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, 2014

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 325,113,505 common units outstanding as of July 25, 2014.

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES TABLE OF CONTENTS
		Page Number
	Glossary	2
	Information Regarding Forward-Looking Statements	3
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2014 and 2013	4
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2014 and 2013	5
	Consolidated Balance Sheets – June 30, 2014 and December 31, 2013	6
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2014 and 2013	7
	Consolidated Statements of Partners’ Capital – Six Months Ended June 30, 2014 and 2013	8
	Notes to Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation	38
	Critical Accounting Policies and Estimates	39
	Results of Operations	39
	Financial Condition	53
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	58
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	59
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 3.	Defaults Upon Senior Securities	59
Item 4.	Mine Safety Disclosures	59
Item 5.	Other Information	59
Item 6.	Exhibits	59
	Signature	60

1

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES GLOSSARY
Company Abbreviations
APT	=	American Petroleum Tankers	EPNG	=	El Paso Natural Gas Company, L.L.C.
BOSTCO	=	Battleground Oil Specialty Terminal	General Partner	=	Kinder Morgan G.P., Inc.
		Company LLC	KinderHawk	=	KinderHawk Field Services LLC
Calnev	=	Calnev Pipe Line LLC	KMCO2	=	Kinder Morgan CO2 Company, L.P.
Copano	=	Copano Energy, L.L.C.	KMEP	=	Kinder Morgan Energy Partners, L.P.
Eagle Ford	=	Eagle Ford Gathering LLC	KMGP	=	Kinder Morgan G.P., Inc.
EP	=	El Paso Corporation and its majority-owned	KMI	=	Kinder Morgan, Inc.
		and controlled subsidiaries	KMR	=	Kinder Morgan Management, LLC
EPB	=	El Paso Pipeline Partners, L.P. and its	SFPP	=	SFPP, L.P.
		majority-owned and controlled subsidiaries	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
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
Bcf/d	=	billion cubic feet per day	LIBOR	=	London Interbank Offered Rate
BBtu/d	=	billion British Thermal Units per day	LLC	=	limited liability company
CERCLA	=	Comprehensive Environmental Response,	MBbl/d	=	thousands of barrels per day
		Compensation and Liability Act	MLP	=	master limited partnership
CO2	=	carbon dioxide	NEB	=	National Energy Board
CPUC	=	California Public Utilities Commission	NGL	=	natural gas liquids
EBDA	=	earnings before depreciation, depletion and	NYSE	=	New York Stock Exchange
		amortization	OTC	=	over-the-counter
DD&A	=	depreciation, depletion and amortization	PHMSA	=	Pipeline and Hazardous Materials Safety
DCF	=	distributable cash flow			Administration
EPA	=	United States Environmental Protection	SEC	=	United States Securities and Exchange
		Agency			Commission
FERC	=	Federal Energy Regulatory Commission	Sustaining	=	capital expenditures which do not increase
FASB	=	Financial Accounting Standards Board			capacity or throughput
GAAP	=	United States Generally Accepted Accounting	TBtu	=	trillion British Thermal Units
		Principles	WTI	=	West Texas Intermediate
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

2

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, expressed or implied statements 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 “Information Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 (2013 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 2013 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.

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,
	2014			2013			2014			2013
Revenues
Natural gas sales	$	1,012		$	942		$	2,108		$	1,677
Services	1,467			1,252			2,925			2,483
Product sales and other	1,098			823			2,196			1,518
Total Revenues	3,577			3,017			7,229			5,678
Operating Costs, Expenses and Other
Costs of sales	1,602			1,248			3,240			2,205
Operations and maintenance	492			597			942			981
Depreciation, depletion and amortization	406			357			807			685
General and administrative	132			163			285			297
Taxes, other than income taxes	87			75			170			149
Other expense (income), net	3			(24		)	(3		)	(24		)
Total Operating Costs, Expenses and Other	2,722			2,416			5,441			4,293
Operating Income	855			601			1,788			1,385
Other Income (Expense)
Earnings from equity investments	65			74			137			157
Amortization of excess cost of equity investments	(5		)	(2		)	(8		)	(4		)
Interest, net	(231		)	(214		)	(469		)	(413		)
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	9			19			15			23
Total Other Income (Expense)	(162		)	435			(325		)	546
Income from Continuing Operations Before Income Taxes	693			1,036			1,463			1,931
Income Tax Expense	(24		)	(26		)	(40		)	(127		)
Income from Continuing Operations	669			1,010			1,423			1,804
Loss from Discontinued Operations	—			—			—			(2		)
Net Income	669			1,010			1,423			1,802
Net Income Attributable to Noncontrolling Interests	(8		)	(10		)	(16		)	(19		)
Net Income Attributable to KMEP	$	661		$	1,000		$	1,407		$	1,783
Calculation of Limited Partners’ Interest in Net Income Attributable to KMEP:
Income from Continuing Operations attributable to KMEP	$	661		$	1,000		$	1,407		$	1,785
Less: Pre-acquisition income from operations of March 2013 drop-down asset group allocated to General Partner (Note 1)	—			—			—			(19		)
Add: Drop-down asset group’s severance expense allocated to General Partner (Note 1)	1			4			6			6
Less: General Partner’s remaining interest	(465		)	(422		)	(917		)	(824		)
Limited Partners’ Interest	197			582			496			948
Add: Limited Partners’ Interest in Discontinued Operations	—			—			—			(2		)
Limited Partners’ Interest in Net Income	$	197		$	582		$	496		$	946
Limited Partners’ Net Income per Unit:
Income from Continuing Operations	$	0.43		$	1.41		$	1.09		$	2.40
Loss from Discontinued Operations	—			—			—			(0.01		)
Net Income	$	0.43		$	1.41		$	1.09		$	2.39
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income per Unit	457			413			453			395
Per Unit Cash Distribution Declared for the Period	$	1.39		$	1.32		$	2.77		$	2.62
The accompanying notes are an integral part of these consolidated financial statements.

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,
	2014			2013			2014			2013
Net Income	$	669		$	1,010		$	1,423		$	1,802
Other Comprehensive Income (Loss):
Change in fair value of derivatives utilized for hedging purposes	(113		)	70			(169		)	29
Reclassification of change in fair value of derivatives to net income	18			(3		)	36			(10		)
Foreign currency translation adjustments	71			(71		)	(8		)	(114		)
Adjustments to pension and other postretirement benefit plan liabilities	(1		)	—			(3		)	1
Total Other Comprehensive (Loss)	(25		)	(4)			(144		)	(94		)
Comprehensive Income	644			1,006			1,279			1,708
Comprehensive Income Attributable to Noncontrolling Interests	(8		)	(10		)	(15		)	(18		)
Comprehensive Income Attributable to KMEP	$	636		$	996		$	1,264		$	1,690
The accompanying notes are an integral part of these consolidated financial statements.

5

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions)
	June 30, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	263		$	404
Accounts receivable, net	1,445			1,511
Inventories	424			393
Other current assets	388			360
Total current assets	2,520			2,668
Property, plant and equipment, net	29,285			27,405
Investments	2,193			2,233
Goodwill	6,721			6,547
Other intangibles, net	2,345			2,414
Deferred charges and other assets	1,487			1,497
Total Assets	$	44,551		$	42,764
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	1,337		$	1,504
Accounts payable	1,397			1,537
Accrued interest	396			371
Accrued contingencies	600			529
Other current liabilities	808			636
Total current liabilities	4,538			4,577
Long-term liabilities and deferred credits
Long-term debt
Outstanding	19,610			18,410
Debt fair value adjustments	1,267			1,214
Total long-term debt	20,877			19,624
Deferred income taxes	297			285
Other long-term liabilities and deferred credits	1,054			1,057
Total long-term liabilities and deferred credits	22,228			20,966
Total Liabilities	26,766			25,543
Commitments and contingencies (Notes 3 and 9)
Partners’ Capital
Common units	9,878			9,459
Class B units	(2		)	6
i-units	4,459			4,222
General partner	3,092			3,081
Accumulated other comprehensive (loss) income	(110		)	33
Total KMEP Partners’ Capital	17,317			16,801
Noncontrolling interests	468			420
Total Partners’ Capital	17,785			17,221
Total Liabilities and Partners’ Capital	$	44,551		$	42,764
The accompanying notes are an integral part of these consolidated financial statements.

6

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)
	Six Months Ended June 30,
	2014			2013
Cash Flows From Operating Activities
Net Income	$	1,423		$	1,802
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	807			685
Amortization of excess cost of equity investments	8			4
Gain on remeasurement of previously held equity interest in Eagle Ford Gathering to fair value (Note 2)	—			(558		)
Gain on sale of investments in Express pipeline system (Note 2)	—			(225		)
Earnings from equity investments	(137		)	(157		)
Distributions from equity investment earnings	124			152
Proceeds from termination of interest rate swap agreements	—			96
Changes in components of working capital, net of the effects of acquisitions:
Accounts receivable	36			(26		)
Inventories	(25		)	(50		)
Other current assets	(35		)	(35		)
Accounts payable	(53		)	(151		)
Accrued interest	25			12
Accrued contingencies and other current liabilities	116			(7		)
Rate reparations, refunds and other litigation reserve adjustments, net	36			177
Other, net	(76		)	23
Net Cash Provided by Operating Activities	2,249			1,742
Cash Flows From Investing Activities
Payment to KMI for March 2013 drop-down asset group (Note 1)	—			(994		)
Acquisitions of assets and investments, net of cash acquired	(993		)	(286		)
Capital expenditures	(1,658		)	(1,268		)
Proceeds from sale of investments in Express pipeline system	—			403
Contributions to investments	(89		)	(93		)
Distributions from equity investments in excess of cumulative earnings	37			36
Natural gas storage and natural gas and liquids line-fill	22			—
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs	11			23
Other, net	(5		)	5
Net Cash Used in Investing Activities	(2,675		)	(2,174		)
Cash Flows From Financing Activities
Issuance of debt	6,083			4,858
Payment of debt	(5,060		)	(3,860		)
Debt issue costs	(11		)	(11		)
Proceeds from issuance of common units	938			834
Proceeds from issuance of i-units	97			73
Contributions from noncontrolling interests	57			99
Contributions from General Partner	—			38
Pre-acquisition contributions from KMI to March 2013 drop-down asset group	—			35
Distributions to partners and noncontrolling interests	(1,813		)	(1,487		)
Other, net	(2		)	—
Net Cash Provided by Financing Activities	289			579
Effect of Exchange Rate Changes on Cash and Cash Equivalents	(4		)	(20		)
Net (decrease) increase in Cash and Cash Equivalents	(141		)	127
Cash and Cash Equivalents, beginning of period	404			529
Cash and Cash Equivalents, end of period	$	263		$	656
Noncash Investing and Financing Activities
Assets acquired or liabilities settled by the issuance of common units (Note 1)	$	—		$	3,841
Assets acquired by the assumption or incurrence of liabilities	$	73		$	1,490
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	451		$	411
Cash paid during the period for income taxes	$	17		$	14
The accompanying notes are an integral part of these consolidated financial statements.

7

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (In Millions, Except Units) (Unaudited)
	Six Months Ended June 30,
	2014				2013
	Units	Amount			Units	Amount
Common units:
Beginning Balance	312,791,561	$	9,459		252,756,425	$	4,723
Net income		350				659
Units issued as consideration in the acquisition of assets	—	—			44,620,662	3,841
Units issued for cash	12,321,944	938			9,863,329	834
Distributions		(869		)		(662		)
Ending Balance	325,113,505	9,878			307,240,416	9,395
Class B units:
Beginning Balance	5,313,400	6			5,313,400	14
Net income		6				13
Distributions		(14		)		(14		)
Ending Balance	5,313,400	(2		)	5,313,400	13
i-Units:
Beginning Balance	125,323,734	4,222			115,118,338	3,564
Net income		140				274
Units issued for cash	1,333,960	97			860,600	73
Distributions	4,624,072	—			3,531,548	—
Ending Balance	131,281,766	4,459			119,510,486	3,911
General partner:
Beginning Balance		3,081				4,026
Net income		911				837
Distributions		(906		)		(792		)
Drop-Down acquisition (Note 1)		—				(1,057		)
Reimbursed severance expense allocated from KMI		6				5
Contributions		—				38
Other adjustments		—				2
Ending Balance		3,092				3,059
Accumulated other comprehensive income (loss):
Beginning Balance		33				168
Other comprehensive loss		(143		)		(93		)
Ending Balance		(110		)		75
Total KMEP Partners’ Capital	461,708,671	17,317			432,064,302	16,453
Noncontrolling interests:
Beginning Balance		420				267
Net income		16				19
Contributions		57				99
Distributions		(24		)		(19		)
Drop-Down acquisition (Note 1)		—				(10		)
Other comprehensive loss		(1		)		(1		)
Ending Balance		468				355
Total Partners’ Capital	461,708,671	$	17,785		432,064,302	$	16,808
The accompanying notes are an integral part of these consolidated financial statements.

8

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

KMEP is a Delaware limited partnership formed in August 1992.  We are a leading pipeline transportation and energy storage company in North America, with a diversified portfolio of energy transportation and storage assets. We own an interest in or operate approximately 52,000 miles of pipelines and 180 terminals, and we conduct our business through five reportable business segments (described further in Note 7). Our common units trade on the NYSE under the symbol “KMP.”

Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO₂ and other products, and our terminals transport, transload and store petroleum products, ethanol and chemicals, and handle such products as coal, petroleum coke and steel. We are also the leading producer and transporter of CO₂, for enhanced oil recovery projects in North America.

KMI 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, 2014, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary KMR (discussed below), an approximate 11.4% interest in us. In addition, as of June 30, 2014, KMI owns a 39.6% limited partner interest and the 2% general partner interest in EPB.

KMR

KMR is a Delaware LLC. 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. 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 KMEP. KMR’s shares representing LLC interests trade on the NYSE under the symbol “KMR.” As of June 30, 2014, KMR, through its sole ownership of our i-units, owned approximately28.4% of all of our outstanding limited partner units (which are in the form of i-units that are issued only to KMR).

More information about the entities referred to above and the delegation of control agreement is contained in our 2013 Form 10-K. For a more complete discussion of our related party transactions with the entities referred to above, 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 2013 Form 10-K.

Basis of Presentation

General

Our reporting currency is in U.S. dollars, and all references to dollars are U.S. dollars, except where stated otherwise.  Our accompanying unaudited consolidated financial statements include our accounts, majority-owned and controlled subsidiaries, and have been prepared 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, the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, 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.

9

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. In addition, certain amounts from prior periods have been reclassified to conform to the current presentation (including reclassifications between “Services” and “Product sales and other” within the “Revenues” section of our accompanying consolidated statements of income). 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 2013 Form 10-K.

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 and Sales,” KMI is not liable for, and its assets are not available to satisfy, our obligations and/or our subsidiaries’ obligations, 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.

March 2013 KMI Asset Drop-Down

Effective March 1, 2013, we acquired from KMI the remaining 50% ownership interest we did not already own in both EPNG and 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; and the EP midstream assets of Kinder Morgan Altamont LLC (formerly, El Paso Midstream Investment Company, L.L.C.) as the EP midstream assets. Prior to the March 2013 drop-down transaction, we accounted for our initial 50% ownership interests in both EPNG and the EP midstream assets under the equity method of accounting.

KMI acquired all of the assets included in the March 2013 drop-down asset group as part of its May 25, 2012 acquisition of EP, and KMI accounted for its EP acquisition under the acquisition method of accounting. We, however, accounted for the March 2013 drop-down transaction as combinations of entities under common control. Accordingly, we prepared our consolidated financial statements to reflect the transfer of the March 2013 drop-down asset group from KMI to us as if such transfer had taken place on the date when the March 2013 drop-down asset group met the accounting requirements for entities under common control—May 25, 2012 for EPNG, and June 1, 2012 for the EP midstream assets.

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

▪ incremental severance expense related to KMI’s acquisition of EP and allocated to us from KMI. This severance expense allocated to us was associated with both the March 2013 drop-down asset group and assets we acquired pursuant to an earlier drop-down from KMI effective August 1, 2012; however, we do not have any obligation, nor did we pay any amounts related to this expense. Furthermore, we reported this expense separately as “Drop-down asset group’s severance expense allocated to General Partner” within the “Calculation of Limited Partners’ Interest in Net Income Attributable to KMEP” section of our accompanying consolidated statements of income for each of the three and six months ended June 30, 2014 and 2013.

For all periods beginning after our acquisition date of March 1, 2013, we allocated our earnings (including the earnings from the March 2013 drop-down asset group) to all of our partners according to our partnership agreement.

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Goodwill

We evaluate goodwill for impairment on May 31 of each year.  There were no impairment charges resulting from our May 31, 2014 impairment testing, and no event indicating an impairment has occurred subsequent to that date.

Limited Partners’ Net Income per Unit

We compute Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period.

2. Acquisitions and Divestitures    

Acquisitions

American Petroleum Tankers and State Class Tankers

Effective January 17, 2014, we acquired APT and State Class Tankers (SCT) for aggregate consideration of $961 million in cash (the APT acquisition). APT is engaged in the marine transportation of crude oil, condensate and refined products in the U.S. domestic trade, commonly referred to as the Jones Act trade. APT’s primary assets consist of a fleet of five medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity, and each operating pursuant to long-term time charters with high quality counterparties, including major integrated oil companies, major refiners and the U.S. Military Sealift Command. As of the closing date, the vessels’ time charters had an average remaining term of approximately four years, with renewal options to extend the terms by an average of two years. APT’s vessels are operated by Crowley Maritime Corporation.

SCT has commissioned the construction of four medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity. The SCT vessels are scheduled to be delivered in 2015 and 2016 and are being constructed by General Dynamics’ NASSCO shipyard. We expect to invest approximately $214 million to complete the construction of these four SCT vessels, and upon delivery, the vessels will be operated pursuant to long-term time charters with a major integrated oil company. Each of the time charters has an initial term of five years, with renewal options to extend the term by up to three years. Our APT acquisition complements and extends our existing crude oil and refined products transportation business, and all of the acquired assets are included in our Terminals business segment.

As of June 30, 2014, our preliminary purchase price allocation related to our APT acquisition, as adjusted to date, is as follows (in millions). Our evaluation of the assigned fair values is ongoing and subject to adjustment.

Purchase Price Allocation:
Current assets	$	6
Property, plant and equipment	951
Goodwill	67
Other assets	3
Total assets acquired	1,027
Current liabilities	(5		)
Unfavorable customer contracts	(61		)
Cash consideration	$	961

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 goodwill was primarily generated by the value of the synergies created by expanding our non-pipeline liquids handling operations. Furthermore, we expect to fully deduct for tax purposes the entire amount of goodwill we recognized. The “Unfavorable customer contracts” figure represents the amount, on a present value basis, by which the customer contracts were below market day rates at the time of acquisition. This amount is amortized as a noncash adjustment to revenue over the remaining contract period.

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Other

Effective May 1, 2013, 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). Also, due to the fact that our Copano acquisition included the remaining 50% interest in Eagle Ford Gathering LLC 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. As a result of our remeasurement, we recognized a $558 million non-cash gain, which represented the excess of the investment’s fair value ($704 million) over our carrying value as of May 1, 2013 ($146 million), and we reported this gain separately as “Gain on remeasurement of previously held equity interest in Eagle Ford Gathering to fair value” on our accompanying consolidated statements of income for the three and six months ended June 30, 2013.

As of June 30, 2014, our purchase price allocation related to the Copano acquisition, is as follows (in millions):

Purchase Price Allocation:
Current assets (including cash acquired of $30)	$	218
Property, plant and equipment	2,788
Investments	300
Goodwill	1,248
Other intangibles	1,375
Other assets	13
Total assets	5,942
Less: Fair value of previously held 50% interest in Eagle Ford Gathering LLC	(704		)
Total assets acquired	5,238
Current liabilities	(208		)
Other liabilities	(28		)
Long-term debt	(1,252		)
Noncontrolling interests	(17		)
Common unit consideration	$	3,733

The table above reflects changes we made in the first six months of 2014 to our preliminary purchase price allocation as of December 31, 2013. Based on our final measurement of fair values for all of the identifiable tangible and intangible assets acquired and liabilities assumed on the acquisition date, we reduced the preliminary value assigned to (i) “Investments” by $87 million; (ii) “Property, plant and equipment” by $17 million; and (ii) combined working capital items by $3 million.

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, but 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.

Effective June 1, 2013, we acquired certain oil and gas properties, rights, and related assets located in the Goldsmith Landreth San Andres oil field unit in the Permian Basin of West Texas from Legado Resources LLC for an aggregate consideration of $298 million, consisting of $280 million in cash and assumed liabilities of $18 million (including $12 million of long-term asset retirement obligations).

For additional information about our Copano and Goldsmith Landreth acquisitions (including our preliminary purchase price allocations as of December 31, 2013), see Note 3 “Acquisitions and Divestitures—Business Combinations and Acquisitions of Investments” to our consolidated financial statements included in our 2013 Form 10-K.

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Pro Forma Information

The following summarized unaudited pro forma consolidated income statement information for the six months ended June 30, 2013 assumes that our acquisitions of (i) APT, (ii) Copano and (iii) the Goldsmith Landreth oil field unit had occurred as of January 1, 2013. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed these acquisitions as of January 1, 2013, or the results that will be attained in the future. Amounts presented below are in millions, except for the per unit amounts:

	Pro Forma
	Six Months Ended June 30, 2013
	(Unaudited)
Revenues	$	6,432
Income from Continuing Operations	1,766
Loss from Discontinued Operations	(2		)
Net Income	1,764
Net Income Attributable to Noncontrolling Interests	(19		)
Net Income Attributable to KMEP	$	1,745
Limited Partners’ Net Income per Unit:
Income from Continuing Operations	$	2.12
Net Income	$	2.12

Divestitures

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. We received net cash proceeds of $402 million (after paying $1 million in the third quarter of 2013 for both a final working capital settlement and certain

transaction-related selling expenses), and we reported the $403 million proceeds received in the first half of 2013 separately as “Proceeds from sale of investments in Express pipeline system” within the investing section of our accompanying consolidated statement of cash flows for the six months ended June 30, 2013. Additionally, we recognized a combined $225 million pre-tax gain with respect to this sale in the first half of 2013, and we reported this gain amount separately as “Gain on sale of investments in Express pipeline system” on our accompanying consolidated statement of income for the six months ended June 30, 2013. We also recorded an income tax expense of $84 million related to this gain on sale for the six months ended June 30, 2013, and we included this expense within “Income Tax Expense.” As of the date of sale, our equity investment in Express totaled $67 million and our note receivable due from Express totaled $110 million.

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 using the effective interest rate method. The following table provides detail on the principal amount of our outstanding debt as of June 30, 2014 and December 31, 2013. The table amounts exclude all debt fair value adjustments, including debt discounts and premiums (in millions).

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	June 30, 2014			December 31, 2013
KMEP borrowings:
Senior notes, 2.65% through 9.00%, due 2014 through 2044(a)	$	17,100		$	15,600
Commercial paper borrowings(b)	513			979
Credit facility due May 1, 2018(c)	—			—
Subsidiary borrowings (as obligor):
TGP - Senior Notes, 7.00% through 8.375%, due 2016 through 2037	1,790			1,790
EPNG - Senior Notes, 5.95% through 8.625%, due 2017 through 2032	1,115			1,115
Copano - Senior Notes, 7.125%, due April 1, 2021	332			332
Other miscellaneous subsidiary debt	97			98
Total debt	20,947			19,914
Less: Current portion of debt(d)	(1,337		)	(1,504		)
Total long-term debt(e)	$	19,610		$	18,410

__________

(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.

(b) As of both June 30, 2014 and December 31, 2013, the average interest rate on our outstanding commercial paper borrowings was 0.28%. The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions, 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 Facilities” below.

(d) Amounts include outstanding commercial paper borrowings, discussed above in footnote (b).

(e) As of June 30, 2014 and December 31, 2013, our “Debt fair value adjustments” increased our debt balances by $1,267 million and $1,214 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—Debt Fair Value Adjustments.”

Credit Facilities

As of both June 30, 2014 and December 31, 2013, we had no borrowings under our $2.7 billionfive-year senior unsecured revolving credit facility maturing May 1, 2018. Borrowings under our revolving credit facility can be used for general partnership purposes and as a backup for our commercial paper program. Similarly, borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.

We had, as of June 30, 2014,$1,807 million of borrowing capacity available under our credit facility. The amount available for borrowing under our credit facility was reduced bya combined amount of $893 million, consisting of(i) $513 million of commercial paper borrowings; (ii) $205 million of letters of credit; and (iii) $175 million related to a capital contribution commitment to one of our unconsolidated subsidiaries. For more information, see Note 8 “Related Party Transactions.”

Changes in Debt

On January 15, 2014, in anticipation of our APT acquisition, we entered into a short-term unsecured liquidity facility with us as borrower, and UBS as administrative agent. This liquidity facility provided for borrowings of up to $1.0 billion from a syndicate of financial institutions and was scheduled to mature on July 15, 2014. Additionally, in conjunction with the establishment of this liquidity facility, we increased our commercial paper program to provide for the issuance of up to $3.7 billion (up from $2.7 billion). We made no borrowings under this liquidity facility, and after receiving the cash proceeds from both our February 2014 public offering of senior notes (described following) and our February 2014 public offering of common units (described in Note 4 “Partners’ Capital—Equity Issuances”), we terminated the liquidity facility and decreased our commercial paper program to again provide for the issuance of up to $2.7 billion.

On February 24, 2014, we completed a public offering of a total $1.5 billion in principal amount of senior notes in two separate series. We received net proceeds of $743 million from the offering of $750 million in principal amount of 3.50% senior notes due March 1, 2021, and$739 million from the offering of $750 million in principal amount of 5.50% senior

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notes due March 1, 2044. We used the proceeds from our February 2014 debt offering to reduce the borrowings under our commercial paper program (reducing the incremental commercial paper borrowings we made in January 2014 to fund our APT acquisition).

4. Partners’ Capital

Equity Issuances

For the six month period ended June 30, 2014, our equity issuances, which were used to reduce borrowings under our commercial paper program, consisted of the following:

• on February 24, 2014, we issued, in a public offering, 7,935,000 of our common units at a price of $78.32 per unit, resulting in net proceeds of $603 million;

• during the six months ended June 30, 2014, we issued 4,386,944 of our common units pursuant to our equity distribution agreements with UBS (including 198,110 common units to settle sales made on or before December 31, 2013), resulting in net proceeds of $335 million; and

• during the six months ended June 30, 2014, we issued 1,333,960 i-units to KMR (including 76,100

i-units to settle sales made on or before December 31, 2013), resulting in net proceeds of $97 million.

Income Allocations

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.

Partnership Distributions

The following table provides information about our distributions for the three and six month periods ended June 30, 2014 and 2013 (in millions except per unit and i-unit distributions amounts):

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Per unit cash distribution declared for the period	$	1.39	$	1.32	$	2.77	$	2.62
Per unit cash distribution paid in the period	$	1.38	$	1.30	$	2.74	$	2.59
Cash distributions paid in the period to all partners(a)(b)	$	918	$	757	$	1,813	$	1,487
i-unit distributions made in the period to KMR(c)	2,386,814		1,726,952		4,624,072		3,531,548
General Partner’s incentive distribution(d):
Declared for the period(e)	$	463	$	416	$	912	$	814
Paid in the period(b)(c)(f)	$	449	$	398	$	894	$	782

______________

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

(b) The period-to-period increases in distributions paid primarily reflect the increases in amounts distributed per unit as well as the issuance of additional units.

(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 $1.38 and $1.30 per unit paid to our common unitholders during the second quarters of 2014 and 2013, respectively, and the $2.74 and $2.59 per unit paid to our common unitholders during the first six months of 2014 and 2013, respectively.

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

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(e) Amounts are net of waived incentive distributions of $33 million and $25 million for the three months ended June 30, 2014 and 2013, respectively, and $66 million and $29 million for the six months ended June 30, 2014 and 2013, respectively, related to certain acquisitions. In addition, our general partner agreed to waive a portion of our future incentive distributions amounts equal to $33 million and $34 million for our third and fourth quarters in 2014, respectively, $139 million for 2015, $116 million for 2016, $105 million for 2017, and annual amounts thereafter decreasing by $5 million per year from the 2017 level related to certain acquisitions.

(f) Amounts are net of waived incentive distributions of $33 million and $4 million for the three months ended June 30, 2014 and 2013, respectively, and $58 million and $11 million for the six months ended June 30, 2014 and 2013, respectively, related to certain acquisitions.

For additional information about our partnership distributions, see Note 11 “Related Party Transactions—Partnership Interests and Distributions” to our consolidated financial statements included in our 2013 Form 10-K.

Subsequent Events

On July 16, 2014, we declared a cash distribution of $1.39 per unit for the quarterly period ended June 30, 2014.  The distribution will be paid on August 14, 2014 to unitholders of record as of July 31, 2014. KMR will receive a distribution of additional i-units based on the$1.39 distribution per common unit. For each outstanding i-unit that KMR holds, a fraction of an i-unit will be issued. This fraction will be determined by dividing:

• $1.39, the cash amount distributed per common unit

by

• the average of KMR’s shares’ closing market prices from July 15-28, 2014, 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, NGL and crude oil. We also have exposure to interest rate risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks.

Energy Commodity Price Risk Management

As of June 30, 2014, 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	(24.2)	MMBbl
Natural gas fixed price	(26.1)	Bcf
Natural gas basis	(26.7)	Bcf
Derivatives not designated as hedging contracts
Crude oil fixed price	(0.4)	MMBbl
Crude oil basis	(0.6)	MMBbl
Natural gas fixed price	(7.7)	Bcf
Natural gas basis	(0.1)	Bcf
NGL fixed price	(0.8)	MMBbl

As of June 30, 2014, 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 2018.

Interest Rate Risk Management

As of June 30, 2014, we had a combined notional principal amount of $5,175 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

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that correspond to the maturity dates of the related series of senior notes and, as of June 30, 2014, 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, 2013, we had a combined notional principal amount of $4,675 million of fixed-to-variable interest rate swap agreements. In February 2014, we entered into four separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million. These agreements effectively convert a portion of the interest expense associated with our 3.50% senior notes due March 1, 2021, from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.

Fair Value of Derivative Contracts

The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of June 30, 2014 and December 31, 2013 (in millions):

Fair Value of Derivative Contracts
		Asset derivatives				Liability derivatives
		June 30, 2014		December 31, 2013		June 30, 2014			December 31, 2013
	Balance sheet location	Fair value		Fair value		Fair value			Fair value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Other current assets/(Other current liabilities)	$	6	$	18	$	(97	)	$	(33	)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		58		(72		)	(30		)
Subtotal		10		76		(169		)	(63		)
Interest rate swap agreements	Other current assets/(Other current liabilities)	79		76		—			—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	192		141		(46		)	(116		)
Subtotal		271		217		(46		)	(116		)
Total		281		293		(215		)	(179		)
Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Other current assets/(Other current liabilities)	4		4		(10		)	(5		)
Total		4		4		(10		)	(5		)
Total derivatives		$	285	$	297	$	(225	)	$	(184	)

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. As of June 30, 2014 and December 31, 2013, these fair value adjustments to our debt balances included (i) $613 million and $645 million, respectively, associated with fair value adjustments to our debt previously recorded in purchase accounting; (ii) $225 million and $101 million, respectively, associated with the offsetting entry for hedged debt; (iii) $486 million and $517 million, respectively, associated with unamortized premium from the termination of interest rate swap agreements; and offset by (iv) $57 million and $49 million, respectively, associated with unamortized debt discount amounts. As of June 30, 2014, 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 three 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, 2014 and 2013 (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,
		2014			2013			2014			2013
Interest rate swap agreements	Interest expense	$	63		$	(211	)	$	124		$	(294	)
Total		$	63		$	(211	)	$	124		$	(294	)
Fixed rate debt	Interest expense	$	(63	)	$	211		$	(124	)	$	294
Total		$	(63	)	$	211		$	(124	)	$	294

______________

(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 other  comprehensive income on derivative (effective portion)(a)					Location of gain/(loss) reclassified from Accumulated  other  comprehensive income into income (effective portion)	Amount of gain/(loss) reclassified from Accumulated other  comprehensive income 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,
	2014			2013			2014			2013				2014			2013
Energy commodity derivative contracts	$	(113	)	$	70	Revenues-Natural gas sales	$	(2	)	$	—		Revenues-Natural gas sales	$	—		$	—
						Revenues-Product sales and other	(23		)	8			Revenues-Product sales and other	(27		)	9
						Costs of sales	7			(5		)	Costs of sales	—			—
Total	$	(113	)	$	70	Total	$	(18	)	$	3		Total	$	(27	)	$	9
	Six Months Ended June 30,						Six Months Ended June 30,							Six Months Ended June 30,
	2014			2013			2014			2013				2014			2013
Energy commodity derivative contracts	$	(169	)	$	29	Revenues-Natural gas sales	$	(12	)	$	—		Revenues-Natural gas sales	$	—		$	—
						Revenues-Product sales and other	(32		)	15			Revenues-Product sales and other	(32		)	6
						Costs of sales	8			(5		)	Costs of sales	—			—
Total	$	(169	)	$	29	Total	$	(36	)	$	10		Total	$	(32	)	$	6

______________

(a) We expect to reclassify an approximate $71 millionloss associated with energy commodity price risk management activities included in our Partners’ Capital as of June 30, 2014 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) Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).

Derivatives not designated as accounting hedges	Location of gain/(loss) recognized in income on derivatives	Amount of gain/(loss) recognized in income on derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2014			2013			2014			2013
Energy commodity derivative contracts	Revenues-Natural gas sales	$	(9	)	$	—		$	(16	)	$	—
	Revenues-Product sales and other	6			(1		)	(1		)	3
	Costs of sales	(3		)	(1		)	7			(1		)
	Other expense (income)	—			—			(2		)	—
Total		$	(6	)	$	(2	)	$	(12	)	$	2

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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; (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, 2014 and December 31, 2013, we had no outstanding letters of credit supporting our hedging of energy commodity price risks associated with the sale of natural gas, NGL 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, 2014, we estimate that if our credit rating was downgraded one notch, we would be required to postnoadditional collateral to our counterparties. If we were downgradedtwonotches (that is, below investment grade), we would be required to post$122 millionof additional collateral.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive (loss) income” within “Partners’ Capital” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive (loss) income” for each of the six months ended June 30, 2014 and 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, 2013	$	24		$	(4	)	$	13		$	33
Other comprehensive (loss) income before reclassifications	(169		)	(7		)	(3		)	(179		)
Amounts reclassified from accumulated other comprehensive income	36			—			—			36
Net current-period other comprehensive (loss) income	(133		)	(7		)	(3		)	(143		)
Balance as of June 30, 2014	$	(109	)	$	(11	)	$	10		$	(110	)

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

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, 2014 and December 31, 2013, based on the three levels established by the Codification. Also, certain of our derivative contracts are subject to master netting agreements. The following tables present our derivative contracts subject to such netting agreements as of June 30, 2014 and December 31, 2013 (in millions):

	Balance Sheet asset fair value measurements using								Amounts not offset in the Balance Sheet					Net Amount
	Level 1		Level 2		Level 3		Gross Amount		Financial Instruments			Cash Collateral Held(b)
As of June 30, 2014
Energy commodity derivative contracts(a)	$	3	$	7	$	4	$	14	$	(12	)	$	—	$	2
Interest rate swap agreements	$	—	$	271	$	—	$	271	$	(22	)	$	—	$	249
As of December 31, 2013
Energy commodity derivative contracts(a)	$	4	$	46	$	30	$	80	$	(44	)	$	—	$	36
Interest rate swap agreements	$	—	$	217	$	—	$	217	$	(28	)	$	—	$	189

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	Balance Sheet liability fair value measurements using												Amounts not offset in the Balance Sheet				Net Amount
	Level 1			Level 2			Level 3			Gross Amount			Financial Instruments		Cash Collateral Posted(c)
As of June 30, 2014
Energy commodity derivative contracts(a)	$	(10	)	$	(134	)	$	(35	)	$	(179	)	$	12	$	17	$	(150	)
Interest rate swap agreements	$	—		$	(46	)	$	—		$	(46	)	$	22	$	—	$	(24	)
As of December 31, 2013
Energy commodity derivative contracts(a)	$	(6	)	$	(31	)	$	(31	)	$	(68	)	$	44	$	17	$	(7	)
Interest rate swap agreements	$	—		$	(116	)	$	—		$	(116	)	$	28	$	—	$	(88	)

______________

(a) Level 1 consists primarily of New York Mercantile Exchange natural gas futures. Level 2 consists primarily of OTC WTI swaps. Level 3 consists primarily of WTI options and NGL options.

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

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

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, 2014 and 2013 (in millions):

Significant unobservable inputs (Level 3)
	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Derivatives-net asset (liability)
Beginning of Period	$	(3	)	$	3		$	(1	)	$	3
Total gains or (losses):
Included in earnings	(19		)	—			(18		)	6
Included in other comprehensive income (loss)	(9		)	1			(10		)	—
Purchases(a)	—			18			—			18
Settlements	—			(4		)	(2		)	(9		)
End of Period	$	(31	)	$	18		$	(31	)	$	18
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	$	(14	)	$	1		$	(16	)	$	5

______________

(a) Three and six month 2013 amounts represent the purchase of Level 3 energy commodity derivative contracts associated with our May 1, 2013 Copano acquisition.

As of June 30, 2014, our Level 3 derivative assets and liabilities consisted primarily of WTI options and NGL 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 is 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, 2014 and December 31, 2013 (both short-term and long-term and including debt fair value adjustments), is disclosed below (in millions):

	June 30, 2014				December 31, 2013
	Carrying Value		Estimated Fair value		Carrying Value		Estimated Fair value
Total debt	$	22,214	$	23,450	$	21,128	$	21,550

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We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both June 30, 2014 and December 31, 2013.

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 NGL;

▪ 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 and jet fuel), NGL, crude oil and condensate, and bio-fuels;

▪ Terminals—the transportation, transloading and storing of refined petroleum products, crude oil, condensate, and 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 EBDA (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. Financial information by segment follows (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Revenues
Natural Gas Pipelines
Revenues from external customers	$	2,111		$	1,696		$	4,286		$	3,065
Intersegment revenues	1			—			2			—
CO2	454			460			937			889
Products Pipelines	524			443			1,058			897
Terminals
Revenues from external customers	420			343			$	811		$	680
Intersegment revenues	1			1			1			1
Kinder Morgan Canada	68			75			137			147
Total segment revenues	3,579			3,018			7,232			5,679
Less: Total intersegment revenues	(2		)	(1		)	(3		)	(1		)
Total consolidated revenues	$	3,577		$	3,017		$	7,229		$	5,678

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	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Segment EBDA(a)
Natural Gas Pipelines(b)	$	639		$	1,123		$	1,358		$	1,680
CO2	332			358			695			700
Products Pipelines(c)	203			12			411			197
Terminals	233			207			447			393
Kinder Morgan Canada(d)	40			50			88			243
Segment EBDA	1,447			1,750			2,999			3,213
Total segment DD&A expense	(406		)	(357		)	(807		)	(685		)
Total segment amortization of excess cost of investments	(5		)	(2		)	(8		)	(4		)
General and administrative expense	(132		)	(163		)	(285		)	(297		)
Interest expense, net of unallocable interest income	(231		)	(215		)	(470		)	(417		)
Unallocable income tax expense	(4		)	(3		)	(6		)	(6		)
Loss from discontinued operations	—			—			—			(2		)
Total consolidated net income	$	669		$	1,010		$	1,423		$	1,802

	June 30, 2014		December 31, 2013
Assets
Natural Gas Pipelines	$	25,704	$	25,721
CO2	3,039		2,954
Products Pipelines	5,782		5,488
Terminals	7,592		6,124
Kinder Morgan Canada	1,690		1,678
Total segment assets	43,807		41,965
Corporate assets(e)	744		799
Total consolidated assets	$	44,551	$	42,764

______________

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

(b) Three and six month 2013 amounts include a $558 million non-cash gain from the remeasurement of our previously held equity interest in Eagle Ford Gathering to fair value (discussed further in Note 2 “Acquisitions and Divestitures—Acquisitions—Other”).

(c) Three and six month 2013 amounts include increases in operating 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-taxgain 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

Asset Acquisitions and Sales

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 March 2013 drop-down asset group, KMI has agreed to indemnify us and our general partner with respect to approximately $5.9 billion of our debt as of June 30, 2014. 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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Contingent Debt

Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantees or indemnifications are remote.  As of June 30, 2014 and December 31, 2013, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $79 million and $74 million, respectively.

Other Commitments

One of our wholly owned subsidiaries is committed to contribute $175 million to one of our unconsolidated subsidiaries during 2014.

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 CPUC cases described below them. 

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).  In late June of 2014, certain shippers filed complaints with the FERC (docketed at OR14-35 and OR14-36) challenging SFPP’s adjustments to its rates in 2012 and 2013 for inflation under the FERC’s indexing regulations. If the shippers are successful in proving these claims or other of 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 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. EPNG implemented certain aspects of that decision and believes it has an appropriate reserve related to the findings in Opinion 517. EPNG has sought rehearing on Opinion 517. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528) on October 17, 2013. EPNG sought rehearing on certain issues in Opinion 528. As required by Opinion 528, EPNG filed revised pro forma recalculated rates consistent with the terms of Opinion 528. The FERC also required an Administrative Law Judge to conduct an additional hearing concerning one of the issues in Opinion 528 and a decision is expected in September 2014.

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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 included determinations on issues, such as SFPP’s entitlement to an income tax allowance, allocation of environmental expenses, and refund liability which we asserted 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. 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 denied SFPP’s petition, and on October 16, 2013, the California Supreme Court declined SFPP’s request for further review. The precise impact of the now final state rulings denying SFPP an income tax allowance, together with other pending ratemaking issues, are subject to further consideration and determination by the CPUC.

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.

On July 19, 2013, Calnev filed an application with the CPUC requesting a 36% increase in its intrastate rates. A decision from the CPUC approving the requested rate increase was issued on November 14, 2013.

On November 27, 2013, the CPUC issued its Order to Show Cause directing SFPP to demonstrate whether or not the CPUC should require immediate refund payments associated with various pending SFPP rate matters. Subsequently, the CPUC issued an order directing SFPP and its shippers to engage in mandatory settlement discussions. On April 3, 2014, the CPUC issued its ruling suspending proceedings in all pending SFPP matters until October 1, 2014 or the date upon which SFPP and its shippers inform the CPUC that SFPP and its shippers have reached settlement of all pending matters or have failed to do so. If the matter is not settled, a decision addressing, if not resolving, all pending SFPP rate matters at the CPUC is anticipated in the first quarter of 2015.

Based on our review of these CPUC proceedings and the shipper comments thereon, we estimate that the shippers are requesting approximately $400 million in reparation payments and approximately $30 million in annual rate reductions.  The actual amount of reparations will be determined through settlement negotiations or further proceedings at the CPUC. As of June 30, 2014, we believe our legal reserve 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. Furthermore, we do not expect any reparations that we would pay in this matter to impact the per unit cash distributions we expect to pay to our limited partners for 2014.

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

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al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In September 2011, the trial judge determined that the annual rent payable as of January 1, 2004 was $14 million, subject to annual consumer price index increases. Judgment was entered by the Superior Court on May 29, 2012 and SFPP appealed the judgment. If the judgment is upheld on appeal, SFPP would owe approximately $95 million in back rent. Accordingly, we have increased our rights-of-way liability to cover this potential liability for back rent. In addition, the trial judge determined that UPRR is entitled to approximately $20 million for interest through the date of the judgment on the outstanding back rent liability. We believe the award of interest is without merit and are pursuing our appellate rights. On June 27, 2014, the California Court of Appeals heard oral argument and requested that the parties submit supplemental briefing on the following issues: whether the UPRR ever had sufficient ownership interests to allow it to grant subsurface easements in land granted to it by Congress; whether there is sufficient evidence in the record on this question; and assuming that the UPRR did not have sufficient ownership interests to grant subsurface easements and that its rental agreements with SFPP were invalid, whether the parties can limit the scope of the Court’s inquiry on appeal by not disputing the underlying rights of the railroad. The parties are in the process of filing supplemental briefs on the foregoing issues and a decision is anticipated by the Court of Appeals in 2014.

By notice dated October 25, 2013, UPRR demanded the payment of $22.25 million in rent for the first year of the next ten-year period beginning January 1, 2014. SFPP rejected the demand and the parties are pursuing the dispute resolution procedure in their contract to determine the rental adjustment, if any, for such period.

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. On March 10, 2014, the trial court issued a tentative statement of decision addressing all of the causes of action and defenses and resolved those matters against SFPP, consistent with the jury’s verdict. If the tentative statement of decision and jury verdict become final and are affirmed on appeal, SFPP will be required to pay a judgment of $42.65 million. SFPP is continuing to evaluate 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 our subsidiary 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 U.S. 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. A bench trial occurred in November 2013. On March 6, 2014, the Court issued findings of fact and conclusions of law and entered judgment against KMBT in the amount of $13.79 million, which was later amended to $15.55 million by order dated May 6, 2014. KMBT has filed a notice of appeal of the judgment.

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Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al

On October 16, 2013, Plains Gas Solutions, LLC (Plains) filed a petition in the 151^st Judicial District Court for Harris County, Texas (Case No. 62528) against TGP, Kinetica Partners, LLC and two other Kinetica entities. The suit arises from the sale by TGP of the Cameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleges that defendants breached a straddle agreement requiring that gas on the Cameron System be committed to Plains’ Grand Chenier gas-processing facility, that requisite daily volume reports were not provided, that TGP improperly assigned its obligations under the straddle agreement to Kinetica, and that defendants interfered with Plains’ contracts with producers. The petition alleges damages of at least $100 million. Under the Amended and Restated Purchase and Sale Agreement with Kinetica, Kinetica has agreed to indemnify TGP in connection with the gas commitment and reporting claims. The suit was removed to federal court and Plains has filed a motion to remand. We intend to vigorously defend the suit.

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, 2014 and December 31, 2013, our total reserve for legal matters was $678 million and $611 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising from our products pipeline and natural gas pipeline transportation rates.

Other

Slotoroff v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc., et al

On February 5, 2014, a putative class action and derivative complaint was filed in the Court of Chancery in the State of Delaware (Case No. 9318) against defendants KMI, KMGP and nominal defendant KMEP. The suit was filed by Jon Slotoroff, a purported unitholder of KMEP, and seeks to assert claims both individually and on behalf of a putative class consisting of all public holders of KMEP units during the period of February 5, 2011 through the date of the filing of the suit. The suit alleges direct and derivative causes of action for breach of the partnership agreement, breach of the duty of good faith and fair dealing, aiding and abetting, and tortious interference. Among other things, the suit alleges that defendants made a bad faith allocation of capital expenditures to expansion capital expenditures rather than maintenance capital expenditures for the alleged purpose of “artificially” inflating KMEP’s distributions and growth rate. The suit seeks disgorgement of any distributions to KMGP, KMI and any related entities, beyond amounts that would have been distributed in accordance with a “good faith” allocation of maintenance capital expenses, together with other unspecified monetary damages including punitive damages and attorney fees. Defendants believe this suit is without merit and intend to defend it vigorously.

Burns et al v. Kinder Morgan, Inc. Kinder Morgan G.P., Inc. et al

On March 27, 2014, a putative class action and derivative complaint was filed in the Court of Chancery in the State of Delaware (Case No. 9479) against defendants KMI, KMGP and nominal defendant KMEP. The suit was filed by Darrell Burns and Terrence Zehrer, purported unitholders of KMEP, and seeks to assert claims both individually and on behalf of a putative class consisting of all public holders of KMEP units during the period of February 5, 2011 through the date of the filing of the suit. The suit asserts claims and allegations substantially similar to the suit filed by Jon Slotoroff described above. On April 8, 2014, the Court ordered that this suit be consolidated for all purposes with the suit filed by Jon Slotoroff described above and that the caption of the consolidated action shall be In Re Kinder Morgan Energy Partners, L.P. Derivative Litigation, Consolidated Case No. 9318.

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Walker v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al

On March 6, 2014, a putative class action and derivative complaint was filed in the District Court of Harris County, Texas (Case No. 2014-11872 in the 215th Judicial District) against KMI, KMGP, KMR, Richard D. Kinder, Steven J. Kean, Ted A. Gardner, Gary L. Hultquist, Perry M. Waughtal and nominal defendant KMEP. The suit was filed by Kenneth Walker, a purported unit holder of KMEP, and alleges direct and derivative causes of action for alleged violation of duties owed under the partnership agreement, breach of the implied covenant of good faith and fair dealing, “abuse of control” and “gross mismanagement” in connection with the calculation of distributions and allocation of capital expenditures to expansion capital expenditures and maintenance capital expenditures. The suit seeks unspecified money damages, interest, punitive damages, attorney and expert fees, costs and expenses, unspecified equitable relief, and demands a trial by jury. Defendants believe this suit is without merit and intend to defend it vigorously. By agreement of the parties, the case is stayed pending further resolution of the suit filed by Jon Slotoroff described above.

Environmental Matters

We are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and 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. 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, NGL, natural gas and CO₂.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

In December 2000, the EPA issued 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 (RI/FS) 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 process to conclude in 2015. We also expect the LWG to complete the RI/FS process in 2015, after which the EPA is expected to develop a proposed plan leading to a Record of Decision targeted for 2017. It is anticipated that the cleanup activities will begin within one year of the issuance of the Record of Decision.

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

The Roosevelt Irrigation District sued KMGP, KMEP and others under CERCLA for contamination of the water purveyor’s wells.  The First Amended Complaint sought $175 million in damages against approximately 70 defendants.  On August 6, 2013, plaintiffs filed their Second Amended Complaint seeking monetary damages in unspecified amounts and reducing the number of defendants to 26 including KMEP and SFPP. The claims now presented against KMEP and SFPP are related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. On October 24, 2013, we moved to dismiss this suit and the motion remains pending.

Paulsboro, New Jersey Liquids Terminal Consent Judgment

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 in Gloucester County, New Jersey against ExxonMobil and KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corporation from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC. The terminal is now owned by Plains Products, which was also joined as a party to the lawsuit. 

In mid-2011, KMLT and Plains Products entered into a settlement agreement and subsequent Consent Judgment with the NJDEP which resolved the state’s alleged natural resource damages 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 an 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. We are awaiting approval from the NJDEP in order to begin remediation activities.

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 U.S. 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.

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 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 U.S. Court of Appeals for the Ninth Circuit. The appeal is currently pending.

This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board (RWQCB).  SFPP has completed the soil and groundwater remediation at the City of San Diego’s stadium property site and will continue quarterly sampling and monitoring through 2014 as part of the compliance evaluation required by the RWQCB. SFPP's remediation effort is now focused on its adjacent Mission Valley Terminal site.

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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 RWQCB’s 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. SFPP and KMEP are coordinating with the RWQCB to oppose the City’s writ.

Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., an historical subsidiary of EPNG, operated approximately 20 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 U.S. 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 August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work, pursuant to which EPNG will conduct a radiological assessment of the surface of the mines.  We are also seeking contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given their pervasive control over all aspects of the nuclear weapons program.

PHMSA Inspection of Carteret Terminal, Carteret, New Jersey

On April 4, 2013, the PHMSA, Office of Pipeline Safety issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV) arising from an inspection at the KMLT, Carteret, New Jersey location on March 15, 2011, following a release and fire that occurred during maintenance activity on March 14, 2011. On July 17, 2013, KMLT entered into a Consent Agreement and Order with the PHMSA, pursuant to which KMLT paid a penalty of $63,100 and is required to complete ongoing pipeline integrity testing and other corrective measures by May 2015.

Southeast Louisiana Flood Protection Litigation

On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (SLFPA) filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP and approximately 100 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 SLFPA 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. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On September 10, 2013, the SLFPA filed a motion to remand the case to the state district court for Orleans Parish. The Court denied the remand motion on June 27, 2014. Louisiana Act 544 went into effect on June 6, 2014 and specified the political entities authorized to institute litigation for environmental damage in the coastal zone. Under the Act, which was specifically made retroactive, the SLFPA is not a valid plaintiff. Defendants intend to move to dismiss the suit under the Act among other grounds.

Plaquemines Parish Louisiana Coastal Zone Litigation

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana (Docket No. 60-999) against TGP and 17 other energy companies, alleging that defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. On December 18, 2013, defendants removed the case to the U.S. District Court for

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the Eastern District of Louisiana. On January 14, 2014, the plaintiff filed a motion to remand the case to state court and such motion remains pending.

Pennsylvania Department of Environmental Protection Notice of Alleged Violations

The Pennsylvania Department of Environmental Protection (PADEP) has notified TGP of alleged violations of certain conditions to the construction permits issued to TGP for the construction of TGP’s 300 Line Project in 2011. The alleged violations arise from field inspections performed during construction by county conservation districts, as delegates of the PADEP, and generally involve the alleged failure by TGP to implement and maintain best practices to achieve sufficient erosion and sediment controls, stabilization of the right of way, and prevention of potential discharge of sediment into the waters of the commonwealth during construction and before placing the line into service. To resolve such alleged violations, the PADEP initially proposed a collective penalty of approximately $1.5 million. TGP and the PADEP are seeking to reach a mutually agreeable resolution of the alleged notices of violations, including an agreed penalty amount.

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, 2014 and December 31, 2013, our total reserve for environmental liabilities was $161 million and $168 million, respectively.

10. Recent Accounting Pronouncements

Accounting Standards Updates-Adopted

None of the Accounting Standards Updates (ASU) that we adopted and that became effective January 1, 2014 (including 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)) had a material impact on our consolidated financial statements. More information about this ASU can be found in Note 17 “Recent Accounting Pronouncements” to our consolidated financial statements that were included in our 2013 Form 10-K.

ASU No. 2014-09

On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU is designed to create greater comparability for financial statement users across industries and jurisdictions. The provisions of ASU No. 2014-09 include a five-step process by which entities will recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which an entity expects to be entitled in exchange for those goods or services. The standard also will require enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. ASU No. 2014-09 will be effective for U.S. public companies for annual reporting periods beginning after December 15, 2016, including interim reporting periods (January 1, 2017 for us). Early adoption is not permitted. We are currently reviewing the effect of ASU No. 2014-09 on our revenue recognition.

11. Guarantee of Securities of Subsidiaries

KMEP has guaranteed the payment of Copano’s outstanding 7.125% senior notes due 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. Excluding fair value adjustments, as of June 30, 2014, Copano had $332 million 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. The prior periods presented herein have been retrospectively adjusted for a Copano reorganization that occurred on December 31, 2013.

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

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it receives from its respective subsidiaries. For purposes of the condensed consolidating financial information, distributions from our wholly-owned subsidiaries have been presented as operating cash flows whether or not distributions exceeded cumulative earnings. In addition, we utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the subsidiary issuers and non-guarantor subsidiaries. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities.

Included among the non-guarantor subsidiaries are KMEP’s five operating limited partnerships and their majority-owned and controlled subsidiaries, along with Copano’s remaining majority-owned and controlled subsidiaries. In the following unaudited condensed consolidating financial information, KMEP is “Parent Guarantor,” and Copano and Copano Finance Corp. are the “Subsidiary Issuers.” The Subsidiary Issuers are 100% owned by KMEP.

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months ended June 30, 2014 (In Millions) (Unaudited)
	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Total Revenues	$	—		$	—		$	3,577		$	—		$	3,577
Operating Costs, Expenses and Other
Costs of sales	—			—			1,602			—			1,602
Depreciation, depletion and amortization	—			—			406			—			406
Other operating expenses	—			8			706			—			714
Total Operating Costs, Expenses and Other	—			8			2,714			—			2,722
Operating (Loss) Income	—			(8		)	863			—			855
Other Income (Expense), Net	663			45			(160		)	(710		)	(162		)
Income Before Income Taxes	663			37			703			(710		)	693
Income Tax Expense	(2		)	—			(22		)	—			(24		)
Net Income	661			37			681			(710		)	669
Net Income Attributable to Noncontrolling Interests	—			—			(8		)	—			(8		)
Net Income Attributable to KMEP	$	661		$	37		$	673		$	(710	)	$	661
Net Income	$	661		$	37		$	681		$	(710	)	$	669
Total Other Comprehensive (Loss)	(25		)	—			(25		)	25			(25		)
Comprehensive Income	636			37			656			(685		)	644
Comprehensive Income Attributable to Noncontrolling Interests	—			—			(8		)	—			(8		)
Comprehensive Income Attributable to KMEP	$	636		$	37		$	648		$	(685	)	$	636

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Condensed Consolidating Statements of Income and Comprehensive Income  for the Three Months ended June 30, 2013 (In Millions) (Unaudited)
	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Total Revenues	$	—		$	—		$	3,017		$	—		$	3,017
Operating Costs, Expenses and Other
Costs of sales	—			—			1,248			—			1,248
Depreciation, depletion and amortization	—			2			355			—			357
Other operating expenses	—			26			785			—			811
Total Operating Costs, Expenses and Other	—			28			2,388			—			2,416
Operating (Loss) Income	—			(28		)	629			—			601
Other Income, Net	1,004			35			435			(1,039		)	435
Income Before Income Taxes	1,004			7			1,064			(1,039		)	1,036
Income Tax Expense	(4		)	—			(22		)	—			(26		)
Net Income	1,000			7			1,042			(1,039		)	1,010
Net Income Attributable to Noncontrolling Interests	—			—			(10		)	—			(10		)
Net Income Attributable to KMEP	$	1,000		$	7		$	1,032		$	(1,039	)	$	1,000
Net Income	$	1,000		$	7		$	1,042		$	(1,039	)	$	1,010
Total Other Comprehensive (Loss)	(4		)	—			(4		)	4			(4		)
Comprehensive Income	996			7			1,038			(1,035		)	1,006
Comprehensive Income Attributable to Noncontrolling Interests	—			—			(10		)	—			(10		)
Comprehensive Income Attributable to KMEP	$	996		$	7		$	1,028		$	(1,035	)	$	996

Condensed Consolidating Statements of Income and Comprehensive Income  for the Six Months ended June 30, 2014 (In Millions) (Unaudited)
	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Total Revenues	$	—		$	—		$	7,229		$	—		$	7,229
Operating Costs, Expenses and Other
Costs of sales	—			—			3,240			—			3,240
Depreciation, depletion and amortization	—			—			807			—			807
Other operating expenses	—			15			1,379			—			1,394
Total Operating Costs, Expenses and Other	—			15			5,426			—			5,441
Operating (Loss) Income	—			(15		)	1,803			—			1,788
Other Income (Expense), Net	1,412			78			(323		)	(1,492		)	(325		)
Income Before Income Taxes	1,412			63			1,480			(1,492		)	1,463
Income Tax Expense	(5		)	—			(35		)	—			(40		)
Net Income	1,407			63			1,445			(1,492		)	1,423
Net Income Attributable to Noncontrolling Interests	—			—			(16		)	—			(16		)
Net Income Attributable to KMEP	$	1,407		$	63		$	1,429		$	(1,492	)	$	1,407
Net Income	$	1,407		$	63		$	1,445		$	(1,492	)	$	1,423
Total Other Comprehensive (Loss)	(143		)	—			(144		)	143			(144		)
Comprehensive Income	1,264			63			1,301			(1,349		)	1,279
Comprehensive Income Attributable to Noncontrolling Interests	—			—			(15		)	—			(15		)
Comprehensive Income Attributable to KMEP	$	1,264		$	63		$	1,286		$	(1,349	)	$	1,264

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Condensed Consolidating Statements of Income and Comprehensive Income for the Six Months ended June 30, 2013 (In Millions) (Unaudited)
	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Total Revenues	$	—		$	—		$	5,678		$	—		$	5,678
Operating Costs, Expenses and Other
Costs of sales	—			—			2,205			—			2,205
Depreciation, depletion and amortization	—			2			683			—			685
Other operating expenses	—			26			1,377			—			1,403
Total Operating Costs, Expenses and Other	—			28			4,265			—			4,293
Operating (Loss) Income	—			(28		)	1,413			—			1,385
Other Income, Net	1,789			35			537			(1,815		)	546
Income from Continuing Operations Before Income Taxes	1,789			7			1,950			(1,815		)	1,931
Income Tax Expense	(6		)	—			(121		)	—			(127		)
Income from Continuing Operations	1,783			7			1,829			(1,815		)	1,804
Loss from Discontinued Operations	—			—			(2		)	—			(2		)
Net Income	1,783			7			1,827			(1,815		)	1,802
Net Income Attributable to Noncontrolling Interests	—			—			(19		)	—			(19		)
Net Income Attributable to KMEP	$	1,783		$	7		$	1,808		$	(1,815	)	$	1,783
Net Income	$	1,783		$	7		$	1,827		$	(1,815	)	$	1,802
Total Other Comprehensive (Loss)	(93		)	—			(94		)	93			(94		)
Comprehensive Income	1,690			7			1,733			(1,722		)	1,708
Comprehensive Income Attributable to Noncontrolling Interests	—			—			(18		)	—			(18		)
Comprehensive Income Attributable to KMEP	$	1,690		$	7		$	1,715		$	(1,722	)	$	1,690

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Condensed Consolidating Balance Sheets as of June 30, 2014 (In Millions) (Unaudited)
	Parent Guarantor		Subsidiary Issuers		Non-guarantor Subsidiaries		Eliminations			Consolidated KMP
ASSETS
Cash and cash equivalents	$	28	$	—	$	235	$	—		$	263
All other current assets	3,433		7		2,165		(3,348		)	2,257
Property, plant and equipment, net	—		15		29,270		—			29,285
Investments	—		—		2,193		—			2,193
Investments in subsidiaries	14,017		4,434		—		(18,451		)	—
Goodwill	—		920		5,801		—			6,721
Notes receivable from affiliates	18,279		—		—		(18,279		)	—
Other non-current assets	290		—		3,542		—			3,832
Total Assets	$	36,047	$	5,376	$	43,206	$	(40,078	)	$	44,551
LIABILITIES AND PARTNERS’ CAPITAL
Liabilities
Current portion of debt	$	1,337	$	—	$	—	$	—		$	1,337
All other current liabilities	355		137		6,057		(3,348		)	3,201
Total long-term debt	16,931		389		3,557		—			20,877
Notes payable to affiliates	—		765		17,514		(18,279		)	—
Deferred income taxes	—		2		295		—			297
Other long-term liabilities and deferred credits	107		2		945		—			1,054
Total Liabilities	18,730		1,295		28,368		(21,627		)	26,766
Partners’ Capital
Total KMEP Partners’ Capital	17,317		4,081		14,370		(18,451		)	17,317
Noncontrolling interests	—		—		468		—			468
Total Partners’ Capital	17,317		4,081		14,838		(18,451		)	17,785
Total Liabilities and Partners’ Capital	$	36,047	$	5,376	$	43,206	$	(40,078	)	$	44,551

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Condensed Consolidating Balance Sheets as of December 31, 2013 (In Millions)
	Parent Guarantor		Subsidiary Issuers		Non-guarantor Subsidiaries		Eliminations			Consolidated KMP
ASSETS
Cash and cash equivalents	$	10	$	1	$	393	$	—		$	404
All other current assets	3,071		13		2,151		(2,971		)	2,264
Property, plant and equipment, net	—		170		27,235		—			27,405
Investments	—		—		2,233		—			2,233
Investments in subsidiaries	13,931		4,430		—		(18,361		)	—
Goodwill	—		813		5,734		—			6,547
Notes receivable from affiliates	17,284		—		—		(17,284		)	—
Other non-current assets	233		—		3,678		—			3,911
Total Assets	$	34,529	$	5,427	$	41,424	$	(38,616	)	$	42,764
LIABILITIES AND PARTNERS’ CAPITAL
Liabilities
Current portion of debt	$	1,504	$	—	$	—	$	—		$	1,504
All other current liabilities	407		107		5,530		(2,971		)	3,073
Total long-term debt	15,644		393		3,587		—			19,624
Notes payable to affiliates	—		907		16,377		(17,284		)	—
Deferred income taxes	—		2		283		—			285
Other long-term liabilities and deferred credits	173		—		884		—			1,057
Total Liabilities	17,728		1,409		26,661		(20,255		)	25,543
Partners’ Capital
Total KMEP Partners’ Capital	16,801		4,018		14,343		(18,361		)	16,801
Noncontrolling interests	—		—		420		—			420
Total Partners’ Capital	16,801		4,018		14,763		(18,361		)	17,221
Total Liabilities and Partners’ Capital	$	34,529	$	5,427	$	41,424	$	(38,616	)	$	42,764

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Condensed Consolidating Statements of Cash Flow for the Six Months ended June 30, 2014 (In Millions) (Unaudited)
	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Cash Provided by (Used in) Operating Activities	$	1,723		$	(29	)	$	2,691		$	(2,136	)	$	2,249
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired	—			—			(993		)	—			(993		)
Capital expenditures	—			(47		)	(1,803		)	192			(1,658		)
Contributions to investments	—			—			(89		)	—			(89		)
Distributions from equity investments in excess of cumulative earnings	—			—			37			—			37
Funding (to) from affiliates	(1,571		)	72			420			1,079			—
Natural gas storage and natural gas and liquids line-fill	—			—			22			—			22
Sale, casualty and transfer of property, plant and equipment, investments and other net assets, net of removal costs	—			192			11			(192		)	11
Other, net	—			—			(5		)	—			(5		)
Net Cash (Used in) Provided by Investing Activities	(1,571		)	217			(2,400		)	1,079			(2,675		)
Cash Flows From Financing Activities
Issuance of debt	6,083			—			—			—			6,083
Payment of debt	(5,059		)	—			(1		)	—			(5,060		)
Debt issue costs	(11		)	—			—			—			(11		)
Funding (to) from affiliates	(392		)	(189		)	1,660			(1,079		)	—
Proceeds from issuance of common units	938			—			—			—			938
Proceeds from issuance of i-units	97			—			—			—			97
Contributions from noncontrolling interests	—			—			57			—			57
Distributions to partners and noncontrolling interests	(1,789		)	—			(2,160		)	2,136			(1,813		)
Other, net	(1		)	—			(1		)	—			(2		)
Net Cash (Used in) Provided by Financing Activities	(134		)	(189		)	(445		)	1,057			289
Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—			(4		)	—			(4		)
Net increase (decrease) in Cash and Cash Equivalents	18			(1		)	(158		)	—			(141		)
Cash and Cash Equivalents, beginning of period	10			1			393			—			404
Cash and Cash Equivalents, end of period	$	28		$	—		$	235		$	—		$	263

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Condensed Consolidating Statements of Cash Flow for the Six Months ended June 30, 2013 (In Millions) (Unaudited)
	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Cash Provided by Operating Activities	$	1,548		$	6		$	1,956		$	(1,768	)	$	1,742
Cash Flows From Investing Activities
Payment to KMI for March 2013 drop-down asset group	—			—			(994		)	—			(994		)
Acquisitions of assets and investments, net of cash acquired	—			5			(291		)	—			(286		)
Capital expenditures	—			(60		)	(1,208		)	—			(1,268		)
Proceeds from sale of investments in Express pipeline system	—			—			403			—			403
Contributions to investments	—			—			(93		)	—			(93		)
Distributions from equity investments in excess of cumulative earnings	—			—			36			—			36
Funding to affiliates	(3,690		)	(501		)	(1,234		)	5,425			—
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs	—			—			23			—			23
Other, net	5			—			—			—			5
Net Cash Used in Investing Activities	(3,685		)	(556		)	(3,358		)	5,425			(2,174		)
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 affiliates	832			1,214			3,379			(5,425		)	—
Proceeds from issuance of common units	834			—			—			—			834
Proceeds from issuance of i-units	73			—			—			—			73
Contributions from noncontrolling interests	—			—			99			—			99
Contributions from General Partner	38			—			—			—			38
Pre-acquisition contributions from KMI to March 2013 drop-down asset group	—			—			35			—			35
Distributions to partners and noncontrolling interests	(1,468		)	—			(1,787		)	1,768			(1,487		)
Net Cash Provided by Financing Activities	2,042			551			1,643			(3,657		)	579
Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—			(20		)	—			(20		)
Net (decrease) increase 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

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 2013 Form 10-K; and (iii) our management’s discussion and analysis of financial condition and results of operations included in our 2013 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, our financial statements reflect our March 2013 drop-down transaction as if such acquisition had taken place on the effective dates of common control. We accounted for the March 2013 drop-down transaction 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 includes the financial results of the March 2013 drop-down asset group for all periods subsequent to the effective dates of common control.

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Critical Accounting Policies and Estimates

Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of 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, 2014. Our goodwill impairment analysis performed as of 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 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 2013 Form 10-K.

Results of Operations

Non-GAAP Measures

The non-GAAP financial measures of (i) DCF before certain items, and (ii) segment earnings before DD&A; amortization of excess cost of equity investments; and certain items, are presented belowunder “—Distributable Cash Flow” and “—Consolidated Earnings Results,” respectively. Certain items are items that are required by GAAP to be reflected in net income, but typically either do not have a cash impact, or by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically.

Our non-GAAP measures described below should not be considered as an alternative to GAAP net income, operating income or any other GAAP measure. DCF before certain items, and segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider any of these non-GAAP measures in isolation or as a substitute for an analysis of our results as reported under GAAP. Because DCF before certain items excludes some but not all items that affect net income, and because DCF measures are defined differently by different companies in our industry, our DCF before certain items may not be comparable to DCF measures of other companies. Segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, has similar limitations. Our management compensates for the limitations of these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.

Distributable Cash Flow

As more fully described in our 2013 Form 10-K, we own and manage a diversified portfolio of energy transportation, production 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). For more information about our available cash and partnership distributions, see Note 11 “Related Party Transactions—Partnership Interests and Distributions” to our consolidated financial statements included in our 2013 Form 10-K.

DCF is an overall performance metric we use to estimate the ability of our assets to generate cash flows on an ongoing basis and as a measure of available cash. We believe the primary measure of company performance used by us, investors

39

and industry analysts covering MLPs is cash generation performance. Therefore, we believe DCF is an important measure to evaluate the operating and financial performance of the partnership and to compare it with the performance of other publicly traded MLPs within the industry. The following table discloses the calculation of our DCF for each of the three and six months ended June 30, 2014 and 2013 (calculated before the combined effect from all of the 2014 and 2013 certain items disclosed in the footnotes to the tables below):

Distributable Cash Flow
	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net Income	$	669		$	1,010		$	1,423		$	1,802
Add/(Less): Certain items - combined expense/(income)(a)	29			(383		)	63			(520		)
Net Income before certain items	698			627			1,486			1,282
Less: Net Income before certain items attributable to noncontrolling interests(b)	(9		)	(7		)	(17		)	(14		)
Net Income before certain items attributable to KMEP	689			620			1,469			1,268
Less: General Partner’s interest in Net Income before certain items(c)	(466		)	(418		)	(919		)	(819		)
Limited Partners’ interest in Net Income before certain items	223			202			550			449
Depreciation, depletion and amortization(d)(f)	431			379			857			717
Book (cash) taxes paid, net	(1		)	—			16			12
Incremental contributions from equity investments in the Express Pipeline and Endeavor Gathering LLC	7			(6		)	2			(5		)
Sustaining capital expenditures(e)(f)	(99		)	(70		)	(171		)	(118		)
Distributable cash flow before certain items	$	561		$	505		$	1,254		$	1,055

______________

(a) Consists of certain items summarized in footnotes (b) through (d) and (f) through (j) to the “—Results of Operations” table included below (and described in more detail below in both our management’s discussion and analysis of segment results and “—Other”).

(b) Equal to “Net income attributable to noncontrolling interests;” in addition, (i) three and six month 2014 amounts exclude a $1 million decrease in income attributable to our noncontrolling interests related to the combined effect from all of the three and six month 2014 certain items disclosed in the footnotes to the “—Results of Operations” table included below; and (ii) three and six month 2013 amounts exclude increases in income of $3 million and $5 million, respectively, in income attributable to our noncontrolling interests related to the combined effect from all of the three and six month 2013 certain items disclosed in footnotes (e) and (k) to the “—Results of Operations” tables included below.

(c) Amounts are net of waived incentive distributions of $33 million and $25 million for the three months ended June 30, 2014 and 2013, respectively, and $66 million and $29 million for the six months ended June 30, 2014 and 2013, respectively, related to certain acquisitions.

(d) Three and six month 2014 amounts include expense amounts of $20 million and $42 million, respectively, and three and six month 2013 amounts include expense amounts of $20 million and $47 million, respectively, for our proportionate share of the DD&A expenses of certain unconsolidated joint ventures. Six month 2013 amount also excludes a $19 million expense amount attributable to our March 2013 drop-down asset group for periods prior to our acquisition.

(e) Three and six month 2014 amounts include expenditures of $2 million and $3 million, respectively, and three and six month 2013 amounts each include expenditures of $1 million, for our proportionate share of the sustaining capital expenditures of certain unconsolidated joint ventures.

(f) In order to more closely track the cash distributions we receive from our unconsolidated joint ventures, our calculation of DCF (i) adds back our proportionate share of the DD&A expenses of certain joint ventures; and (ii) subtracts our proportionate share of the sustaining expenditures of the corresponding joint ventures (i.e. the same equity investees for which we add back DD&A as discussed in footnote (d)).

Consolidated Earnings Results

With regard to our reportable business segments, we consider segment earnings before all DD&A expenses, and amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. This measure, sometimes referred to in this report as segment EBDA, is more fully defined in footnote (a) to the “—Results of Operations” table below. 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. EBDA may not be comparable to measures used by other companies. Additionally, EBDA should be considered in

40

conjunction with net income and other performance measures such as operating income, income from continuing operations or operating cash flows.

Results of Operations
	Three Months Ended June 30,						Earnings increase/(decrease)
	2014			2013
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	639		$	1,123		$	(484	)	(43	)%
CO2	332			358			(26		)	(7	)%
Products Pipelines	203			12			191			1,592	%
Terminals	233			207			26			13	%
Kinder Morgan Canada	40			50			(10		)	(20	)%
Segment EBDA(b)	1,447			1,750			(303		)	(17	)%
DD&A expense	(406		)	(357		)	(49		)	(14	)%
Amortization of excess cost of equity investments	(5		)	(2		)	(3		)	(150	)%
General and administrative expense(c)	(132		)	(163		)	31			19	%
Interest expense, net of unallocable interest income(d)	(231		)	(215		)	(16		)	(7	)%
Unallocable income tax expense	(4		)	(3		)	(1		)	(33	)%
Income from continuing operations	669			1,010			(341		)	(34	)%
Net Income	669			1,010			(341		)	(34	)%
Net Income attributable to noncontrolling interests(e)	(8		)	(10		)	2			20	%
Net Income attributable to KMEP	$	661		$	1,000		$	(339	)	(34	)%

______________

Results of Operations
	Six Months Ended June 30,						Earnings increase/(decrease)
	2014			2013
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	1,358		$	1,680		$	(322	)	(19	)%
CO2	695			700			(5		)	(1	)%
Products Pipelines	411			197			214			109	%
Terminals	447			393			54			14	%
Kinder Morgan Canada	88			243			(155		)	(64	)%
Segment EBDA(f)	2,999			3,213			(214		)	(7	)%
DD&A expense(g)	(807		)	(685		)	(122		)	(18	)%
Amortization of excess cost of equity investments	(8		)	(4		)	(4		)	(100	)%
General and administrative expense(h)	(285		)	(297		)	12			4	%
Interest expense, net of unallocable interest income(i)	(470		)	(417		)	(53		)	(13	)%
Unallocable income tax expense	(6		)	(6		)	—			—	%
Income from continuing operations	1,423			1,804			(381		)	(21	)%
Loss from discontinued operations(j)	—			(2		)	2			100	%
Net Income	1,423			1,802			(379		)	(21	)%
Net Income attributable to noncontrolling interests(k)	(16		)	(19		)	3			16	%
Net Income attributable to KMEP	$	1,407		$	1,783		$	(376	)	(21	)%

______________

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

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Certain item footnotes

(b) 2014 and 2013 amounts include a decrease in earnings of $31 million and an increase in earnings of $413 million, respectively, related to the combined effect from all of the three month 2014 and 2013 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results.

(c) 2013 amount includes a $32 million increase in expense related to the combined effect from all of the three month 2013 certain items related to general and administrative expenses disclosed below in “—Other.”

(d) 2014 and 2013 amounts include a certain item that decreases interest expense by$2 million, and is associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition.

(e) 2014 and 2013 amounts include a$1 million decrease and a $3 million increase, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the three month 2014 and 2013 certain items disclosed below in both our management’s discussion and analysis of segment results and “—Other.”

(f) 2014 and 2013 amounts include a decrease in earnings of $48 million and an increase in earnings of $600 million, respectively, related to the combined effect from all of the six month 2014 and 2013 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results.

(g) 2013 amount includes a certain item resulting in a $19 million increase in expense attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.

(h) 2014 and 2013 amounts include increases in expense of$6 million and $46 million, respectively, related to the combined effect from all of the six month 2014 and 2013 certain items related to general and administrative expenses disclosed below in “—Other.”

(i) 2014 and 2013 amounts includes certain items that decrease interest expense by $4 million and $2 million, respectively, associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition. 2014 amount also includesa certain item $13 million increase in interest expense associated with a certain Pacific operations litigation matter. 2013 amount also includes a certain item $15 million increase in interest expense attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.

(j) 2013 amount represents an incremental loss related to the certain item sale of our FTC Natural Gas Pipelines disposal group effective November 1, 2012.

(k) 2014 and 2013 amounts include a$1 million decrease and a $5 million increase, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the six month 2014 and 2013 certain items disclosed below in both our management’s discussion and analysis of segment results and “—Other.”

For the comparable second quarter periods, the certain items described in footnote (b) to the tables above accounted for a$444 million decrease in EBDA in the second quarter of 2014, when compared to the second quarter of 2013 (combining to decrease total segment EBDA by $31 million in the second quarter of 2014 and increase total segment EBDA by $413 million in the second quarter of 2013). After taking into effect these certain items, the remaining$141 million (11%) quarter-to-quarter increase in EBDA was largely driven by better performance in the second quarter of 2014 from ourNatural Gas Pipelines, Terminals, Products Pipelines and CO₂ business segments.

For the comparable six month periods, the certain items described infootnote (f) to the tables above accounted for a $648 million decrease in EBDA in the first half of 2014, when compared to the first half of 2013 (combining todecrease total segment EBDA by$48 million in the first half of 2014 and increase total segment EBDA by $600 million in the first half of 2013). After taking into effect these certain items, the remaining$434 million (17%) period-to-period increase in EBDA was largely driven by better performance in the first six months of 2014 from ourNatural Gas Pipelines, Terminals, CO₂ and Products Pipelines business segments.

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Natural Gas Pipelines

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In millions, except operating statistics)
Revenues(a)	$	2,112		$	1,696		$	4,288		$	3,065
Operating expenses(b)	(1,509		)	(1,179		)	(3,010		)	(2,039		)
Other income (expense)	(1		)	—			3			—
Earnings from equity investments(c)	34			45			77			93
Interest income and Other, net(d)	6			564			6			565
Income tax expense	(3		)	(3		)	(6		)	(4		)
EBDA from continuing operations	639			1,123			1,358			1,680
Discontinued operations(e)	—			—			—			(2		)
Certain items, net(a)(b)(c)(d)(e)	3			(557		)	7			(615		)
EBDA before certain items	$	642		$	566		$	1,365		$	1,063
Change from prior period	Increase/(Decrease)
Revenues before certain items(a)	$	418		25		%	$	1,340		45		%
EBDA before certain items	$	76		13		%	$	302		28		%
Natural gas transport volumes (BBtu/d)(f)	16,948			15,555			17,441			16,310
Natural gas sales volumes (BBtu/d)(g)	2,208			2,417			2,231			2,387
Natural gas gathering volumes (BBtu/d)(h)	3,090			3,060			2,981			2,975

______________

Certain item footnotes

(a) Three and six month 2014 amounts include decreases in revenues of $3 million and$7 million, respectively, and three and six month 2013 amounts each include a decrease in revenues of $1 million from other certain items. Six month 2013 amount also includes an increase in revenues of $111 million attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.

(b) Six month 2013 amount includes an increase in expense of $30 million attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date, and a $1 million increase in expense from other certain items.

(c) Six month 2013 amount includes a decrease in earnings of $19 million attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date, and a $1 million decrease in earnings from other certain items.

(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) Six month 2013 amount represents an incremental loss from the sale of our FTC Natural Gas Pipelines disposal group’s net assets.

Other footnotes

(f) Includes 100% of pipeline volumes for our wholly-owned assets as well as our joint venture assets as if they were wholly-owned for all periods presented. Volumes for acquired pipelines are included for all periods.

(g) Represents volumes for the Texas intrastate natural gas pipeline group.

(h) Includes 100% of gas gathering volumes for our wholly-owned assets. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods.

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Following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013:

Three months ended June 30, 2014 versus Three months ended June 30, 2013
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
TGP	$	41		22	%	$	44		18	%
Copano operations (excluding Eagle Ford)	31			n/a		279			n/a
Eagle Ford(a)	6			n/a		91			n/a
EP midstream asset operations	5			28	%	13			32	%
EPNG	2			2	%	10			7	%
Kinder Morgan treating operations	(5		)	(29	)%	(10		)	(35	)%
Texas Intrastate Natural Gas Pipeline Group	(1		)	(3	)%	29			3	%
All others (including eliminations)	(3		)	(3	)%	(38		)	(610	)%
Total Natural Gas Pipelines	$	76		13	%	$	418		25	%

______________

Six months ended June 30, 2014 versus Six months ended June 30, 2013
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Copano operations (excluding Eagle Ford)	$	111		n/a		$	742		n/a
TGP	76			19	%	83			16	%
EPNG	58			42	%	107			62	%
Eagle Ford(a)	30			n/a		236			n/a
Texas Intrastate Natural Gas Pipeline Group	18			11	%	302			17	%
EP midstream asset operations	17			56	%	50			93	%
Kinder Morgan treating operations	(7		)	(25	)%	(24		)	(40	)%
All others (including eliminations)	(1		)	—	%	(156		)	(215	)%
Total Natural Gas Pipelines	$	302		28	%	$	1,340		45	%

______________

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 our share of depreciation and amortization expenses less our share of sustaining capital expenditures.

The primary increases and decreases in our Natural Gas Pipelines business segment’s EBDA in the comparable three and six month periods of 2014 and 2013 included the following:

▪ increases of $41 million (22%) and $76 million (19%), respectively, from TGP primarily due to higher revenues from (i) firm transportation and storage, due largely to new projects placed in service in the latter part of 2013 and new southbound capacity contracts; (ii) usage and interruptible transportation services due to both weather-related increases and higher short-haul volumes; and (iii) natural gas park and loan customer services due also primarily to colder winter weather relative to the first half of 2013;

▪ incremental earnings of $31 million and $111 million, respectively, from our Copano operations 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 previously owned);

▪ incremental earnings of $6 million and $30 million, 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, and to higher natural gas gathering volumes from the Eagle Ford shale formation;

▪ increases of $5 million (28%) and $17 million (56%), respectively, from our EP midstream assets, due largely to higher gathering revenues from increased drilling from both the Altamont gathering system in Utah and the Camino Real gathering system in South Texas, and for the comparable six month periods, by our acquisition from KMI effective March 1, 2013 of the remaining 50% interest we did not already own;

44

▪ increases of $2 million (2%) and $58 million (42%), respectively, from EPNG, due largely to higher transport revenues, and for the comparable six month periods, to our acquisition of the remaining 50% interest we did not already own from KMI effective March 1, 2013;

▪ decreases of $5 million (29%) and $7 million (25%), respectively, from our Kinder Morgan treating operations, due largely to reduced activity at SouthTex Treaters (our manufacturing facility); and

▪ a decrease of $1 million (3%) and an increase of $18 million (11%), respectively, from our Texas intrastate natural gas pipeline group, due largely to higher maintenance costs in the second quarter of 2014, and for the comparable six month periods, to higher natural gas sales, transportation and storage margins, all driven in part by colder weather in the first quarter of 2014.

CO₂ 

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In millions, except operating statistics)
Revenues(a)	$	454		$	460		$	937		$	889
Operating expenses	(127		)	(107		)	(252		)	(199		)
Earnings from equity investments	7			7			14			13
Income tax expense	(2		)	(2		)	(4		)	(3		)
EBDA	332			358			695			700
Certain items(a)	28			(7		)	31			(9		)
EBDA before certain items	$	360		$	351		$	726		$	691
Change from prior period	Increase/(Decrease)
Revenues before certain items(a)	$	29		6		%	$	88		10		%
EBDA before certain items	$	9		3		%	$	35		5		%
Southwest Colorado CO2 production (gross) (Bcf/d)(b)	1.3			1.2			1.3			1.2
Southwest Colorado CO2 production (net) (Bcf/d)(b)	0.5			0.5			0.5			0.5
SACROC oil production (gross)(MBbl/d)(c)	32.2			30.0			32.0			30.4
SACROC oil production (net)(MBbl/d)(d)	26.8			25.0			26.6			25.3
Yates oil production (gross)(MBbl/d)(c)	19.6			20.7			19.6			20.6
Yates oil production (net)(MBbl/d)(d)	8.5			9.2			8.6			9.1
Katz oil production (gross)(MBbl/d)(c)	3.8			2.5			3.7			2.3
Katz oil production (net)(MBbl/d)(d)	3.2			2.1			3.0			1.9
Goldsmith oil production (gross)(MBbl/d)(c)	1.3			0.4			1.2			0.2
Goldsmith oil production (net)(MBbl/d)(d)	1.1			0.4			1.1			0.2
NGL sales volumes (net)(MBbl/d)(d)	9.9			9.6			9.9			9.9
Realized weighted average oil price per Bbl(e)	$	88.83		$	94.20		$	90.35		$	90.55
Realized weighted average NGL price per Bbl(f)	$	45.71		$	44.17		$	47.56		$	45.36

______________

n/a – not applicable

Certain item footnote

(a) Three and six month 2014 amounts include unrealized losses of $28 million and $31 million, respectively, and three and six month 2013 amounts include unrealized gains of $7 million and $9 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales.

Other footnotes

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

(c) 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, an approximately 99% working interest in the Katz Strawn unit and a 100% working interest in the Goldsmith Landreth unit.

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

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

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

45

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 NGL.We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and its Source and Transportation Activities, and for each of these two primary businesses, following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013:

Three months ended June 30, 2014 versus Three months ended June 30, 2013
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Source and Transportation Activities	$	21		23	%	$	23		22	%
Oil and Gas Producing Activities	(12		)	(4	)%	11			3	%
Intrasegment eliminations	—			—	%	(5		)	(30	)%
Total CO2	$	9		3	%	$	29		6	%

______________

Six months ended June 30, 2014 versus Six months ended June 30, 2013
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Source and Transportation Activities	$	41		22	%	$	49		24	%
Oil and Gas Producing Activities	(6		)	(1	)%	49			7	%
Intrasegment eliminations	—			—	%	(10		)	(30	)%
Total CO2	$	35		5	%	$	88		10	%

The primary increases and decreases in our CO₂ segment’s source and transportation activities in the comparable three and six month periods of 2014 and 2013 included the following:

▪ EBDA increases of $21 million (23%) and $41 million (22%), respectively, driven primarily by higher revenues (described following), somewhat offset by higher labor costs, power costs and property taxes.

▪ revenue increases of $23 million (22%) and $49 million (24%), respectively, driven primarily byincreases of 14% and 16%, respectively, in average CO₂ sales prices. The increases in sales prices were due primarily to two factors: (i) a change in the mix of contracts resulting in more CO₂ being delivered under higher price contracts; and (ii) heavier weighting of new CO₂ contract prices to the price of crude oil. CO₂ sales volumes were also higher by 13% and 14%, respectively, when compared to the same two periods in 2013, primarily due to expansion projects at our Doe Canyon field which went in service in the fourth quarter of 2013.

The primary increases and decreases in our CO₂ segment’s oil and gas producing activities, which include the operations associated with the segment’s ownership interests in oil-producing fields and natural gas processing plants, in the comparable three and six month periods of 2014 and 2013 included the following:

▪ EBDA decreases of $12 million (4%) and $6 million (1%), respectively, driven by higher operating expenses as a result of incremental well work over costs at our recently acquired Goldsmith Landreth unit.  Power costs increased primarily due to increased production at SACROC and higher power prices along with the incremental power required at the Goldsmith Landreth unit. In addition, operating expenses increased due to higher property taxes and severance taxes related to the increases in revenue (described following).

▪ revenue increases of $11 million (3%) and $49 million (7%), respectively, driven primarily byan increase of 8% and 8%, respectively, in crude oil volumes. The increases in sales volumes were due primarily to higher production at the Katz field unit, incremental production from the Goldsmith Landreth unit (acquired effective June 1, 2013), and higher production at the SACROC unit (volumes presented in the results of operations table above). The increases in revenues from productions were offset somewhat in the second quarter by a decrease in weighted average prices of 5%.

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Products Pipelines

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In millions, except operating statistics)
Revenues	$	524		$	443		$	1,058		$	897
Operating expenses(a)	(333		)	(439		)	(672		)	(720		)
Other income (expense)(b)	(1		)	(5		)	2			(5		)
Earnings from equity investments	18			17			35			35
Interest income and Other, net	—			2			(1		)	2
Income tax expense	(5		)	(6		)	(11		)	(12		)
EBDA	203			12			411			197
Certain items, net(a)(b)	6			167			2			182
EBDA before certain items	$	209		$	179		$	413		$	379
Change from prior period	Increase/(Decrease)
Revenues	$	81		18		%	$	161		18		%
EBDA before certain items	$	30		17		%	$	34		9		%
Gasoline (MMBbl)(c)	112.8			105.6			215.7			203.4
Diesel fuel (MMBbl)	38.8			36.8			74.6			69.6
Jet fuel (MMBbl)	29.4			27.7			56.8			54.9
Total refined product volumes (MMBbl)(d)	181.0			170.1			347.1			327.9
NGL (MMBbl)(e)	6.2			8.0			14.9			17.8
Condensate (MMBbl)(f)	7.8			2.6			12.4			4.6
Total delivery volumes (MMBbl)	195.0			180.7			374.4			350.3
Ethanol (MMBbl)(g)	10.4			9.7			20.1			18.4

______________

Certain item footnotes

(a) Three and six month 2014 amounts include increases in expense of $5 million and $4 million, respectively, associated with a certain Pacific operations litigation matter. Three and six month 2013 amounts include a $162 million increase in operations and maintenance expense associated with certain rate case liability adjustments. Six month 2013 amount also includes a $15 million increase in expense associated with a rate case liability adjustment related to a certain West Coast terminal environmental matter.

(b) Three and six month 2014 amounts include a loss of $1 million and a gain of $2 million, respectively, from the sale of propane pipeline line-fill. Three and six month 2013 amounts represent the loss from the write-off of assets at our Los Angeles Harbor West Coast terminal.

Other footnotes

(c) Volumes include ethanol pipeline volumes.

(d) Includes Pacific, Plantation Pipe Line Company, Calnev, Central Florida and Parkway pipeline volumes.

(e) Includes Cochin and Cypress pipeline volumes.

(f) Includes Kinder Morgan Crude & Condensate and Double Eagle pipeline volumes.

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

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Following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013:

Three months ended June 30, 2014 versus Three months ended June 30, 2013
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Crude & Condensate Pipeline	$	14		699	%	$	19		417	%
Pacific operations	13			20	%	12			12	%
Transmix operations	9			176	%	56			26	%
Southeast terminal operations	3			16	%	1			5	%
Cochin Pipeline	(9		)	(52	)%	(8		)	(38	)%
All others (including eliminations)	—			—	%	1			2	%
Total Products Pipelines	$	30		17	%	$	81		18	%

______________

Six months ended June 30, 2014 versus Six months ended June 30, 2013
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Crude & Condensate Pipeline	$	19		289	%	$	42		435	%
Transmix operations	12			64	%	107			24	%
Pacific operations	10			8	%	14			7	%
Southeast terminal operations	5			14	%	6			11	%
Cochin Pipeline	(14		)	(30	)%	(14		)	(26	)%
All others (including eliminations)	2			1	%	6			5	%
Total Products Pipelines	$	34		9	%	$	161		18	%

The primary increases and decreases in our Products Pipelines business segment’s EBDA in the comparable three and six month periods of 2014 and 2013 included the following:

▪ increases of $14 million (699%) and $19 million (289%), respectively, from our Kinder Morgan Crude Oil & Condensate Pipeline, due mainly to increases of 199% and 128%, respectively, in higher pipeline throughput volumes as the facility comes closer to capacity;

▪ increases of $13 million (20%) and $10 million (8%), respectively, from our Pacific operations, due primarily to higher volumes and margins and higher physical gains;

▪ increases of $9 million (176%) and $12 million (64%), respectively, from our transmix processing operations, due to higher volumes and margins at various transmix sales plants;

▪ increases of $3 million (16%) and $5 million (14%), respectively, from our Southeast terminal operations, driven by higher butane blending revenues; and

▪ decreases of $9 million (52%) and $14 million (30%), respectively, from our Cochin Pipeline, primarily due to lower terminal, storage and petrochemical volumes and associated revenues, as a result of the Cochin Reversal project, which converted the line to northbound condensate service to serve oilsands producers’ needs in western Canada.

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Terminals

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In millions, except operating statistics)
Revenues(a)	$	421		$	344		$	812		$	681
Operating expenses(b)	(190		)	(169		)	(373		)	(326		)
Other income (expense)(c)	(1		)	29			(2		)	29
Earnings from equity investments	6			5			11			12
Interest income and Other, net(d)	4			1			5			2
Income tax expense(e)	(7		)	(3		)	(6		)	(5		)
EBDA	233			207			447			393
Certain items, net(a)(b)(c)(d)(e)	(6		)	(16		)	8			(15		)
EBDA before certain items	$	227		$	191		$	455		$	378
Change from prior period	Increase/(Decrease)
Revenues before certain items(a)	$	69		20		%	$	123		18		%
EBDA before certain items	$	36		19		%	$	77		20		%
Bulk transload tonnage (MMtons)(f)	22.4			22.0			44.0			44.4
Ethanol (MMBbl)	18.6			15.6			35.1			30.8
Liquids leaseable capacity (MMBbl)	72.1			62.1			72.1			62.1
Liquids utilization %(g)	94.8		%	94.5		%	94.8		%	94.5		%

______________

Certain item footnotes

(a) Three and six month 2014 amounts include an $8 million increase in revenues from amortization of deferred credits from our APT acquisition. The amortization is related to the valuation of certain customer contracts at fair value in purchase accounting. We are amortizing these deferred credits as noncash adjustments (increases) to revenue over the remaining contract period.

(b) Three and six month 2014 amounts include increases in expense of $1 million and$8 million, respectively, and three and six month 2013 amounts include increases in expense of $13 million and$14 million, respectively, all related to hurricane clean-up and repair activities at our New York Harbor and Mid-Atlantic terminals. Three and six month 2014 amounts also include increases in expense of $2 million and$12 million, respectively, primarily associated with a legal liability adjustment related to a certain litigation matter.

(c) Six month 2014 amount includes a $1 million casualty indemnification loss, and three and six month 2013 amounts include a $28 million casualty indemnification gain, all related to 2012 hurricane activity at our New York Harbor and Mid-Atlantic terminals.

(d) 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.

(e) Three and six month 2014 amounts include decreases in expense (representing tax savings) of $1 million and$5 million, respectively, related to the pre-tax expense amount associated with the litigation matter described in footnote (b).

Other footnotes

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

(g) The ratio of our actual leased capacity (excluding the capacity of tanks out of service) to our estimated potential capacity.

49

Our Terminals business segment includes the transportation, transloading and storing of refined petroleum products, crude oil, condensate (other than those included in our Products Pipelines segment), and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals. Following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013:

Three months ended June 30, 2014 versus Three months ended June 30, 2013
	EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)
Acquired assets and businesses	$	16	n/a		$	28	n/a
Gulf Central	7		210	%	12		997	%
West	6		42	%	10		33	%
Gulf Liquids	3		4	%	3		4	%
Gulf Bulk	1		4	%	3		9	%
All others (including intrasegment eliminations and unallocated income tax expenses)	3		3	%	13		6	%
Total Terminals	$	36	19	%	$	69	20	%

______________

Six months ended June 30, 2014 versus Six months ended June 30, 2013
	EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)
Acquired assets and businesses	$	29	n/a		$	50	n/a
West	13		39	%	20		32	%
Gulf Liquids	12		12	%	11		8	%
Gulf Central	11		162	%	21		994	%
Gulf Bulk	6		18	%	10		15	%
All others (including intrasegment eliminations and unallocated income tax expenses)	6		3	%	11		3	%
Total Terminals	$	77	20	%	$	123	18	%

The primary increases and decreases in our Terminals business segment’s EBDA in the comparable three and six month periods of 2014 and 2013 included the following:

▪ increases $16 million and $29 million, respectively, from acquired assets and businesses, primarily the marine operations we acquired effective January 17, 2014 (our APT acquisition);

▪ increases of $7 million (210%) and $11 million (162%), respectively, from our Gulf Central terminals, driven by higher earnings from our approximately 55%-owned BOSTCO oil terminal joint venture, which is located on the Houston Ship Channel and began operations in October 2013;

▪ increases of $6 million (42%) and $13 million (39%), respectively, from our West region terminals, driven by the completion of expansion projects since the end of the second quarter of 2013;

▪ increases of $3 million (4%) and $12 million (12%), respectively, from our Gulf Liquids terminals, due to higher liquids warehousing revenues from our Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services and new and incremental customer agreements at higher rates, including new tankage from completed expansion projects since the end of the second quarter of 2013; and

▪ increases of $1 million (4%) and $6 million (18%), respectively, from our Gulf Bulk terminals, driven by higher volumes in 2014, due in large part to refinery and coker shutdowns in 2013 as a result of turnarounds taken.

50

Kinder Morgan Canada

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In millions, except operating statistics)
Revenues	$	68		$	75		$	137		$	147
Operating expenses	(24		)	(27		)	(48		)	(52		)
Earnings from equity investments	—			—			—			4
Interest income and Other, net(a)	(1		)	11			6			241
Income tax expense(b)	(3		)	(9		)	(7		)	(97		)
EBDA	40			50			88			243
Certain items, net(a)(b)	—			—			—			(141		)
EBDA before certain items	$	40		$	50		$	88		$	102
Change from prior period	Increase/(Decrease)
Revenues	$	(7	)	(9		)%	$	(10	)	(7		)%
EBDA before certain items	$	(10	)	(20		)%	$	(14	)	(14		)%
Transport volumes (MMBbl)(c)	27.0			26.8			51.9			53.6

______________

Certain item footnotes

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

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

Other footnote

(c) Represents Trans Mountain pipeline system volumes.

Our Kinder Morgan Canada business segment includes the operations of our Trans Mountain and Jet Fuel pipeline systems, and until March 14, 2013, the effective date of sale, our one-third ownership interest in the Express pipeline system. Following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013:

Three months ended June 30, 2014 versus Three months ended June 30, 2013
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Express Pipeline(a)	$	(11	)	(194	)%	n/a			n/a
Trans Mountain Pipeline	1			1	%	$	(7	)	(9	)%
Total Kinder Morgan Canada	$	(10	)	(20	)%	$	(7	)	(9	)%

______________

Six months ended June 30, 2014 versus Six months ended June 30, 2013
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Express Pipeline(a)	$	(11	)	(103	)%	n/a			n/a
Trans Mountain Pipeline	(3		)	(4	)%	$	(10	)	(7	)%
Total Kinder Morgan Canada	$	(14	)	(14	)%	$	(10	)	(7	)%

______________

(a) Amount consists of foreign currency losses, net of tax, on outstanding, short-term intercompany borrowings.

The increase of $1 million (1%) for the comparable quarterly periods from Trans Mountain’s earnings was due to minor changes in volumes. The decrease of $3 million (4%) for the comparable six month periods from Trans Mountain’s earnings was driven by an unfavorable impact from foreign currency translation. Due to the weakening of the Canadian

51

dollar since the end of the second quarter of 2013, we translated Canadian denominated income and expense amounts into fewer U.S. dollars in 2014.

Other

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(In millions)
General and administrative expenses(a)	$	132	$	163	$	285	$	297
Interest expense, net of unallocable interest income(b)	$	231	$	215	$	470	$	417
Unallocable income tax expense	$	4	$	3	$	6	$	6
Net income attributable to noncontrolling interests(c)	$	8	$	10	$	16	$	19

______________

Certain item footnotes

(a) The three month amount for 2013 includes certain items of $32 million. The six month amounts for 2014 and 2013 include certain items of $6 million and $46 million, respectively. These increases in expense from certain items are primarily related to severance expense allocated to us from KMI (associated with both our March 2013 asset drop-down group and assets we acquired from KMI in August 2012), and for 2013, to both business acquisition expenses and increases in expense attributable to our drop-down asset groups for periods prior to our acquisition dates.

(b) The three month amounts for 2014 and 2013 each are decreased by certain items of $2 million, associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition. The six month amounts for 2014 and 2013 include certain items of $9 million and $13 million, respectively. The six month 2014 certain item amount primarily related to incremental interest expense associated with a certain Pacific operations litigation matter, and the six month 2013 certain item amount was largely related to incremental interest expense attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.

(c) Three and six month 2014 amounts include a $1 million decrease, and three and six month 2013 amounts include increases of $3 million and $5 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the three and six month 2014 and 2013 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, 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 to evaluate 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, 2014, the certain items described in footnote (a) to the table above accounted for decreases of $32 million and $40 million, respectively, in our general and administrative expenses, when compared to the same two periods a year ago. The remaining $1 million (1%) and $28 million (11%) period-to-period increases in expense were largely driven bythe acquisition of additional businesses, associated primarily with our acquisition of both Copano (effective May 1, 2013) and the March 2013 drop-down asset group from KMI (effective March 1, 2013). Additional drivers were increased benefits costs and higher segment labor expenses.

In the table above, 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 $16 million (7%) and $57 million (14%), respectively, in the second quarter and first six months of 2014, when compared to the same year-earlier periods. The increases were driven by higher average debt levels.

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, 2014 and December 31, 2013, approximately28% and 29%,

52

respectively, of our consolidated debt balances (excluding 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.

Financial Condition

General

As of June 30, 2014, we had $263 million of “Cash and cash equivalents” on our consolidated balance sheet, a decrease of$141 million (35%) from December 31, 2013. We also had, as of June 30, 2014, approximately$1.8 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, 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), proceeds from divestitures, 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 with proceeds from divestitures, 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.” Cash provided from our operations is fairly stable across periods since a majority of our cash generated is fee based from a diversified portfolio of assets and is not sensitive to commodity prices. However, in our CO₂ business segment, while we hedge the majority of our oil production, we do have exposure to unhedged volumes, a significant portion of which are NGL.

Short-term Liquidity

As of June 30, 2014, 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; (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, 2014 and December 31, 2013, we had no outstanding credit facility borrowings.

Our outstanding short-term debt as of June 30, 2014 was $1,337 million, primarily consisting of (i)$513 million of outstanding commercial paper borrowings; (ii) $500 million in principal amount of 5.125% senior notes that mature November 15, 2014; and (iii) $300 million in principal amount of 5.625% senior notes that mature February 15, 2015. 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. As of December 31, 2013, our short-term debt totaled $1,504 million.

We had a working capital deficit of$2,018 million as of June 30, 2014, and a working capital deficit of $1,909 million as of December 31, 2013.  The overall$109 million (6%) unfavorable change from year-end 2013 was primarily due to both lower cash balances (described above) and higher “Other current liabilities,” and partly offset by lower outstanding short-term debt (described above, and driven by lower commercial paper borrowings). The period-to-period increase in current liabilities was due largely to higher fair values on short-term commodity hedging derivative contract liabilities and

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to higher short-term legal and litigation 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). For more information about our equity issuances in the first half of 2014, see Note 4 “Partners’ Capital—Equity Issuances” to our consolidated financial statements.

From time to time, we issue long-term debt securities, often referred to as our senior notes. Our senior notes issued to date, 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. 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, 2014 and December 31, 2013, the aggregate principal amount of the various series of our senior notes was$17,100 million and $15,600 million, respectively.

In addition, from time to time, our subsidiaries have issued long-term debt securities, often referred to as their senior notes. Most of the debt of our operating partnerships and subsidiaries is unsecured; however, a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries. As of June 30, 2014 and December 31, 2013, the total liability balance due on the various borrowings of our operating partnerships and subsidiaries (including senior notes) was$3,334 million and$3,335 million, respectively.

To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt-related transactions in the first half of 2014 and our consolidated debt obligations as of both June 30, 2014 and December 31, 2013, see Note 3 “Debt” to our consolidated financial statements. For additional information regarding our debt securities, see Note 8 “Debt” to our consolidated financial statements included in our 2013 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.

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. Capital expenditures under our partnership agreement include those that are maintenance/sustaining capital expenditures and those that are capital additions and improvements (which we refer to as expansion or discretionary capital expenditures). These distinctions are used when determining cash from operations pursuant to our partnership agreement (which is distinct from GAAP cash flows from operating activities). Capital additions and improvements are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating cash from operations. With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e. production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those which maintain throughput or capacity. Thus, under our partnership agreement, the distinction between maintenance capital expenditures and capital additions and improvements is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.

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Budgeting of maintenance capital expenditures is done annually on a bottom up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of capital additions and improvements are generally made periodically throughout the year on a project by project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures.

Generally, the determination of whether a capital expenditure is classified as maintenance or as capital additions and improvements is made on a project level. The classification of capital expenditures as capital additions and improvements or as maintenance capital expenditures under our partnership agreement is left to the good faith determination of the general partner, which is deemed conclusive.

Our capital expenditures for the six months ended June 30, 2014, and the amount we expect to spend for the remainder of 2014 to grow and sustain our businesses are as follows:

	Six Months Ended June 30, 2014		2014 Remaining		Total
	(In millions)
Sustaining(a)	$	171	$	271	$	442
Discretionary(b)(c)	1,484		2,471		3,955
Total	$	1,655	$	2,742	$	4,397

______________

(a) Six month 2014 amount, 2014 remaining amount, and total 2014 amount include $3 million, $3 million and $6 million, respectively, for our proportionate share of sustaining capital expenditures of our unconsolidated joint ventures.

(b) Six month 2014 amount (i) includes $117 million of discretionary capital expenditures of our unconsolidated joint ventures and acquisitions; and (ii) excludes a combined $123 million net change from accrued capital expenditures, contractor retainage and amounts primarily related to contributions from our noncontrolling interests to fund a portion of certain capital projects.

(c) 2014 remaining amount includes our contributions to certain unconsolidated joint ventures and small acquisitions, net of contributions estimated from unaffiliated joint venture partners for consolidated investments.

We generally fund our sustaining capital expenditures with existing cash or from cash flows from operations. Generally, we initially fund our discretionary 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 replace the initial funding with long-term debt, equity (including retained cash related to i-unit distributions), or both.

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, andfor each of the six months ended June 30, 2014 and 2013, these amounts totaled $1,658 million and $1,268 million, respectively. The overall$390 million(31%) period-to-period increase in our consolidated capital expenditures in the first half of 2014 versus the first half of 2013 was primarily due to higher investment undertaken to expand and improve ourProducts Pipelines business segment. However, all five of our business segments reported higher capital expenditures in the first six months of 2014, when compared to the same period in 2013.

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 MBbl/d of crude oil and refined petroleum products to approximately 890 MBbl/d. In December 2013, we filed a Facilities Application with the NEB seeking authorization to build and operate the necessary facilities for the proposed expansion project. The NEB issued a hearing order for the proposed project in July 2014, and we expect an NEB decision in January 2016. If approvals are received as planned, we expect to begin construction in 2016 and begin operations in 2018. Failure to secure NEB approval on reasonable terms could require us to either delay or cancel this project. Our current estimate of total construction costs on the project is approximately $5.4 billion.

In March 2014, we announced that we will build and operate a new, 213-mile, 16-inch diameter pipeline in Torrance County, New Mexico to transport carbon dioxide from our St. Johns source field (located in Apache County, Arizona) to

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our 50%-owned Cortez Pipeline (which we operate). The new Lobos Pipeline will have an initial capacity of 300 million standard cubic feet per day and will support current and future enhanced oil recovery projects owned by us and other operators in the Permian Basin of West Texas and eastern New Mexico. We plan to invest approximately $300 million in the pipeline and an additional $700 million to drill wells and build field gathering, treatment and compression facilities at the St. Johns field. We expect to place the project into service by the third quarter of 2016, pending receipt of environmental and regulatory approvals.

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.

Our ability to expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such expansions. As an 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.

Off Balance Sheet Arrangements

Except as set forth below, 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, 2013 in our 2013 Form 10-K.

As described in Note 8 “Related Party Transactions—Other Commitments,” one of our wholly owned subsidiaries is committed to contribute $175 million to one of our unconsolidated subsidiaries during 2014.

Cash Flows

Operating Activities

Net cash provided by operating activities was $2,249 million for the first half of 2014, versus $1,742 million in the first half of 2013. The period-to-period increase of $507 million (29%) in cash flow from operations consisted of the following:

▪ a $389 million increase in cash from overall higher partnership income—after adjusting our period-to-period$379 million decrease in net income (discussed above in “—Results of Operations”) for the following four non-cash items: (i) a $558 million increase from the 2013 gain on the remeasurement of our previous 50% equity investment in Eagle Ford Gathering to its fair value; (ii) a $225 million increase from the 2013 gain on the sale of our investments in Express (see the discussion of these investments in Note 2 “Acquisitions and Divestitures” to our consolidated financial statements); (iii) a $126 million increase due to higher DD&A expenses (including amortization of excess cost of equity investments); and (iv) a $141 million decrease from expenses associated with adjustments to accrued legal liabilities, primarily related to incremental adjustments recorded in the first half of 2013 related to both our West Coast Products Pipelines’ interstate and California intrastate transportation rate case liabilities and our West Coast terminals’ legal liabilities;

▪ a $160 million increase in cash due to favorable changes in the collection and payment of trade and related party receivables and payables, due primarily to the timing of invoices received from customers and paid to vendors and suppliers;

▪ a $96 million decrease in cash from interest rate swap termination payments. In the first half of 2013, in separate transactions, we terminated three existing fixed-to-variable interest rate swap agreements prior to their contractual maturity dates; and

▪ a $54 million increase in cash from the combined net activity of our equity method investees and the net changes in all other operating assets and liabilities. The increase was driven by, among other things, higher period-to-period cash inflows from both favorable changes in previously deferred reimbursable costs and expenses, and higher non-cash losses related to commodity hedging activities. The overall increase in cash from operating net assets was

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partly offset by lower cash flows from both natural gas storage and pipeline transportation system balancing, and accrued tax liabilities.

Investing Activities

Net cash used in investing activities was $2,675 million for the six month period ended June 30, 2014, compared to $2,174 million in the comparable 2013 period. The $501 million (23%) decrease in cash due to higher cash expended for investing activities was primarily attributable to the following:

▪ a$707 million decrease in cash due to higher expenditures for the acquisition of assets and investments from unrelated parties. The overall increase was primarily related to the $961 million we paid in the first half of 2014 for our APT acquisition, versus the $280 million we paid in the first half of 2013 to acquire the Goldsmith Landreth San Andres oil field unit. For more information about our asset acquisitions during the first six months of 2014 and 2013, see Note 2 “Acquisitions and Divestitures—Acquisitions” to our consolidated financial statements;

▪ a $403 million decrease in cash due to the net proceeds we received in the first half of 2013 from the sale of our investments in the Express pipeline system;

▪ a$390 million decrease in cash due to higher capital expenditures in the first half of 2014, as described above in “—Capital Expenditures;” and

▪ a $994 million increase in cash due to the payments we made to KMI in the first half of 2013 to acquire our March 2013 drop-down asset group.

Financing Activities

Net cash provided by financing activities amounted to $289 million for the first half of 2014, and $579 million for the first half of 2013. The $290 million (50%) overall decrease in cash from all of our financing activities in the first half of 2014 versus the first half of 2013 was primarily attributable to the following:

▪ a$326 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$1,813 million in the first half of 2014, compared to $1,487 million in the first half of 2013. The increase in distributions was due to increases in the per unit cash distribution 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;”

▪ a $42 million decrease in cash due to lower net contributions from noncontrolling interests, chiefly due to the $73 million 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 $128 million increase in cash due to higher partnership equity issuances. This increase reflects thecombined $1,035 million we received, after commissions and underwriting expenses, from issuing additional common and i-units during the first half of 2014 (discussed in Note 4 “Partners’ Capital—Equity Issuances” to our consolidated financial statements), versus the$907 million we received from the sales of additional common units and i-units in the first half of 2013. The proceeds we received from equity issuances in the first six months of 2013 primarily consisted of $449 million from the issuance of common units pursuant to our equity distribution agreement with UBS, and $385 million from the public offering of 4,600,000 common units completed on February 26, 2013.

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 2013 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 declared and paid in the three and six months ended June 30, of 2014 and 2013, see Note 4 “Partners’ Capital—Partnership Distributions” to our consolidated financial statements.

On July 16, 2014, we declared a cash distribution of$1.39 per unit for the second quarter of 2014 compared to the $1.32 per unit distribution we declared for the second quarter of 2013. Based on (i) our declared distribution; (ii) the number of units outstanding; and (iii) our general partner’s agreement to forgo a combined$33 million of its incentive cash

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distribution in conjunction with both our May 2013 Copano acquisition and our January 2014 APT acquisition, our declared distribution for the second quarter of 2014 of$1.39 per unit will result in an incentive distribution to our general partner of$463 million.

Comparatively, our distribution of $1.32 per unit paid on August 14, 2013 for the second quarter of 2013 resulted in an incentive distribution payment to our general partner in the amount of $416 million (and included the effect of a waived incentive distribution amount of$25 million related to our May 2013 Copano acquisition). The increased incentive distribution to our general partner for the second quarter of 2014 over the incentive distribution for the second quarter of 2013 reflects the increase in the distribution per unit as well as the issuance of additional units. For additional information about our second quarter 2014 cash distribution, see Note 4 “Partners’ Capital—Subsequent Event” to our consolidated financial statements. For additional information about our 2013 partnership distributions, see Note 10 “Partners’ Capital—Income Allocation and Declared Distributions” and Note 11 “Related Party Transactions—Partnership Interests and Distributions” to our consolidated financial statements included in our 2013 Form 10-K.

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 NGL, and while we hedge the majority of our crude oil production, we do have exposure on our unhedged volumes, the majority of which are NGL volumes.  Our 2014 budget assumes an average WTI crude oil price of approximately $96.15 per barrel (with some minor adjustments for timing, quality and location differences) in 2014, 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 2014 budget), we currently expect the average price of WTI crude oil will be approximately$102.71 per barrel in 2014. For 2014, 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 $7 million on a full year basis (or approximately 0.125% of our combined business segments’ anticipated EBDA expenses).  This sensitivity to the average WTI price is very similar to what we experienced in 2013.

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, 2013, in Item 7A in our 2013 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, 2014, 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, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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.

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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 2013 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 95.1 to this quarterly report.

Item 5. Other Information.

None.

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.
12.1	Statement re: computation of ratio of earnings to fixed charges.
31.1	Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification by Chief Executive Officer 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 Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95.1	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, 2014 and 2013; (ii) our Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2014 and 2013; (iii) our Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013; (iv) our Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013; (v) our Consolidated Statements of Partners’ Capital for the six months ended June 30, 2014 and 2013; and (vi) the notes to our Consolidated Financial Statements.

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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
	By:	KINDER MORGAN G.P., INC.,
		its general partner
		By:	KINDER MORGAN MANAGEMENT, LLC,
			its delegate
Date: July 28, 2014		By:	/s/ Kimberly A. Dang
			Kimberly A. Dang
			Vice President and Chief Financial Officer
			(principal financial and accounting officer)

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