KINDER MORGAN, INC. - Quarter Report: 2015 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

F O R M 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

o 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: 001-35081

KINDER MORGAN, INC.

(Exact name of registrant as specified in its charter)



Delaware	80-0682103
(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 þ No o

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 þ No o

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 þ Accelerated filer o Non-accelerated filer o Smaller reporting company o

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

As of October 21, 2015, the registrant had 2,231,514,695 Class P shares outstanding.

KINDER MORGAN, INC. AND SUBSIDIARIES

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		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 Nine Months Ended September 30, 2015 and 2014	4
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2015 and 2014	5
	Consolidated Balance Sheets - September 30, 2015 and December 31, 2014	6
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2015 and 2014	7
	Consolidated Statements of Stockholders’ Equity - Nine Months Ended September 30, 2015 and 2014	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	39
	Results of Operations	39
	Financial Condition	55

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	58

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	58

Item 3.	Defaults Upon Senior Securities	58

Item 4.	Mine Safety Disclosures	59

Item 5.	Other Information	59

Item 6.	Exhibits	59

	Signature	60

KINDER MORGAN, INC. AND SUBSIDIARIES GLOSSARY Company Abbreviations

CIG	=	Colorado Interstate Gas Company, L.L.C.	KMI	=	Kinder Morgan, Inc. and its majority-owned and/or
Copano	=	Copano Energy, L.L.C.			controlled subsidiaries
CPG	=	Cheyenne Plains Gas Pipeline Company, L.L.C.	KMLP	=	Kinder Morgan Louisiana Pipeline LLC
Elba Express	=	Elba Express Company, L.L.C.	KMP	=	Kinder Morgan Energy Partners, L.P. and its
EPB	=	El Paso Pipeline Partners, L.P. and its majority-			majority-owned and controlled subsidiaries
		owned and controlled subsidiaries	KMR	=	Kinder Morgan Management, LLC
EPNG	=	El Paso Natural Gas Company, L.L.C.	SFPP	=	SFPP, L.P.
EPPOC	=	El Paso Pipeline Partners Operating Company,	SLNG	=	Southern LNG Company, L.L.C.
		L.L.C.	SNG	=	Southern Natural Gas Company, L.L.C.
KMEP	=	Kinder Morgan Energy Partners, L.P.	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
KMGP	=	Kinder Morgan G.P., Inc.

Unless the context otherwise requires, references to “we,” “us,” or “our,” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.

Common Industry and Other Terms
/d	=	per day	FASB	=	Financial Accounting Standards Board
AFUDC	=	allowance for funds used during construction	FERC	=	Federal Energy Regulatory Commission
BBtu	=	billion British Thermal Units	GAAP	=	United States Generally Accepted Accounting
Bcf	=	billion cubic feet			Principles
CERCLA	=	Comprehensive Environmental Response,	LLC	=	limited liability company
		Compensation and Liability Act	MBbl	=	thousand barrels
CO₂	=	carbon dioxide or our CO₂ business segment	MMBbl	=	million barrels
CPUC	=	California Public Utilities Commission	NGL	=	natural gas liquids
DCF	=	distributable cash flow	NYMEX	=	New York Mercantile Exchange
DD&A	=	depreciation, depletion and amortization	NYSE	=	New York Stock Exchange
EBDA	=	earnings before depreciation, depletion and	OTC	=	over-the-counter
		amortization expenses, including amortization of	PHMSA	=	United States Department of Transportation
		excess cost of equity investments			Pipeline and Hazardous Materials Safety
EPA	=	United States Environmental Protection Agency			Administration

When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

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Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, 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 pay dividends 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, 2014 (2014 Form 10-K) and Item 1A “Risk Factors” included elsewhere in this report for a more detailed description of factors that may affect the forward-looking statements. You should keep these risk factors in mind when considering forward-looking statements. These 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.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions, Except Per Share Amounts) (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Revenues
Natural gas sales	$	744		$	1,043		$	2,206		$	3,154
Services	2,015			2,050			5,948			5,655
Product sales and other	948			1,198			2,613			3,466
Total Revenues	3,707			4,291			10,767			12,275

Operating Costs, Expenses and Other
Costs of sales	1,106			1,642			3,281			4,895
Operations and maintenance	612			557			1,707			1,580
Depreciation, depletion and amortization	617			520			1,725			1,518
General and administrative	160			135			540			461
Taxes, other than income taxes	108			105			339			326
Loss on impairments and disposals of long-lived assets, net	385			—			489			3
Other income, net	(2		)	—			(5		)	—
Total Operating Costs, Expenses and Other	2,986			2,959			8,076			8,783

Operating Income	721			1,332			2,691			3,492

Other Income (Expense)
Earnings from equity investments	114			107			330			306
Loss on impairments of equity investments	—			—			(26		)	—
Amortization of excess cost of equity investments	(13		)	(12		)	(39		)	(33		)
Interest, net	(540		)	(432		)	(1,524		)	(1,320		)
Other, net	9			30			33			56
Total Other Expense	(430		)	(307		)	(1,226		)	(991		)

Income Before Income Taxes	291			1,025			1,465			2,501

Income Tax Expense	(108		)	(246		)	(521		)	(624		)

Net Income	183			779			944			1,877

Net Loss (Income) Attributable to Noncontrolling Interests	3			(450		)	4			(977		)

Net Income Attributable to Kinder Morgan, Inc.	$	186		$	329		$	948		$	900

Class P Shares
Basic Earnings Per Common Share	$	0.08		$	0.32		$	0.43		$	0.87

Basic Weighted Average Shares Outstanding	2,203			1,028			2,173			1,028

Diluted Earnings Per Common Share	$	0.08		$	0.32		$	0.43		$	0.87

Diluted Weighted Average Shares Outstanding	2,203			1,028			2,181			1,028

Dividends Per Common Share Declared for the Period	$	0.51		$	0.44		$	1.48		$	1.29

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

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KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Millions)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014

Net income	$	183		$	779		$	944		$	1,877
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(60), $(37), $(25) and $4, respectively)	104			121			44			(20		)
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $37, $1, $111 and $(8), respectively)	(63		)	(1		)	(192		)	29
Foreign currency translation adjustments (net of tax benefit of $45, $23, $98 and $24, respectively)	(79		)	(73		)	(170		)	(79		)
Benefit plan adjustments (net of tax expense of $-, $(1), $(4) and $-, respectively)	1			(1		)	7			—
Total other comprehensive (loss) income	(37		)	46			(311		)	(70		)

Comprehensive income	146			825			633			1,807
Comprehensive loss (income) attributable to noncontrolling interests	3			(478		)	4			(933		)
Comprehensive income attributable to KMI	$	149		$	347		$	637		$	874

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

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KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions, Except Share and Per Share Amounts)

	September 30, 2015			December 31, 2014
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	179		$	315
Accounts receivable, net	1,404			1,641
Inventories	445			459
Fair value of derivative contracts	529			535
Deferred income taxes	50			56
Other current assets	460			746
Total current assets	3,067			3,752

Property, plant and equipment, net	40,608			38,564
Investments	5,943			6,036
Goodwill	24,952			24,654
Other intangibles, net	3,619			2,302
Deferred income taxes	5,327			5,651
Deferred charges and other assets	2,161			2,090
Total Assets	$	85,677		$	83,049

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	3,003		$	2,717
Accounts payable	1,226			1,588
Accrued interest	563			637
Accrued contingencies	322			383
Other current liabilities	1,077			1,037
Total current liabilities	6,191			6,362

Long-term liabilities and deferred credits
Long-term debt
Outstanding	39,675			38,212
Preferred interest in general partner of KMP	100			100
Debt fair value adjustments	1,855			1,785
Total long-term debt	41,630			40,097
Other long-term liabilities and deferred credits	2,014			2,164
Total long-term liabilities and deferred credits	43,644			42,261
Total Liabilities	49,835			48,623

Commitments and contingencies (Notes 3 and 9)
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,227,894,462 and 2,125,147,116 shares, respectively, issued and outstanding	22			21
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none outstanding	—			—
Additional paid-in capital	40,062			36,178
Retained deficit	(4,242		)	(2,106		)
Accumulated other comprehensive loss	(328		)	(17		)
Total Kinder Morgan, Inc.’s stockholders’ equity	35,514			34,076
Noncontrolling interests	328			350
Total Stockholders’ Equity	35,842			34,426
Total Liabilities and Stockholders’ Equity	$	85,677		$	83,049

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

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KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)

	Nine Months Ended September 30,
	2015			2014
Cash Flows From Operating Activities
Net income	$	944		$	1,877
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,725			1,518
Deferred income taxes	524			369
Amortization of excess cost of equity investments	39			33
Loss on impairments and disposals of long-lived assets and equity investments, net	515			3
Earnings from equity investments	(330		)	(306		)
Distributions from equity investment earnings	289			294
Pension contributions and noncash pension benefit credits	(78		)	(79		)
Changes in components of working capital, net of the effects of acquisitions
Accounts receivable, net	304			23
Income tax receivable	195			—
Inventories	2			(29		)
Other current assets	82			3
Accounts payable	(264		)	(90		)
Accrued interest, net of interest rate swaps	(72		)	(113		)
Accrued contingencies and other current liabilities	6			228
Other, net	(374		)	(239		)
Net Cash Provided by Operating Activities	3,507			3,492

Cash Flows From Investing Activities
Business acquisitions, net of cash acquired	(1,864		)	(961		)
Acquisitions of other assets and investments	(55		)	(139		)
Capital expenditures	(2,999		)	(2,678		)
Contributions to investments	(69		)	(342		)
Distributions from equity investments in excess of cumulative earnings	181			138
Other, net	84			(38		)
Net Cash Used in Investing Activities	(4,722		)	(4,020		)

Cash Flows From Financing Activities
Issuances of debt	12,281			13,399
Payments of debt	(11,893		)	(11,585		)
Debt issue costs	(20		)	(52		)
Issuances of shares	3,833			—
Cash dividends	(3,084		)	(1,304		)
Repurchases of shares and warrants	(12		)	(192		)
Contributions from noncontrolling interests	7			1,638
Distributions to noncontrolling interests	(25		)	(1,491		)
Other, net	(1		)	(2		)
Net Cash Provided by Financing Activities	1,086			411

Effect of Exchange Rate Changes on Cash and Cash Equivalents	(7		)	(9		)

Net decrease in Cash and Cash Equivalents	(136		)	(126		)
Cash and Cash Equivalents, beginning of period	315			598
Cash and Cash Equivalents, end of period	$	179		$	472

Non-cash Investing and Financing Activities
Assets acquired by the assumption or incurrence of liabilities	$	1,680		$	73
Net assets contributed to equity investment	$	46		$	—

Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	1,596		$	1,446
Cash (refunded) paid during the period for income taxes, net	$	(183	)	$	228

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In Millions)

(Unaudited)



	Nine Months Ended September 30, 2015
	Outstanding shares	Par value of common shares		Additional paid-in capital			Retained deficit			Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI			Non-controlling interests			Total
Beginning Balance at December 31, 2014	2,125	$	21	$	36,178		$	(2,106	)	$	(17	)	$	34,076		$	350		$	34,426
Issuances of shares	101	1		3,832									3,833						3,833
Warrants repurchased				(12		)							(12		)				(12		)
EP Trust I Preferred security conversions	1			23									23						23
Warrants exercised				2									2						2
Restricted shares	1			40									40						40
Net income							948						948			(4		)	944
Distributions													—			(25		)	(25		)
Contributions													—			7			7
Cash dividends							(3,084		)				(3,084		)				(3,084		)
Other				(1		)							(1		)				(1		)
Other comprehensive loss										(311		)	(311		)				(311		)
Ending Balance at September 30, 2015	2,228	$	22	$	40,062		$	(4,242	)	$	(328	)	$	35,514		$	328		$	35,842



	Nine Months Ended September 30, 2014
	Outstanding shares		Par value of common shares		Additional paid-in capital			Retained deficit			Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI			Non-controlling interests			Total
Beginning Balance at December 31, 2013	1,031		$	10	$	14,479		$	(1,372	)	$	(24	)	$	13,093		$	15,192		$	28,285
Shares repurchased	(3	)			(94		)							(94		)				(94		)
Warrants repurchased					(98		)							(98		)				(98		)
Restricted shares					38									38						38
Impact from equity transactions of KMP, EPB and KMR					29									29			(44		)	(15		)
Net income								900						900			977			1,877
Distributions														—			(1,491		)	(1,491		)
Contributions														—			1,638			1,638
Cash dividends								(1,304		)				(1,304		)				(1,304		)
Other					7									7			(4		)	3
Other comprehensive loss											(26		)	(26		)	(44		)	(70		)
Ending Balance at September 30, 2014	1,028		$	10	$	14,361		$	(1,776	)	$	(50	)	$	12,545		$	16,224		$	28,769

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

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KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

We are the largest energy infrastructure and the third largest energy company in North America with an enterprise value of approximately $110 billion. We own an interest in or operate approximately 84,000 miles of pipelines and 165 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO₂ and other products, and our terminals 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, which is utilized for enhanced oil recovery projects in North America.

On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we did not already own. The transactions, valued at approximately $77 billion, are referred to collectively as the “Merger Transactions.” On January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP. References to EPB refer to EPB for periods prior to its merger into KMP.

Prior to the Merger Transactions, we owned an approximate 10% limited partner interest (including our interest in KMR) and the 2% general partner interest including incentive distribution rights in KMP, and an approximate 39% limited partner interest and the 2% general partner interest and incentive distribution rights in EPB. Effective with the Merger Transactions, the incentive distribution rights held by the general partner of KMP were eliminated.

The earnings recorded by KMP, EPB and KMR that are attributed to their units and shares, respectively, held by the public prior to the Merger Transactions are reported as “Net loss (income) attributable to noncontrolling interests” in our accompanying consolidated statements of income.

Basis of Presentation

General

Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the United States Securities and Exchange Commission (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, certain amounts from prior years have been reclassified to conform to the current presentation.

In the nine months ended September 30, 2015, we adopted Accounting Standards Updates (ASU) 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” and ASU 2015-15, “Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements—Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update).” These ASUs are designed to simplify presentation of debt issuance costs. The standards require that debt issuance costs related to a recognized debt liability, except for line-of-credit debt issuance costs, be presented in the balance sheet as an offset to the carrying amount of that debt liability, consistent with debt discounts. The application of this new accounting guidance resulted in the reclassification of $149 million of debt issuance costs from “Deferred charges and other assets” to “Debt fair value adjustments” in our accompanying consolidated balance sheet as of December 31, 2014.

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 2014 Form 10-K.

Impairments

During the three and nine months ended September 30, 2015, we recorded non-cash pre-tax impairment charges of $387 million and $523 million, respectively. These amounts include $388 million and $397 million for the three and nine months ended September 30, 2015, respectively, within our CO₂ business segment primarily related to our Goldsmith oil and gas field,

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primarily driven by a decrease in commodity prices during the quarter. The nine months ended September 30, 2015 amount also includes $99 million of impairments, related to the sale of certain gas gathering and processing assets within our Oklahoma midstream operations and the continued deterioration of the commodity price environment, and $26 million related to our investments in Fort Union Gas Gathering L.L.C. and Bighorn Gas Gathering L.L.C., which are all included in our Natural Gas Pipelines business segment.

As conditions warrant, we routinely evaluate our assets for potential triggering events that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future cash flow estimates, future volume expectations, current and future commodity prices, management’s decisions to dispose of certain assets, as well as general economic conditions and the related demand for products handled or transported by our assets. In the current commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may necessitate further impairments to the carrying value of our assets. Such non-cash impairments could have a significant effect on our results of operations.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares of common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards do not participate in excess distributions over earnings.

The following tables set forth the allocation of net income available to shareholders of Class P shares and participating securities and the reconciliation of Basic Weighted Average Shares Outstanding to Diluted Weighted Average Shares Outstanding (in millions):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Class P	$	182	$	327	$	938	$	892
Participating securities(a)	4		2		10		8
Net Income Attributable to Kinder Morgan, Inc.	$	186	$	329	$	948	$	900



	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Basic Weighted Average Shares Outstanding	2,203	1,028	2,173	1,028
Effect of dilutive securities:
Warrants(b)	—	—	8	—
Diluted Weighted Average Shares Outstanding	2,203	1,028	2,181	1,028

________


(a)	Participating securities are unvested restricted stock awards, which may be stock or stock units issued to management employees and include non-forfeitable dividend equivalent payments. As of September 30, 2015, there were approximately 8 million such restricted stock awards.


(b)	Each warrant entitles the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise, at any time until May 25, 2017.

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The following potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share (in millions on a weighted-average basis):



	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Unvested restricted stock awards	8	7	7	7
Warrants to purchase our Class P shares	296	298	290	316
Convertible trust preferred securities	8	10	8	10

2. Acquisitions

Hiland Partners, LP

On February 13, 2015, we acquired Hiland Partners, LP, a privately held Delaware limited partnership (Hiland) for aggregate consideration of approximately $3,120 million, including assumed debt. Approximately $368 million of the debt assumed was immediately paid down after closing. Hiland’s assets consist primarily of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily handling production from the Bakken Formation in North Dakota and Montana. The acquired gathering and processing assets are included in our Natural Gas Pipelines business segment while the acquired crude oil transport pipeline (Double H pipeline) is included in our Products Pipelines business segment.

Vopak Terminal Assets

On February 27, 2015, we acquired three U.S. terminals and one undeveloped site from Royal Vopak (Vopak) for approximately $158 million in cash. The acquisition included (i) a 36-acre, 1,069,500-barrel storage facility at Galena Park, Texas that handles base oils, biodiesel and crude oil and is immediately adjacent to our Galena Park terminal facility; (ii) two terminals in North Carolina: one in North Wilmington that handles chemicals and black oil and the other in South Wilmington that is not currently operating; and (iii) an undeveloped waterfront access site in Perth Amboy, New Jersey. We include the acquired assets as part of the Terminals business segment.

Allocation of Purchase Price

The evaluation of the assigned fair values for the above acquisitions is ongoing and subject to adjustment. Our preliminary allocation of the purchase price for each of our significant acquisitions during the nine months ended September 30, 2015 is detailed below (in millions).



	Acquisitions
	Hiland			Vopak Terminal Assets
Purchase Price Allocation:
Current assets	$	82		$	2
Property, plant and equipment	1,504			155
Goodwill	316			7
Other intangibles(a)	1,481			—
Total assets acquired	3,383			164
Current liabilities	(259		)	(2		)
Debt	(1,411		)	—
Other liabilities	(4		)	(4		)
Cash consideration	$	1,709		$	158

_______


(a)	Relates to customer contracts and relationships with a weighted average amortization period of 16.4 years.

After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, goodwill is an intangible asset representing the future economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated our goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and

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our expected ability to grow the business we acquired by leveraging our pre-existing business experience. We expect our recorded goodwill associated with the above acquisitions to be deductible for tax purposes.

Asset Purchase

On July 15, 2015, we purchased from Shell US Gas & Power LLC (Shell) its 49% interest in a joint venture, Elba Liquefaction Company (ELC), that was in the pre-construction stage of development for liquefaction facilities at Elba Island, Georgia. The transaction was treated as an asset purchase with the net cash consideration of $185 million attributed to incremental costs of construction. The purchase gives us full ownership and control of ELC. Therefore, we prospectively changed our method of accounting for ELC from the equity method to full consolidation. Shell continues to subscribe to 100% of the liquefaction capacity.

3. Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income. The following table provides detail on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts and premiums (in millions):



	September 30, 2015		December 31, 2014
KMI
Senior notes, 1.50% through 8.25%, due 2015 through 2098(a)	$	13,385	$	11,438
Credit facility due November 26, 2019(b)	275		850
Commercial paper borrowings(b)	193		386
KMP
Senior notes, 2.65% through 9.00%, due 2015 through 2044(c)	20,360		20,660
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
CIG senior notes, 5.95% through 6.85%, due 2015 through 2037	440		475
SNG notes, 4.40% through 8.00%, due 2017 through 2032	1,211		1,211
Other Subsidiary Borrowings (as obligor)
Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036	1,636		1,636
Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022	974		—
EPC Building, LLC, promissory note, 3.967%, due 2015 through 2035	445		453
Preferred securities, 4.75%, due March 31, 2028	221		280
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock	100		100
Other miscellaneous debt	301		303
Total debt – KMI and Subsidiaries	42,778		41,029
Less: Current portion of debt(d)	3,003		2,717
Total long-term debt – KMI and Subsidiaries(e)	$	39,775	$	38,312

_______

(a)

September 30, 2015 amount includes senior notes that are denominated in Euros and have been converted and are reported at the September 30, 2015 exchange rate of 1.1177 U.S. dollars per Euro. From the issuance date of these senior notes in March 2015 through September 30, 2015, our debt increased by $40 million as a result of the change in the exchange rate of U.S. dollars per Euro. We entered into cross-currency swap agreements associated with these senior notes (see Note 5 “Risk Management—Foreign Currency Risk Management”).


(b)	As of September 30, 2015 and December 31, 2014, the weighted average interest rates on our credit facility borrowings, including commercial paper borrowings, were 1.34% and 1.54%, respectively.


(c)	On January 1, 2015, EPB and EPPOC merged with and into KMP. On that date, KMP succeeded EPPOC as the issuer of approximately $2.9 billion of EPPOC’s senior notes, which were guaranteed by EPB, and EPB and EPPOC ceased to be obligors for those senior notes.


(d)	Amounts include outstanding credit facility and commercial paper borrowings.


(e)	Excludes our “Debt fair value adjustments” which, as of September 30, 2015 and December 31, 2014, increased our combined debt balances by $1,855 million and $1,785 million, respectively. In addition to all unamortized debt discount/premium amounts, debt

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issuance costs (resulting from the implementation of ASU Nos. 2015-03 and 2015-15) and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements.

Credit Facilities

As of September 30, 2015, we had $275 million outstanding under our five-year $4.0 billion revolving credit facility, $193 million outstanding under our $4.0 billion commercial paper program and $117 million in letters of credit. Our availability under this facility as of September 30, 2015 was $3,415 million. Borrowings under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.

On February 13, 2015, in connection with the Hiland acquisition, we entered into and made borrowings of $1,641 million under a new six-month bridge credit facility with UBS AG, Stamford Branch. Interest under this bridge credit facility was charged at the same rate as our $4.0 billion revolving credit facility. Prior to March 31, 2015, we repaid the outstanding borrowings and the facility was terminated on April 6, 2015.

Hiland Debt Acquired

As of the February 13, 2015 Hiland acquisition date, we assumed (i) $975 million in principal amount of senior notes (which were valued at $1,043 million as of the acquisition date) and (ii) $368 million of other borrowings that were immediately repaid after closing, primarily consisting of borrowings outstanding under a revolving credit facility. The senior notes are subject to our cross guarantee agreement discussed in Note 11.

Long-term Debt Issuances and Repayments

Apart from the assumption of the Hiland debt discussed above, following are significant long-term debt issuances and repayments made during the nine months ended September 30, 2015:



Issuances		$800 million 5.05% notes due 2046
		$815 million 1.50% notes due 2022(a)
		$543 million 2.25% notes due 2027(a)

Repayments		$300 million 5.625% notes due 2015
		$250 million 5.15% notes due 2015

_______


(a)	Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0860 U.S. dollars per Euro. At the time of issuance, we entered into cross-currency swap agreements effectively converting these senior notes to U.S. dollars (see Note 5 “Risk Management—Foreign Currency Risk Management”).

4. Stockholders’ Equity

Common Equity

As of September 30, 2015, our common equity consisted of our Class P common stock. For additional information regarding our Class P common stock, see Note 10 to our consolidated financial statements included in our 2014 Form 10-K.

On June 12, 2015, we announced that our board of directors approved a warrant repurchase program authorizing us to repurchase in the aggregate up to $100 million of warrants. As of September 30, 2015, we had $91 million of availability remaining under the above announced program. As of December 31, 2014, we had $2 million available for repurchases under our 2014 repurchase program, which was exhausted in June 2015.

On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares of our Class P common stock having an aggregate offering of up to $5.0 billion from time to time during the term of this agreement. During the nine months ended September 30, 2015, we issued and sold 101,290,190 shares of our Class P common stock pursuant to the equity distribution agreement, and issued an additional 1,324,318 shares after September 30, 2015 to settle sales made on or before September 30, 2015, resulting in net proceeds of $3.9 billion.

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Dividends

Holders of our common stock share equally in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Per common share cash dividend declared for the period	$	0.51	$	0.44	$	1.48	$	1.29
Per common share cash dividend paid in the period	$	0.49	$	0.43	$	1.42	$	1.26

On October 21, 2015, our board of directors declared a cash dividend of $0.51 per share for the quarterly period ended September 30, 2015, which is payable on November 13, 2015 to shareholders of record as of November 2, 2015.

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 and foreign currency 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. In addition, we have legacy power forward and swap contracts for which we entered into offsetting positions that eliminate the price risks associated with these power contracts.

As of December 31, 2014, we had discontinued hedge accounting on certain of our crude derivative contracts as we did not expect them to continue to be highly effective, for accounting purposes, in offsetting the variability in cash flows. This was caused primarily by volatility in basis differentials. As the forecasted transactions are still probable, accumulated gains and losses remain in other comprehensive income until earnings are impacted by the forecasted transactions. Changes in the derivative contracts’ fair value subsequent to the discontinuance of hedge accounting are reported in earnings. We re-designate certain of these hedging relationships as the expected effectiveness improves to required levels.

Energy Commodity Price Risk Management

As of September 30, 2015, 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	(23.0	)	MMBbl
Crude oil basis	(9.4	)	MMBbl
Natural gas fixed price	(41.2	)	Bcf
Natural gas basis	(16.7	)	Bcf
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.8	)	MMBbl
Crude oil basis	(1.7	)	MMBbl
Natural gas fixed price	(20.6	)	Bcf
Natural gas basis	(15.0	)	Bcf
NGL and other fixed price	(1.9	)	MMBbl

As of September 30, 2015, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2018. We have additional economic hedge contracts not designated as accounting hedges through December 2019.

Interest Rate Risk Management

As of September 30, 2015 and December 31, 2014, we had a combined notional principal amount of $9,700 million and $9,200 million, respectively, of fixed-to-variable interest rate swap agreements, effectively converting the interest expense

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associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of London Interbank Offered Rate (LIBOR) plus a spread. All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of September 30, 2015, 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.

Foreign Currency Risk Management

In connection with the issuance of our Euro denominated senior notes in March 2015 (see Note 3), we entered into cross-currency swap agreements to manage the related foreign currency risk by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates equivalent to approximately 3.79% and 4.67% for the 7-year and 12-year senior notes, respectively. These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior notes.

Fair Value of Derivative Contracts

The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions):



Fair Value of Derivative Contracts
		Asset derivatives				Liability derivatives
		September 30, 2015		December 31, 2014		September 30, 2015			December 31, 2014
	Location	Fair value				Fair value
Derivatives designated as hedging contracts
Natural gas and crude derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	347	$	309	$	(33	)	$	(34	)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	233		6		(4		)	—
Subtotal		580		315		(37		)	(34		)
Interest rate swap agreements	Fair value of derivative contracts/(Other current liabilities)	153		143		—			—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	361		260		(1		)	(53		)
Subtotal		514		403		(1		)	(53		)
Cross-currency swap agreements	Fair value of derivative contracts/(Other current liabilities)	—		—		(14		)	—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		—		(21		)	—
Subtotal		1		—		(35		)	—
Total		1,095		718		(73		)	(87		)

Derivatives not designated as hedging contracts
Natural gas, crude, NGL and other derivative contracts	Fair value of derivative contracts/(Other current liabilities)	23		73		(4		)	(2		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	13		196		(1		)	—
Subtotal		36		269		(5		)	(2		)
Power derivative contracts	Fair value of derivative contracts/(Other current liabilities)	6		10		(30		)	(57		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		—			(16		)
Subtotal		6		10		(30		)	(73		)
Total		42		279		(35		)	(75		)
Total derivatives		$	1,137	$	997	$	(108	)	$	(162	)

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Effect of Derivative Contracts on the Income Statement

The following tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income (in millions):



Derivatives in fair value hedging relationships	Location	Gain/(loss) recognized in income on derivatives and related hedged item
		Three Months Ended September 30,						Nine Months Ended September 30,
		2015			2014			2015			2014

Interest rate swap agreements	Interest, net	$	251		$	(25	)	$	163		$	87

Hedged fixed rate debt	Interest, net	$	(283	)	$	25		$	(166	)	$	(87	)



Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative (effective portion)(a)					Location	Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)						Location	Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Three Months Ended September 30,						Three Months Ended September 30,							Three Months Ended September 30,
	2015			2014			2015			2014				2015			2014
Energy commodity derivative contracts	$	119		$	121	Revenues—Natural gas sales	$	4		$	9		Revenues—Natural gas sales	$	—		$	—
						Revenues—Product sales and other	60			(5		)	Revenues—Product sales and other	(6		)	26
						Costs of sales	(2		)	(2		)	Costs of sales	—			—
Interest rate swap agreements	(4		)	—		Interest, net	(1		)	(1		)	Interest, net	—			—
Cross-currency swap	(11		)	—		Other, net	2			—
Total	$	104		$	121	Total	$	63		$	1		Total	$	(6	)	$	26



Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative (effective portion)(a)						Location	Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)						Location	Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Nine Months Ended September 30,							Nine Months Ended September 30,							Nine Months Ended September 30,
	2015			2014				2015			2014				2015		2014
Energy commodity derivative contracts	$	72		$	(10	)	Revenues—Natural gas sales	$	29		$	—		Revenues—Natural gas sales	$	—	$	—
							Revenues—Product sales and other	161			(30		)	Revenues—Product sales and other	4		(6		)
							Costs of sales	(21		)	4			Costs of sales	—		—
Interest rate swap agreements	(6		)	(10		)	Interest, net	(2		)	(3		)	Interest, net	—		—
Cross-currency swap	(22		)	—			Other, net	25			—
Total	$	44		$	(20	)	Total	$	192		$	(29	)	Total	$	4	$	(6	)

_________

(a)

We expect to reclassify an approximate $161 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of September 30, 2015 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).

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Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,
		2015		2014			2015		2014
Energy commodity derivative contracts	Revenues—Natural gas sales	$	6	$	4		$	9	$	(12	)
	Revenues—Product sales and other	169		5			173		6
	Costs of sales	—		(3		)	—		4
	Other expense (income)	—		—			—		(2		)
Total(a)		$	175	$	6		$	182	$	(4	)

_______

(a) For the three and nine months ended September 30, 2015, includes approximate gains of $19 million and $21 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

In conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of both September 30, 2015 and December 31, 2014, we had $2 million and $20 million, respectively, of outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2015 and December 31, 2014, we had cash margins of $14 million and $47 million posted as collateral and $32 million and $13 million, respectively, held as collateral.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of September 30, 2015, based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches, we would not be required to post additional collateral.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

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” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):



	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjustments			Total accumulated other comprehensive loss
Balance as of December 31, 2014	$	327		$	(108	)	$	(236	)	$	(17	)
Other comprehensive loss before reclassifications	44			(170		)	7			(119		)
Amounts reclassified from accumulated other comprehensive loss	(192		)	—			—			(192		)
Net current-period other comprehensive loss	(148		)	(170		)	7			(311		)
Balance as of September 30, 2015	$	179		$	(278	)	$	(229	)	$	(328	)



	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjustments			Total accumulated other comprehensive loss
Balance as of December 31, 2013	$	(3	)	$	2		$	(23	)	$	(24	)
Other comprehensive loss before reclassifications	(8		)	(31		)	2			(37		)
Amounts reclassified from accumulated other comprehensive loss	11			—			—			11
Net current-period other comprehensive loss	3			(31		)	2			(26		)
Balance as of September 30, 2014	$	—		$	(29	)	$	(21	)	$	(50	)

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6. Fair Value

The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.

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


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


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


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

Fair Value of Derivative Contracts

The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.



	Balance sheet asset fair value measurements by level														Net amount
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting			Cash collateral held(b)			Net amount
As of September 30, 2015
Energy commodity derivative contracts(a)	$	54	$	561	$	7	$	622	$	(40	)	$	(32	)	$	550
Interest rate swap agreements	$	—	$	514	$	—	$	514	$	(1	)	$	—		$	513
Cross-currency swap agreements	$	—	$	1	$	—	$	1	$	(1	)	$	—		$	—
As of December 31, 2014
Energy commodity derivative contracts(a)	$	49	$	533	$	12	$	594	$	(46	)	$	(13	)	$	535
Interest rate swap agreements	$	—	$	403	$	—	$	403	$	(44	)	$	—		$	359



	Balance sheet liability fair value measurements by level																Net amount
	Level 1			Level 2			Level 3			Gross amount			Contracts available for netting		Collateral posted(c)		Net amount
As of September 30, 2015
Energy commodity derivative contracts(a)	$	(9	)	$	(33	)	$	(30	)	$	(72	)	$	40	$	14	$	(18	)
Interest rate swap agreements	$	—		$	(1	)	$	—		$	(1	)	$	1	$	—	$	—
Cross-currency swap agreements	$	—		$	(35	)	$	—		$	(35	)	$	1	$	—	$	(34	)
As of December 31, 2014
Energy commodity derivative contracts(a)	$	(25	)	$	(11	)	$	(73	)	$	(109	)	$	46	$	47	$	(16	)
Interest rate swap agreements	$	—		$	(53	)	$	—		$	(53	)	$	44	$	—	$	(9	)

_______


(a)	Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC West Texas Intermediate swaps and options. Level 3 consists primarily of power derivative contracts.


(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.

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The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts (in millions):

Significant unobservable inputs (Level 3)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Derivatives-net asset (liability)
Beginning of Period	$	(37	)	$	(116	)	$	(61	)	$	(110	)
Total gains or (losses)
Included in earnings	(1		)	14			(1		)	—
Included in other comprehensive loss	—			10			—			—
Settlements	15			13			39			31
End of Period	$	(23	)	$	(79	)	$	(23	)	$	(79	)
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	$	—		$	16		$	2		$	(4	)

As of September 30, 2015, our Level 3 derivative assets and liabilities consisted primarily of power derivative contracts, where a significant portion of fair value is calculated from underlying market data that is not readily observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value.

Fair Value of Financial Instruments

The estimated fair value of our outstanding debt balances (the carrying amounts below include both short-term and long-term and debt fair value adjustments), is disclosed below (in millions):



	September 30, 2015				December 31, 2014
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
Total debt	$	44,633	$	41,136	$	42,814	$	43,582

We used Level 2 input values to measure the estimated fair value of our outstanding debt balances as of both September 30, 2015 and December 31, 2014.

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7. Reportable Segments

Financial information by segment follows (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Revenues
Natural Gas Pipelines
Revenues from external customers	$	2,176		$	2,745		$	6,444		$	7,766
Intersegment revenues	8			6			16			11
CO₂	517			508			1,316			1,445
Terminals
Revenues from external customers	469			433			1,395			1,244
Intersegment revenues	—			—			1			1
Products Pipelines
Revenues from external customers	467			520			1,388			1,578
Intersegment revenues	—			—			1			—
Kinder Morgan Canada	68			73			193			210
Other	—			3			3			5
Total segment revenues	3,705			4,288			10,757			12,260
Other revenues	10			9			28			27
Less: Total intersegment revenues	(8		)	(6		)	(18		)	(12		)
Total consolidated revenues	$	3,707		$	4,291		$	10,767		$	12,275



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Segment Earnings Before DD&A(a)
Natural Gas Pipelines	$	993		$	1,182		$	2,936		$	3,207
CO₂	29			388			605			1,083
Terminals	249			249			798			692
Products Pipelines	288			222			811			632
Kinder Morgan Canada	42			50			120			138
Other	(9		)	6			(55		)	13
Total segment earnings before DD&A	1,592			2,097			5,215			5,765
DD&A expense	(617		)	(520		)	(1,725		)	(1,518		)
Amortization of excess cost of equity investments	(13		)	(12		)	(39		)	(33		)
Other revenues	10			9			28			27
General and administrative expense	(160		)	(135		)	(540		)	(461		)
Interest expense, net of unallocable interest income	(539		)	(431		)	(1,525		)	(1,325		)
Unallocable income tax expense	(90		)	(229		)	(470		)	(578		)
Total consolidated net income	$	183		$	779		$	944		$	1,877



	September 30, 2015		December 31, 2014
Assets
Natural Gas Pipelines	$	54,725	$	52,532
CO₂	4,906		5,227
Terminals	9,212		8,850
Products Pipelines	8,471		7,179
Kinder Morgan Canada	1,452		1,593
Other	427		455
Total segment assets	79,193		75,836
Corporate assets(b)	6,438		7,157
Assets held for sale	46		56
Total consolidated assets	$	85,677	$	83,049

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(a)

We evaluate performance based on each segment’s earnings before DD&A. Amounts include revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income), net, and losses on impairments and disposals of long-lived assets, net and equity investments. Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.


(b)	Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, prepaid assets and deferred charges, deferred tax assets, risk management assets related to debt fair value adjustments and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.

8. Income Taxes

Income tax expense included in our accompanying consolidated statements of income were as follows (in millions, except percentages):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Income tax expense	$	108		$	246		$	521		$	624
Effective tax rate	37.1		%	24.0		%	35.6		%	25.0		%

Income tax expense for the three months ended September 30, 2015 is approximately $108 million resulting in an effective tax rate of 37.1%, as compared with $246 million income tax expense and an effective tax rate of 24.0%, for the same period of 2014. The effective tax rate for the three months ended September 30, 2015 is higher than the statutory federal rate of 35% primarily due to state and foreign income taxes, partially offset by dividend-received deductions from our investment in Florida Gas Pipeline (Citrus) and adjustments to our income tax reserve for uncertain tax positions.

Income tax expense for the nine months ended September 30, 2015 is approximately $521 million resulting in an effective tax rate of 35.6%, as compared with $624 million income tax expense and an effective tax rate of 25.0%, for the same period of 2014. The effective tax rate for the nine months ended September 30, 2015 is marginally higher than the statutory federal rate of 35% primarily due to state and foreign income taxes, offset by (i) dividend-received deductions from our investment in Citrus; (ii) the change in the effective state tax rate as a result of the Hiland acquisition; and (iii) adjustments to our income tax reserve for uncertain tax positions.

The effective tax rate for the three months ended September 30, 2014 is lower than the statutory federal rate of 35% primarily due to the net effect of consolidating KMP’s and EPB’s income tax provisions and dividend-received deductions from our investment in Citrus, partially offset by state income taxes.

The effective tax rate for the nine months ended September 30, 2014 is lower than the statutory federal rate of 35% primarily due to the net effect of consolidating KMP’s and EPB’s income tax provisions and dividend-received deductions from our investment in Citrus. These decreases are partially offset by state income taxes and the amortization of the deferred charge recorded as a result of the drop-downs of TGP, EPNG, and the midstream assets.

As of September 30, 2015, the total amount of unrecognized tax benefits relating to uncertain tax positions is $156 million, a decrease of $33 million from the December 31, 2014 balance of $189 million. This $33 million decrease in unrecognized tax benefits resulted primarily from the settlement of a claim for refund and certain statute of limitations expiration related to state income taxes.

9. Litigation, Environmental, Other Contingencies and Commitments

We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses that may result in claims against the Company. 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 dividends to our shareholders. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. 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.

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Federal Energy Regulatory Commission Proceedings

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 additional 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 $119 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 dividends to our shareholders.

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-A) in July 2015. FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it will apply its findings in Opinion 517-A to the same issues in the 2010 rate case. EPNG has sought federal appellate review of Opinion 517-A. 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 (ALJ) to conduct an additional hearing concerning one of the issues in Opinion 528. On September 17, 2014, the ALJ issued an initial decision finding certain shippers qualify for lower rates under a prior settlement. EPNG has sought FERC review of the ALJ decision. EPNG believes it has an appropriate reserve related to the findings in Opinions 517-A and 528 for both rate cases. We do not expect refunds in these cases to have an impact on our dividends to our shareholders.

Other Commercial Matters

Union Pacific Railroad Company Easements & Related Litigation

SFPP and Union Pacific Railroad Company (UPRR) are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten-year period beginning January 1, 2004 (Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In September 2011, the 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.

By notice dated October 25, 2013, UPRR demanded the payment of $22.3 million in rent for the first year of the next ten-year period beginning January 1, 2014, which SFPP rejected.

On November 5, 2014, the Court of Appeals issued an opinion which reversed the judgment, including the award of prejudgment interest, and remanded the matter to the trial court for a determination of UPRR’s property interest in its right-of-way, including whether UPRR has sufficient interest to grant SFPP’s easements. UPRR filed a petition for rehearing with the Court of Appeals, and a subsequent petition for review to the California Supreme Court, both of which were denied.

On April 23, 2015, after the above-referenced decision by the California Court of Appeals which held that UPRR does not own the subsurface rights to grant certain easements and may not be able to collect rent from those easements, a purported class action lawsuit was filed in the U.S. District Court for the Northern District of California (Case No. 01842) by private landowners in California who claim to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP. Substantially similar follow-on lawsuits have been filed in federal courts by landowners in Nevada, Arizona, New

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Mexico and Texas. These suits, which are brought purportedly as class actions on behalf of all landowners who own land in fee adjacent to and underlying the railroad easement under which the SFPP pipeline is located in those respective states, assert claims against UPRR, SFPP, KMGP, and Kinder Morgan Operating L.P. “D” for declaratory judgment, trespass, ejectment, quiet title, unjust enrichment, accounting, and alleged unlawful business acts and practices arising from defendants’ alleged improper use or occupation of subsurface real property. SFPP views these cases as primarily a dispute between UPRR and the plaintiffs. UPRR purported to grant SFPP a network of subsurface pipeline easements along UPRR’s railroad right-of-way. SFPP relied on the validity of those easements and paid rent to UPRR for the value of those easements. We believe we have recorded a right-of-way liability sufficient to cover our potential liability, if any, for back rent.

SFPP and UPRR have engaged in multiple disputes over the circumstances under which SFPP must pay for relocations of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In 2006, following a bench trial regarding the circumstances under which SFPP must pay for relocations, the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. The decision was affirmed on appeal. 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 has sought declaratory relief with respect to its positions regarding the application of these standards with respect to relocations. In 2011, a jury verdict was reached that SFPP was obligated to comply with AREMA standards in connection with a railroad project in Beaumont Hills, California. In 2014, the trial court entered judgment against SFPP, consistent with the jury’s verdict. On June 29, 2015, the parties entered into a confidential settlement of all of the claims relating to the project in Beaumont Hills and the case was dismissed.

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 cost (i.e., for railroad purposes, with the standards in the federal Pipeline Safety Act applying) could have an adverse effect on our financial position, results of operations, cash flows, and our dividends to our shareholders. These effects could be even greater in the event SFPP is unsuccessful in one or more of these lawsuits.

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 case was removed to the United States District Court for the Southern District of Texas. 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 is obligated to defend and indemnify TGP in connection with the gas commitment and reporting claims. After agreeing initially to defend and indemnify TGP against such claims, Kinetica withdrew its defense and disputed its indemnity obligation. We intend to vigorously defend the suit and pursue Kinetica, if necessary, for indemnity and costs of defense.

Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al.

In December 2011 (Brinckerhoff I), March 2012, (Brinckerhoff II), May 2013 (Brinckerhoff III) and June 2014 (Brinckerhoff IV), derivative lawsuits were filed in Delaware Chancery Court against El Paso Corporation, El Paso Pipeline GP Company, L.L.C., the general partner of EPB, and the directors of the general partner at the time of the relevant transactions. EPB was named in these lawsuits as a “Nominal Defendant.” The lawsuits arise from the March 2010, November 2010, May 2012 and June 2011 drop-down transactions involving EPB’s purchase of SLNG, Elba Express, CPG and interests in SNG and CIG. The lawsuits allege various conflicts of interest and that the consideration paid by EPB was excessive. Brinckerhoff I and II were consolidated into one proceeding. Motions to dismiss were filed in Brinckerhoff III and Brinckerhoff IV, and such motions remain pending. On June 12, 2014, defendants’ motion for summary judgment was granted in Brinckerhoff I, dismissing the case in its entirety. Defendants’ motion for summary judgment in Brinckerhoff II was granted in part, dismissing certain claims and allowing the matter to go to trial in late 2014 on the remaining claims. On April 20, 2015, the Court issued a post-trial memorandum opinion (Memorandum Opinion) in Brinckerhoff II entering judgment in favor of all of the defendants other than the general partner of EPB, but finding the general partner liable for breach of contract in connection with EPB’s purchase of 49% interests in Elba and SLNG and a 15% interest in SNG in a $1.13 billion drop-down transaction that closed on November 19, 2010 (Fall Dropdown), prior to our acquisition of El Paso Corporation in 2012. In its Memorandum Opinion, the Court determined that EPB suffered damages of $171 million from the Fall Dropdown, which the Court determined to be

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the amount that EPB overpaid for Elba. We believe the claim is derivative in nature and was extinguished by our acquisition on November 26, 2014, pursuant to a merger agreement, of all of the outstanding common units of EPB that we did not already own. On December 2, 2014, we filed a motion to dismiss the remaining claims in Brinckerhoff II based upon our acquisition of all of the outstanding common units of EPB. Oral argument on the motion was held on September 3, 2015 and we await the Court’s decision. In the event our motion to dismiss is denied, we will consider an appeal to the Delaware Supreme Court once a final decision is issued. At the present time, we do not believe that an ultimate award, if any, will have a material financial impact on our Company. We continue to believe the transactions at issue were appropriate and in the best interests of EPB and we intend to continue to defend the lawsuits vigorously.

Price Reporting Litigation

Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which were pending in Nevada federal court, were dismissed, but the dismissal was reversed by the 9^thCircuit Court of Appeals. The U.S. Supreme Court affirmed the 9^th Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the Nevada federal court for further consideration and trial, if necessary, of numerous remaining issues. Although damages in excess of $140 million have been alleged in total against all defendants in one of the remaining lawsuits where a damage number is provided, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, that may be allocated to us. Therefore, our costs and legal exposure related to the remaining outstanding lawsuits and claims are not currently determinable.

Kinder Morgan, Inc. Corporate Reorganization Litigation

Certain unitholders of KMP and EPB filed five putative class action lawsuits in the Court of Chancery of the State of Delaware in connection with the Merger Transactions, which the Court consolidated under the caption In re Kinder Morgan, Inc. Corporate Reorganization Litigation (Consolidated Case No. 10093-VCL). The plaintiffs originally sought to enjoin one or more of the proposed Merger Transactions, which relief the Court denied on November 5, 2014. On December 12, 2014, the plaintiffs filed a Verified Second Consolidated Amended Class Action Complaint, which purports to assert claims on behalf of both the former EPB unitholders and the former KMP unitholders. The EPB plaintiff alleged that (i) El Paso Pipeline GP Company, L.L.C. (EPGP), the general partner of EPB, and the directors of EPGP breached duties under the EPB partnership agreement, including the implied covenant of good faith and fair dealing, by entering into the EPB Transaction; (ii) EPB, E Merger Sub LLC, KMI and individual defendants aided and abetted such breaches; and (iii) EPB, E Merger Sub LLC, KMI, and individual defendants tortiously interfered with the EPB partnership agreement by causing EPGP to breach its duties under the EPB partnership agreement.

The KMP plaintiffs allege that (i) KMR, KMGP, and individual defendants breached duties under the KMP partnership agreement, including the implied duty of good faith and fair dealing, by entering into the KMP Transaction and by failing to adequately disclose material facts related to the transaction; (ii) KMI aided and abetted such breach; and (iii) KMI, KMP, KMR, P Merger Sub LLC, and individual defendants tortiously interfered with the rights of the plaintiffs and the putative class under the KMP partnership agreement by causing KMGP to breach its duties under the KMP partnership agreement. The complaint seeks declaratory relief that the transactions were unlawful and unenforceable, reformation, rescission, rescissory or compensatory damages, interest, and attorneys’ and experts’ fees and costs. On December 30, 2014, the defendants moved to dismiss the complaint. On April 2, 2015, the EPB plaintiff and the defendants submitted a stipulation and proposed order of dismissal, agreeing to dismiss all claims brought by the EPB plaintiff with prejudice as to the EPB lead plaintiff and without prejudice to all other members of the putative EPB class. The Court entered such order on April 2, 2015.

On August 24, 2015, the Court issued an order granting the defendants’ motion to dismiss the remaining counts of the complaint for failure to state a claim. On September 21, 2015, plaintiffs filed a notice of appeal to the Supreme Court of the State of Delaware, captioned Haynes Family Trust et al. v. Kinder Morgan G.P., Inc. et al. (Case No. 515). The plaintiffs are only appealing the dismissal of claims brought against defendants KMGP, Ted A. Gardner, Gary L. Hultquist, and Perry M. Waughtal and not those asserted against KMI, P. Merger Sub LLC, Richard D. Kinder, Steven J. Kean, KMP and KMR. The defendants believe the allegations against them lack merit, and they intend to vigorously defend these lawsuits.

Kinder Morgan Energy Partners, L.P. Capex Litigation

Putative class action and derivative complaints were filed in the Court of Chancery in the State of Delaware against defendants KMI, KMGP and nominal defendant KMEP on February 5, 2014 and March 27, 2014 captioned Slotoroff v. Kinder

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Morgan, Inc., Kinder Morgan G.P., Inc. et al (Case No. 9318) and Burns et al v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al (Case No. 9479) respectively. The cases were consolidated on April 8, 2014 (Consolidated Case No. 9318). The consolidated suit 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 complaints. 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 alleges that hundreds of millions of dollars were distributed improperly and 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.

On August 14, 2015, the parties entered into a Stipulation and Agreement of Settlement pursuant to which defendants will pay $27.5 million (the “Settlement Fund”) to a class of former holders of KMEP common units, and all claims asserted in the consolidated suit will be released. The settlement is subject to court approval following notice to the putative class members. If the court approves the settlement, the final judgment will also include a release of all claims asserted in the Walker litigation discussed below. Plaintiffs’ counsel is seeking an award of attorneys’ fees and litigation expenses from the Court which would be paid from the Settlement Fund. The Court has scheduled a hearing for November 23, 2015 to consider the proposed settlement as well as Plaintiff counsel’s request for fees and expenses. All of the defendants believe they acted properly, in good faith, and in a manner consistent with any and all legal, contractual and equitable duties and obligations, including those contained in the Limited Partnership Agreement. We are entering into this settlement solely to avoid the substantial burden, expense, inconvenience and distraction of continued litigation and to resolve each of the released claims.

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 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. By agreement of the parties, the case is stayed and all claims asserted in this action will be released with prejudice if the Delaware Court approves the settlement in the Kinder Morgan Energy Partners, L.P. Capex Litigation described above.

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 September 30, 2015 and December 31, 2014, our total reserve for legal matters was $441 million and $400 million, respectively. The reserve primarily relates to various claims from regulatory rate and right-of-way proceedings arising in our products and natural gas pipeline segments and certain corporate matters. The overall increase in the reserve from December 31, 2014 is related to certain legal developments during the nine months ended September 30, 2015 on corporate matters.

Environmental Matters

We and our subsidiaries 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,

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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 dividends to our shareholders.

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 (ROD). Currently, KMLT and 90 other parties are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs. We are participating in the allocation process on behalf of KMLT and KMBT in connection with their current or former ownership or operation of four facilities located in Portland Harbor. We expect the RI/FS process to conclude in 2016, after which the EPA is expected to develop a proposed plan leading to a ROD targeted for 2017. The allocation process will follow the issuance of the ROD with an expected completion date of 2017. We anticipate that the cleanup activities will begin within two years after the ROD is issued.

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 alleged 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. We have filed an answer, general denial, and affirmative defenses in response to the Second Amended Complaint.

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 No. 37-2007-00073033). On September 26, 2007, we removed the case to the U.S. District Court, Southern District of California (Case No. 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 its claim for damages to approximately $365 million.

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On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ summary adjudication motions. The Court tentatively granted our partial motions for summary judgment on the City’s claims for water and real estate damages and the State’s claims for violations of California Business and Professions Code § 17200, tentatively denied the City’s motion for summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary judgment on such claims. On January 25, 2013, the Court 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 to the U.S. Court of Appeals for the Ninth Circuit. On May 21, 2015, the Court of Appeals issued a memorandum decision which affirmed the District Court’s summary judgment in our favor with respect to the City’s claim under California Safe Drinking Water and Toxic Enforcement Act, but reversed the District Court’s summary judgment decision in our favor on the City’s remaining claims, and also reversed the District Court’s decision to exclude the City’s expert testimony. On July 14, 2015, the Court of Appeals denied our petition for rehearing and issued a mandate returning the case to the U.S. District Court. We intend to pursue dispositive motions before the U.S. District Court and continue to vigorously defend the case.

This site remains 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 conducted quarterly sampling and monitoring through 2014 as part of the compliance evaluation required by the RWQCB. SFPP expects the RWQCB to issue a notice of no further action with respect to the stadium property site. SFPP’s remediation effort is now focused on its adjacent Mission Valley Terminal site.

Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the 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. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona (Case No. 3:14-08165-DGC) seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given the pervasive control of such federal agencies over all aspects of the nuclear weapons program. Defendants filed an answer and counterclaims seeking contribution and recovery of response costs allegedly incurred by the federal agencies in investigating uranium impacts on the Navajo Reservation.

Lower Passaic River Study Area of the Diamond Alkali Superfund Site, Essex, Hudson, Bergen and Passaic Counties, New Jersey

EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area Superfund Site (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be potentially responsible parties under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group (JDG) of approximately 70 cooperating parties which have entered into AOCs and are directing and funding the work required by the EPA. Under the first AOC, draft remedial investigation and feasibility studies (RI/FS) of the Site were submitted to the EPA in 2015, and comments from the EPA are expected by the end of 2016. Under the second AOC, the JDG members conducted a CERCLA removal action at the Passaic River Mile 10.9, and the group is currently conducting EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with the AOCs.

On April 11, 2014, the EPA announced the issuance of its Focused Feasibility Study (FFS) for the lower eight miles of the Passaic River Study Area, and its proposed plan for remedial alternatives to address the dioxin sediment contamination from the mouth of Newark Bay to River Mile 8.3. The EPA estimates the cost for the alternatives will range from $365 million to $3.2 billion. The EPA’s preferred alternative would involve dredging the river bank-to-bank and installing an engineered cap at an estimated cost of $1.7 billion. In its FFS, the EPA stated that it has identified over 100 industrial facilities as potentially

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responsible parties and it is likely that there are hundreds more private and public entities that could be named in any litigation concerning responsibility for the Site contamination.

No final remedy for this portion of the Site will be selected until the public comment and response period for the FFS is completed and the Record of Decision (ROD) is issued by the EPA, which is expected by the end of 2015. Until the ROD is issued, there is uncertainty about what remedy will be implemented and the extent of potential costs. There is also uncertainty as to the impact of the RI/FS that the CPG is currently preparing for portions of the Site. The draft RI/FS was submitted by the CPG earlier in 2015 and proposes a different remedy than the FFS announced by the EPA. Therefore, the scope of potential EPA claims for the lower eight miles of the Passaic River is not reasonably estimable at this time.

Philadelphia and Point Breeze Terminals, Notices of Violation

On August 7, 2015, KMLT’s Philadelphia Terminal received a Notice of Violation (NOV) from the Pennsylvania Department of Environmental Protection (PADEP) related to an alleged ethanol release from an above ground storage tank at the facility. The NOV alleged a failure to investigate and confirm a suspected release within the regulatory time period and failure of emergency containment to contain a release from a tank. On July 30, 2015, KMLT’s Point Breeze Terminal received a NOV from the PADEP relating to an alleged violation of a regulatory requirement to remove storm water from the emergency containment areas surrounding above ground storage tanks at the facility prior to capacity of containment being reduced by ten percent (10%) or more. Following an informal administrative hearing with the PADEP on October 14, 2015 with respect to both matters, the NOV related to the Philadelphia Terminal was tentatively settled for approximately $0.6 million and the NOV related to the Point Breeze Terminal was tentatively settled for approximately $0.2 million.

Central Florida Pipeline Release, Tampa, Florida

On July 22, 2011, our subsidiary Central Florida Pipeline LLC (CFPL) reported a refined petroleum products release on a section of its 10-inch diameter pipeline near Tampa, Florida. The pipeline carries jet fuel and diesel to Orlando and was carrying jet fuel at the time of the incident. There was no fire and no injuries associated with the incident. CFPL cleaned up the release in coordination with federal, state and local agencies. The cause of the incident was determined to be a third party line strike. In August 2015, the EPA requested that CFPL engage in settlement discussions regarding potential penalties sought by the EPA under the Clean Water Act up to the statutory maximum of approximately $0.9 million. Although CFPL does not believe it caused the incident, and is prepared to vigorously defend any claims that might be asserted by the EPA, we are engaging in good faith settlement negotiations as requested by the EPA.

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, SNG and approximately 100 other 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 February 13, 2015, the Court granted defendants’ motion to dismiss the suit for failure to state a claim, and issued an order dismissing the SLFPA’s claims with prejudice. The SLFPA filed a notice of appeal on February 20, 2015.

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. The

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case was removed to the U.S. District Court for the Eastern District of Louisiana, but it has since been remanded to the state district court, where the parties are engaged in discovery. In connection with this suit, TGP has made two tenders for defense and indemnity: (1) to Anadarko, as successor to the entity that purchased TGP’s oil and gas assets in Bastian Bay, and (2) to Kinetica, which purchased TGP’s pipeline assets in Bastian Bay in 2013. Anadarko has accepted TGP’s tender (limited to oil and gas assets), and Kinetica rejected TGP’s tender. TGP responded to Kinetica by reasserting TGP’s demand for defense and indemnity and reserving its rights.

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 and our subsidiaries are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows. As of September 30, 2015 and December 31, 2014, we have accrued a total reserve for environmental liabilities in the amount of $306 million and $340 million, respectively. In addition, as of September 30, 2015 and December 31, 2014, we have recorded a receivable of $13 million and $14 million, respectively, for expected cost recoveries that have been deemed probable.

Commitments

Commitment for Jones Act Trade Fleet Expansion

In August 2015, we entered into a definitive agreement with Philly Tankers LLC totaling $568 million for the construction of four new Tier II, LNG-conversion-ready tankers each with a capacity of 337 MBbl. The tankers are expected to be delivered between November 2016 and November 2017 and would increase our Jones Act tanker fleet to 16 ships by late 2017. Our obligation for payments due under the terms of this agreement total $14 million in 2015; $170 million in 2016; and $384 million in 2017.

10. Recent Accounting Pronouncements

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 us January 1, 2018. Early adoption is permitted for the interim periods within the adoption year. We are currently reviewing the effect of ASU No. 2014-09 on our revenue recognition and assessing the timing of our adoption.

ASU No. 2015-02

On February 18, 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810) - Amendments to the Consolidated Analysis.” This ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. ASU No. 2015-02 will be effective for us January 1, 2016. We are currently reviewing the effect of ASU No. 2015-02.

ASU No. 2015-11

On July 22, 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory.” This ASU requires entities to subsequently measure inventory at the lower of cost and net realizable value, and defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. ASU No. 2015-11 will be effective for us January 1, 2017. We are currently reviewing the effect of ASU No. 2015-11.

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11. Guarantee of Securities of Subsidiaries

KMI, along with its direct and indirect subsidiaries KMP and Copano, are issuers of certain public debt securities. After the completion of the Merger Transactions, KMI, KMP, Copano and substantially all of KMI’s wholly owned domestic subsidiaries, entered into a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuers and other subsidiaries are all guarantors of each series of public debt. As a result of the cross guarantee agreement, a holder of any of the guaranteed public debt securities issued by KMI, KMP or Copano are in the same position with respect to the net assets, income and cash flows of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the guaranteed public debt securities to satisfy the repayment of such securities are the net assets, income and cash flows of the Subsidiary Non-Guarantors.

In lieu of providing separate financial statements for each subsidiary issuer and guarantor, we have included the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X. We have presented each of the parent and subsidiary issuers in separate columns in this single set of condensed consolidating financial statements.

Excluding fair value adjustments, as of September 30, 2015, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Issuer and Guarantor-Copano, and Subsidiary Guarantors had $13,853 million, $20,360 million, $332 million, and $7,222 million of Guaranteed Notes outstanding, respectively. Included in the Subsidiary Guarantors debt balance as presented in the accompanying September 30, 2015 condensed consolidating balance sheets are approximately $177 million of capitalized lease debt that is not subject to the cross guarantee agreement.

The accounts within the Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Issuer and Guarantor-Copano, Subsidiary Guarantors and Subsidiary Non-Guarantors are presented using the equity method of accounting for investments in subsidiaries, including subsidiaries that are guarantors and non-guarantors, for purposes of these condensed consolidating financial statements only. These intercompany investments and related activity eliminate in consolidation and are presented separately in the accompanying balance sheets and statements of income and cash flows.

A significant amount of each Issuers’ income and cash flow is generated by its respective subsidiaries. As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries. We utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the Subsidiary Issuers and Guarantors and Subsidiary Non-Guarantors. 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.

On January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP with KMP surviving the merger. As a result of such merger, all of the wholly owned subsidiaries of EPB became wholly owned subsidiaries of KMP and effective January 1, 2015, EPB is no longer a Subsidiary Issuer and Guarantor. The condensed consolidating financial information reflects this transaction for all periods presented below.

Effective November 26, 2014, the Merger Transactions close date, KMR merged into KMI. Therefore, for all periods presented KMR’s financial statement balances and activities are reflected within the Parent Issuer and Guarantor column.

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Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended September 30, 2015 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Issuer and Guarantor - Copano			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	9		$	—		$	—		$	3,289		$	421		$	(12	)	$	3,707

Operating costs, expenses and other
Costs of sales	—			—			—			1,007			98			1			1,106
Depreciation, depletion and amortization	6			—			—			508			103			—			617
Other operating expenses	16			1			(2		)	1,100			161			(13		)	1,263
Total operating costs, expenses and other	22			1			(2		)	2,615			362			(12		)	2,986

Operating (loss) income	(13		)	(1		)	2			674			59			—			721

Other income (expense)
Earnings from consolidated subsidiaries	366			484			48			376			10			(1,284		)	—
Earnings from equity investments	—			—			—			114			—			—			114
Interest, net	(155		)	23			(12		)	(381		)	(15		)	—			(540		)
Amortization of excess cost of equity investments and other, net	—			—			—			(5		)	1			—			(4		)

Income before income taxes	198			506			38			778			55			(1,284		)	291

Income tax expense	(12		)	(2		)	—			(93		)	(1		)	—			(108		)

Net income	186			504			38			685			54			(1,284		)	183
Net loss attributable to noncontrolling interests	—			—			—			—			—			3			3
Net income attributable to controlling interests	$	186		$	504		$	38		$	685		$	54		$	(1,281	)	$	186

Net Income	$	186		$	504		$	38		$	685		$	54		$	(1,284	)	$	183
Total other comprehensive loss	(37		)	(42		)	—			(24		)	(125		)	191			(37		)
Comprehensive income (loss)	149			462			38			661			(71		)	(1,093		)	146
Comprehensive loss attributable to noncontrolling interests	—			—			—			—			—			3			3
Comprehensive income (loss) attributable to controlling interests	$	149		$	462		$	38		$	661		$	(71	)	$	(1,090	)	$	149

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Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended September 30, 2014 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Issuer and Guarantor - Copano			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	9		$	—		$	—		$	3,649		$	637		$	(4	)	$	4,291

Operating costs, expenses and other
Costs of sales	—			—			—			1,510			124			8			1,642
Depreciation, depletion and amortization	5			—			—			423			92			—			520
Other operating expenses	4			2			9			667			127			(12		)	797
Total operating costs, expenses and other	9			2			9			2,600			343			(4		)	2,959

Operating (loss) income	—			(2		)	(9		)	1,049			294			—			1,332

Other income (expense)
Earnings from consolidated subsidiaries	581			1,126			59			640			487			(2,893		)	—
Earnings from equity investments	—			—			—			108			(1		)	—			107
Interest, net	(111		)	(28		)	(13		)	(261		)	(19		)	—			(432		)
Amortization of excess cost of equity investments and other, net	—			—			—			(6		)	24			—			18

Income before income taxes	470			1,096			37			1,530			785			(2,893		)	1,025

Income tax expense	(57		)	(3		)	—			(21		)	(165		)	—			(246		)

Net income	413			1,093			37			1,509			620			(2,893		)	779
Net income attributable to noncontrolling interests	(84		)	(44		)	—			—			—			(322		)	(450		)
Net income attributable to controlling interests	$	329		$	1,049		$	37		$	1,509		$	620		$	(3,215	)	$	329

Net Income	$	413		$	1,093		$	37		$	1,509		$	620		$	(2,893	)	$	779
Total other comprehensive income (loss)	24			58			—			85			(83		)	(38		)	46
Comprehensive income	437			1,151			37			1,594			537			(2,931		)	825
Comprehensive income attributable to noncontrolling interests	(90		)	(45		)	—			—			—			(343		)	(478		)
Comprehensive income attributable to controlling interests	$	347		$	1,106		$	37		$	1,594		$	537		$	(3,274	)	$	347

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Condensed Consolidating Statements of Income and Comprehensive Income for the Nine Months Ended September 30, 2015 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Issuer and Guarantor - Copano			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	28		$	—		$	—		$	9,565		$	1,210		$	(36	)	$	10,767

Operating costs, expenses and other
Costs of sales	—			—			—			2,997			282			2			3,281
Depreciation, depletion and amortization	16			—			—			1,423			286			—			1,725
Other operating expenses	66			39			(1		)	2,552			452			(38		)	3,070
Total operating costs, expenses and other	82			39			(1		)	6,972			1,020			(36		)	8,076

Operating (loss) income	(54		)	(39		)	1			2,593			190			—			2,691

Other income (expense)
Earnings from consolidated subsidiaries	1,454			2,033			20			1,510			41			(5,058		)	—
Earnings from equity investments	—			—			—			304			—			—			304
Interest, net	(356		)	30			(36		)	(1,133		)	(29		)	—			(1,524		)
Amortization of excess cost of equity investments and other, net	—			—			—			(13		)	7			—			(6		)

Income (loss) before income taxes	1,044			2,024			(15		)	3,261			209			(5,058		)	1,465

Income tax expense	(96		)	(6		)	—			(409		)	(10		)	—			(521		)

Net income (loss)	948			2,018			(15		)	2,852			199			(5,058		)	944
Net loss attributable to noncontrolling interests	—			—			—			—			—			4			4
Net income (loss) attributable to controlling interests	$	948		$	2,018		$	(15	)	$	2,852		$	199		$	(5,054	)	$	948

Net Income (loss)	$	948		$	2,018		$	(15	)	$	2,852		$	199		$	(5,058	)	$	944
Total other comprehensive loss	(311		)	(419		)	—			(525		)	(266		)	1,210			(311		)
Comprehensive income (loss)	637			1,599			(15		)	2,327			(67		)	(3,848		)	633
Comprehensive loss attributable to noncontrolling interests	—			—			—			—			—			4			4
Comprehensive income (loss) attributable to controlling interests	$	637		$	1,599		$	(15	)	$	2,327		$	(67	)	$	(3,844	)	$	637

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Condensed Consolidating Statements of Income and Comprehensive Income for the Nine Months Ended September 30, 2014 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Issuer and Guarantor - Copano			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	27		$	—		$	—		$	10,784		$	1,465		$	(1	)	$	12,275

Operating costs, expenses and other
Costs of sales	—			—			—			4,467			393			35			4,895
Depreciation, depletion and amortization	15			—			—			1,232			271			—			1,518
Other operating expenses	24			5			24			1,980			373			(36		)	2,370
Total operating costs, expenses and other	39			5			24			7,679			1,037			(1		)	8,783

Operating (loss) income	(12		)	(5		)	(24		)	3,105			428			—			3,492

Other income (expense)
Earnings from consolidated subsidiaries	1,554			2,897			159			1,432			1,414			(7,456		)	—
Earnings from equity investments	—			—			—			307			(1		)	—			306
Interest, net	(373		)	(80		)	(35		)	(766		)	(66		)	—			(1,320		)
Amortization of excess cost of equity investments and other, net	—			—			—			(13		)	36			—			23

Income before income taxes	1,169			2,812			100			4,065			1,811			(7,456		)	2,501

Income tax expense	(98		)	(8		)	—			(50		)	(468		)	—			(624		)

Net income	1,071			2,804			100			4,015			1,343			(7,456		)	1,877
Net income attributable to noncontrolling interests	(171		)	(156		)	—			—			—			(650		)	(977		)
Net income attributable to controlling interests	$	900		$	2,648		$	100		$	4,015		$	1,343		$	(8,106	)	$	900

Net Income	$	1,071		$	2,804		$	100		$	4,015		$	1,343		$	(7,456	)	$	1,877
Total other comprehensive loss	(33		)	(93		)	—			(106		)	(128		)	290			(70		)
Comprehensive income	1,038			2,711			100			3,909			1,215			(7,166		)	1,807
Comprehensive income attributable to noncontrolling interests	(164		)	(152		)	—			—			—			(617		)	(933		)
Comprehensive income attributable to controlling interests	$	874		$	2,559		$	100		$	3,909		$	1,215		$	(7,783	)	$	874

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Condensed Consolidating Balance Sheets as of September 30, 2015 (In Millions) (Unaudited)

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - KMP		Subsidiary Issuer and Guarantor - Copano		Subsidiary Guarantors		Subsidiary Non-Guarantors		Consolidating Adjustments			Consolidated KMI
ASSETS
Cash and cash equivalents	$	12	$	—	$	—	$	25	$	142	$	—		$	179
Other current assets - affiliates	1,915		1,042		19		9,399		550		(12,925		)	—
All other current assets	184		129		1		2,305		276		(7		)	2,888
Property, plant and equipment, net	258		—		—		31,972		8,378		—			40,608
Investments	16		2		—		5,811		114		—			5,943
Investments in subsidiaries	33,775		29,470		2,294		18,420		3,337		(87,296		)	—
Goodwill	15,089		22		920		5,743		3,178		—			24,952
Notes receivable from affiliates	4,588		22,175		—		2,228		360		(29,351		)	—
Deferred tax assets	—		—		—		8,939		—		(3,612		)	5,327
Other non-current assets	267		349		—		5,046		118		—			5,780
Total assets	$	56,104	$	53,189	$	3,234	$	89,888	$	16,453	$	(133,191	)	$	85,677

LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	535	$	875	$	—	$	1,471	$	122	$	—		$	3,003
Other current liabilities - affiliates	664		9,654		259		1,761		587		(12,925		)	—
All other current liabilities	334		260		15		1,987		599		(7		)	3,188
Long-term debt	13,953		20,149		380		6,461		687		—			41,630
Notes payable to affiliates	2,516		448		651		24,378		1,358		(29,351		)	—
Deferred income taxes	2,147		—		2		—		1,463		(3,612		)	—
All other long-term liabilities and deferred credits	441		180		—		965		428		—			2,014
Total liabilities	20,590		31,566		1,307		37,023		5,244		(45,895		)	49,835

Stockholders’ equity
Total KMI equity	35,514		21,623		1,927		52,865		11,209		(87,624		)	35,514
Noncontrolling interests	—		—		—		—		—		328			328
Total stockholders’ equity	35,514		21,623		1,927		52,865		11,209		(87,296		)	35,842
Total liabilities and stockholders’ equity	$	56,104	$	53,189	$	3,234	$	89,888	$	16,453	$	(133,191	)	$	85,677

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Condensed Consolidating Balance Sheets as of December 31, 2014 (In Millions)

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - KMP		Subsidiary Issuer and Guarantor - Copano		Subsidiary Guarantors		Subsidiary Non-Guarantors		Consolidating Adjustments			Consolidated KMI
ASSETS
Cash and cash equivalents	$	4	$	15	$	—	$	17	$	279	$	—		$	315
Other current assets - affiliates	1,868		1,335		11		11,573		403		(15,190		)	—
All other current assets	397		152		3		2,547		358		(20		)	3,437
Property, plant and equipment, net	263		—		5		29,490		8,806		—			38,564
Investments	16		1		—		5,910		109		—			6,036
Investments in subsidiaries	31,372		33,414		1,911		17,868		3,337		(87,902		)	—
Goodwill	15,087		22		920		5,419		3,206		—			24,654
Notes receivable from affiliates	4,459		19,832		—		2,415		496		(27,202		)	—
Deferred tax assets	—		—		—		9,256		—		(3,605		)	5,651
Other non-current assets	258		249		—		3,772		113		—			4,392
Total assets	$	53,724	$	55,020	$	2,850	$	88,267	$	17,107	$	(133,919	)	$	83,049

LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	1,486	$	699	$	—	$	381	$	151	$	—		$	2,717
Other current liabilities - affiliates	709		11,949		115		1,551		866		(15,190		)	—
All other current liabilities	319		498		12		1,812		1,024		(20		)	3,645
Long-term debt	11,833		20,564		386		6,599		715		—			40,097
Notes payable to affiliates	2,619		153		753		22,437		1,240		(27,202		)	—
Deferred income taxes	2,099		—		2		—		1,504		(3,605		)	—
Other long-term liabilities and deferred credits	583		78		2		987		514		—			2,164
Total liabilities	19,648		33,941		1,270		33,767		6,014		(46,017		)	48,623

Stockholders’ equity
Total KMI equity	34,076		21,079		1,580		54,500		11,093		(88,252		)	34,076
Noncontrolling interests	—		—		—		—		—		350			350
Total stockholders’ equity	34,076		21,079		1,580		54,500		11,093		(87,902		)	34,426
Total liabilities and stockholders’ equity	$	53,724	$	55,020	$	2,850	$	88,267	$	17,107	$	(133,919	)	$	83,049

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Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2015 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Issuer and Guarantor - Copano			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Net cash (used in) provided by operating activities	$	(2,208	)	$	5,917		$	81		$	6,834		$	193		$	(7,310	)	$	3,507

Cash flows from investing activities
Funding to affiliates	(1,767		)	(7,699		)	(2		)	(7,293		)	(597		)	17,358			—
Capital expenditures	(9		)	—			(3		)	(2,747		)	(245		)	5			(2,999		)
Contributions to investments	(5		)	—			—			(62		)	(7		)	5			(69		)
Investment in KMP	(159		)	—			—			—			—			159			—
Acquisitions of assets and investments	(1,709		)	—			—			(210		)	—			—			(1,919		)
Distributions from equity investments in excess of cumulative earnings	1,060			—			—			113			—			(992		)	181
Other, net	—			16			5			50			18			(5		)	84
Net cash used in investing activities	(2,589		)	(7,683		)	—			(10,149		)	(831		)	16,530			(4,722		)

Cash flows from financing activities
Issuances of debt	12,281			—			—			—			—			—			12,281
Payments of debt	(11,544		)	(300		)	—			(42		)	(7		)	—			(11,893		)
Funding from (to) affiliates	3,351			5,602			(81		)	7,842			644			(17,358		)	—
Debt issue costs	(20		)	—			—			—			—			—			(20		)
Issuances of shares	3,833			—			—			—			—			—			3,833
Cash dividends	(3,084		)	—			—			—			—			—			(3,084		)
Repurchases of warrants	(12		)	—			—			—			—			—			(12		)
Contributions from parents	—			156			—			3			12			(171		)	—
Contributions from noncontrolling interests	—			—			—			—			—			7			7
Distributions to parents	—			(3,706		)	—			(4,480		)	(141		)	8,327			—
Distributions to noncontrolling interests	—			—			—			—			—			(25		)	(25		)
Other, net	—			(1		)	—			—			—			—			(1		)
Net cash provided by (used in) financing activities	4,805			1,751			(81		)	3,323			508			(9,220		)	1,086

Effect of exchange rate changes on cash and cash equivalents	—			—			—			—			(7		)	—			(7		)

Net increase (decrease) in cash and cash equivalents	8			(15		)	—			8			(137		)	—			(136		)
Cash and cash equivalents, beginning of period	4			15			—			17			279			—			315
Cash and cash equivalents, end of period	$	12		$	—		$	—		$	25		$	142		$	—		$	179

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Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2014 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Issuer and Guarantor - Copano			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Net cash provided by (used in) operating activities	$	1,166		$	2,868		$	(92	)	$	3,897		$	1,219		$	(5,566	)	$	3,492

Cash flows from investing activities
Funding to affiliates	(197		)	(5,037		)	—			(2,785		)	(1,149		)	9,168			—
Capital expenditures	(11		)	—			(64		)	(2,254		)	(548		)	199			(2,678		)
Contributions to investments	—			(118		)	—			(342		)	—			118			(342		)
Investment in KMP	(34		)	—			—			—			—			34			—
Drop down assets to KMP	875			(875		)	—			—			—			—			—
Acquisitions of assets and investments	—			—			—			(1,085		)	(15		)	—			(1,100		)
Distributions from equity investments in excess of cumulative earnings	70			367			—			139			—			(438		)	138
Other, net	—			(2		)	199			23			(60		)	(198		)	(38		)
Net cash provided by (used in) investing activities	703			(5,665		)	135			(6,304		)	(1,772		)	8,883			(4,020		)

Cash flows from financing activities
Issuances of debt	3,258			10,141			—			—			—			—			13,399
Payments of debt	(3,804		)	(7,698		)	—			(76		)	(7		)	—			(11,585		)
Funding from (to) affiliates	149			2,225			(44		)	6,344			494			(9,168		)	—
Debt issue costs	(28		)	(24		)	—			1			(1		)	—			(52		)
Cash dividends	(1,304		)	—			—			—			—			—			(1,304		)
Repurchases of shares and warrants	(192		)	—			—			—			—			—			(192		)
Contributions from parents	—			1,578			—			151			62			(1,791		)	—
Contributions from noncontrolling interests	—			—			—			—			—			1,638			1,638
Distributions to parents	—			(3,322		)	—			(4,021		)	(152		)	7,495			—
Distributions to noncontrolling interests	—			—			—			—			—			(1,491		)	(1,491		)
Other, net	—			(1		)	—			(1		)	—			—			(2		)
Net cash (used in) provided by financing activities	(1,921		)	2,899			(44		)	2,398			396			(3,317		)	411

Effect of exchange rate changes on cash and cash equivalents	—			—			—			—			(9		)	—			(9		)

Net (decrease) increase in cash and cash equivalents	(52		)	102			(1		)	(9		)	(166		)	—			(126		)
Cash and cash equivalents, beginning of period	83			88			1			17			409			—			598
Cash and cash equivalents, end of period	$	31		$	190		$	—		$	8		$	243		$	—		$	472

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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 our accompanying interim consolidated financial statements and related notes included elsewhere in this report, and in conjunction with (i) our consolidated financial statements and related notes and (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2014 Form 10-K.

Results of Operations

Non-GAAP Measures

The non-GAAP financial measures, DCF before certain items and segment EBDA before certain items are presented below under “—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 or any other GAAP measure. DCF before certain items and segment EBDA before certain items are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider either 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. Our computation of segment EBDA before certain items has similar limitations. 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

DCF before certain items 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 cash available to pay dividends. We believe the primary measure of company performance used by us, investors and industry analysts is cash generation performance. Therefore, we believe DCF before certain items is an important measure to evaluate our operating and financial performance and to compare it with the performance of other publicly traded companies within the industry. For a discussion of our anticipated dividends for 2015, see “—Financial Condition—Cash Flows—Dividends.”

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The table below details the reconciliation of Net Income to DCF before certain items:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014

Net Income	$	183		$	779		$	944		$	1,877
Add/(Subtract):
Certain items before book tax(a)	260			(269		)	350			(229		)
Book tax certain items	(95		)	27			(136		)	28
Certain items after book tax	165			(242		)	214			(201		)
Net income before certain items	348			537			1,158			1,676
Add/(Subtract):
Net income attributable to third-party noncontrolling interests(b)	(3		)	(4		)	(16		)	(7		)
Depreciation, depletion and amortization(c)	708			608			2,004			1,780
Book taxes(d)	224			240			713			655
Cash taxes(e)	(3		)	(133		)	(19		)	(437		)
Other, net(f)	7			12			23			26
Sustaining capital expenditures(g)	(152		)	(144		)	(397		)	(353		)
Declared distributions to noncontrolling interests(h)	—			(681		)	—			(2,000		)
DCF before certain items	$	1,129		$	435		$	3,466		$	1,340

Weighted Average Shares Outstanding for Dividends(i)	2,210			1,036			2,189			1,035
DCF per share before certain items	$	0.51		$	0.42		$	1.58		$	1.29
Declared dividend per common share	$	0.51		$	0.44		$	1.48		$	1.29

_______


(a)	Consists of certain items summarized in footnotes (b) through (d) to the “—Consolidated Earnings Results” table included below, and described in more detail below in the footnotes to tables included in both our management’s discussion and analysis of segment results and “—General and Administrative, Interest, and Noncontrolling Interests.”


(b)	Represents net income allocated to third-party ownership interests in consolidated subsidiaries other than our former master limited partnerships. Three and nine month 2015 amounts exclude a loss attributable to noncontrolling interests of $6 million and $20 million, respectively, related to impairments included as certain items.


(c)	Includes DD&A and amortization of excess cost of equity investments. Three and nine month 2015 amounts also include $78 million and $240 million, respectively, and three and nine month 2014 amounts also include $76 million and $229 million, respectively, of our share of equity investee’s DD&A.


(d)	Excludes book tax certain items and includes income tax allocated to the segments. Three and nine month 2015 amounts also include $21 million and $56 million, respectively, and three and nine month 2014 amounts also include $21 million and $59 million, respectively, of our share of taxable equity investee’s book tax expense.


(e)	Three and nine month 2015 amounts include $(2) million and $(8) million, respectively, and three and nine month 2014 amounts include $(4) million and $(18) million, respectively, of our share of taxable equity investee’s cash taxes.


(f)	For 2015, consists primarily of non-cash compensation associated with our restricted stock program and for 2014 consists primarily of excess coverage from our former master limited partnerships.


(g)	Three and nine month 2015 amounts include $(16) million and $(50) million, respectively, and three and nine month 2014 amounts include $(11) million and $(36) million, respectively, of our share of equity investee’s sustaining capital expenditures.


(h)	Represents distributions to KMP and EPB limited partner units formerly owned by the public.


(i)	Includes restricted stock awards that participate in dividends and dilutive effect of warrants.

Consolidated Earnings Results

In the Results of Operations table below and in the business segment tables that follow, segment EBDA before certain items is calculated by adjusting the segment earnings before DD&A for the applicable certain item amounts in the footnotes to those tables.

In general, interest expense, general and administrative expenses, DD&A and unallocable income taxes are not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. Our general and administrative expenses include such items as employee benefits insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

We evaluate business segment performance primarily based on segment EBDA before certain items in relation to the level of capital allocated and consider this to be an important measure of our business segment performance. We account for intersegment sales at market prices, which are eliminated in consolidation.

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Results of Operations

	Three Months Ended September 30,
	2015			2014			Earnings increase/(decrease)
	(In millions, except percentages)
Segment earnings before DD&A(a)
Natural Gas Pipelines	$	993		$	1,182		$	(189	)	(16	)%
CO₂	29			388			(359		)	(93	)%
Terminals	249			249			—			—	%
Products Pipelines	288			222			66			30	%
Kinder Morgan Canada	42			50			(8		)	(16	)%
Other	(9		)	6			(15		)	(250	)%
Total segment earnings before DD&A(b)	1,592			2,097			(505		)	(24	)%
DD&A expense	(617		)	(520		)	(97		)	(19	)%
Amortization of excess cost of equity investments	(13		)	(12		)	(1		)	(8	)%
Other revenues	10			9			1			11	%
General and administrative expense(c)	(160		)	(135		)	(25		)	(19	)%
Interest expense, net of unallocable interest income(d)	(539		)	(431		)	(108		)	(25	)%
Income before unallocable income taxes	273			1,008			(735		)	(73	)%
Unallocable income tax expense	(90		)	(229		)	139			61	%
Net income	183			779			(596		)	(77	)%
Net loss (income) attributable to noncontrolling interests	3			(450		)	453			101	%
Net income attributable to Kinder Morgan, Inc.	$	186		$	329		$	(143	)	(43	)%



	Nine Months Ended September 30,
	2015			2014			Earnings increase/(decrease)
	(In millions, except percentages)
Segment earnings before DD&A(a)
Natural Gas Pipelines	$	2,936		$	3,207		$	(271	)	(8	)%
CO₂	605			1,083			(478		)	(44	)%
Terminals	798			692			106			15	%
Products Pipelines	811			632			179			28	%
Kinder Morgan Canada	120			138			(18		)	(13	)%
Other	(55		)	13			(68		)	(523	)%
Total segment earnings before DD&A(b)	5,215			5,765			(550		)	(10	)%
DD&A expense	(1,725		)	(1,518		)	(207		)	(14	)%
Amortization of excess cost of equity investments	(39		)	(33		)	(6		)	(18	)%
Other revenues	28			27			1			4	%
General and administrative expense(c)	(540		)	(461		)	(79		)	(17	)%
Interest expense, net of unallocable interest income(d)	(1,525		)	(1,325		)	(200		)	(15	)%
Income before unallocable income taxes	1,414			2,455			(1,041		)	(42	)%
Unallocable income tax expense	(470		)	(578		)	108			19	%
Net income	944			1,877			(933		)	(50	)%
Net loss (income) attributable to noncontrolling interests	4			(977		)	981			100	%
Net income attributable to Kinder Morgan, Inc.	$	948		$	900		$	48		5	%

_______

(a)

Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, other expense(income), net, and losses on impairments and disposals of long-lived assets, net and equity investments. Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes. Allocable income tax expenses included in segment earnings for the three months ended September 30, 2015 and 2014 were $18

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million and $17 million, respectively, and for the nine months ended September 30, 2015 and 2014 were $51 million and $46 million, respectively.

Certain item footnotes

(b)

Three and nine month 2015 amounts include decreases in earnings of $247 million and $363 million, respectively, and three and nine month 2014 amounts include increases in earnings of $241 million and $198 million, respectively, related to the combined effect from all of the 2015 and 2014 certain items impacting segment earnings before DD&A and disclosed below in our management discussion and analysis of segment results.

(c)

Three and nine month 2015 amounts include a decrease in expense of $2 million and an increase in expense of $27 million, respectively, and three and nine month 2014 amounts include decreases in expense of $15 million and $18 million, respectively, related to the combined effect from the 2015 and 2014 certain items related to general and administrative expense disclosed below in “—General and Administrative, Interest, and Noncontrolling Interests.”

(d)

Three and nine month 2015 amounts include an increase in expense of $15 million and a decrease in expense of $40 million, respectively, and three and nine month 2014 amounts include a decrease in expense of $13 million for both respective periods, related to the combined effect from the 2015 and 2014 certain items related to interest expense, net of unallocable interest income disclosed below in “—General and Administrative, Interest, and Noncontrolling Interests.”

The certain item totals reflected in footnotes (b), (c) and (d) to the tables above totaled a $529 million decrease in income before unallocable income taxes for the third quarter of 2015, when compared to the same prior year period (combining a decrease of $260 million and an increase of $269 million in income before unallocable income taxes for the third quarters of 2015 and 2014, respectively), and totaled a $579 million decrease in income before unallocable income taxes for the nine months ended September 30, 2015, when compared to the same prior year period (combining a decrease of $350 million and an increase of $229 million in income before unallocable income taxes for the nine months ended September 30, 2015 and 2014, respectively). After giving effect to these certain items, the remaining decreases of $206 million (28%) and $462 million (21%) from the prior year quarter and year-to-date, respectively, in income before unallocable income taxes is primarily attributable to increased DD&A expense, general and administrative expense and interest expense, net of unallocable interest income. Our segment earnings before DD&A were relatively flat for the quarter and year-to-date when compared to the prior comparable periods as unfavorable commodity prices affecting our CO2 business segment were offset by increased results from our Products Pipelines and Terminals business segments.

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Natural Gas Pipelines



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In millions, except operating statistics)
Revenues(a)	$	2,184		$	2,751		$	6,460		$	7,777
Operating expenses	(1,289		)	(1,651		)	(3,688		)	(4,802		)
Gain (loss) on impairments and disposals of long-lived assets and equity investments, net	2			(5		)	(116		)	(7		)
Other income	—			—			3			—
Earnings from equity investments	91			85			264			235
Interest income and Other, net	6			4			18			13
Income tax expense	(1		)	(2		)	(5		)	(9		)
Segment earnings before DD&A(b)	993			1,182			2,936			3,207
Certain items, net(b)	(18		)	(204		)	91			(195		)
EBDA before certain items	$	975		$	978		$	3,027		$	3,012

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	(378	)	(15		)%	$	(1,141	)	(15		)%
EBDA before certain items	$	(3	)	—		%	$	15		—		%

Natural gas transport volumes (BBtu/d)(c)	28,580			27,250			28,230			26,891
Natural gas sales volumes (BBtu/d)(d)	2,445			2,446			2,416			2,303
Natural gas gathering volumes (BBtu/d)(e)	3,541			3,508			3,554			3,354
Crude/condensate gathering volumes (MBbl/d)(f)	343			321			340			282

_______

Certain item footnotes

(a)

Three and nine month 2015 amounts include increases in revenue of $17 million and $23 million, respectively, and three and nine month 2014 amounts include increases in revenue of $8 million and $1 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. Three and nine month 2014 amounts also include a $198 million increase in revenue for both periods associated with the early termination charge of a long-term natural gas transportation contract from a certain customer of Kinder Morgan Louisiana Pipeline LLC.

(b)

Three and nine month 2015 amounts include increases in earnings of $17 million and $23 million, respectively, related to derivative contracts, as described in footnote (a) and increases in earnings of $1 million and $4 million, respectively, from other certain items. The nine month ended 2015 amount also includes a decrease in earnings of $128 million related to losses on impairments and disposals of long-lived assets and equity investments partially offset by a $10 million gain on the sale of an asset. Three and nine month 2014 amounts include increases in earnings of $8 million and $1 million, respectively, related to derivative contracts and $198 million for both periods associated with the early termination charge of a transportation contract, as described in footnote (a). Three and nine month 2014 amounts also include decreases in earnings of $2 million and $4 million, respectively, from other certain items.

Other footnotes

(c)

Includes pipeline volumes for Kinder Morgan North Texas Pipeline LLC, Monterrey, TransColorado Gas Transmission Company LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC, Fayetteville Express Pipeline LLC, TGP, EPNG, Copano South Texas, the Texas intrastate natural gas pipeline group, CIG, Wyoming Interstate Company, L.L.C., CPG, SNG, Elba Express, Sierrita, Natural Gas Pipeline Company of America LLC (NGPL), Citrus and Ruby Pipeline, L.L.C. Joint Venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods. However, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.


(d)	Represents volumes for the Texas intrastate natural gas pipeline group and Kinder Morgan North Texas Pipeline LLC.

(e)

Includes Copano operations, Camino Real Gathering Company, L.L.C. (Camino Real), Kinder Morgan Altamont LLC, KinderHawk Field Services LLC (KinderHawk), Endeavor, Bighorn Gas Gathering L.L.C., Webb Duval Gatherers, Fort Union Gas Gathering L.L.C., EagleHawk, Red Cedar Gathering Company and Hiland Midstream throughput volumes. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods.


(f)	Includes Hiland Midstream, EagleHawk and Camino Real. 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 nine month periods of 2015 and 2014:

Three months ended September 30, 2015 versus Three months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Hiland Midstream	$	37		n/a		$	145		n/a
EPNG	13			13	%	25			17	%
EagleHawk field services(a)	5			—	%	n/a			n/a
KinderHawk field services	(21		)	(41	)%	(22		)	(39	)%
KMLP	(17		)	(74	)%	(17		)	(68	)%
Oklahoma Midstream	(10		)	(59	)%	(61		)	(47	)%
CPG	(8		)	(38	)%	(7		)	(27	)%
EP Midstream asset operations	(6		)	(24	)%	(17		)	(33	)%
South Texas Midstream	(5		)	(6	)%	(173		)	(35	)%
Texas Intrastate Natural Gas Pipeline Group	(2		)	(3	)%	(289		)	(28	)%
All others (including eliminations)	11			2	%	38			7	%
Total Natural Gas Pipelines	$	(3	)	—	%	$	(378	)	(15	)%

Nine months ended September 30, 2015 versus Nine months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Hiland Midstream	$	95		n/a		$	363		n/a
EPNG	33			11	%	48			11	%
EagleHawk field services(a)	25			278	%	n/a			n/a
KinderHawk field services	(46		)	(30	)%	(48		)	(29	)%
KMLP	(34		)	(67	)%	(34		)	(58	)%
Oklahoma Midstream	(32		)	(62	)%	(198		)	(48	)%
CPG	(18		)	(29	)%	(18		)	(23	)%
EP Midstream asset operations	(20		)	(27	)%	(52		)	(34	)%
South Texas Midstream	(1		)	—	%	(370		)	(28	)%
Texas Intrastate Natural Gas Pipeline Group	7			3	%	(900		)	(29	)%
All others (including eliminations)	6			—	%	68			4	%
Total Natural Gas Pipelines	$	15		—	%	$	(1,141	)	(15	)%

_______

n/a – not applicable

(a) Equity Investment

The significant changes in our Natural Gas Pipelines business segment’s EBDA before certain items in the comparable three and nine month periods of 2015 and 2014 included the following:


•	increases of $37 million and $95 million, respectively, from our February 2015 acquisition of the Hiland Midstream asset;


•	increases of $13 million (13%) and $33 million (11%), respectively, from EPNG due largely to additional firm transport revenues;


•	increases of $5 million (0%) and $25 million (278%), respectively, from EagleHawk driven by higher volumes and lower pipeline integrity costs;


•	decreases of $21 million (41%) and $46 million (30%), respectively, from KinderHawk primarily due to the expiration of a minimum volume contract;

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•	decreases of $17 million (74%) and $34 million (67%), respectively, from KMLP as a result of a customer contract buyout in the third quarter of 2014;


•	decreases of $10 million (59%) and $32 million (62%), respectively, from Oklahoma Midstream primarily due to lower commodity prices and lower volumes. Lower revenues of $61 million and $198 million, respectively, and associated decreases in costs of goods sold were also due to lower commodity prices;


•	decreases of $8 million (38%) and $18 million (29%), respectively, from CPG due primarily to lower transport revenues as a result of contract expirations;


•	decreases of $6 million (24%) and $20 million (27%), respectively, from EP Midstream asset operations primarily due to lower commodity prices partially offset by higher volumes;


•	decreases of $5 million (6%) and $1 million (0%), respectively, from South Texas Midstream primarily due to lower commodity prices, partially offset by higher gathering and processing volumes. Lower revenues of $173 million and $370 million, respectively, and associated decreases in costs of goods sold were also due to lower commodity prices; and

•

decrease of $2 million (3%) and increase of $7 million (3%), respectively, from our Texas intrastate natural gas pipeline group (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems). The year-to-date increase was due largely to higher transportation and natural gas sale margins as a result of new customer contracts, partially offset by lower processing margins due to the non-renewal of a customer contract in the second quarter of 2014 and lower storage margins. The decreases in revenues of $289 million and $900 million, respectively, and associated decreases in costs of goods sold were caused by lower natural gas prices.

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CO2



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In millions, except operating statistics)
Revenues(a)	$	517		$	508		$	1,316		$	1,445
Operating expenses	(104		)	(123		)	(328		)	(375		)
Loss on impairments and disposals of long-lived assets, net	(388		)	—			(397		)	—
Earnings from equity investments	5			5			17			19
Income tax expense	(1		)	(2		)	(3		)	(6		)
Segment earnings before DD&A(b)	29			388			605			1,083
Certain items(b)	253			(25		)	244			6
EBDA before certain items	$	282		$	363		$	849		$	1,089

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	(101	)	(21		)%	$	(288	)	(20		)%
EBDA before certain items	$	(81	)	(22		)%	$	(240	)	(22		)%

Southwest Colorado CO₂ production (gross)(Bcf/d)(c)	1.2			1.2			1.2			1.3
Southwest Colorado CO₂ production (net)(Bcf/d)(c)	0.6			0.5			0.6			0.5
SACROC oil production (gross)(MBbl/d)(d)	32.5			33.1			34.4			32.4
SACROC oil production (net)(MBbl/d)(e)	27.1			27.6			28.7			26.9
Yates oil production (gross)(MBbl/d)(d)	18.9			19.2			18.9			19.5
Yates oil production (net)(MBbl/d)(e)	7.6			8.7			8.2			8.6
Katz oil production (gross)(MBbl/d)(d)	4.1			3.4			4.0			3.6
Katz oil production (net)(MBbl/d)(e)	3.4			2.9			3.4			3.0
Goldsmith oil production (gross)(MBbl/d)(d)	1.6			1.3			1.5			1.3
Goldsmith oil production (net)(MBbl/d)(e)	1.4			1.1			1.3			1.1
NGL sales volumes (net)(MBbl/d)(e)	10.5			10.3			10.3			10.1
Realized weighted-average oil price per Bbl(f)	$	74.18		$	87.59		$	73.19		$	89.40
Realized weighted-average NGL price per Bbl(g)	$	16.29		$	43.57		$	18.96		$	46.18

_______

Certain item footnote

(a)

Three and nine month 2015 amounts include unrealized gains of $135 million and $143 million, respectively, and three and nine month 2014 amounts include unrealized gains of $25 million and unrealized losses of $6 million, respectively, relating to derivative contracts used to hedge forecasted crude oil sales. Nine month 2015 amount also includes a favorable adjustment of $10 million related to carried working interest at McElmo Dome.

(b)

Three and nine month 2015 amounts include increases in earnings of $135 million $143 million, respectively, related to derivative contracts, as described in footnote (a) and decreases in earnings for both periods of a $378 million impairment charge associated with our Goldsmith oil and gas field driven primarily by lower crude prices, and a $10 million impairment charge associated with our Cottonwood Canyon CO₂ source project. Nine month 2015 amount also includes a favorable adjustment of $10 million as described in footnote (a) and a $9 million impairment charge associated with the pending sale of excess construction pipe. Three and nine month 2014 amounts include an increase in earnings of $25 million and a decrease in earnings of $6 million, respectively, related to derivative contracts, as described in footnote (a).

Other footnotes


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


(d)	Represents 100% of the production from the field. We own 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 unit and a 99% working interest in the Goldsmith Landreth unit.


(e)	Net after royalties and outside working interests.


(f)	Includes all crude oil production properties. Hedge gains/losses for Oil and NGL are included with Crude Oil.


(g)	Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements. Hedge gains/losses for Oil and NGL are included with Crude Oil.

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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 nine month periods of 2015 and 2014.

Three months ended September 30, 2015 versus Three months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Source and Transportation Activities	$	(30	)	(27	)%	$	(27	)	(22	)%
Oil and Gas Producing Activities	(51		)	(20	)%	(84		)	(22	)%
Intrasegment eliminations	—			—	%	10			45	%
Total CO2	$	(81	)	(22	)%	$	(101	)	(21	)%

Nine months ended September 30, 2015 versus Nine months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Source and Transportation Activities	$	(94	)	(28	)%	$	(94	)	(25	)%
Oil and Gas Producing Activities	(146		)	(19	)%	(223		)	(20	)%
Intrasegment eliminations	—			—	%	29			44	%
Total CO2	$	(240	)	(22	)%	$	(288	)	(20	)%

The primary changes in our CO2 business segment’s EBDA before certain items in the comparable three and nine month periods of 2015 and 2014 included the following:


•	decreases of $30 million (27%) and $94 million (28%), respectively, from source and transportation activities due to lower revenues primarily due to lower commodity prices; and


•	decreases of $51 million (20%) and $146 million (19%), respectively, from oil and gas producing activities due to lower revenues driven by lower commodity prices. The nine month decrease was partially offset by higher crude oil sales volumes up 5% from the nine month period of 2014 largely attributable to higher production at the SACROC unit in 2015.

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Terminals



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In millions, except operating statistics)
Revenues(a)	$	469		$	433		$	1,396		$	1,245
Operating expenses	(221		)	(183		)	(599		)	(556		)
Other income (expense)	1			2			(1		)	—
Earnings from equity investments	7			5			16			16
Interest income and Other, net	1			1			7			6
Income tax expense	(8		)	(9		)	(21		)	(19		)
Segment earnings before DD&A(b)	249			249			798			692
Certain items, net(b)	14			(2		)	—			10
EBDA before certain items	$	263		$	247		$	798		$	702

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	34		8		%	$	144		12		%
EBDA before certain items	$	16		6		%	$	96		14		%

Bulk transload tonnage (MMtons)(c)	16.9			20.4			48.9			60.3
Ethanol (MMBbl)	15.0			17.1			47.3			49.8
Liquids leasable capacity (MMBbl)	81.3			75.6			81.3			75.6
Liquids utilization %(d)	93.4		%	94.4		%	93.4		%	94.4		%

______

Certain item footnotes


(a)	Three and nine month 2015 amounts include increases in revenue of $6 million and $19 million, respectively, and three and nine month 2014 amounts include increases in revenue of $4 million and $12 million, respectively, from the amortization of a fair value adjustment (associated with the below market contracts assumed upon acquisition) from our Jones Act tankers.

(b)

Three and nine month 2015 amounts include (i) increases in revenue of $6 million and $19 million, respectively, as discussed in footnote (a) above; (ii) increases in expenses of $22 million for both periods associated with the write-off of Alpha Natural Resources (Alpha) accounts receivable, due to bankruptcy, for revenues recognized in prior years but not yet collected. Accounts receivable written off associated with revenue recognized in 2015 are not considered a certain item; (iii) increases in earnings of $1 million and $4 million, respectively, associated with a liability adjustment related to a litigation matter; and (iv) an increase in earnings of $1 million and a decrease in earnings of $1 million, respectively from other certain items. Three and nine month 2014 amounts include increases in revenue of $4 million and $12 million, respectively, as discussed in footnote (a) above and increases in expense of $2 million and $10 million, respectively, due to hurricane clean-up and repair activities at our New York Harbor and Mid-Atlantic terminals. Nine month 2014 amount also includes an $12 million increase in expenses associated with a legal reserve adjustment.

Other footnotes


(c)	Includes our proportionate share of joint venture tonnage.


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

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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 nine month periods of 2015 and 2014.

Three months ended September 30, 2015 versus Three months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Alberta, Canada	$	13		76	%	$	21		124	%
Marine Operations	10			n/a		11			n/a
Gulf Liquids	9			17	%	12			17	%
Gulf Central	2			17	%	4			25	%
Gulf Bulk	1			4	%	6			16	%
Mid Atlantic	(9		)	(53	)%	(10		)	(30	)%
All others (including intrasegment eliminations and unallocated income tax expenses)	(10		)	(9	)%	(10		)	(4	)%
Total Terminals	$	16		6	%	$	34		8	%

Nine months ended September 30, 2015 versus Nine months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Alberta, Canada	$	34		77	%	$	50		111	%
Marine Operations	32			n/a		43			n/a
Gulf Liquids	16			10	%	27			13	%
Gulf Central	22			73	%	29			74	%
Gulf Bulk	16			26	%	26			25	%
Mid Atlantic	(15		)	(28	)%	(17		)	(17	)%
All others (including intrasegment eliminations and unallocated income tax expenses)	(9		)	(3	)%	(14		)	(2	)%
Total Terminals	$	96		14	%	$	144		12	%

_______

n/a – not applicable

The primary changes in our Terminals business segment’s EBDA before certain items in the comparable three and nine month periods of 2015 and 2014 included the following:


•	increases of $13 million (76%) and $34 million (77%), respectively, from our Alberta, Canada terminals, driven by our Edmonton-area expansion projects, including storage and connectivity additions at our Edmonton South and North 40 terminals as well as the commissioning of two joint venture rail terminals;


•	increases of $10 million and $32 million, respectively, from our Marine Operations related primarily to the incremental earnings from the Jones Act tankers we acquired in the first and fourth quarters of 2014;


•	increases of $9 million (17%) and $16 million (10%), respectively, from our Gulf Liquids terminals, related to the Vopak terminal acquisition completed in first quarter 2015 and the addition of nine new tanks at Galena Park placed into service during fourth quarter 2014 and first quarter 2015;


•	increases of $2 million (17%) and $22 million (73%), respectively, from our Gulf Central terminals, driven by higher earnings from expansion projects at our joint venture terminals, Battleground Oil Specialty Terminal Company LLC and Deeprock Development LLC;


•	increases of $1 million (4%) and $16 million (26%), respectively, from our Gulf Bulk terminals, driven by increased shortfall revenue from take-or-pay coal contracts;


•	decreases of $9 million (53%) and $15 million (28%), respectively, from our Mid Atlantic terminals, driven by lower revenues as a result of lower tonnage partially offset by higher shortfall revenue from take-or-pay coal contracts; and


•	decrease of $10 million for both periods resulting from the write-off of Alpha accounts receivable associated with revenue recognized in 2015, which impacted our International Marine Terminals included in “All others” and the Mid Atlantic terminals noted above by $8 million and $2 million, respectively.

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Products Pipelines



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In millions, except operating statistics)
Revenues(a)	$	467		$	520		$	1,389		$	1,578
Operating expenses	(188		)	(313		)	(607		)	(985		)
Other income (expense)	—			3			(1		)	4
Earnings from equity investments	10			11			32			36
Interest income and Other, net	2			1			5			—
Income tax expense	(3		)	—			(7		)	(1		)
Segment earnings before DD&A(b)	288			222			811			632
Certain items, net(b)	(1		)	—			(4		)	3
EBDA before certain items	$	287		$	222		$	807		$	635

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	(54	)	(10		)%	$	(189	)	(12		)%
EBDA before certain items	$	65		29		%	$	172		27		%

Gasoline (MMBbl)(c)	95.3			94.5			281.6			270.6
Diesel fuel (MMBbl)	34.8			33.4			98.7			96.7
Jet fuel (MMBbl)	26.7			25.3			77.8			75.7
Total refined product volumes (MMBbl)(d)	156.8			153.2			458.1			443.0
NGL (MMBbl)(e)	10.0			6.1			29.4			16.1
Crude and condensate (MMBbl)(f)	27.3			8.9			70.9			19.5
Total delivery volumes (MMBbl)	194.1			168.2			558.4			478.6
Ethanol (MMBbl)(g)	10.7			10.8			31.1			30.9

_______

Certain item footnotes


(a)	Three month 2015 amount includes an increase in revenue of $1 million related to an unrealized swap gain.

(b)

Three month 2015 amount includes an increase in revenue of $1 million as discussed in footnote (a) above. Nine month 2015 amount includes a decrease in expense of $4 million related to a certain Pacific operations litigation matter. Nine month 2014 amount includes an increase in expense of $4 million associated with a certain Pacific operations litigation matter, a $3 million gain from the sale of propane pipeline line-fill and an increase in expense of $2 million related to other certain items.

Other footnotes


(c)	Volumes include ethanol pipeline volumes.


(d)	Includes Pacific, Plantation Pipe Line Company, Calnev Pipe Line LLC, Central Florida and Parkway pipeline volumes. Joint Venture throughput is reported at our ownership share.


(e)	Includes Cochin and Cypress pipeline volumes. Joint Venture throughput is reported at our ownership share.


(f)	Includes Kinder Morgan Crude & Condensate, Double Eagle Pipeline LLC and Double H pipeline volumes. Joint Venture throughput is reported at our ownership share.


(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 nine month periods of 2015 and 2014.

Three months ended September 30, 2015 versus Three months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Crude & Condensate Pipeline (including KMCC - Splitter)	$	35		121	%	$	48		200	%
Pacific operations	12			16	%	10			9	%
Double H pipeline	12			n/a		15			n/a
Cochin	6			26	%	16			64	%
Transmix operations	2			33	%	(135		)	(54	)%
All others (including eliminations)	(2		)	(3	)%	(8		)	(8	)%
Total Products Pipelines	$	65		29	%	$	(54	)	(10	)%

Nine months ended September 30, 2015 versus Nine months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Crude & Condensate Pipeline (including KMCC - Splitter)	$	99		183	%	$	90		118	%
Pacific operations	29			13	%	22			7	%
Double H pipeline	30			n/a		38			n/a
Cochin	29			53	%	51			78	%
Transmix operations	(10		)	(28	)%	(378		)	(47	)%
All others (including eliminations)	(5		)	(2	)%	(12		)	(4	)%
Total Products Pipelines	$	172		27	%	$	(189	)	(12	)%

_______

n/a – not applicable

The primary changes in our Products Pipelines business segment’s EBDA before certain items in the comparable three and nine month periods of 2015 and 2014 included the following:

•

increases of $35 million (121%) and $99 million (183%), respectively, from our Kinder Morgan Crude & Condensate Pipeline driven primarily by an increase of 155% and 226%, respectively, in pipeline throughput volumes due to the ramp up of existing customer volumes and additional volumes from new customers and the startup of the first and second phases of KMCC - Splitter in March 2015 and July 2015. KMCC - Splitter contributed $12 million and $22 million to EBDA for the three and nine months ended September 30, 2015;


•	increases of $12 million (16%) and $29 million (13%), respectively, from our Pacific operations due to higher service revenues, resulting from higher volumes and margins, and a reduction in rights-of-way expenses;


•	increases of $12 million and $30 million, respectively, from our Double H pipeline which was acquired in February 2015 as part of the Hiland acquisition;


•	increases of $6 million (26%) and $29 million (53%), respectively, from Cochin driven by higher service revenues due to the completion of the Cochin Reversal project in the third quarter of 2014; and


•	increase of $2 million (33%) and a decrease of $10 million (28%), respectively, from our Transmix processing operations. The decrease for the nine month period was primarily due to unfavorable inventory adjustments impacting margins. The decreases in revenues of $135 million and $378 million, respectively, and associated decreases in costs of goods sold were caused by lower commodity prices.

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Kinder Morgan Canada



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In millions, except operating statistics)
Revenues	$	68		$	73		$	193		$	210
Operating expenses	(22		)	(27		)	(64		)	(75		)
Interest income and Other, net	1			8			6			14
Income tax expense	(5		)	(4		)	(15		)	(11		)
Segment earnings before DD&A	$	42		$	50		$	120		$	138

Change from prior period	Increase/(Decrease)
Revenues	$	(5	)	(7		)%	$	(17	)	(8		)%
EBDA	$	(8	)	(16		)%	$	(18	)	(13		)%

Transport volumes (MMBbl)(a)	29.5			27.6			86.9			79.5

_______


(a)	Represents Trans Mountain pipeline system volumes.

Following is information related to the increases and decreases in both EBDA and revenues in the comparable three and nine month periods of 2015 and 2014.

Three months ended September 30, 2015 versus Three months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Trans Mountain Pipeline	$	(2	)	(5	)%	$	(5	)	(7	)%
Express Pipeline(a)	(6		)	(100	)%	n/a			n/a
Total Kinder Morgan Canada	$	(8	)	(16	)%	$	(5	)	(7	)%

Nine months ended September 30, 2015 versus Nine months ended September 30, 2014



	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Trans Mountain Pipeline	$	(12	)	(9	)%	$	(17	)	(8	)%
Express Pipeline(a)	(6		)	(100	)%	n/a			n/a
Total Kinder Morgan Canada	$	(18	)	(13	)%	$	(17	)	(8	)%

_______

n/a - not applicable


(a)	Amount consists of unrealized foreign currency gains, net of book tax, on 2014 outstanding, short-term intercompany borrowings that were repaid in December 2014. We sold our debt and equity investments in Express Pipeline on March 14, 2013.

For the comparable three and nine month periods of 2015 and 2014, the Kinder Morgan Canada business segment had decreases in earnings of $8 million (16%) and $18 million (13%), respectively, driven by an unfavorable impact from foreign currency exchange rates, and repayment of the Express note as discussed in footnote (a) above.

Other

This segment contributed losses of $9 million and $55 million for the three and nine months ended September 30, 2015, respectively. Earnings were $6 million and $13 million for the three and nine months ended September 30, 2014, respectively. However, three and nine month 2015 losses included certain items of a $1 million increase in earnings and a $32 million decrease in earnings, respectively. The nine month 2015 certain items related primarily to a certain litigation matter; and three and nine month 2014 earnings included certain items of $10 million and $22 million, respectively, which increased earnings

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and were primarily related to foreign operations and our corporate headquarters building. After taking into effect the certain items, the losses for the three and nine months ended September 30, 2015 increased by $6 million and $14 million, respectively, when compared with the same prior year periods primarily due to increased corporate franchise taxes as a result of the Merger Transactions and lower interest income.

General and Administrative, Interest, and Noncontrolling Interests



	Three Months Ended September 30,
	2015			2014			Increase/(decrease)
	(In millions, except percentages)
General and administrative expense(a)(c)	$	160		$	135		$	25		19	%
Certain items(a)	2			15			(13		)	(87	)%
Management fee reimbursement(c)	(10		)	(9		)	(1		)	(11	)%
General and administrative expense before certain items	$	152		$	141		$	11		8	%

Unallocable interest expense net of interest income and other, net(b)	$	539		$	431		$	108		25	%
Certain items(b)	(15		)	13			(28		)	(215	)%
Unallocable interest expense net of interest income and other, net, before certain items	$	524		$	444		$	80		18	%

Net (loss) income attributable to noncontrolling interests	$	(3	)	$	450		$	(453	)	(101	)%
Noncontrolling interests associated with certain items(d)	6			—			6			n/a
Net income attributable to noncontrolling interests before certain items	$	3		$	450		$	(447	)	(99	)%



	Nine Months Ended September 30,
	2015			2014			Increase/(decrease)
	(In millions, except percentages)
General and administrative expense(a)(c)	$	540		$	461		$	79		17	%
Certain items(a)	(27		)	18			(45		)	(250	)%
Management fee reimbursement(c)	(28		)	(27		)	(1		)	(4	)%
General and administrative expense before certain items	$	485		$	452		$	33		7	%

Unallocable interest expense net of interest income and other, net(b)	$	1,525		$	1,325		$	200		15	%
Certain items(b)	40			13			27			208	%
Unallocable interest expense net of interest income and other, net, before certain items	$	1,565		$	1,338		$	227		17	%

Net (loss) income attributable to noncontrolling interests	$	(4	)	$	977		$	(981	)	(100	)%
Noncontrolling interests associated with certain items(d)	20			—			20			n/a
Net income attributable to noncontrolling interests before certain items	$	16		$	977		$	(961	)	(98	)%

________

n/a – not applicable

Certain item footnotes

(a)

Three month 2015 amount includes increases in expense of $1 million related to certain corporate legal matters and $2 million related to costs associated with our Hiland acquisition. Nine month 2015 amount includes increases in expense of $41 million related to certain corporate legal matters and $14 million related to costs associated with our Hiland acquisition. Partially offsetting these three and nine month 2015 increases are decreases in expense of $5 million and $28 million, respectively, related to pension credit income. Three and nine month 2014 amounts include (i) decreases in expense of $11 million and $29 million, respectively, related to pension credit income; (ii) a decrease in expense of $1 million and an increase in expense of $7 million, respectively, primarily related to severance costs associated with acquisitions; and (iii) a decrease in expense of $3 million and an increase in expense of $4 million, respectively, for various other certain items.

(b)

Three and nine month 2015 amounts include increases in interest expense of $33 million and $3 million, respectively, primarily related to a non-cash true-up of our estimate of swap ineffectiveness and decreases in interest expense of $18 million and $53 million, respectively, related to debt fair value adjustments associated with acquisitions. Nine month 2015 amount also includes a decrease in interest expense of $13 million associated with a certain Pacific operations litigation matter and a $23 million increase in interest

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expense for a non-cash adjustment related to a certain legal matter. Three and nine month 2014 amounts include (i) decreases in interest expense of $15 million and $48 million, respectively, related to debt fair value adjustments associated with acquisitions; (ii) a decrease in interest expense of $1 million and an increase in interest expense of $9 million, respectively, of amortization of capitalized financing fees; (iii) increases in interest expense of $2 million and $12 million of interest expense on margin for marketing contracts; and (iv) increases in interest expense of $1 million and $14 million, respectively, associated with a certain Pacific operations litigation matter.

Other footnotes

(c)

Three and nine month 2015 amounts include NGPL Holdco LLC general and administrative reimbursements of $10 million and $28 million. respectively. Three and nine month 2014 amounts include NGPL Holdco LLC general and administrative reimbursements of $9 million and $27 million, respectively. These amounts were recorded to the “Product sales and other” caption with the offsetting expenses primarily included in the “General and administrative” expense caption in our accompanying consolidated statements of income.


(d)	Three and nine month 2015 amount includes a $6 million loss associated with a terminals segment certain item and disclosed above in “—Terminals”. Nine month 2015 amount also includes a $14 million loss associated with a natural gas pipelines segment impairment certain item and disclosed above in “—Natural Gas Pipelines.”

Our consolidated general and administrative expenses before certain items for the three and nine months ended September 30, 2015 as compared to the respective prior year periods increased $11 million and $33 million, respectively. The quarter over quarter increase was primarily driven by lower capitalized costs partially offset by lower benefit costs. The year over year increase was primarily driven by lower capitalized costs and higher benefit costs, payroll taxes and labor expenses, in part due to the Hiland acquisition, partially offset by lower insurance costs.

In the table above, we report our interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense net of interest income and other, net before certain items for the three and nine months ended September 30, 2015 as compared to the same periods a year ago increased $80 million and $227 million, respectively. The increases in interest expense was due to higher average debt balances as a result of capital expenditures, joint venture contributions and acquisitions that were made during 2014 and 2015, and incremental debt borrowings to fund the $3.9 billion cash portion of the Merger Transactions in November 2014. This increase in interest expense was partially offset by a lower overall weighted average interest rate on our outstanding debt.

We use interest rate swap agreements to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of September 30, 2015 and December 31, 2014, approximately 24% and 26%, respectively, of our 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 swaps. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Net income attributable to noncontrolling interests, represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. The decreases for the three and nine months ended September 30, 2015 as compared to the same periods a year ago of $447 million (99%) and $961 million (98%), respectively, were primarily due to our purchase of the KMP and EPB limited partner units and KMR shares formerly owned by the public in the fourth quarter of 2014 as part of the Merger Transactions.

Income Taxes

Our tax expense for the three months ended September 30, 2015 was approximately $108 million as compared to $246 million for the same period of 2014. The $138 million decrease in tax expense was primarily due to (i) a decrease in our earnings as a result of lower commodity prices and asset impairments in 2015; (ii) the elimination (due to the Merger Transactions) of the deferred charge that had been recorded as a result of the drop-downs of TGP, EPNG, and the midstream assets; and (iii) adjustments to our income tax reserve for uncertain tax positions. These decreases are partially offset by (i) higher foreign taxes primarily as a result of the increase in the Alberta income tax rate; (ii) an increase in our share of taxable income from KMP following the Merger Transactions; and (iii) lower dividend-received deductions from our investment in Florida Gas Pipeline (Citrus).

Our tax expense for the nine months ended September 30, 2015 was approximately $521 million as compared to $624 million for the same period of 2014. The $103 million decrease in tax expense was primarily due to a decrease in our earnings as a result of lower commodity prices and asset impairments in 2015 and the elimination (due to the Merger Transactions) of the deferred charge that had been recorded as a result of the drop-downs of TGP, EPNG, and the midstream assets, partially offset by an increase in our share of taxable income from KMP following the Merger Transactions.

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Financial Condition

General

As of September 30, 2015, we had $179 million of “Cash and cash equivalents” on our consolidated balance sheet, a decrease of $136 million (43%) from December 31, 2014. We believe our cash position, remaining borrowing capacity on our credit facility (discussed below in “—Short-term Liquidity”), and our access to financial resources are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have relied primarily on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, and dividend payments.

In general, we expect to fund expansion capital expenditures, acquisitions and debt principal payments through (i) additional borrowings; (ii) the issuance of additional common stock or other forms of equity; and (iii) in some instances, proceeds from divestitures.

Short-term Liquidity

As of September 30, 2015, our principal sources of short-term liquidity are (i) our $4.0 billion revolving credit facility and associated $4.0 billion commercial paper program; and (ii) cash from operations. The loan commitments under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program and letters of credit reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and have consistently generated strong cash flow from operations, providing a source of funds of $3,507 million and $3,492 million in the first nine months of 2015 and 2014, respectively (the period-to-period increase is discussed below in “Cash Flows—Operating Activities”).

Our short-term debt as of September 30, 2015 was $3,003 million, primarily consisting of (i) $275 million outstanding borrowings under our $4 billion revolving credit facility; (ii) $193 million outstanding borrowings under our $4 billion commercial paper program; and (iii) a combined $2,382 million of six separate series of senior notes that mature in the next year. We intend to refinance our short-term debt through additional credit facility borrowings, commercial paper borrowings, or with issuing new long-term debt or equity. Our combined balance of short-term debt as of December 31, 2014 was $2,717 million.

We had working capital (defined as current assets less current liabilities) deficits of $3,124 million and $2,610 million as of September 30, 2015 and December 31, 2014, respectively. Our current liabilities include short-term borrowings used to finance our expansion capital expenditures which are periodically replaced with long-term financing. The overall $514 million (20%) unfavorable change from year-end 2014 was primarily due to (i) a net increase in the current portion of long-term debt; (ii) lower cash balances; (iii) lower other current assets driven by the 2015 receipt of a federal tax refund; (iv) a net decrease in accounts receivable trade; (v) a net increase in property tax accruals; offset partially by (vi) a net decrease in our credit facility and commercial paper borrowings; and (vii) a net decrease in accounts payable trade. 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 our cash and cash equivalent balances as a result of equity and debt issuances.

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as discretionary capital expenditures). Expansion capital expenditures 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 DCF (see “Results of Operations—Distributable Cash Flow”). 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. The distinction between maintenance and expansion capital expenditures 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 expansion capital expenditures 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/sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on cash available to pay dividends because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are. See “—Cash Flows—Dividends.”

Our capital expenditures for the nine months ended September 30, 2015, and the amount we expect to spend for the remainder of 2015 to grow and sustain our businesses are as follows:



	Nine Months Ended September 30, 2015		2015 Remaining		Total
	(In millions)
Sustaining capital expenditures(a)	$	397	$	175	$	572
Discretionary capital expenditures(b)(c)	$	2,626	$	827	$	3,453

_______


(a)	Nine-month 2015, 2015 Remaining, and Total 2015 amounts include $50 million, $22 million, and $72 million, respectively, for our proportionate share of sustaining capital expenditures of unconsolidated joint ventures.


(b)	Nine-month 2015 amount includes an increase of $308 million related to discretionary capital expenditures of unconsolidated joint ventures and small acquisitions (i.e. excludes Hiland acquisition) and a decrease of a combined $334 million of net changes from accrued capital expenditures and contractor retainage.


(c)	2015 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.

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2014 in our 2014 Form 10-K.

Cash Flows

Operating Activities

The net increase of $15 million in cash provided by operating activities for the first nine months of 2015 compared to the respective 2014 period was primarily attributable to:

•

a $216 million decrease in cash from overall net income after adjusting our period-to-period $933 million decrease in net income for non-cash items primarily consisting of the following: (i) net losses on impairments and disposals of long-lived assets and equity investments (see discussion above in “—Results of Operations”); (ii) DD&A expenses (including amortization of excess cost of equity investments); (iii) deferred income taxes; (iv) a net increase in legal reserves (see discussion above in “—Results of Operations”); (v) a net unrealized gain relating to derivative contracts used to hedge forecasted natural gas, NGL, and crude oil sales (see discussion above in “—Results of Operations”); and (v) a net increase in equity earnings from our equity investments; and

•

a $231 million increase in cash associated with net changes in working capital items and non-current assets and liabilities. The increase was driven, among other things, primarily by a $195 million income tax refund on taxes we previously paid in 2014, and higher cash flows due to favorable changes in the collection of trade and exchange gas receivables. These increases were offset by lower cash flow due to the timing of payments from our trade payables and rate case payments.

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Investing Activities

The $702 million net decrease in cash provided by investing activities for the first nine months of 2015 compared to the respective 2014 period was primarily attributable to:


•	an $819 million decrease in cash due to higher expenditures for acquisitions and investments. The overall increase in acquisitions was primarily related to the $1,706 million (net of cash assumed) and $158 million we paid for the Hiland and Vopak acquisitions, respectively, in the 2015 period, versus the $961 million we paid for the Jones Act tankers in 2014;


•	a $321 million decrease in cash due to higher capital expenditures, which includes a $185 million payment related to our ELC project in the third quarter of 2015. See discussion in Note 2 “Acquisitions” for further information regarding this purchase;


•	a $273 million increase in cash due to lower capital contributions to our equity investments, primarily due to a $175 million contribution we made in the third quarter of 2014 to our 50%-owned Midcontinent Express Pipeline LLC to fund our share of its repayment of $350 million in senior notes that matured on September 15, 2014; and


•	a $114 million increase in cash primarily due to favorable changes in restricted deposit accounts associated with our hedging activities.

Financing Activities

The net increase of $675 million in cash provided by financing activities for the first nine months of 2015 compared to the respective 2014 period was primarily attributable to:


•	a $3,833 million increase in cash from the issuances of our Class P shares under our equity distribution agreement;


•	a $1,466 million increase in cash due to lower distributions to noncontrolling interests, primarily resulting from our acquisition of the noncontrolling interests associated with KMP and EPB in the Merger Transactions in November 2014;


•	a $180 million increase in cash due to the reduction of payments made to repurchase shares and warrants in the first nine months of 2015 compared to the respective 2014 period;


•	a $1,780 million decrease in cash due to higher total dividend payments;


•	a $1,631 million decrease in contributions provided by noncontrolling interests, primarily reflecting the proceeds received from the issuance of KMP’s and EPB’s common units to the public in the 2014 period and no proceeds in the 2015 period due to the Merger Transactions; and


•	a $1,394 million net decrease in cash from overall debt financing activities. See Note 3 “Debt” for further information regarding our debt activity.

Dividends

We remain on track to meet our full-year dividend target of $2.00 per share on our common stock for 2015, an approximately 15% increase over the 2014 declared dividends of $1.74 per share. While we are largely insulated from fluctuations in commodity prices due to our predominantly take-or-pay supported cash flows, the lower commodity price environment has decreased the amount by which we expect our cash available for dividends to exceed our full-year dividend target.



Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
December 31, 2014	$	0.45	January 21, 2015	February 2, 2015	February 17, 2015
March 31, 2015	$	0.48	April 15, 2015	April 30, 2015	May 15, 2015
June 30, 2015	$	0.49	July 15, 2015	July 31, 2015	August 14, 2015
September 30, 2015	$	0.51	October 21, 2015	November 2, 2015	November 13, 2015

Our governing documents or credit agreements do not prohibit us from borrowing to pay dividends. The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. All of these matters will be taken into consideration by our board of directors in declaring dividends.

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Our dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the intended levels, our common stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 16th day of each February, May, August and November.

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, 2014, in Item 7A in our 2014 Form 10-K. For more information on our risk management activities, see Item 1, Note 5 “Risk Management” to our consolidated financial statements.

Item 4. Controls and Procedures.

As of September 30, 2015, 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 September 30, 2015 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, Other Contingencies and Commitments,” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2014 Form10-K.

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

Our Purchases of Our Warrants

Period	Total number of securities purchased(a)	Average price paid per security		Total number of securities purchased as part of publicly announced plans(a)	Maximum approximate dollar value of securities that may yet be purchased under the plans or programs
July 1 to July 31, 2015	1,121,717	$	2.57	1,121,717	$	94,878,754
August 1 to August 31, 2015	1,664,269	$	1.50	1,664,269	$	92,369,260
September 1 to September 30, 2015	1,571,195	$	1.10	1,571,195	$	90,621,765

Total Warrants	4,357,181	$	1.63	4,357,181
					$	90,621,765

_______


(a)	On June 12, 2015, we announced that our board of directors had approved a warrant repurchase program authorizing us to repurchase up to $100 million of warrants.

Item 3. Defaults Upon Senior Securities.

None.

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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.



3.1	*	Amended and Restated Certificate of Incorporation of Kinder Morgan, Inc. (filed as Exhibit 3.1 to Kinder Morgan, Inc.’s Quarterly Report on Form 10‑Q for the three months ended June 30, 2015).

3.2	*	Amended and Restated Bylaws of Kinder Morgan, Inc. as amended by the Amendment No. 1 to the Amended and Restated Bylaws (filed as Exhibit 3.2 to Kinder Morgan, Inc.’s Annual Report on Form 10‑K for the year ended December 31, 2014).

10.1		Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules current as of September 30, 2015.

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 nine months ended September 30, 2015 and 2014; (ii) our Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014; (iii) our Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014; (v) our Consolidated Statements of Stockholders’ Equity for the nine months ended September 30, 2015 and 2014; and (vi) the notes to our Consolidated Financial Statements.

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

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SIGNATURE

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



	KINDER MORGAN, INC.
		Registrant



Date:	October 23, 2015	By:	/s/ Kimberly A. Dang
			Kimberly A. Dang Vice President and Chief Financial Officer (principal financial and accounting officer)