	Amended and Restated Credit Agreement dated as of May 1, 2013, among Kinder Morgan Energy Partners, L.P.; Kinder Morgan Operating L.P. “B”; the lenders party thereto; and Wells Fargo Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on May 1, 2013 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 months ended June 30, 2013 and 2012; (ii) our Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2013 and 2012; (iii) our Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012; (iv) our Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012; (v) our Consolidated Statements of Partners’ Capital for the six months ended June 30, 2013 and 2012; and (vi) 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.

Date: July 29, 2013	By:	/s/ Kimberly A. Dang
		Kimberly A. Dang Vice President and Chief Financial Officer (principal financial and accounting officer)

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